TABLE OF CONTENTS
PART I
PAGE
ITEM 1. BUSINESS 2
GENERAL 2
ELECTRIC INDUSTRY RESTRUCTURING 3
REGULATION 3
RATES 4
POWER SUPPLY 5
FUEL 6
WATER RIGHTS 7
ENVIRONMENTAL REGULATION 7
RESEARCH AND DEVELOPMENT 9
DIVERSIFIED BUSINESS OPERATIONS 9
CONSTRUCTION PROGRAM 11
FINANCING PROGRAM 11
ITEM 2. PROPERTIES 13
ITEM 3. LEGAL PROCEEDINGS 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS 16
EXECUTIVE OFFICERS OF THE REGISTRANTS 17
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND
RELATED STOCKHOLDER MATTERS 20
ITEM 6. SELECTED FINANCIAL DATA 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 22
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT
MARKET RISK 32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 33
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 69
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANTS* 69
ITEM 11. EXECUTIVE COMPENSATION* 69
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT* 69
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 69
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND
REPORTS ON FORM 8-K 69
SIGNATURES 75
*INCORPORATED BY REFERENCE.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K-405
(Mark One)
X Annual Report pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1999
OR
Transition report pursuant to section 13 or 15(d) of
the Securities Exchange Act of 1934
For the transition period from ................... to
.................................................................
Exact name of Registrants as
specified in their charters,
Commission address of principal executive IRS Employer Iden-
File Number offices and Registrants' tification Number
telephone number
1-14465 IDACORP, Inc. 82-0505802
1-3198 Idaho Power Company 82-0130980
1221 W. Idaho Street
Boise, ID 83702-5627
(208) 388-2200
State or other jurisdiction of incorporation: Idaho
SECURITIES REGISTERED PURSUANT TO SECTION 12(b)
OF THE ACT: Name of exchange
on which registered
IDACORP, Inc.: Common Stock, without par value New York and Pacific
Preferred Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrants were required to
file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes ( X ) No ( )
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrants' knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ( X )
Aggregate market value of voting and non-voting common stock held
by nonaffiliates (March 1, 2000)
IDACORP, Inc.: $1,160,332,841
Idaho Power Company: None
Number of shares of common stock outstanding at February 29,2000:
IDACORP, Inc.: 37,612,351
Idaho Power Company: 37,612,351 shares, all of which are held
by IDACORP, Inc.
Documents Incorporated by Reference:
Part III, Item 10 - 13 Portions of the joint definitive proxy
statement of the Registrant.
to be filed pursuant to Regulation 14A for
the 2000 Annual Meeting of Shareholders to
be held on May 11, 2000.
This Combined Form 10-K represents separate filings by IDACORP,
Inc. and Idaho Power Company. Information contained herein
relating to an individual registrant is filed by that registrant
on its own behalf. Idaho Power Company makes no representations
as to the information relating to IDACORP, Inc.'s other
operations.
PART I - IDACORP, Inc. and Idaho Power Company
ITEM 1. BUSINESS
SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7-
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Forward-Looking Information". Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar
expressions.
GENERAL
IDACORP, Inc. (IDACORP or the Company) is a holding company
incorporated in 1998 under the laws of the state of Idaho. The
Company's principal subsidiary is Idaho Power Company (IPC), an
electric public utility that represents over 90 percent of
IDACORP's total assets and substantially all of its operating
revenues. IDACORP's other subsidiaries include Ida-West Energy
Company, an independent power project management and development
company, IDACORP Energy Solutions, LP, a marketer of energy
commodities, and IDACORP Technologies, Inc., a majority owner of
Northwest Power Systems, a developer of integrated fuel cell
systems.
IPC was incorporated under the laws of the state of Idaho in 1989
as successor to a Maine corporation organized in 1915. IPC is
engaged in the generation, purchase, transmission, distribution
and sale of electric energy in an approximate 20,000-square-mile
area in southern Idaho, eastern Oregon and northern Nevada, with
an estimated population of 794,000. IPC holds franchises in
approximately 72 cities in Idaho and ten cities in Oregon, and
holds certificates from the respective public utility regulatory
authorities to serve all or a portion of 28 counties in Idaho,
three counties in Oregon and one county in Nevada. As of
December 31, 1999, IPC supplied electric energy to 384,421
general business customers and employed 1,720 people in its
operations.
IPC operates 17 hydroelectric power plants and shares ownership
in three coal-fired generating plants (see Item 2 - "Properties").
IPC relies heavily on hydroelectric power for its generating needs
and is one of the nation's few investor-owned utilities with a
predominantly hydro base. IPC has participated in the development
of thermal generation in Wyoming, Oregon and Nevada using low-sulfur
coal from Wyoming and Utah.
IPC's operations, like those of certain other utilities in the
Northwest, can be significantly affected by changing weather,
precipitation and streamflow conditions. In 1993 a power cost
adjustment (PCA) mechanism was implemented in IPC's Idaho
jurisdiction. With the implementation of the PCA, which
incorporates a major portion of the operating expenses with the
largest variation potential (net power supply costs), IPC's
operating results have become more dependent upon general
regulatory, economic, temperature and competitive conditions and
less on precipitation and streamflow conditions. Variations in
energy usage by ultimate customers occur from year to year, from
season to season and from month to month within a season,
primarily as a result of weather conditions.
With a predominantly hydroelectric base and low-cost thermal
plants, IPC is one of the lowest cost producers of electric
energy among the nation's investor-owned utilities. Through its
interconnections with the Bonneville Power Administration (BPA)
and other utilities, IPC has access to all the major electric
systems in the West.
For the year ended December 31, 1999, total revenues from
residential customers accounted for 41 percent of total general
business revenues. Commercial customers with less than 1,000
kilowatt (kW) demand accounted for 23 percent, industrial
customers with 1,000 kW demand or more accounted for 23 percent,
irrigation customers accounted for 12 percent and other revenues
accounted for 1 percent.
IPC's principal commercial and industrial customers are involved
in: elemental phosphorus production; food processing; phosphate
fertilizer production; electronics and general manufacturing;
lumber; beet sugar refining; and the recreation industry, such as
lodges, condominiums, ski lifts and related facilities.
ELECTRIC INDUSTRY RESTRUCTURING
The legislatures and/or the regulatory commissions in several
states, and at a national level, have considered or are considering
various forms of retail competition. In 1997, the Idaho
Legislature appointed a committee to study restructuring of the
electric utility industry. Although the committee will continue
studying a variety of restructuring ideas, it has not recommended
any restructuring legislation and is not expected to in the
foreseeable future. In 1999 the Oregon legislature passed
legislation restructuring the electric utility industry in that
state, but exempted IPC's service territory.
In December 1999 the FERC issued Order No. 2000, dealing with
Regional Transmission Organizations (RTOs). It proposes to ensure
non-discriminatory, open-access to electricity transmission
facilities. Each utility is required to file by October 15, 2000 a
statement regarding its intention to join a RTO. IPC is engaged in
formation discussions with other Northwest utilities. These
utilities include both investor-owned and other entities.
IPC's resource acquisition policy reflects the changing nature of
the electric utility industry. IPC has adopted a policy of
acquiring all new resources as close as possible to the actual time
of need, and selecting the lowest cost resources meeting all of
IPC's requirements.
REGULATION
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
Federal Energy Regulatory Commission (FERC), the Idaho Public
Utilities Commission (IPUC), the Oregon Public Utility Commission
(OPUC) and the Public Utility Commission of Nevada. IPC is also
under the regulatory jurisdiction of the IPUC, OPUC and the
Public Service Commission of Wyoming as to the issuance of
securities. IPC is subject to the provisions of the Federal
Power Act as a "licensee" and "public utility" as therein
defined. IPC's retail rates are established under the
jurisdiction of the state regulatory agencies and its wholesale
and transmission rates are regulated by the FERC (See "Rates").
Pursuant to the requirements of Section 210 of the Public
Utilities Regulatory Policy Act of 1978 (PURPA), the state
regulatory agencies have each issued orders and rules regulating
IPC's purchase of power from Cogeneration and Small Power
Production (CSPP) facilities.
As a licensee under the Federal Power Act, IPC and its licensed
hydroelectric projects are subject to the provisions of Part I of
the Act. All licenses are subject to conditions set forth in the
Act and related FERC regulations. These conditions and
regulations include provisions relating to condemnation of a
project upon payment of just compensation, amortization of
project investment from excess project earnings, possible
takeover of a project after expiration of its license upon
payment of net investment, severance damages, and other matters.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. IPC's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake
River where it forms the boundary between Idaho and Oregon and
occupy land located in both states. With respect to project
property located in Oregon, these facilities are subject to the
Oregon Hydroelectric Act. IPC has obtained Oregon licenses for
these facilities and these licenses are not in conflict with the
Federal Power Act or IPC's FERC license (see Item 2.
"Properties").
RATES
Idaho Jurisdiction -
IPC adjusts its Idaho retail rates based on a PCA mechanism
adopted in 1993. The PCA enables IPC to collect or refund a
portion of the difference between net power supply costs actually
incurred and power supply costs allowed in base rates. These
adjustments, which take effect annually in mid-May, are based on
two components: the difference between a forecast of the upcoming
year's net power supply costs and the amount in base rates, and a
true-up of the prior year's forecasted costs to actual costs.
The May 1999 rate adjustment reduced rates by 9.2 percent. The
decrease was the result of both forecasted above-average
hydroelectric generating conditions for the upcoming year and a
true-up from the 1998-99 rate period. Overall, the May 1999 rate
adjustment is expected to decrease annual general business
revenue by $40 million during the 1999-2000 rate period.
So far in the 1999-2000 rate period, actual power costs and
generating conditions have been near forecast. IPC has recorded
a regulatory asset and a reduction of expenses of $1.7 million as
of December 31, 1999, representing the difference between actual
and forecasted costs so far in this rate period. The variance
that exists at the end of the 1999-2000 rate period will be trued-
up in the next annual PCA adjustment.
The May 1998 rate adjustment increased expected annual revenue by
$34 million over the amount that would have been recorded at the
1997-98 rates. The 1998-99 forecast had assumed a return to more
normal hydroelectric generating conditions from the above-average
conditions experienced in the prior year. This resulted in
forecasted power supply costs being near the amounts used in base
rates.
In August 1995 the IPUC approved a Settlement that authorized IPC
to defer and amortize costs related to reorganization in return
for a general rate freeze through the end of 1999.
Under the Settlement, which expired at the end of 1999, when
actual annual earnings exceeded an 11.75 percent return on year-
end common equity for the Idaho jurisdiction, the Company shared
50 percent of the additional earnings with its Idaho retail
customers. IPC set aside approximately $8.9 million, $6.4
million and $7.6 million for 1999, 1998 and 1997 respectively for
the benefit of its Idaho customers. Of the $14.0 million set
aside during 1997 and 1998, $6.2 million was applied against
Idaho demand-side management / conservation expenditures and $2.6
million was applied to 1997-1998 Northwest Energy Efficiency
Alliance (NEEA) expenditures. In addition, $2.0 million was
reserved to fund 1999 NEEA and demand-side management (DSM)
expenditures (once they have been approved for recovery by the
IPUC), and $0.7 million was refunded to certain customers. The
balance of $2.5 million has been set in a reserve for the benefit
of Idaho customers. The disposition of this benefit has yet to
be determined. In December 1999 IPC filed a request that $5.5
million of the 1999 sharing amount be reserved to fund 2000-2004
NEEA participation.
Other important points in the Settlement were that IPC was not
allowed to increase its Idaho general rates prior to January 1,
2000, except under special conditions as defined in the
Settlement, and IPC agreed that its quality of service would not
decline as a result of corporate reorganization.
In 1998, IPC received an order from the IPUC reducing the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to 12 years. At
the same time the IPUC approved an additional $16 million of
Idaho allocated demand-side management expenditures for recovery
through rates resulting in an increase of 0.67 percent to Idaho
customers effective May 16, 1999. This order was appealed to the
Idaho Supreme Court by a group of IPC customers. Oral arguments
were heard on December 8, 1999 and the matter is awaiting a
Supreme Court decision.
Other Jurisdictions -
In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to five years. The
OPUC also approved additional Oregon allocated demand-side
management expenditures for recovery through rates. The Oregon
costs will be recovered by extending an existing surcharge until
the amounts are collected.
In July 1996, IPC filed an open-access tariff with the FERC, in
compliance with Order 888. The terms and conditions of the
tariff were approved for use beginning in 1997 (see "Transmission
Services").
POWER SUPPLY
IPC meets its system load requirements using a combination of its
own system generation, mandated purchases from private developers
(see "CSPP Purchases" below) and purchases from other utilities
and power producers. IPC's generating stations and capacities
are listed in "Item 2. Properties". Historically, under normal
water conditions, IPC's hydro system supplies approximately 56
percent, thermal generation accounts for 33 percent and purchased
power and other interchanges contribute the remaining 11 percent
of total system resources. IPC's system is dual-peaking, with
the larger peak demand generally occurring in the summer. The
system peak demand for 1999 was 2,839 MW, set on July 13, 1999.
Peak demands in 1998 and 1997 were 2,747 MW and 2,545 MW
respectively. IPC periodically updates its load and resource
projections and now expects total system energy requirements to
grow 2.3 percent annually over the next five years.
Because of its reliance upon hydroelectric generation, which
varies according to streamflows, IPC's generating system is
constrained more by resource (water) availability than by
capacity. Seasonal exchanges of winter-for-summer power are
included among the contracted resources to maximize the firm load
carrying capability. Exchanges are currently made with The
Montana Power Company under a contract that expires in 2000 and
with Seattle City Light under a contract that expires in 2003.
During the 2000-2003 period, IPC plans to provide all the energy
required to serve its firm load requirements by using its
hydroelectric and coal-fired generating units and CSPP purchases,
supplemented by purchases of power from neighboring utilities or
marketing entities.
Even though its significant hydroelectric generation can operate
to meet peak demands, seasonal energy requirements are important
to IPC because its seasonal energy capability is determined in
part by the availability of water. In 1997, 1998 and 1999, IPC's
hydro generating system experienced above average water years.
IPC's generating facilities are interconnected through its
integrated transmission system and are operated on a coordinated
basis to achieve maximum load-carrying capability and
reliability. IPC's transmission system is directly
interconnected with the transmission systems of the Bonneville
Power Administration Avista Corporation, PacifiCorp, The Montana
Power Company and Sierra Pacific Power Company. Such
interconnections, coupled with transmission line capacity made
available under agreements with certain of the above utilities,
permit the interchange, purchase and sale of power among all
major electric systems in the West. IPC is a member of the
Western Systems Coordinating Council, the Western Systems Power
Pool, the Northwest Power Pool, the Western Regional Transmission
Association and the Northwest Regional Transmission Association.
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 estimated
annualized cost for the 65 CSPP projects on-line as of December
31, 1999 is $56.2 million. During 1999, IPC purchased 931.8
million kWh of power from these private developers at a blended
price of 6.3 cents per kWh.
The IPUC has determined that negotiated rates for future CSPP
projects larger than one MW should be tied more closely to values
determined in IPC's integrated resource planning process and has
limited the length of new contracts to a maximum of five years.
Wholesale Power Sales -
IPC has firm wholesale power sales contracts with several
entities. These contracts are for various amounts of energy, up
to 100 average megawatts, and are of various lengths expiring
between 2000 and 2009.
Transmission Services -
IPC has long had an informal open-access transmission policy and
is experienced in providing reliable, high quality, economical
transmission service. IPC provides various firm and non-firm
wheeling services for several surrounding utilities.
In December 1999 the FERC issued Order No. 2000, dealing with
Regional Transmission Organizations (RTOs). It proposes to ensure
non-discriminatory, open-access to electricity transmission
facilities. Each utility is required to file by October 15, 2000 a
statement regarding its intention to join a RTO. IPC is engaged in
formation discussions with other Northwest utilities. These
utilities include both investor-owned and other entities.
In 1996 the FERC issued Order Nos. 888 and 889 dealing with open
access non-discriminatory transmission services by public
utilities, and standards of conduct regarding these services.
These orders require public utilities owning transmission lines
to file open-access tariffs available to buyers and sellers of
wholesale electricity; to require utilities to use the tariffs
for their own wholesale sales; and to allow utilities to recover
stranded costs, subject to certain conditions. The FERC has
issued an unconditional acceptance of the terms and conditions of
IPC's tariff.
IPC's system lies between and is interconnected to the winter-
peaking northern and summer-peaking southern regions of the
western interconnected power system. This position allows IPC to
both provide transmission services and reach a broad power sales
market. IPC is a member of both the Western Regional
Transmission Association and the Northwest Regional Transmission
Association. These associations help facilitate transmission
access and planning throughout the power system.
FUEL
IPC, through its subsidiary Idaho Energy Resources Co., owns a
one-third interest in the Bridger Coal Company, which owns the
Jim Bridger mine supplying coal to the Jim Bridger generating
plant in Wyoming. The mine, located near the Jim Bridger plant,
operates under a long-term sales agreement that provides for
delivery of coal over a 51-year period ending in 2025. The Jim
Bridger mine has sufficient reserves to provide coal deliveries
pursuant to the sales agreement. IPC also has a coal supply
contract providing for annual deliveries of coal through 2005
from the Black Butte Coal Company's Black Butte and Leucite Hills
mines located near the Jim Bridger project. This contract
supplements the Bridger Coal Company deliveries and provides
another coal supply to operate the Jim Bridger plant. The Jim
Bridger plant's rail load-in facility and unit coal train allows
the plant to take advantage of potentially lower-cost coal from
outside mines for tonnage requirements above established contract
minimums.
Sierra Pacific Power Company (SPPCo), with whom IPC is a joint
(50/50) participant in the ownership and operation of the North
Valmy Steam Electric Generating plant (Valmy plant), has a long-
term coal contract with Southern Utah Fuel Company, a subsidiary
of Canyon Fuel Co., LLC. This contract, which expires on June
30, 2003, calls for the delivery of up to 17.5 million tons of
low-sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1.
In 1986 IPC and SPPCo signed a long-term coal supply agreement
with the Black Butte Coal Company. This contract provides for
Black Butte to supply coal to the Valmy project under a flexible
delivery schedule that allows for variations in the number of
tons to be delivered ranging from a minimum of 300,000 tons per
year to a maximum of 1,000,000 tons per year. This flexibility
accommodates fluctuations in energy demand, hydroelectric
generating conditions and purchases of energy from CSPP
facilities.
WATER RIGHTS
Except as discussed below, IPC has acquired valid water rights
under applicable state law for all waters used in its
hydroelectric generating facilities. In addition, IPC holds
water rights for domestic, irrigation, commercial and other
necessary purposes related to other land and facility holdings
within the state. The exercise and use of all of these water
rights are subject to prior rights and, with respect to certain
hydroelectric facilities, IPC's water rights for power generation
are subordinated to future upstream diversions of water for
irrigation and other recognized consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill the IPC's water rights at certain
hydroelectric generating facilities. In reaction to these
reductions, IPC initiated and continues to pursue a course of
action to determine and protect its water rights. As part of
this process, IPC and the state of Idaho signed the Swan Falls
agreement on October 25, 1984 which provided a level of
protection for IPC's hydropower water rights at specified plants
by setting minimum stream flows and establishing an
administrative process governing the future development of water
rights that may affect IPC's hydroelectric generation. In 1987,
Congress passed and the President signed into law House Bill 519.
This legislation permitted implementation of the Swan Falls
agreement and further provided that during the remaining term of
certain of IPC's project licenses that the relationship
established by the agreement would not be considered by the FERC
as being inconsistent with the terms of IPC's project licenses or
imprudent for the purposes of determining rates under Section 205
of the Federal Power Act. The FERC entered an order implementing
the legislation on March 25, 1988.
In addition to providing for the protection of IPC's hydropower
water rights, the Swan Falls agreement contemplated the
initiation of a general adjudication of all water uses within the
Snake River basin. In 1987, the director of the Idaho Department
of Water Resources filed a petition in state district court
asking that the court adjudicate all claims to water rights,
whether based on state or federal law, within the Snake River
basin. A commencement order initiating the Snake River Basin
Adjudication was signed by the court on November 19, 1987. This
legal proceeding was authorized by state statute based upon a
determination by the Idaho Legislature that the effective
management of the waters of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water uses within the basin. The adjudication is expected to
continue for at least the next 10 years. IPC has filed claims to
its water rights within the basin and is actively participating
in the adjudication to ensure that its water rights and the
operation of its hydroelectric facilities are not adversely
impacted. IPC does not anticipate any modification of its water
rights as a result of the adjudication process.
ENVIRONMENTAL REGULATION
Environmental regulation at the federal, state, regional and
local levels is having a continuing impact on IPC's operations
due to the cost of installation and operation of equipment
required for compliance with such regulations and the
modification of system operations to accommodate such regulation.
Based upon present environmental laws and regulations, IPC
estimates its capital expenditures (excluding allowance for funds
used during construction) for environmental matters for 2000 and
during the period 2001-2004 will total approximately $10.8 million
and $47.3 million, respectively. Studies related to mitigation of
environmental concerns due to relicensing of hydro facilities will
be a major portion of these expenditures. IPC anticipates
incurring approximately $24 million annually of operating expenses
for environmental facilities during the period 2000-2004, based
upon present environmental laws and regulation.
Clean Air -
IPC has analyzed the Clean Air Act's legislation and its effects
upon IPC and its ratepayers. IPC's coal-fired plants in Nevada
and Oregon already meet the federal emission rate standards for
sulfur dioxide (SO2) and IPC's coal-fired plant in Wyoming meets
that state's even more stringent SO2 regulations. The Company
foresees no material adverse effects upon its operations with
regard to SO2 emissions.
In July 1997 the Environmental Protection Agency (EPA) announced
new National Ambient Air Quality Standards (NAAQS) for ozone and
Particulate Matter (PM) and in July 1999 the EPA announced
regional haze regulations for protection of visibility in
national parks and wilderness areas. Other parties have appealed
the NAAQS standards on the constitutionality of the primary
protective standards that were set.
Impacts of the ozone and PM regulations and regional haze
regulations on IPC's thermal operations are unknown at this time.
North Valmy, Boardman and Jim Bridger Unit 4 elected to meet
Phase I nitrogen oxide (NOx ) limits beginning in 1998. As a
result of this voluntary "early election" these units will not be
required to meet the more restrictive Phase II NO x limits until
2008. Had the units not voluntarily "early elected," they would
have been required to meet the Phase II limits in 2000. Jim
Bridger Units 1, 2, and 3 were accepted as substitution units in
1995 and are subject to NO x limits of Phase I instead of the
more restrictive limits of Phase II. Jim Bridger has installed
low NO x equipment to reduce NO x levels even lower than
currently required.
Water -
IPC has received National Pollutant Discharge Elimination System
Permits, as required under the Federal Water Pollution Control
Act Amendments of 1972, for the discharge of effluents from its
hydroelectric generating plants.
IPC has agreed to meet certain dissolved oxygen standards at its
American Falls hydroelectric generating plant. IPC signed
amendments to the agreements relating to the operation of the
American Falls Dam and the location of water quality monitoring
facilities. The amendments were made to provide more accurate
and reliable water quality measurements necessary to maintain
water quality standards downstream from IPC's plant during the
period from May 15 to October 15 each year.
IPC has installed aeration equipment, water quality monitors and
data processing equipment as part of the Cascade hydroelectric
project to provide accurate water quality data and increase
dissolved oxygen levels as necessary to maintain water quality
standards on the Payette River. IPC has also installed and
operates water quality monitors at the Milner and Twin Falls
hydroelectric projects, in order to meet compliance standards for
water quality.
IPC owns and finances the operation of anadromous fish hatcheries
and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, IPC sponsors ongoing programs for the control of
fish disease and improvement of fish production. IPC's
anadromous fish facilities at Hells Canyon, Oxbow, Rapid River,
Pahsimeroi and Niagara Springs continue to be operated under
agreements with the Idaho Department of Fish and Game. At
December 31, 1999, the investment in these facilities was $12.3
million and the annual cost of operation pursuant to FERC License
1971 was approximately $2.6 million annually.
Endangered Species -
Several species of salmon and Snake River mollusks living within
IPC's operating area are listed as threatened or endangered. IPC
continues to review and analyze the effect such designation has
on its operations. IPC is cooperating with various governmental
agencies to resolve issues related to these species. (See Part
II, Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Environmental Issues".)
Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the EPA has
adopted regulations governing the use, storage, inspection and
disposal of electrical equipment that contain polychlorinated
biphenyls (PCBs). The regulations permit the continued use and
servicing of certain electrical equipment (including transformers
and capacitors) that contain PCBs. IPC continues to meet all
federal requirements of TSCA for the continued use of equipment
containing PCBs. IPC has a program to make the 200-plus
substations on its system non-PCB. While IPC's use of equipment
containing PCBs falls well within the federal standards, IPC has
voluntarily decided to virtually eliminate these compounds from
its system. This program will save costs associated with the
long-term monitoring and testing of equipment and grounds for PCB
contamination as well as being good for the environment.. Total
IPC costs for the identification and disposal of PCBs from IPC's
system were $0.6 million, $0.5 million and $1.0 million for 1999,
1998 and 1997 respectively. IPC believes that all generation
facilities are presently non-PCB.
RESEARCH AND DEVELOPMENT
In March 1999 IDACORP Technologies, Inc., a subsidiary of
IDACORP, purchased a controlling interest in Northwest Power
Systems (NPS). NPS owns several patents on a unique fuel
reformer that allows for the processing of a number of fuels into
hydrogen that is then used for the generation of electricity.
Fully operational prototypes have been constructed and
successfully tested.
During 1999, IPC spent approximately $0.4 million on research and
development of which $0.3 million was through membership in
Electric Power Research Institute (EPRI). EPRI's mission is to
discover, develop and deliver advances in science and technology.
Some of the subjects of EPRI projects include: electrification
technologies, power quality, electric transportation systems, EMF
assessment/risk management and air quality issues. IPC also has
an internal research and development effort called the Emerging
Technology (ET) Program. The ET program was established to
maintain an active and coordinated response to new technology of
interest to IPC.
In 1998, IPC entered into an agreement with Proton Energy Systems
(PES) to purchase an electrolyzer that produces hydrogen from
electricity. IPC is conducting a pilot program with the
electrolyzer as part of its efforts to gain experience with fuel
cells and to gain first-hand working knowledge and information
about the technology. Because of IPC's low cost of electrical
power, there is great potential that the electrolyzer can supply
high-value hydrogen to consumers at their plant sites and at a
lower cost than conventional bottled hydrogen. IPC has an
agreement with the Department of Energy, Lockheed and PES to test
the electrolyzer and validate the operating characteristics of
the unit.
As an active member of the NEEA, IPC has been shifting the focus
of its conservation, or DSM, activities towards regional market
transformation efforts and renewing its commitment to public
purpose programs. At the same time, IPC has discontinued many of
the traditional DSM programs that required deferral of costs. In
1999, $2.1 million was expended on energy-efficiency programs.
DIVERSIFIED BUSINESS OPERATIONS
The Company has been pursuing a strategy of expanding non-
regulated activities and separating the regulated utility
operations of IPC from non-regulated activities. The following
discussion highlights significant events related to this
strategy.
In mid-1997, IPC began trading natural gas, opening trading
offices in Houston, Texas and Boise, Idaho. Beginning in 1999,
these unregulated trading operations were transferred from under
IPC to IDACORP Energy Solutions L.P., an unregulated subsidiary
of IDACORP. IPC has also greatly increased its participation in
electricity commodity markets. IDACORP plans to move this
electricity marketing activity out of IPC and to a non-regulated
branch of the Company in 2000.
IDACORP Technologies' NPS focuses on the production and
distribution of fully-integrated fuel cell systems that combine
its patented reformer with other fuel cell components. NPS has
received orders from the BPA and other parties for more than 115
prototype fuel cell systems, with delivery scheduled to begin in
March 2000. At December 31, 1999, total investment in IDACORP
Technologies was $2.5 million.
Ida-West Energy Company develops, acquires, owns and manages
electric power projects. In March 2000, Ida-West sold for cash
its interest in the Hermiston Power Project, a 536 MW, gas-fired
project to be located near Hermiston, Oregon. Ida-West was
responsible for managing all permitting and development
activities relating to the project since its inception in 1993.
The Company anticipates recording a pre-tax gain of approximately
$14.0 million on this transaction in 2000.
Ida-West has investments in 12 operating hydroelectric plants
with a total generating capacity of approximately 72 MW. IPC has
purchased all of the power from the five Idaho hydroelectric
entities that are fifty percent owned by Ida-West, totaling
approximately $8.8 million in 1999.
Through September 30, 1998, Ida-West was a subsidiary of IPC. On
October 1, 1998 Ida-West was transferred to become a direct
subsidiary of IDACORP. At December 31, 1999, total investment in
Ida-West was $29.3 million.
In 1998 and 1999, another IDACORP subsidiary, IDACORP Energy
Solutions Co. (IESCo), introduced a variety of energy and non-
energy related products, such as home surge protectors, carbon
monoxide detectors, internet services, digital satellite
television systems, and payment protection insurance.
On February 17, 1998, the Company announced it had joined the
Allied Utility Network (AUN), a member-supported alliance that
provides customer research, marketing and other support services
to utilities. Through its relationship with AUN, IESCo is
developing new products and services to offer to retail
customers. Collectively, the members of the alliance serve
approximately one million customers.
IDACORP Financial Services, Inc. (IFS) has a portfolio of 17
investments, primarily in affordable housing programs, which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits. On December
31, 1999, total investment in IFS was $18.7 million. On January
1, 2000, ownership of IFS was transferred from IPC to become a
direct subsidiary of IDACORP.
Applied Power Corporation (APC) is a Lacey, Washington based
company that designs, supplies and distributes photovoltaic (PV)
systems. APC provides reliable, cost-effective solar electric
products and systems for industry, contractors, utilities,
government and an international network of solar dealers and
distributors. At December 31, 1999, total investment in APC was
$3.4 million. On January 1, 2000, IPC's ownership interest in
APC was also transferred to IDACORP.
Idaho Energy Resources Company (IERCo), a subsidiary of IPC, is a
joint venturer in the Bridger Coal Company, which operates the
mine supplying coal to the Jim Bridger power plant near Rock
Springs, Wyoming (see "Fuel"). At December 31, 1999, total
investment in IERCO was $12.9 million.
Pathnet/Idaho Equipment, LLC (Pathnet), a subsidiary of IPC, was
formed in 1998 to develop and distribute microwave communication
services and products. At December 31, 1999, total investment in
Pathnet was $1.7 million.
CONSTRUCTION PROGRAM
IPC's construction program for the 2000-2004 period (excluding
allowances for funds used during construction) is presently
estimated to require cash funds of approximately $580.9 million
as follows:
2000 2001-2004
(Millions of Dollars)
Generating facilities
Hydro $ 14.3 $ 61.5
Thermal 7.2 27.3
Total generating facilities 21.5 88.8
Transmission lines and substations 23.6 75.5
Distribution lines and substations 46.8 216.0
General 28.3 72.2
Total IPC cash construction 120.2 452.5
Non-utility cash construction 0.8 7.4
Total IPC cash construction
expenditures $ 121.0 $ 459.9
IPC has no nuclear involvement and its future construction plans
do not include development of any nuclear generation. IPC is
looking at various options that may be available to meet the
future energy requirements of its customers including efficiency
improvements on IPC's generation, transmission and distribution
systems and purchased power and exchange agreements with other
utilities or other power suppliers. IPC will pursue the projects
that best meet its future energy needs.
FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital are outlined in the following table:
IDACORP, Inc. Idaho Power
Company
2000 2001-2004 2000 2001-2004
(Millions of Dollars)
Capital Requirements:
Net cash construction
expenditure $120.2 $452.5 $120.2 $452.5
Other cash expenditures 21.4 50.1 0.8 7.4
Total $141.6 $502.6 $121.0 $459.9
Sources of Capital:
Internal generation $119.1 $550.6 $ 99.2 $421.1
Short-term bank loans
- Net 17.8 (17.8) 22.0 50.4
Affordable housing
debt repayment (8.9) (39.3) - -
Other debt issued 11.5 20.9 - (0.9)
Other 1.5 (10.7) (0.2) (10.7)
Cash investments
(increase) 0.6 (1.1) - -
Total $141.6 $502.6 $121.0 $459.9
These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation. Any additional securities to be sold
will depend upon market conditions and other factors. The
Company will continue to take advantage of any refinancing
opportunities as they become available.
Under the terms of the Indenture relating to IPC's First Mortgage
Bonds, net earnings must be at least two times the annual
interest on all bonds and other equal or senior debt. For the
twelve months ended December 31, 1999, net earnings were 5.94
times. Additional preferred stock may be issued when earnings
for twelve consecutive months within the preceding fifteen months
are at least equal to l.5 times (until December 31, 2000, at
which time the issuance ratio will increase to 1.75 times) the
aggregate annual interest requirements on all debt securities and
dividend requirements on preferred stock. At December 31, 1999,
the actual preferred dividend earnings coverage was 3.33 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 3.05 times. The Indenture and IPC's Restated
Articles of Incorporation are exhibits to the Form 10-K and
reference is made to them for a full and complete statement of
their provisions.
ITEM 2. PROPERTIES
IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below) and an
interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,656 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 205 energized distribution
substations (excludes mobile substations and dispatch centers).
IPC holds licenses under the Federal Power Act for 13
hydroelectric projects from the FERC. These and the other
generating stations and their capacities are listed below:
Maximum
Project Non-
Coincident
Operating Nameplate License
Capacity Capacity Expiration
kW kW
Properties Subject to
Federal Licenses:
Lower Salmon 70,000 60,000 1997 (a)
Bliss 80,000 75,000 1998 (a)
Upper Salmon 39,000 34,500 1998 (a)
Shoshone Falls 12,500 12,500 1999 (a)
C J Strike 89,000 82,800 2000
Upper Malad 9,000 8,270 2004
Lower Malad 15,000 13,500 2004
Brownlee-Oxbow-Hells
Canyon 1,398,000 1,166,900 2005
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Milner 59,448 59,448 2038
Twin Falls 54,300 52,737 2041
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (coal-fired) 703,333 709,617
Valmy (coal-fired) 260,650 260,650
Boardman (coal-fired) 53,000 56,050
(a)Renewed on a year-to-year basis; application for relicense is
pending.
At December 31, 1999, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 20 years; transmission system and substations,
19 years; and distribution lines and substations, 15 years. IPC
considers its properties to be well maintained and in good
operating condition.
IPC owns in fee all of its principal plants and other important
units of real property, except for portions of certain projects
licensed under the Federal Power Act and reservoirs and other
easements. IPC's property is also subject to the lien of its
Mortgage and Deed of Trust and the provisions of its project
licenses. In addition, IPC's property is subject to minor
defects common to properties of such size and character that do
not materially impair the value to, or the use by, IPC of such
properties.
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization), a major issue facing IPC
is the relicensing of its hydro facilities. The relicensing of
these projects is not automatic under federal law. IPC must
demonstrate comprehensive usage of the facilities, that it has
been a conscientious steward of the natural resource entrusted to
it, and that it is in the public interest for IPC to continue to
hold the federal licenses.
IPC is actively pursuing new licenses for 10 of its 17
hydroelectric projects from the FERC. This process could take
anywhere from eight to 15 years, depending on environmental
issues and political processes.
The most significant relicensing will be the Hells Canyon
Complex, which provides over half of IPC's generation capacity.
Presently, IPC is developing study plans within the framework of
a collaborative team made up of individuals representing state
and federal agencies, businesses, environmental, tribal,
customer, local government and local landowner interests. IPC
expects to file the new license application in August 2003.
Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss
hydroelectric projects are awaiting the Environmental Impact
Statement (EIS) from the federal government, which will precede
license issuance. IPC is completing additional information
requests (AIRs) in 2000, which will provide the government with
the necessary data to complete the environmental impact statement
by mid-to-late 2000.
IPC filed its application for new license for the CJ Strike
project in November 1998. Similarly, AIRs were issued on this
project as well and are scheduled to be completed in October
2000, which should result in an EIS by mid-2001.
The Upper and Lower Malad projects, scheduled for an August 2002
new license application, are nearing completion of field studies
and reporting should be complete in 2000.
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 twelve operating hydroelectric
plants with a total generating capacity of 72 MW.
ITEM 3. LEGAL PROCEEDINGS
On November 30, 1995, a complaint entitled Idaho Power Company
vs. Cogeneration, Inc., Case No. 98467, was filed by IPC in the
District Court of the Fourth Judicial District of the State of
Idaho. The proceeding involves an effort by IPC to terminate a
firm energy sales agreement (FESA) for a small hydroelectric
generating plant.
As required by PURPA and the orders of the Idaho Public Utilities
Commission (IPUC), on January 7, 1992, IPC entered into a 35-year
FESA with Cogeneration, Inc., to purchase the output of a 43-
megawatt hydroelectric generating project known as the Auger
Falls Project. The FESA for the Auger Falls Project was approved
by the IPUC on January 27, 1992. The FESA required that on or
before January 1, 1994, Cogeneration, Inc. post cash or cash
equivalent security in the amount of approximately $1.9 million
to assure performance of the FESA. Cogeneration, Inc. failed to
provide the security amount. Consistent with the FESA, IPC filed
a petition for declaratory order with the IPUC requesting that
the FESA be terminated as a result of Cogeneration, Inc.'s
breach. Cogeneration, Inc. cross petitioned claiming that its
failure to perform was excused by the occurrence of an event of
force majeure. On April 17, 1995, the IPUC issued its order
finding that Cogeneration, Inc.'s failure to post the cash
security on January 1, 1994, was a default under the FESA and
further finding that the posting of the liquid security was
required by the public interest. Based upon those findings, the
IPUC ordered Cogeneration, Inc. to post the cash security prior
to May 1, 1995. Cogeneration, Inc. failed to comply with the
Commission's order and has never posted the $1.9 million amount
required by the FESA.
After the IPUC's order became final and non-appealable, IPC filed
a complaint for declaratory relief in the District Court of the
Fourth Judicial District. The Complaint sought a determination
by the district court that Cogeneration, Inc.'s failure to
provide the cash security and its violation of the IPUC's orders
requiring that it expeditiously provide the cash security
constituted material breaches of the FESA. IPC asked the
district court to find that as a matter of law Idaho Power was
entitled to either terminate or rescind the FESA.
In response to IPC's complaint, Cogeneration, Inc. filed
counterclaims alleging that IPC, by seeking to terminate the
FESA, had breached the FESA and was attempting to monopolize the
electric generation market and drive Cogeneration, Inc. out of
business. Cogeneration, Inc. alleged damages for breach in
excess of $50 million and requested that any damages be trebled
under the anti-trust laws.
On November 30, 1995, the district judge, by memorandum decision
found that Cogeneration, Inc. had materially breached the FESA
and IPC was entitled to either rescind or terminate the FESA.
On February 16, 1996, Cogeneration, Inc. dismissed its anti-trust
claims against IPC with prejudice, and on February 23, 1996, the
Idaho Supreme Court granted Cogeneration, Inc.'s request for an
expedited appeal of the district court's decision establishing an
accelerated briefing schedule and scheduling oral argument for
May 10, 1996.
On August 12, 1996, the Idaho Supreme Court determined that the
District Court's decision that Cogeneration, Inc. had breached
the FESA was premature.
On February 10, 1997, Cogeneration, Inc. filed an amended
Complaint restating its previous claims, requesting a jury trial
rather than the court trial it had previously requested and
raising several new allegations and claims.
Following a court trial, on June 24, 1998 the District Court
issued a memorandum decision finding that Cogeneration, Inc. had
materially breached the FESA and as a result IPC had properly
terminated the FESA.
On July 27, 1998, Cogeneration, Inc. filed a Notice of Appeal
with the Idaho Supreme Court.
The case was fully briefed in 1999 and argued on January 5, 2000.
The parties are now awaiting a decision from the court.
This matter has been previously reported in Form 10-K dated March
11, 1999 and other reports filed with the Commission.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
IDACORP, Inc. are listed below along with their business
experience during the past five years. There are no family
relationships among these officers, nor any arrangement or
understanding between any officer and any other person pursuant
to which the officer was elected.
IDACORP, Inc.
Name, Age and Position Business Experience During Past Five
(5) Years*
Jan B. Packwood, 56 Appointed May 30, 1999. Mr. Packwood
President and Chief was President and Chief Operating
Executive Officer Officer from February 2, 1998 to May
30, 1999.
J. LaMont Keen, 47 Appointed May 5, 1999. Mr. Keen was
Senior Vice President - Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
and Vice President, Chief Financial
Officer and Treasurer from February
2, 1998 to March 15, 1999.
Richard Riazzi, 45 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President - was Vice President - Marketing and
Marketing and Sales Sales from January 14, 1999 to March
15, 1999.
Darrel T. Anderson, 41 Appointed May 5, 1999.
Vice President - Finance
and Treasurer
Robert W. Stahman, 55 Appointed February 2, 1998.
Vice President, General
Counsel and Secretary
________________
*IDACORP, Inc. executive officers serve in the same capacities at
Idaho Power Company. For these officers' business experience
during the past five years, please refer to the next table.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
Idaho Power Company are listed below along with their business
experience during the past five years. There are no family
relationships among these officers, nor any arrangement or
understanding between any officer and any other person pursuant
to which the officer was elected.
Idaho Power Company
Name, Age and Position Business Experience During Past Five
(5) Years
Jan B. Packwood, 56 Appointed May 30, 1999. Mr. Packwood
President and Chief was President and Chief Operating
Executive Officer Officer from September 1, 1997 to May
30, 1999, Executive Vice President
from July 11, 1996 to September 1,
1997, and Vice President-Power Supply
prior to July 11, 1996.
J. LaMont Keen, 47 Appointed May 5, 1999. Mr. Keen was
Senior Vice President - Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
Vice President, Chief Financial
Officer and Treasurer from March 14,
1996 to March 15, 1999 and Vice
President and Chief Financial Officer
prior to March 14, 1996.
James C. Miller, 45 Appointed November 18, 1999. Mr.
Senior Vice President - Miller was Vice President -
Delivery Generation from July 10, 1997 to
November 18, 1999 and was General
Manager - Generation prior to July
10, 1997.
Richard Riazzi, 45 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President - was Vice President - Marketing and
Marketing and Sales Sales from January 9, 1997 to March
15, 1999. Mr. Riazzi was Vice
President, Corporate Marketing (1995-
1996) for Equitable Resources, Inc.
Darrel T. Anderson, 41 Appointed May 5, 1999. Mr. Anderson
Vice President - Finance was corporate controller from January
and Treasurer 25, 1999 to May 5, 1999, Executive
Vice President of Finance and
Operations at Applied Power Corp.
from June 5, 1998 to January 25,
1999, and corporate controller from
February 26, 1996 to June 5, 1998.
Mr. Anderson was Senior Manager of
Audit Services for Deloitte & Touche
LLP prior to February 26, 1996.
John P. Prescott, 43 Appointed November 18, 1999. Mr.
Vice President - Prescott was Vice President of
Generation Business Development for IDACORP
Technologies, Inc. from August 1999
to November 18, 1999, and President
and Treasurer of Stellar Dynamics
from October 5, 1995 to August 1999.
Bryan A.B. Kearney, 37 Appointed November 18, 1999. Mr.
Vice President and Chief Kearney was Vice President and Chief
Information Officer Technology Officer at Bear Creek Corp
(1998-1999), Chief Information
Officer for Shasta County, California
(1996-1998), and Director of
Information Systems and Services for
the City of Fort Worth, Texas (1994-
1995).
Cliff N. Olson, 50 Appointed July 11, 1991.
Vice President -Corporate
Services
Robert W. Stahman, 55 Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
Marlene K. Williams, 47 Appointed May 5, 1999. Ms. Williams
Vice President - Human was Director of Human Resources at
Resources Arizona Public Service prior to May
5, 1999.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATE
STOCKHOLDER MATTERS
IDACORP, Inc.'s common stock (without par value) is traded on the
New York and Pacific Stock Exchanges. At December 31, 1999,
there were 23,758 holders of record and the year-end stock price
was $26 13/16 per share.
The outstanding shares of Idaho Power Company common stock ($2.50
par value) are held by IDACORP, Inc. and are not traded. IDACORP,
Inc. became the holding company of Idaho Power Company on October
1, 1998.
The following table shows the reported high and low sales price
and dividends paid for the years 1999 and 1998 as reported by the
Wall Street Journal as composite tape transactions. Amounts
reported for periods prior to October 1, 1998, were for Idaho
Power Company only.
1999 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $ 36 1/2 $ 33 5/8 $ 32 $ 31 1/4
Low 29 1/4 29 1/2 29 3/16 26
Dividends paid per
share (cents) 46.5 46.5 46.5 46.5
______________________________
1998 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $ 38 1/16 $ 37 7/8 $ 35 $ 36 1/4
Low 33 15/16 32 15/16 29 7/8 31 1/8
Dividends paid per
share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts)
IDACORP, Inc.
For the Years Ended 1999 1998 1997 1996 1995
December 31,
Operating revenues $ 658,336 756,410 605,183 578,445 545,621
Income from operations 172,458 180,584 180,731 187,171 175,991
Net income 91,349 89,176 87,098 83,155 78,930
Earnings per average
share outstanding
(basic and diluted) 2.43 2.37 2.32 2.21 2.10
Dividends declared per
share 1.86 1.86 1.86 1.86 1.86
At December 31,
Total long-term debt* 821,558 815,937 746,142 769,810 672,618
Total assets 2,636,993 2,451,620 2,451,816 2,328,738 2,241,753
*Excludes amount due within one year.
The above data should be read in conjunction with IDACORP's
consolidated financial statements and notes to consolidated
financial statements included in this Annual Report on Form 10-K.
SUMMARY OF OPERATIONS (Thousands of Dollars)
IDAHO POWER COMPANY
For the Years Ended 1999 1998 1997 1996 1995
December 31,
Operating revenues $ 658,336 $ 756,410 $ 605,183 $ 578,445 $ 545,621
Income from operations 172,458 180,584 180,731 187,171 175,991
Net income 97,528 95,919 92,274 90,618 86,921
At December 31,
Total long-term debt* 821,558 815,937 746,142 769,810 672,618
Total assets 2,559,374 2,421,790 2,451,816 2,328,738 2,241,753
Utility Customer Data:
General business 384,421 373,730 363,085 352,487 340,708
customers
Average kWh per customer 36,379 36,368 37,080 37,627 35,740
Average rate per kWh (cents) 3.75 3.85 3.63 3.71 3.85
*Excludes amount due within one year.
The above data should be read in conjunction with Idaho Power
Company's consolidated financial statements and notes to
consolidated financial statements included in this Annual Report
on Form 10-K.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In Management's Discussion and Analysis we explain the general
financial condition and results of operations of IDACORP, Inc.
and its subsidiaries (IDACORP or the Company) and Idaho Power
Company and its subsidiaries (IPC). IDACORP is a holding company
formed in 1998 as the parent of IPC and several other entities.
IPC, an electric utility, is IDACORP's principal operating
subsidiary, and accounts for over 90 percent of its assets,
revenue and net income. The financial condition and results of
operations of IPC are currently the principal factors affecting
the financial conditions and results of operations of IDACORP.
As you read Management's Discussion and Analysis, it may be
helpful to refer to our Consolidated Statements of Income which
present our results of operations for the years ended December
31, 1999, 1998 and 1997. In our discussion we explain the
significant annual changes between specific line items in the
Consolidated Statements of Income.
FORWARD-LOOKING INFORMATION
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 (Reform Act), we are
hereby filing cautionary statements identifying important factors
that could cause our actual results to differ materially from
those projected in forward-looking statements (as such term is
defined in the Reform Act) made by or on behalf of the Company in
this Annual Report, 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):
economic and geographic factors including political and economic
risks;
changes in and compliance with environmental and safety laws and
policies;
weather conditions;
population growth rates and demographic patterns;
competition for retail and wholesale customers;
Year 2000 issues;
pricing and transportation of commodities;
market demand, including structural market changes;
changes in tax rates or policies or in rates of inflation;
changes in project costs;
unanticipated changes in operating expenses and capital
expenditures;
capital market conditions;
competition for new energy development opportunities; and
legal and administrative proceedings (whether civil or criminal)
and settlements that influence the business and profitability of
the Company.
Any forward-looking statement speaks only as of the date on which
such statement is made, and we undertake no obligation to update
any forward-looking statement to reflect events or circumstances
after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time
to time and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the
business or the extent to which any factor, or combination of
factors, may cause results to differ materially from those
contained in any forward-looking statement.
RESULTS OF OPERATIONS
Earnings per Share and Book Value
Earnings per share of common stock (basic and diluted) were $2.43
in 1999, $2.37 in 1998, and $2.32 in 1997. The 1999 earnings
equate to a 12.1 percent return on year-end common equity, as
compared to 12.2 percent in 1998 and 1997. At December 31, 1999,
the book value per share of common stock was $20.02, compared to
$19.42 at December 31, 1998 and $18.93 at December 31, 1997.
Overview
The primary factors contributing to the increase in earnings per
share over the last three years are a strong economy in our
utility service territory and favorable energy marketing results.
Idaho's economy continued its strong performance over the last
three years. Idaho's non-agricultural employment growth for the
twelve months ended November 1999 was 2.4 percent; annual growth
rates in 1998 and 1997 were 2.4 percent and 3.2 percent,
respectively. Within the Boise Metropolitan Statistical Area,
the heart of our utility service territory, non-agricultural
employment increased 3.2 percent for the twelve months ended
November 1999, 4.1 percent in 1998 and 4.2 percent in 1997.
General business customer growth has been consistent, with 2.9
percent increases in 1999 and 1998 and a 3.0 percent increase in
1997. This growth is attributable to strong overall economic
conditions in our utility service territory.
Our service territory experienced above average water years from
1997-1999. Hydro generation was 17 percent above normal in 1999,
22 percent above normal in 1998, and 30 percent above normal in
1997.
Our energy marketing income increased $14 million in 1999 due to
favorable conditions in the energy markets and $5 million in 1998
due to growth in this business segment.
Income from operations decreased $8 million in 1999 primarily due
to a $5 million decrease in other revenues resulting from
increased funds set aside for refund to IPC ratepayers as part of
a regulatory settlement with the IPUC. This increase results
from an increase in the amount set aside for 1999 compared to
1998, plus true-ups of prior years' sharing estimates. We discuss
the regulatory settlement below in "Regulatory Issues -
Regulatory Settlement." Another factor impacting operating
income was a decrease in the net power supply costs (surplus
sales less purchased power, fuel, and PCA expense) of $6 million
due to effective management of the system given a combination of
favorable market, weather and hydro conditions throughout the
year. Other factors impacting income from operations were a $7
million increase in other operation and maintenance expenses, and
a $3 million increase in depreciation expense.
Income from operations decreased slightly in 1998. The primary
factors affecting income from operations were a $3 million
increase in depreciation expense, offsetting a $3 million
increase in other revenue resulting primarily from decreased
amounts set aside for the regulatory settlement with the IPUC.
While general business increased, that increase was offset by a
similar increase in net power supply costs.
General Business Revenue
Our general business revenue is dependent on many factors,
including the number of customers we serve, the rates we charge,
and weather conditions.
IPC's rates are adjusted annually based primarily on a Power Cost
Adjustment (PCA) mechanism that is described more fully below in
"Regulatory Issues - Power Cost Adjustment."
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 1999, general business revenue was only marginally higher than
1998. The 2.9 percent increase in general business customers
increased revenue $7 million and drier weather conditions and
other factors affecting usage increased revenue $12 million.
These increases were nearly offset by reductions in rates
stemming from the PCA, which decreased revenue $17 million.
The $34 million increase in general business revenue in 1998 was
due primarily to increased rates, which increased revenue $31
million, and the 2.9 percent increase in general business
customers, which increased revenue $16 million. These increases
were offset by a $12 million decrease resulting from more
precipitation and more moderate weather conditions.
Power Supply
Power supply components of income from operations include off-
system sales and purchased power, fuel and PCA expenses.
Off-system sales, which consist primarily of long-term sales
contracts and opportunity sales of surplus system energy,
decreased $95 million in 1999 after increasing $114 million in
1998.
Purchased power expense decreased $79 million in 1999 after
increasing $105 million in 1998. Contributing to these results
are a number of operational factors, including changing hydro
availability, system load and fluctuating wholesale market
conditions.
Net off-system sales less purchases were 2.8 million MWh in 1999,
compared to 3.2 million MWh in 1998 and 3.1 million MWh in 1997.
Fuel expenses were essentially unchanged in 1999 but increased by
$15 million in 1998. Total generation at our coal-fired plants
was approximately 7.3 million MWh in 1999, 6.9 million MWh in
1998 and 5.4 million MWh in 1997.
The PCA expense component is related to the Company's PCA
regulatory mechanism. The PCA mechanism increases expenses when
power supply costs are below forecast, and decreases expenses
when power supply costs are above forecast. In 1999, actual
costs were near forecast, causing the PCA component of expense to
be minimal. In 1998 the PCA expense increased $28 million
because our 1998 power supply costs were well below the forecast,
when in 1997 they were somewhat above the forecast. The 1998
forecast had anticipated near-normal streamflow conditions in the
1998-9 rate period, but conditions were significantly better than
normal. We discuss the PCA in more detail in "Regulatory Issues
- - Power Cost Adjustment."
The impact of these changes in net power supply costs is a
decrease in net expense in 1999 of $6 million and an increase in
net expense in 1998 of $35 million.
Other Expenses
Other operations expenses increased $6 million in 1999 and $8
million in 1998. The increase in 1999 was due primarily to
increased operating expenses at our coal-fired generation plants,
and payroll and consulting expenses. The increase in 1998 was
due primarily to increases in payroll and benefits and
transmission charges for electricity sales.
Maintenance expenses decreased $7 million in 1998, resulting from
decreased cost of maintenance work performed at our steam
generation and distribution facilities.
Depreciation expenses increased $3 million in both 1998 and 1999,
due primarily to plant additions.
Other Income
Energy marketing income increased $14 million in 1999 and $5
million in 1998 due primarily to improved results and increased
volumes of energy trading activities. We discuss our energy
marketing activities more fully below in "Energy Marketing."
Other-net decreased $3 million in 1999 and $5 million in 1998 due
primarily to costs incurred by new subsidiaries and costs of
other diversified business activities. These subsidiaries and
activities were created to compete in the non-regulated business
environment.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Our net cash generated from operations totaled $572 million for
the three-year period 1997-1999. After deducting common
dividends of $210 million, net cash generation from operations
provided approximately $362 million for our construction program
and other capital requirements. Internal cash generation after
dividends provided 114 percent of our total capital requirements
in 1999, 95 percent in 1998, and 89 percent in 1997.
The $88 million increase in cash and cash equivalents in 1999 is
due primarily to IPC's issuance of $80 million of medium-term
notes late in 1999. The proceeds were used in January 2000 to
retire $80 million of first mortgage bonds that had matured.
In 1998, our increase in cash and cash equivalents was due
primarily to $12 million received from life insurance death
benefits and the surrender of life insurance policies.
We forecast that internal cash generation after dividends will
provide approximately 84 percent of total capital requirements in
2000 and over 110 percent during the four-year period 2001-2004.
We expect to continue financing our construction program and
other capital requirements with both internally generated funds
and, to the extent necessary, externally financed capital.
Principal amounts maturing during the next five years are $89
million in 2000, $40 million in 2001, $37 million in 2002, $90
million in 2003 and $60 million in 2004.
At January 1, 2000, IPC had regulatory authority to incur up to
$200 million of short-term indebtedness. At December 31, 1999,
IPC's short-term borrowing totaled $20 million compared to $39
million at December 31, 1998 and $58 million at December 31,
1997.
We have credit facilities established at both IPC and IDACORP.
IPC has a $120 million multi-year revolving credit facility under
which we pay a facility fee on the commitment, quarterly in
arrears, based on IPC's First Mortgage Bond Rating. Commercial
paper may be issued in an amount not to exceed 25 percent of
revenues for the latest twelve-month period, subject to the $200
million maximum, and is supported by bank lines of credit of an
equal amount.
IDACORP has separately established a $50 million three-year
credit facility that expires in December 2001, and a $100 million
364-day credit facility that expires in December 2000. Under
these facilities we pay a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond Rating.
Commercial paper may be issued up to the $150 million and is
supported by the bank credit facilities. (See Note 7 of "Notes to
Consolidated Financial Statements").
Construction Program
Our consolidated cash construction expenditures totaled $111
million in 1999, $89 million in 1998, and $96 million in 1997.
Approximately 28 percent of these expenditures were for
generation facilities, 17 percent for transmission facilities, 39
percent for distribution facilities, and 16 percent for general
plant and equipment. We estimate that our cash construction
program will require $121 million in 2000 and $460 million in the
four-year period 2001-2004. These estimates are subject to
revision in light of changing economic, regulatory,
environmental, and conservation factors.
Financing Program
Our capital structure fluctuated slightly during the three-year
period, with common equity ending at 45 percent, preferred stock
(of IPC) 6 percent, and long-term debt 49 percent at December 31,
1999.
IDACORP, Inc. currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. At December 31, 1999
none had been issued.
IPC has on file a shelf registration statement for the issuance
of first mortgage bonds and/or preferred stock, with an aggregate
principal amount not to exceed $200 million. The remaining
balance on the shelf registration is $3 million as of December
31, 1999. In November 1999 IPC issued $80 million of Secured
Medium Term Notes. The proceeds from this issuance were used in
January 2000 to redeem at maturity $80 million of First Mortgage
Bonds.
In September 1998 IPC issued $60 million of Secured Medium Term
Notes. The proceeds from this issuance were used to redeem at
maturity $30 million of First Mortgage Bonds, and to reduce the
balance of commercial paper issued in connection with ongoing
business.
OTHER MATTERS
Regulatory Issues
Power Cost Adjustment (PCA)
IPC has a PCA mechanism that provides for annual adjustments to
the rates we charge to our Idaho retail customers. These
adjustments, which take effect annually in mid-May, are based on
two components, the difference between our forecast of the
upcoming year's net power supply costs and a base amount, and the
true-up of the prior year's forecasted costs to actual costs.
Our May 1999 rate adjustment reduced Idaho general business
customer rates by 9.2 percent. The decrease was the result of
forecasted above-average hydroelectric generating conditions for
the upcoming year, and a true-up benefit from the 1998-99 rate
period. Overall, the May 1999 rate adjustment is expected to
decrease our annual general business revenue by $40 million
during the 1999-2000 rate period.
The May 1998 rate adjustment increased expected annual revenue by
$34 million over the amount that would have been received at the
1997-98 rates. The 1998-99 forecast had assumed a return to more
normal hydroelectric generating conditions from the above-average
conditions experienced in the prior year. This resulted in
forecasted power supply costs being near the amounts used to
establish base rates in past regulatory proceedings.
So far in the 1999-2000 rate period, actual power costs and
generating conditions have been near forecast. We have recorded
a regulatory asset of $1.7 million as of December 31, 1999. The
variance that exists at the end of the 1999-2000 rate period will
be trued-up in the next annual PCA adjustment.
Regulatory Settlement
IPC had a settlement agreement with the IPUC that expired at the
end of 1999. Under the terms of the settlement, when earnings in
our Idaho jurisdiction exceeded an 11.75 percent return on year-
end common equity, we set aside 50 percent of the excess for the
benefit of our Idaho retail customers. In 1999, we set aside
approximately $8.9 million for this purpose, compared to $6.4
million in 1998 and $7.6 million in 1997.
Demand-Side Management (Conservation) Expenses
We have obtained changes to the regulatory treatment of
previously deferred demand-side management (DSM) expenses. The
IPUC set a new amortization period of 12 years instead of the 24-
year period previously established. The order reflects an
increase in annual Idaho retail revenue requirements of $3.1
million for 12 years. This order was appealed to the Idaho
Supreme Court by a group of IPC customers; oral arguments were
heard on December 8, 1999 and the matter is awaiting a Supreme
Court decision.
Energy Marketing
Over the last three years we have been implementing a strategy to
become a competitive energy provider throughout the western
markets. In order to compete as an energy provider of choice we
needed to build a foundation of an effective and efficient
trading operation that competently participates in the
electricity, natural gas and other related markets. In 1997 we
opened natural gas trading operations in Houston, Texas and in
Boise, Idaho. We also began to expand our electricity marketing,
which, along with natural gas, is included in other income. We
have seen increasing positive results from our strategy. Our
natural gas marketing capability continues to expand as the
electricity and natural gas markets move toward convergence, and
our electricity marketing efforts have resulted in volume and
income increases each year since inception of the strategy. We
have built this capability over the last three years to allow us
to develop controls to mitigate the operational, market and
credit risks inherent in the marketing business.
When buying and selling energy, the high volatility of energy
prices can have a significant impact on profitability if not
managed. Also, counterparty creditworthiness is key to ensuring
that transactions entered into withstand dramatic market
fluctuations. To manage these risks while implementing our
business strategy, the Company has a Risk Management Committee,
comprised of Company officers, to oversee the risk management
program as defined in the risk management policy. The program is
intended to minimize fluctuations in earnings while managing the
volatility of energy prices by mitigating commodity price risk,
credit risk, and other risks related to the energy trading
business
Ida-West Energy Company
In March 2000, Ida-West Energy Company, a wholly owned subsidiary
of IDACORP, sold for cash its 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 anticipate recording a pre-tax
gain of approximately $14 million on this transaction.
Northwest Power Systems
In March 1999 IDACORP Technologies, Inc., a wholly owned
subsidiary of IDACORP, purchased a majority interest in Northwest
Power Systems (NPS). NPS has patented a unique fuel reformer that
allows for the processing of a number of fuels into hydrogen that
is then used for the generation of electricity. Fully
operational prototypes have been constructed and successfully
tested. NPS' focus will be the development, production and
distribution of fully integrated fuel-cell systems.
Electric Industry Restructuring
Competition is increasing in the electric utility industry. Our
goal is to anticipate and fully integrate into our operations any
legislative, regulatory or competitive changes. We are pursuing
a rapid, but orderly transition to at least a partially and
possibly a totally deregulated environment in the years ahead.
The following items describe some of the changes to date, as well
as steps we are taking.
Legislative Actions
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry. 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.
FERC Decisions
In December 1999 the FERC issued Order No. 2000, dealing with
Regional Transmission Organizations (RTO). It proposes to ensure
non-discriminatory, open-access to electricity transmission
facilities. Each utility is required to file by October 15, 2000
a statement regarding its intention to join a RTO. IPC is
engaged in formation discussions with other Northwest utilities.
These utilities include both investor-owned and other entities.
IPC believes the FERC Order will allow sufficient flexibility to
adequately protect the interests of both shareholders and
customers.
In April 1996, the FERC issued its Order Nos. 888 and 889 dealing
with Open-Access Non-Discriminatory Transmission Services by
Public and Transmitting Utilities, and standards of conduct
regarding these issues. These orders require public utilities
owning transmission lines to file open-access tariffs available
to buyers and sellers of wholesale electricity; to require
utilities to use the tariffs for their own wholesale sales; and
to allow utilities to recover stranded costs, subject to certain
conditions. Public utilities owning transmission lines were
required to file compliance tariffs by July 9, 1996.
In November 1995, we filed open-access tariffs with the FERC for
Point-to-Point and Network transmission service. The substance
of these tariffs was to offer the same quality and character of
transmission services that we use in our own operations to anyone
seeking them. We implemented these tariffs beginning February 1,
1996. On July 8, 1996, we filed a new open-access transmission
tariff to replace the 1995 tariffs. This provides full
compliance with Final Order No. 888. This filing did not include
a rate change. On November 13, 1996, FERC issued an
unconditional acceptance of the terms and conditions of this
tariff. The rate was not subject to review.
Market Rate Sensitive Instruments and Risk Management
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that
we held at December 31, 1999. We buy and sell financial and
physical natural gas and electricity commodity contracts as part
of our ongoing business. These contracts are subject to
electricity and natural gas commodity price risk. We have a
trading and risk management policy defining the limits within
which we contain our commodity price risk. We trade commodity
futures, forwards, options and swaps as a method of managing the
commodity price risk and optimizing the profitability of our
electricity and natural gas trading. We have minimal foreign
exchange exposure related to natural gas trading activities in
Canadian dollars. This exposure is periodically offset through
the use of foreign exchange swap instruments. Our sensitivity
related to foreign exchange rate fluctuations as of December 31,
1999 is immaterial.
Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 1999, that are sensitive to changes in interest
rates. We did not hold any interest rate derivative instruments
at December 31, 1999. The majority of our debt is held in fixed
rate securities with embedded call options. We hold $48 million
in variable-rate tax-exempt debt for pollution control financings
and 2.1 percent of our total debt is variable in the form of
commercial paper. By nature, the value of our variable rate debt
is not sensitive to changes in interest rates, and the value of
our commercial paper borrowings does not give rise to significant
interest rate risk because these borrowings generally have
maturities of less than three months.
The table below presents principal cash flows by maturity date
and the related average interest rate. The table also presents
the fair value for all fixed rate instruments as of December 31,
1999, based on market rates for similar instruments as of that
date.
Expected Maturity Date
2000 2001 2002 2003 2004 Thereafter Total Fair
Value
Fixed rate debt
(in millions) $ 89 $ 40 $ 37 $ 90 $ 60 $548 $864 $850
Average
interest rate 8.5% 7.0% 7.0% 6.5% 7.9% 7.7% 7.6%
Commodity Price Risk Sensitivity
This analysis presents the estimated December 31, 1999, value-at-
risk related to our energy commodity contracts and related
derivative instruments that are sensitive to changes in commodity
prices. We use commodity derivative instruments such as futures,
forwards, options and swaps to manage our exposure to commodity
price risk in the electricity and natural gas markets. The
objective of our risk management program is to mitigate the risk
associated with the purchase and sale of natural gas and
electricity. Company policy also allows the use of these
commodity derivative instruments for trading purposes in support
of our operations.
The aggregate potential daily loss in earnings from our energy
trading activity is estimated to be $115,000 at a 95 percent
confidence interval and for a holding period of one business day.
The potential loss in earnings was estimated using an analytic
value-at-risk methodology. This methodology computes value-at-
risk based upon market prices for futures and option-implied
volatilities as of December 31, 1999. The value-at-risk is
understood to be a forecast and is not guaranteed to occur. The
chosen confidence level and holding period are industry
standards. The confidence level and holding period imply that
there is a five percent chance that the daily loss will exceed
$115,000.
Relicensing of Hydroelectric Projects
We are actively pursuing the relicensing of our hydroelectric
projects, a process that will continue for the next 10 to 15
years. We submitted our first applications for license renewal
to the FERC in December 1995. We have now filed applications
seeking renewal of our licenses for our Bliss, Upper Salmon
Falls, Lower Salmon Falls, CJ Strike and Shoshone Falls
Hydroelectric Projects. Although various federal requirements
and issues must be resolved through the license renewal process,
we anticipate that our efforts will be successful. At this
point, however, we cannot predict what type of environmental or
operational requirements we may face, nor can we estimate the
eventual cost of license renewal. At December 31, 1999, $20
million of relicensing costs were included in Construction Work
in Progress.
Environmental Issues
Salmon Recovery Plan
We are continuing to monitor regional efforts to develop a
comprehensive and scientifically credible plan to ensure the long-
term survival of anadromous fish runs on the Columbia and Lower
Snake rivers.
In mid-August 1994, the federal government changed its
designation of the Fall Chinook Salmon from Threatened to
Endangered. This designation has not had any major effects on
our operations.
In September 1991, we modified operations at our three-dam Hells
Canyon Hydroelectric Complex to protect the Fall Chinook
downstream during spawning and juvenile emergence. From its
start, our Fall Chinook program has exceeded the protection
requirements for threatened species, affording the fish the same
high level of protection due an endangered species.
In March 1995, the National Marine Fisheries Service (NMFS)
released a draft Biological Opinion and five-year operating plan
to protect listed Snake River Salmon. The NMFS accepted public
comment on the Plan through December 1995. The final five-year
Plan did not call for any change in the Company's operations for
salmon at the Hells Canyon Complex. The Biological Opinion did
call for a five-year study of various recovery options for the
listed fish including the possible removal of four federally
owned hydro facilities on the lower Snake River. As the five-
year operating plan comes to a close, NMFS is expected to
announce the results of the studies and propose a new operating
plan in the near future. It is unknown whether any change in
operations at the Hells Canyon Complex will be requested as a
result of the studies.
The Northwest Power Planning Council (NWPPC) issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994. The NWPPC plan called for the U. S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within
the Snake River Basin by 1996, and an additional 500,000 acre-
feet by 1998. The water is to be acquired from willing sellers.
Thus far, the BOR has not complied with the request to acquire
1,000,000 acre-feet of additional water. However, if
the BOR does comply and successfully implements the request, its
movement of additional water could have a material impact on our
power supply costs. IPC and the BPA have negotiated a five-year
contract, expiring April 15, 2001, requiring BPA to replace lost
energy and capacity resulting from recovery plans that impact our
power supply cost.
Threatened and Endangered Snails
In December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as Threatened and
Endangered Species. Since that time, we have included this
possibility in all of our discussions regarding relicensing and
new hydro development.
The listing specifically mentions the impact that fluctuating
water levels related to hydroelectric operations may have on the
snails and their habitat. Although the hydro facilities on that
reach of the Snake River do not significantly affect water levels
during typical operations, some of them do provide the daily
operational flexibility to meet increased electricity demand
during high load hours. Recent studies suggest that this has no
impact on the listed snails. While it is possible that the
listing could affect how we operate our existing hydroelectric
facilities on the middle reach of the Snake River, we believe
that such changes will be minor and will not present any undue
hardship.
In 1995, as a part of our federal hydro relicensing process, we
obtained a permit from the USFWS to study the five species of
endangered Snake River snails. Our biologists have completed
several studies to gain scientific insight into how or if these
snails are affected by a variety of factors, including hydropower
production, water quality, and irrigation run-off. Results of
the studies indicated that the snail colonies were part of a
biological community well adapted to the influences of
hydropower, water quality, and irrigation run-off. Company-
sponsored studies continue to review how these and other factors
affect the status of the various colonies and their habitats.
Clean Air Act
We have analyzed the Clean Air Act's effects on us and our
customers. Our coal-fired plants in Oregon and Nevada already
meet the federal emission rate standards for sulfur dioxide (SO2)
and our coal-fired plant in Wyoming meets that state's even more
stringent SO2 regulations. Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.
Electric and Magnetic Fields
While scientific research has not established any conclusive link
between electric and magnetic fields (EMFs) and human health, the
possibility of a link has caused public concern in the United
States and abroad. Electric and magnetic fields exist wherever
there is electric current, whether the source is a high-voltage
transmission line or the simplest of electrical household
appliances. Concerns over possible health effects have prompted
regulatory efforts in several states to limit human exposure to
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could
affect a number of industries, including electric utilities.
However, it is difficult at this time to estimate what effects,
if any, the EMF issue could have on our operations.
Year 2000 Costs
We have not experienced any significant operational issues
resulting from the Year 2000 problem. Our total costs through
the end of 1999 were $3.7 million charged to operations and
maintenance expenses and $0.5 million of capital expenditures.
We do not anticipate any material expenditures or issues to arise
in the future.
New Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Transactions." This statement
establishes accounting and reporting standards for derivative
financial instruments and other similar financial instruments and
for hedging activities. It was originally effective for fiscal
years beginning after June 15, 1999. In June 1999 the FASB
issued SFAS No. 137 "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB
Standard No. 133," which defers the effective date of SFAS No.
133 one year. We are reviewing this statement to determine its
effect on our financial position and results of operations.
Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by this item is included in Item 7
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" under "Market Rate Sensitive Instruments
and Risk Management."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULES
PAGE
Management's Responsibility for Financial Statements 34
Consolidated Financial Statements:
IDACORP, Inc.
Consolidated Statements of Income for the Years Ended December
31, 1999, 1998 and 1997 35
Consolidated Balance Sheets as of December 31, 1999, 1998 and
1997 36-37
Consolidated Statements of Capitalization as of December 31,
1999, 1998 and 1997 38
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997 39
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 1999, 1998 and 1997 40
Notes to Consolidated Financial Statements 41-54
Independent Auditors' Report 55
Idaho Power Company
Consolidated Statements of Income for the Years Ended December
31, 1999, 1998 and 1997 57
Consolidated Balance Sheets as of December 31, 1999, 1998 and
1997 58-59
Consolidated Statements of Capitalization as of December 31,
1999, 1998 and 1997 60
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997 61
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 1999,1998 and 1997 62
Notes to Consolidated Financial Statements 63-66
Independent Auditors' Report 67
Supplemental Financial Information and Financial Statement
Schedules
Supplemental Financial Information (Unaudited) 68
Financial Statement Schedules for the Years Ended December 31,
1999, 1998 and 1997:
Schedule II-Consolidated Valuation and Qualifying Accounts-
IDACORP, Inc. 74
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho
Power Company. 74
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of IDACORP, Inc. and Idaho Power Company is
responsible for the preparation and presentation of the
information and representations contained in the accompanying
financial statements. The financial statements have been
prepared in conformance with generally accepted accounting
principles. Where estimates are required to be made in preparing
the financial statements, management has applied its best
judgment as to the adequacy of the estimates based upon all
available information.
The Companies maintain systems of internal accounting controls
and related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected
against loss or unauthorized use. Also, the systems provide that
transactions are executed in accordance with management's
authorization and properly recorded to permit preparation of
reliable financial statements. The systems are supported by a
staff of corporate accountants and internal auditors who, among
other duties, evaluate and monitor the systems of internal
accounting control in coordination with the independent auditors.
The staff of internal auditors conducts special and operational
audits in support of these accounting controls throughout the
year.
Each Company's Board of Directors, through their Audit Committees
comprised entirely of outside directors, meets periodically with
management, internal auditors and independent auditors to discuss
auditing, internal control and financial reporting matters. To
ensure their independence, both the internal auditors and
independent auditors have full and free access to the Audit
Committees.
The financial statements have been audited by Deloitte & Touche
LLP, the Companies' independent auditors, who were responsible
for conducting their audit in accordance with generally accepted
auditing standards.
Jan B. Packwood J. LaMont Keen Darrel T. Anderson
President and Senior Vice President, Vice President,
Chief Executive Officer Administration and Finance and Treasurer
Chief Financial Officer
IDACORP, Inc.
Consolidated Statements of Income
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars except for
per share amounts)
REVENUES:
General business $516,148 $514,856 $480,458
Off system sales 119,785 214,418 100,554
Other revenues 22,403 27,136 24,171
Total revenues 658,336 756,410 605,183
EXPENSES:
Operations:
Purchased power 106,344 185,271 79,898
Fuel expense 86,617 86,237 71,271
Power cost adjustment (502) 21,866 (6,032)
Other 151,800 145,374 137,458
Maintenance 42,067 41,872 48,722
Depreciation 77,833 74,481 71,973
Taxes other than income taxes 21,719 20,725 21,162
Total expenses 485,878 575,826 424,452
INCOME FROM OPERATIONS 172,458 180,584 180,731
OTHER INCOME:
Allowance for equity funds used
during construction 1,667 300 34
Energy marketing activities -
Net 21,739 7,429 2,837
Other - Net 8,312 10,928 15,402
Total other income 31,718 18,657 18,273
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 54,294 52,270 53,215
Other interest 8,681 8,407 7,546
Allowance for borrowed funds
used during construction (1,392) (900) (503)
Preferred dividends of Idaho
Power Company 5,572 5,658 5,176
Total interest expense
and other 67,155 65,435 65,434
INCOME BEFORE INCOME TAXES 137,021 133,806 133,570
INCOME TAXES 45,672 44,630 46,472
NET INCOME $ 91,349 $ 89,176 $ 87,098
AVERAGE COMMON SHARES OUTSTANDING
(000) 37,612 37,612 37,612
EARNINGS PER SHARE OF COMMON STOCK
(basic and diluted) $ 2.43 $ 2.37 $ 2.32
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Assets
December 31,
1999 1998 1997
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,726,026 $2,659,441 $2,605,697
Accumulated provision for
depreciation (1,073,722) (1,009,387) (942,400)
In service - Net 1,652,304 1,650,054 1,663,297
Construction work in progress 91,637 59,717 51,892
Held for future use 1,742 1,738 1,738
Electric plant - Net 1,745,683 1,711,509 1,716,927
INVESTMENTS AND OTHER PROPERTY 146,019 129,437 97,065
CURRENT ASSETS:
Cash and cash equivalents 111,338 22,867 6,905
Receivables:
Customer 98,923 102,671 105,204
Allowance for uncollectible
accounts (1,397) (1,397) (1,397)
Notes 4,353 4,643 4,613
Employee notes 4,105 4,510 4,757
Other 7,764 6,059 8,854
Energy marketing assets 37,398 - -
Accrued unbilled revenues 31,994 34,610 33,312
Materials and supplies (at
average cost) 29,611 30,157 29,156
Fuel stock (at average cost) 9,329 7,096 7,172
Prepayments 16,097 16,042 15,381
Regulatory assets associated
with income taxes 893 2,965 3,164
Total current assets 350,408 230,223 217,121
DEFERRED DEBITS:
American Falls and Milner water
rights 31,585 31,830 32,055
Company-owned life insurance 40,480 35,149 51,915
Regulatory assets associated
with income taxes 214,782 201,465 198,521
Regulatory assets - other 52,759 62,013 90,239
Other 55,277 49,994 47,973
Total deferred debits 394,883 380,451 420,703
TOTAL $2,636,993 $2,451,620 $2,451,816
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Capitalization and Liabilities
December 31,
1999 1998 1997
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock without par
value (shares authorized
120,000,000; shares
outstanding - 37,612,351) $ 451,343 451,564 452,519
Retained earnings 300,093 278,607 259,299
Accumulated other
comprehensive income 1,534 226 -
Total common stock 752,970 730,397 711,818
equity
Preferred stock of Idaho
Power Company 105,811 105,968 106,697
Long-term debt 821,558 815,937 746,142
Total capitalization 1,680,339 1,652,302 1,564,657
CURRENT LIABILITIES:
Long-term debt due within one
year 89,101 6,029 33,998
Notes payable 19,757 38,524 57,516
Accounts payable 145,737 101,975 111,938
Energy marketing liabilities 33,814 - -
Taxes accrued 21,313 24,785 24,295
Interest accrued 19,126 18,365 17,918
Deferred income taxes 893 2,965 3,164
Other 16,696 12,275 13,703
Total current liabilities 346,437 204,918 262,532
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment
tax credits 67,433 69,396 70,196
Deferred income taxes 430,468 422,196 423,736
Regulatory liabilities
associated with income taxes 33,817 28,075 34,072
Regulatory liabilities -
other 3,363 4,161 509
Other 75,136 70,572 96,114
Total deferred credits 610,217 594,400 624,627
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $2,636,993 $2,451,620 $2,451,816
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Capitalization
December 31,
1999 % 1998 % 1997 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 451,343 $ 451,564 $ 452,519
Retained earnings 300,093 278,607 259,299
Accumulated other
comprehensive income 1,534 226 -
Total common stock
equity 752,970 45 730,397 44 711,818 45
PREFERRED STOCK OF IDAHO POWER
COMPANY:
4% preferred stock 15,811 15,968 16,697
7.68% Series, serial
preferred stock 15,000 15,000 15,000
7.07% Series, serial
preferred stock 25,000 25,000 25,000
Auction rate preferred stock 50,000 50,000 50,000
Total preferred
stock 105,811 6 105,968 7 106,697 7
LONG-TERM DEBT :
First mortgage bonds:
5.33% Series due 1998 - - 30,000
8.65% Series due 2000 80,000 80,000 80,000
6.93% Series due 2001 30,000 30,000 30,000
6.85% Series due 2002 27,000 27,000 27,000
6.40% Series due 2003 80,000 80,000 80,000
8 % Series due 2004 50,000 50,000 50,000
5.83% Series due 2005 60,000 60,000 -
7.20% Series due 2009 80,000 - -
Maturing 2021 through
2031 with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first
mortgage bonds 637,000 557,000 527,000
Amount due within one year (80,000) - (30,000)
Net first mortgage
bonds 557,000 557,000 497,000
Pollution control revenue
bonds:
7.25 % Series due 2008 4,360 4,360 4,360
8.30 % Series 1984 due
2014 49,800 49,800 49,800
6.05 % Series 1996A
due 2026 68,100 68,100 68,100
Variable Rate Series
1996B due 2026 24,200 24,200 24,200
Variable Rate Series
1996C due 2026 24,000 24,000 24,000
Total pollution
control revenue
bonds 170,460 170,460 170,460
REA notes 1,415 1,489 1,561
Amount due within one
year (76) (74) (72)
Net REA notes 1,339 1,415 1,489
American Falls bond
guarantee 19,885 20,130 20,355
Milner Dam note guarantee 11,700 11,700 11,700
Debt related to investments
in affordable housing with
rates ranging from 6.03%
to 8.77% due 2000 to 2010 71,183 62,103 46,385
Amount due within one
year (9,025) (5,955) (3,926)
Net affordable
housing debt 62,158 56,148 42,459
Unamortized premium/discount
- Net (1,441) (1,539) (1,637)
Net Idaho Power
Company debt 821,101 815,314 741,826
Other subsidiary debt 457 623 4,316
Total long-term debt 821,558 49 815,937 49 746,142 48
TOTAL CAPITALIZATION $1,680,339 100 $1,652,302 100 $1,564,657 100
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 91,349 $ 89,176 $ 87,098
Adjustments to reconcile net
income to net cash
provided by operating
activities:
Unrealized gains from energy
marketing activities (3,584) - -
Depreciation and amortization 95,436 87,143 80,485
Deferred taxes and
investment tax credits (1,820) (10,182) 5,978
Accrued PCA costs (891) 21,658 (7,038)
Change in:
Accounts receivable
and prepayments 2,683 4,883 (69,589)
Accrued unbilled revenue 2,616 (1,298) (5,603)
Materials and
supplies and fuel stock (1,687) (925) (57)
Accounts payable 43,762 (9,963) 75,731
Taxes accrued (3,472) 489 6,991
Other current assets and
liabilities 5,182 (825) 3,296
Other - net 1,014 (10,269) (5,562)
Net cash provided by
operating activities 230,588 169,887 171,730
INVESTING ACTIVITIES:
Additions to utility plant (110,974) (89,184) (95,633)
Investments in affordable
housing projects (19,554) (19,139) (17,021)
Investments in company -
owned life insurance (5,862) - -
Other - net (5,060) 3,206 (1,302)
Net cash used in
investing activities (141,450) (105,117) (113,956)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 80,000 60,000 -
Long-term debt related
to affordable housing
projects 18,730 20,556 12,984
Retirement of:
Subsidiary long-term debt (165) (4,316) (4,700)
Long-term debt related to
affordable housing projects (9,650) (4,838) -
First mortgage bonds - (30,000) -
Dividends on common stock (69,863) (69,868) (69,887)
Increase (decrease) in short-
term borrowings (18,767) (18,992) 3,500
Other - net (952) (1,350) (694)
Net cash used in
financing activities (667) (48,808) (58,797)
Net increase (decrease) in cash
and cash equivalents 88,471 15,962 (1,023)
Cash and cash equivalents at
beginning of period 22,867 6,905 7,928
Cash and cash equivalents at end
of period $111,338 $ 22,867 6,905
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the period
for:
Income taxes $ 51,750 $ 55,527 41,786
Interest (net of amount
capitalized) $ 56,295 $ 53,806 53,319
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING
OF YEAR $278,607 $259,299 $242,088
NET INCOME 91,349 89,176 87,098
Total 369,956 348,475 329,186
COMMON STOCK DIVIDENDS (69,863) (69,868) (69,887)
RETAINED EARNINGS, END OF YEAR $300,093 $278,607 $259,299
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
NET INCOME $ 91,349 $ 89,176 $ 87,098
OTHER COMPREHENSIVE INCOME:
Unrealized gains on securities
(net of tax of $677 and $2,185) 1,017 3,385 -
Minimum pension liability
adjustment (net of tax of $189
and ($2,054)) 291 (3,159) -
TOTAL COMPREHENSIVE INCOME $ 92,657 $ 89,402 $ 87,098
The accompanying notes are an integral part of these statements
IDACORP, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nature of Business
IDACORP, Inc. (IDACORP or the Company) is a holding company
whose principal operating subsidiary is Idaho Power Company
(IPC). On October 1, 1998, IPC's outstanding common stock was
converted on a share-for-share basis into common stock of
IDACORP. However, IPC's preferred stock and debt securities
outstanding were unaffected and remain with IPC.
IPC, a public utility, represents over 90% of the consolidated
total assets of the Company and is its principal operating
subsidiary. IPC is regulated by the Federal Energy Regulatory
Commission (FERC) and the state regulatory commissions of Idaho,
Oregon, Nevada and Wyoming, and is engaged in the generation,
transmission, distribution, sale and purchase of electric energy.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly owned or controlled subsidiaries. All
significant intercompany transactions and balances have been
eliminated in consolidation. Investments in business entities in
which the Company and its subsidiaries do not have control, but
have the ability to exercise significant influence over operating
and financial policies, are accounted for using the equity
method.
System of Accounts
The accounting records of IPC conform to the Uniform System of
Accounts prescribed by the FERC and adopted by the public utility
commissions of Idaho, Oregon, Nevada and Wyoming.
Electric Plant
The cost of additions to electric plant in service represents the
original cost of contracted services, direct labor and material,
allowance for funds used during construction and indirect charges
for engineering, supervision and similar overhead items.
Maintenance and repairs of property and replacements and renewals
of items determined to be less than units of property are charged
to operations. For property replaced or renewed the original
cost plus removal cost less salvage is charged to accumulated
provision for depreciation while the cost of related replacements
and renewals is added to electric plant.
Allowance For Funds Used During Construction (AFDC)
The allowance, a non-cash item, represents the composite interest
costs of debt, shown as a reduction to interest charges, and a
return on equity funds, shown as an addition to other income,
used to finance construction. While cash is not realized
currently from such allowance, it is realized under the rate
making process over the service life of the related property
through increased revenues resulting from higher rate base and
higher depreciation expense. Based on the uniform formula
adopted by the FERC, IPC's weighted-average monthly AFDC rates
for 1999, 1998 and 1997 were 7.8 percent, 6.0 percent, and 5.8
percent respectively.
Revenues
In order to match revenues with associated expenses, IPC accrues
unbilled revenues for electric services delivered to customers
but not yet billed at month-end.
IPC had a regulatory settlement with the Idaho Public Utilities
Commission (IPUC) that expired in 1999. Under terms of the
settlement, when earnings in the Idaho jurisdiction exceeded an
11.75 percent return on year-end common equity, 50 percent of the
excess was set aside for the benefit of IPC's Idaho retail
customers. In 1999, 1998 and 1997, approximately $8.9 million,
$6.4 million, and $7.6 million of revenues were set aside for the
benefit of Idaho retail customers.
Power Cost Adjustment
IPC has a Power Cost Adjustment (PCA) mechanism that provides for
annual adjustments to the rates charged to Idaho retail
customers. These adjustments are based on forecasts of net power
supply costs, and take effect annually on May 16. The difference
between the actual costs incurred and the forecasted costs are
deferred, with interest, and trued-up in the next annual rate
adjustment.
Depreciation
All electric plant is depreciated using the straight-line method
at rates approved by regulatory authorities. Annual depreciation
provisions as a percent of average depreciable electric plant in
service approximated 2.94 percent in 1999, 2.87 percent in 1998,
and 2.93 percent in 1997.
Income Taxes
The Company follows the liability method of computing deferred
taxes on all temporary differences between the book and tax basis
of assets and liabilities and adjusts deferred tax assets and
liabilities for enacted changes in tax laws or rates. Consistent
with orders and directives of the IPUC, the regulatory authority
having principal jurisdiction, IPC's deferred income taxes
(commonly referred to as normalized accounting) are provided for
the difference between income tax depreciation and straight-line
depreciation computed using book lives on coal-fired generation
facilities and properties acquired after 1980. On other
facilities, deferred income taxes are provided for the difference
between accelerated income tax depreciation and straight-line
depreciation using tax guideline lives on assets acquired prior
to 1981. Deferred income taxes are not provided for those income
tax timing differences where the prescribed regulatory accounting
methods do not provide for current recovery in rates. Regulated
enterprises are required to recognize such adjustments as
regulatory assets or liabilities if it is probable that such
amounts will be recovered from or returned to customers in future
rates (see Note 2).
The state of Idaho allows a three-percent investment tax credit
(ITC) upon certain qualifying plant additions. ITC earned on
regulated assets are deferred and amortized to income over the
estimated service lives of the related properties. Credits
earned on non-regulated assets or investments are recognized in
the year earned.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents
include cash on hand and highly liquid temporary investments with
maturity dates at date of acquisition of three months or less.
Management Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and the disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Regulation of Utility Operations
Electric utilities have historically been recognized as natural
monopolies and have operated in a highly regulated environment in
which they have an obligation to provide electric service to
their customers in return for an exclusive franchise within their
service territory with an opportunity to earn a regulated rate of
return. This regulatory environment is changing. The generation
sector has experienced competition from non-utility power and
market producers, and the FERC is requiring utilities, including
IPC, to provide wholesale open-access transmission service to
others and may order electric utilities to enlarge their
transmission systems to facilitate transmission services.
Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets. These statutory and
conforming regulations may result in increased wholesale and
retail competition. In 1997, the Idaho Legislature appointed a
committee to study restructuring of the electric utility
industry. Although the committee will continue studying a
variety of restructuring ideas, it has not recommended any
restructuring legislation and is not expected to in the
foreseeable future. In 1999, the Oregon legislature passed
legislation restructuring the electric utility industry, but
exempted IPC's service territory. Due to IPC's low cost
structure, it is well positioned to compete in the evolving
utility market place. However, the Company is unable to predict
what financial impact or effect the adoption of any such
legislation would have on IPC's operations.
IPC follows Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation," and its financial statements reflect the effects of
the different rate making principles followed by the various
jurisdictions regulating IPC. Pursuant to SFAS No. 71 IPC
capitalizes, as deferred regulatory assets, incurred costs that
are expected to be recovered in future utility rates. IPC also
records as deferred regulatory liabilities the current recovery
in utility rates of costs that are expected to be paid in the
future.
The following is a breakdown of IPC's regulatory assets and
liabilities for the years 1999, 1998 and 1997:
1999 1998 1997
Assets Liabilities Assets Liabilities Assets Liabilities
(Millions of Dollars)
Income taxes $215.7 $ 33.8 $204.4 $ 28.1 $201.7 $ 34.1
Conservation 37.5 - 43.3 - 42.4 -
Employee benefits 4.7 - 5.6 - 6.5 -
PCA deferral and
amortization (3.4) - (5.2) - 16.6 -
Other 13.9 3.4 18.3 4.1 24.7 0.5
Deferred investment
tax credits - 67.4 - 69.4 - 70.2
Total $268.4 $104.6 $266.4 $101.6 $291.9 $104.8
At December 31, 1999, IPC had $7.1 million of regulatory assets
that were not earning a return on investment, excluding the
$215.7 million that relates to income taxes.
In the event that recovery of costs through rates becomes
unlikely or uncertain, SFAS No. 71 would no longer apply. If the
Company were to discontinue application of SFAS No. 71 for some
or all of IPC's operations, then these items may represent
stranded investments. If the Company is not allowed recovery of
these investments, it would be required to write off the
applicable portion of regulatory assets and the financial effects
could be significant.
Derivative Financial Instruments
The Company uses financial instruments such as commodity futures,
forwards, options and swaps to manage exposure to commodity price
risk in the electricity and natural gas markets. The objective
of the Company's risk management program is to mitigate the risk
associated with the purchase and sale of natural gas and
electricity as well as to optimize its energy marketing
portfolio. The accounting for derivative financial instruments
that are used to manage risk is in accordance with the concepts
established in SFAS No. 80, "Accounting for Futures Contracts,"
American Institute of Certified Public Accountants Statement of
Position 86-2, "Accounting for Options," and Emerging Issues Task
Force (EITF) 98-10, "Accounting for Contracts Involved in Energy
Trading Activities". EITF 98-10 was adopted effective January 1,
1999 resulting in an adjustment to net income that was not
material. Related to the adoption of EITF 98-10, the Company has
begun reporting electricity trading activity net on the
Consolidated Statements of Income. Prior years have been
reclassified to conform with the current year's presentation.
Energy trading contracts as defined by EITF 98-10 are reported at
fair value on the balance sheet with the resulting gains and
losses reported on the income statement. Cash flows from energy
trading contracts are recognized in the statement of cash flows
as an operating activity.
The following table shows a summary of the notional amounts of
the Company's forward exposure as of December 31, 1999. The
maximum term related to any of our forward positions is two
years.
1999
Gas Electricity
MMBTU's MWh's
Payable 38,421 4,739
Receivable 49,040 6,079
Swaps 25,052 -
The following table displays the fair values of the Company's
energy marketing assets and liabilities at December 31, 1999, and
the average values for the year ended December 31, 1999 (in
thousands of dollars):
1999 End of Year Balance 1999 Average Balance
Assets Liabilities Assets liabilities
(Thousands of Dollars)
Gas $ 8,302 $ 8,220 $14,173 $11,710
Electriciy 29,096 25,594 40,450 43,320
Total $37,398 $33,814 $54,623 $55,030
The gain in fair value of energy trading contract positions
(including electricity and natural gas forwards, futures, options
and swaps) included in income before income taxes for the year
ended December 31, 1999 was $21.7 million.
Notional amounts listed above reflect the volume of energy
related to transactions with counterparties, but do not measure
exposure to market or credit risks. The maximum term detailed
above also is not indicative of likely future cash flows as
positions may be offset in the markets at any time to meet risk
management guidelines.
Comprehensive Income
Components of the Company's comprehensive income include net
income, the Company's proportionate share of unrealized holding
gains on marketable securities held by an equity investee, and
the changes in additional minimum liability under a deferred
compensation plan for certain senior management employees and
directors.
New Accounting Pronouncements
In June 1998 the FASB issued SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Activities." This statement
establishes accounting and reporting standards for derivative
financial instruments and other similar instruments and for
hedging activities. It was originally effective for fiscal years
beginning after June 15, 1999. In June 1999 the FASB issued SFAS
No. 137 "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Standard No.
133", which defers the effective date of SFAS No. 133 one year.
The Company is reviewing SFAS No. 133 to determine its effects on
the Company's financial position and results of operations.
Other Accounting Policies
Debt discount, expense and premium are being amortized over the
terms of the respective debt issues.
Reclassifications
Certain items previously reported for years prior to 1999 have
been reclassified to conform to the current year's presentation.
2. INCOME TAXES:
IPC has settled Federal and Idaho tax liabilities on all open
years through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued.
A reconciliation between the statutory federal income tax rate
and the effective rate is as follows:
1999 1998 1997
(Thousands of Dollars)
Computed income taxes based
on statutory federal
income tax rate $ 47,957 $ 46,832 $ 46,750
Change in taxes resulting
from:
Investment tax credits (3,032) (2,934) (2,887)
Repair allowance (2,800) (2,800) (2,800)
Settlement of prior
years tax returns (380) (1,965) 23
Current state income taxes 6,024 6,258 3,587
Depreciation 7,292 5,237 5,766
Affordable housing tax
credits (9,529) (6,880) (4,519)
Preferred dividends of
IPC 1,950 1,980 1,811
Other (1,810) (1,098) (1,259)
Total provision for federal
and state income taxes $ 45,672 44,630 46,472
Effective tax rate 33.3% 33.4% 34.8%
The provision for income taxes consists of the following:
1999 1998 1997
(Thousands of Dollars)
Income taxes currently
payable:
Federal $ 38,165 $ 45,606 $ 35,038
State 9,327 9,206 5,456
Total 47,492 54,812 40,494
Income taxes deferred -
Net of amortization:
Federal 2,174 (8,006) 6,717
State (2,031) (1,376) 348
Total 143 (9,382) 7,065
Investment tax credits:
Deferred 1,069 2,134 1,800
Restored (3,032) (2,934) (2,887)
Total (1,963) (800) (1,087)
Total provision for
income taxes $ 45,672 $ 44,630 $ 46,472
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
1999 1998 1997
(Thousands of Dollars)
Deferred tax assets:
Regulatory liabilities $ 33,817 $ 28,075 $ 34,072
Advances for
construction 9,646 10,401 18,665
Other 19,019 20,512 16,536
Total 62,482 58,988 69,273
Deferred tax liabilities:
Electric plant 249,597 247,270 251,938
Regulatory assets 215,675 204,430 201,685
Conservation programs 17,396 16,866 14,377
Other 11,175 15,583 28,173
Total 493,843 484,149 496,173
Net deferred tax
liabilities $431,361 $425,161 $426,900
3. COMMON STOCK:
Changes in shares of IDACORP common stock for 1999, 1998 and 1997
were as follows:
Shares Amount
(Thousands of Dollars)
Balance at December 31, 1996 37,612,351 $ 452,486
Other - Net - 33
Balance at December 31, 1997 37,612,351 452,519
Other - Net - (955)
Balance at December 31, 1998 37,612,351 451,564
Other - Net - (221)
Balance at December 31, 1999 37,612,351 $ 451,343
As of December 31, 1999; 3,791,321 of authorized but unissued
shares of IDACORP common stock were reserved for future issuance
under the Company's Dividend Reinvestment and Stock Purchase Plan
and IPC's Employee Savings Plan. In addition, 314,114 shares are
reserved for the Restricted Stock Plan (see Note 9).
The Company has a Shareholder Rights Plan (Plan) designed to
ensure that all shareholders receive fair and equal treatment in
the event of any proposal to acquire control of the Company.
Under the Plan, the Company declared a distribution of one
Preferred Share Purchase Right (Right) for each of the Company's
outstanding Common Shares held on October 1, 1998 or issued
thereafter. The Rights are currently not exercisable and will be
exercisable only if a person or group (Acquiring Person) either
acquires ownership of 20 percent or more of the Company's Voting
Stock or commences a tender offer that would result in ownership
of 20 percent or more of such stock. The Company may redeem all
but not less than all of the Rights at a price of $0.01 per Right
or exchange the Rights for cash, securities (including Common
Shares of the Company) or other assets at any time prior to the
close of business on the 10th day after acquisition by an
Acquiring Person of a 20 percent or greater position.
Additionally, the IDACORP Board created the A Series Preferred
Stock, without par value, and reserved 1,200,000 shares for
issuance upon exercise of the Rights.
Following the acquisition of a 20 percent or greater position,
each Right will entitle its holder to purchase for $95 that
number of shares of Common Stock or Preferred Stock having a
market value of $190.
If after the Rights become exercisable, the Company is acquired
in a merger or other business combination, 50 percent or more of
its consolidated assets or earnings power are sold or the
Acquiring Person engages in certain acts of self-dealing, each
Right entitles the holder to purchase for $95, shares of the
acquiring company's common stock having a market value of $190.
Any Rights that are or were held by an Acquiring Person become
void if any of these events occurs. The Rights expire on
September 30, 2008.
The Rights themselves do not give any voting or other rights as
shareholders to their holders. The terms of the Rights may be
amended without the approval of any holders of the Rights until
an Acquiring Person obtains a 20 percent or greater position, and
then may be amended as long as the amendment is not adverse to
the interests of the holders of the Rights.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at
December 31, 1999, 1998 and 1997 were as follows:
Shares Outstanding at
December 31, Call Price
1999 1998 1997 Per Share
Preferred stock:
Cumulative, $100 par
value:
4% preferred stock
(authorized
215,000 shares) 158,112 159,680 166,972 $104.00
Serial preferred
stock, 7.68%
Series(authorized
150,000 shares) 150,000 150,000 150,000 $102.97
Serial preferred stock,
cumulative, without
par value; total of
3,000,000 shares authorized:
7.07% Series, $100 stated
value,(authorized
250,000 shares)
(a) 250,000 250,000 250,000 $103.535 to
$100.354
Auction rate preferred stock,
$100,000 stated
value,(authorized 500
shares)(b) 500 500 500 $100,000.00
Total 558,612 560,180 567,472
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 1999 was 4.41% and ranged
between 3.60% and 4.41% during the year.
During 1999, 1998 and 1997 IPC reacquired and retired 1,568;
7,292; and 2,781 shares of 4% preferred stock. As of December
31, 1999, the overall effective cost of all outstanding preferred
stock was 5.74 percent.
5. LONG-TERM DEBT:
The Company currently has a $300.0 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. At December 31, 1999,
none had been issued.
The amount of first mortgage bonds issuable by IPC is limited to
a maximum of $900.0 million and by property, earnings and other
provisions of the mortgage and supplemental indentures thereto.
Substantially all of the electric utility plant is subject to the
lien of the indenture.
Pollution Control Revenue Bonds, Series 1984, due December 1,
2014, are secured by First Mortgage Bonds, Pollution Control
Series A, which were issued by IPC and are held by a Trustee for
the benefit of the bondholders.
First mortgage bonds maturing during the five-year period ending
2004 are $80.0 million in 2000, $30.0 million in 2001, $27.0
million in 2002, $80.0 million in 2003 and $50.0 in 2004.
On September 9, 1998, $60.0 million principal amount of Secured
Medium Term Notes, Series B, 5.83% Series due 2005 were issued by
IPC. Proceeds from this issuance were used to redeem at
maturity, the $30.0 million First Mortgage Bonds 5.33% Series B
due September 1998, with the balance used for repayment of
commercial paper issued in connection with IPC's ongoing
business.
On November 23, 1999, $80.0 million principal amount of Secured
Medium Term Notes, Series B, 7.20% Series due 2009 were issued by
IPC. Proceeds from this issuance were used to redeem at
maturity, the $80.0 million First Mortgage Bonds 8.65% Series due
January 2000.
At December 31, 1999, 1998 and 1997 the overall effective cost of
all outstanding first mortgage bonds and pollution control
revenue bonds was 7.62 percent, 7.69 percent, and 7.84 percent,
respectively.
At December 31, 1999, IDACORP Financial Services, Inc., a wholly
owned subsidiary of IPC, has $71.2 million of debt with interest
rates ranging from 6.03 percent to 8.77 percent. This debt is
collateralized by investments in affordable housing projects with
a bookvalue of $80.5 million at December 31, 1999. Principal
amounts maturing during the five-year period ending 2004 are $9.0
million in 2000, $9.7 million in 2001, $10.0 million in 2002,
$9.6 million in 2003 and $9.6 million in 2004.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of the Company's financial instruments
has been determined by the Company using available market
information and appropriate valuation methodologies. The use of
different market assumptions and/or estimation methodologies may
have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued
are reported at their carrying value as these are a reasonable
estimate of their fair value. The estimated fair values for long-
term debt and investments are based upon quoted market prices of
the same or similar issues or discounted cash flow analyses as
appropriate.
The total estimated fair value of the Company's debt was
approximately $898.1 million in 1999, $877.4 million in 1998 and
$801.8 million in 1997. Included in investments and other
property were financial instruments totaling $24.0 million in
1999, $14.2 million in 1998 and $16.5 million in 1997. Estimated
fair value of these instruments was $30.6 million in 1999, $20.3
million in 1998 and $19.9 million in 1997.
7. NOTES PAYABLE:
At December 31, 1999, IPC had regulatory authority to incur up to
$200 million of short-term indebtedness. IPC has a $120 million
multi-year revolving credit facility expiring in December 2001.
Under this facility IPC pays a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond rating.
Commercial paper may be issued in an amount not to exceed 25
percent of revenues for the latest twelve-month period subject to
the $200 million maximum and are supported by bank lines of
credit of an equal amount.
Balances and interest rates of short-term borrowings for IPC were
as follows:
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
Balance at end of year $19,757 $38,524 $57,516
Effective annual interest rate
at end of year 6.1% 6.0% 6.1%
IDACORP has separately established a $50 million three-year
credit facility that expires in December 2001, and a $100 million
364-day credit facility that expires in December 2000. Under
these facilities the Company pays a facility fee on the
commitment, quarterly in arrears, based on IPC's First Mortgage
Bond Rating. Commercial paper may be issued up to the $150
million and is supported by the bank credit facilities. None of
this debt is outstanding at December 31, 1999.
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to IPC's
program for construction and operation of facilities amounted to
approximately $8.6 million at December 31, 1999. The commitments
are generally revocable by IPC subject to reimbursement of
manufacturers' expenditures incurred and/or other termination
charges.
IPC is currently purchasing energy from 65 on-line cogeneration
and small power production facilities with contracts ranging from
1 to 31 years. Under these contracts IPC is required to purchase
all of the output from these facilities. During the fiscal year
ended December 31, 1999, IPC purchased 931,797 (MWh) at a cost of
$56.2 million.
The Company is party to various legal claims, actions, and
complaints, certain of which involve material amounts. Although
unable to predict with certainty whether or not it will
ultimately be successful in these legal proceedings, or, if not,
what the impact might be, based upon the advice of legal counsel,
management presently believes that disposition of these matters
will not have a material adverse effect on the Company's
financial position, results of operation or cash flow.
9. BENEFIT PLANS:
Pension Plans
IDACORP has a noncontributory defined benefit pension plan
covering most employees. The benefits under the plan are based
on years of service and the employee's final average earnings.
The Company's policy is to fund with an independent corporate
trustee at least the minimum required under the Employee
Retirement Income Security Act of 1974 but not more than the
maximum amount deductible for income tax purposes. The Company
was not required to contribute to the plan in 1999, 1998 and
1997. The trustee invests the plan's assets primarily in listed
stocks (both U.S. and foreign), fixed income securities and
investment grade real estate.
IDACORP has a nonqualified, deferred compensation plan for
certain senior management employees and directors. The Company
financed this plan by purchasing life insurance policies and
investments in marketable securities all of which are held by a
trustee. The cash value of the policies and investments exceed
the projected benefit obligation of the plan but do not qualify
as plan assets in the actuarial computation of the funded status.
The following table shows the components of net periodic benefit
cost for these plans (in thousands of dollars):
Pension Plan Deferred Compensation
Plan
1999 1998 1997 1999 1998 1997
Service cost $ 8,389 $ 7,133 $ 6,152 $ 744 $ 572 $ 515
Interest cost 16,402 15,458 14,445 1,797 1,747 1,731
Expected return on
assets (25,240) (22,724) (20,248) - - -
Recognized net
actuarial (gain)
loss (344) (111) - 279 255 222
Amortization of
prior service cost 708 424 424 (325) (332) (346)
Amortization of
transition asset (263) (263) (263) 613 613 613
Net periodic pension
cost $ (348) $ (83) $ 510 $ 3,108 $ 2,855 $ 2,735
The following table summarizes the changes in benefit obligation
and plan assets of these plans (in thousands of dollars):
Pension Plan Deferred Compensation Plan
1999 1998 1997 1999 1998 1997
Change in projected
benefit obligation:
Benefit obligation
at January 1 $253,729 $224,073 $202,049 $ 27,029 $ 25,067 $ 24,122
Service cost 8,389 7,133 6,152 744 572 516
Interest cost 16,402 15,458 14,445 1,797 1,747 1,731
Actuarial loss
(gain) (33,014) 14,139 12,763 (489) 1,297 806
Benefits paid (16,464) (11,774) (11,336) (2,201) (2,049) (2,303)
Plan amendments - 4,700 - 45 395 195
Benefit obligation
at December 31 229,042 253,729 224,073 26,925 27,029 25,067
Change in plan assets:
Fair value at
January 1 290,080 256,893 230,478 - - -
Actual return on
plan assets 66,905 44,961 37,751 - - -
Employer contributions - - - - - -
Benefit payments (16,464) (11,774) (11,336) - - -
Fair value at
December 31 340,521 290,080 256,893 - - -
Funded status 111,479 36,351 32,820 (26,925) (27,029) (25,067)
Unrecognized actuarial
loss/(gain) (108,057) (33,722) (25,734) 5,844 6,612 5,569
Unrecognized prior
service cost 8,662 9,370 5,093 (796) (1,166) (1,893)
Unrecognized net
transition liability (1,441) (1,704) (1,967) 3,375 3,988 4,601
Net amount recognized $ 10,643 $ 10,295 $ 10,212 $(18,502)$(17,595)$(16,790)
Amounts recognized in
the statement of
financial position
consists of:
Prepaid (accrued) pension
cost $ 10,643 $ 10,295 $ 10,212 $(25,815)$(25,631)$(24,657)
Intangible asset - - - 2,579 2,822 7,867
Accumulated other
comprehensive income - - - 4,734 5,214 -
Net amount recognized $ 10,643 $ 10,295 $ 10,212 $(18,502)$(17,595)$(16,790)
The following table sets forth the assumptions used at the end of
each year for all IPC-sponsored pension and postretirement
benefit plans:
Pension Benefits Postretirement
Benefits
1999 1998 1997 1999 1998 1997
Discount rate 7.5 % 6.75 % 7.10 % 7.5 % 6.75 % 7.35 %
Expected long-term rate of
return on assets 9.0 9.0 9.0 9.0 9.0 9.0
Annual salary increases 4.5 4.5 4.5 - - -
Restricted Stock Plan
IDACORP has a restricted stock plan for certain key employees.
Each grant has a three-year restricted period and final award
amounts depend on the attainment of a cumulative earnings per
share performance goal. At December 31, 1999, there were 297,888
remaining shares of common stock available for issuance under the
plan.
Restricted stock awards are compensatory awards and the Company
accrues compensation expense (which is charged to operations)
based upon the market value of the granted shares. For the years
1999, 1998 and 1997, total compensation accrued for the plan was
$519,000, $567,000 and $539,000 respectively.
The Company applies APB Opinion 25 and related interpretations in
accounting for this plan. Had compensation cost for the grants
of restricted stock been determined consistent with the optional
fair value based method provisions of SFAS No. 123, "Accounting
for Stock-Based Compensation," the Company's net income and
earnings per share of common stock for 1999, 1998 and 1997 would
not be significantly different from such amounts as reported.
The following table summarizes restricted stock activity for the
years 1999, 1998 and 1997:
1999 1998 1997
Shares outstanding -
beginning of year, 43,063 38,365 18,140
Shares granted 23,497 21,361 20,225
Shares forfeited (9,585) (4,063) -
Shares issued (13,360) (12,600) -
Shares outstanding - end
of year 43,615 43,063 38,365
Weighted average fair
value of current year
stock grants on
grant date $ 32.88 $ 37.00 $ 31.25
Savings Plan
IDACORP has an Employee Savings Plan which complies with Section
401(k) of the Internal Revenue Code and covers substantially all
employees. The Company matches specified percentages of employee
contributions to the plan. Matching contributions amounted to
$3.1 million in 1999, $3.0 million in 1998 and $2.4 million in
1997.
Postretirement Benefits
The Company maintains a defined benefit postretirement plan
(consisting of health care and death benefits) that covers all
employees who were enrolled in the active group plan at the time
of retirement, their spouses and qualifying dependents.
The net periodic postretirement benefit cost was as follows (in
thousands of dollars):
1999 1998 1997
Service cost $ 896 $ 720 $ 713
Interest cost 2,867 2,913 3,029
Expected return on plan assets (2,230) (1,761) (1,511)
Amortization of unrecognized 2,040 2,040 2,040
transition obligation
Amortization of prior service
cost (691) (280) (87)
Amortization of unrecognized net
gains - (220) (240)
Net periodic post-retirement
benefit cost $ 2,882 3,412 3,944
The following table summarizes the changes in benefit obligation
and plan assets plan (in thousands of dollars):
1999 1998 1997
Change in accumulated benefit
obligation:
Benefit obligation at
January 1 $38,615 $43,459 $44,439
Service cost 896 720 713
Interest cost 2,867 2,913 3,029
Plan amendments - (9,071) (1,214)
Actuarial loss (gain) 1,859 3,483 (1,940)
Benefits paid (3,098) (2,889) (1,568)
Benefit obligation at
December 31 41,139 38,615 43,459
Change in plan assets:
Fair value of plan assets
at January 1 24,346 19,493 17,341
Actual return on plan
assets 2,389 4,853 2,152
Employer (excess)
contributions 2,845 2,789 1,553
Benefits paid (2,775) (2,789) (1,553)
Fair value of plan assets
at December 31 26,805 24,346 19,493
Funded status (14,334) (14,269) (23,966)
Unrecognized prior service cost (9,227) (9,918) (1,127)
Unrecognized actuarial gain (5,556) (7,256) (7,867)
Unrecognized transition
obligation 26,520 28,560 30,600
Accrued benefit obligations
included with other deferred
credits $(2,597) $(2,883) $(2,360)
The assumed health care cost trend rate used to measure the
expected cost of benefits covered by the plan is 6.75%. A one-
percentage point change in the assumed health care cost trend
rate would have the following effect (in thousands of dollars):
1- 1-
Percentage- Percentage-
Point Point
increase decrease
Effect on total of service and
interest cost components $ 293 $ (239)
Effect on accumulated post-
retirement benefit obligation $2,421 $(2,058)
Postemployment Benefits
The Company provides certain benefits to former or inactive
employees, their beneficiaries, and covered dependents after
employment but before retirement. These benefits include salary
continuation, health care and life insurance for those employees
found to be disabled under our disability plans, and health care
for surviving spouses and dependents. The Company accrues a
liability for such benefits. In accordance with an IPUC order,
the portion of the liability attributable to regulated activities
in Idaho as of December 31, 1993, was deferred as a regulatory
asset, and is being amortized over ten years. The following
table summarizes postemployment benefit amounts included in the
Company's consolidated balance sheet (in thousands of dollars):
1999 1998 1997
Included with regulatory
assets - other $ 1,889 $ 2,260 $ 2,632
Included with other
deferred credits $(3,282) $(3,372) $(3,093)
10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the
IPC's electric plant in service, accumulated provision for
depreciation and annual depreciation provisions as a percent of
average depreciable balance for the years 1999, 1998 and 1997 (in
thousands of dollars):
1999 1998 1997
Balance Avg Rate Balance Avg Rate Balance Avg Rate
Production $1,348,531 2.60% $1,344,526 2.60% $1,333,768 2.60%
Transmission 403,010 2.30 389,011 2.30 378,190 2.28
Distribution 786,488 3.37 736,527 3.15 715,091 3.38
General and Other 187,997 5.46 189,377 5.45 178,648 5.39
Total In Service 2,726,026 2.94% 2,659,441 2.87% 2,605,697 2.93%
Less accumulated
provision for
depreciation 1,073,722 1,009,387 942,400
In Service -
Net $1,652,304 $1,650,054 $1,663,297
IPC is involved in the ownership and operation of three jointly-
owned generating facilities. The Consolidated Statements of
Income include IPC's proportionate share of direct operation and
maintenance expenses applicable to the projects.
Each facility and extent of IPC participation as of December 31,
1999 are as follows:
Company Ownership
Accumulated
Electric Provision
Name of Plant Location Plant In for
Service Depreciation % MW
(Thousands of Dollars)
Jim Bridger Rock Springs, $ 389,277 $ 198,393 33 708
Units 1-4 WY
Boardman Boardman, OR 61,728 33,970 10 53
Valmy Units 1 Winnemucca, NV 300,449 139,101 50 261
and 2
IPC's wholly owned subsidiary, Idaho Energy Resources Company, is
a joint venturer in Bridger Coal Company, which operates the mine
supplying coal for the Jim Bridger steam generation plant. Coal
purchased by IPC from the joint venture amounted to $41.9 million
in 1999, $46.2 million in 1998 and $40.7 million in 1997.
IPC has contracts to purchase the energy from five PURPA
Qualified Facilities that are 50 percent owned by Ida-West Energy
Company, a wholly owned subsidiary of the Company. Power
purchased from these facilities amounted to $8.8 in 1999, $8.7
million in 1998 and $9.8 million in 1997.
11. INDUSTRY SEGMENT INFORMATION:
The Company operates an electric utility involving the
generation, transmission, distribution, purchase and sale of
electricity. The Company's primary non-utility segments involve
electricity and natural gas trading, independent power projects,
energy-related products and services, renewable energy products,
fuel-cell technology, and home security, internet and satellite
television services.
The following table summarizes the segment information for the
Company's utility operations and the total of all other segments,
and reconciles this information to total enterprise amounts:
IPC Consolida
ted
Utility Other Total
(Thousands of Dollars)
1999
Revenues $ 658,336 $ - $ 658,336
Income from operations 172,458 - 172,458
Other income 5,120 26,598 31,718
Interest expense 56,679 4,904 61,583
Income before income
taxes 115,327 21,694 137,021
Income taxes 46,395 (723) 45,672
Net income 68,932 22,417 91,349
Total assets 2,355,907 281,086 2,636,993
Expenditures for long-
lived assets 112,772 27,192 139,964
1998
Revenues $ 756,410 $ - $ 756,410
Income from operations 180,584 180,584
Other income 5,909 12,748 18,657
Interest expense 56,646 3,131 59,777
Income before income
taxes 129,847 3,959 133,806
Income taxes 47,552 (2,922) 44,630
Net income 82,295 6,881 89,176
Total assets 2,251,077 200,543 2,451,620
Expenditures for long-
lived assets 91,803 19,205 111,008
1997
Revenues $ 605,183 $ - $ 605,183
Income from operations 180,731 - 180,731
Other income 3,894 14,379 18,273
Interest expense 57,653 2,605 60,258
Income before income
taxes 126,972 6,598 133,570
Income taxes 47,618 (1,146) 46,472
Net income 79,354 7,744 87,098
Total assets 2,272,752 179,064 2,451,816
Expenditures for long-
lived assets 98,219 17,457 115,676
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowners
IDACORP, Inc.
Boise, Idaho
We have audited the accompanying consolidated balance sheets and
statements of capitalization of IDACORP, Inc. and its
subsidiaries as of December 31, 1999, 1998 and 1997, and the
related consolidated statements of income, cash flows, retained
earnings and comprehensive income for the years then ended. Our
audits also include the consolidated financial statement schedule
listed in the Index at Item 8. These financial statements and
financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an
opinion on the financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
IDACORP, Inc. and subsidiaries at December 31, 1999, 1998 and
1997, and the results of their operations and their cash flows
for the years then ended in conformity with generally accepted
accounting principles. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents
fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
January 31, 2000
(This page intentionally left blank)
Idaho Power Company
Consolidated Statements of Income
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
REVENUES:
General business $516,148 $514,856 $480,458
Off system sales 119,785 214,418 100,554
Other revenues 22,403 27,136 24,171
Total revenues 658,336 756,410 605,183
EXPENSES:
Operation:
Purchased power 106,344 185,271 79,898
Fuel expense 86,617 86,237 71,271
Power cost adjustment (502) 21,866 (6,032)
Other 151,800 145,374 137,458
Maintenance 42,067 41,872 48,722
Depreciation 77,833 74,481 71,973
Taxes other than income taxes 21,719 20,725 21,162
Total expenses 485,878 575,826 424,452
INCOME FROM OPERATIONS 172,458 180,584 180,731
OTHER INCOME:
Allowance for equity funds
used during construction 1,667 300 34
Energy marketing activities -
Net 23,206 7,429 2,837
Other - Net 6,369 12,364 15,402
Total other income 31,242 20,093 18,273
INTEREST CHARGES:
Interest on long-term debt 54,150 52,270 53,215
Other interest 7,864 8,323 7,546
Allowance for borrowed funds
used during construction (1,392) (900) (503)
Total interest charges 60,622 59,693 60,258
INCOME BEFORE INCOME TAXES 143,078 140,984 138,746
INCOME TAXES 45,550 45,065 46,472
NET INCOME 97,528 95,919 92,274
Dividends on preferred stock 5,572 5,658 5,176
EARNINGS ON COMMON STOCK $ 91,956 $ 90,261 $ 87,098
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Assets
December 31,
1999 1998 1997
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,726,026 $2,659,441 $2,605,697
Accumulated provision for
depreciation (1,073,722) (1,009,387) (942,400)
In service - Net 1,652,304 1,650,054 1,663,297
Construction work in progress 88,348 58,904 51,892
Held for future use 1,742 1,738 1,738
Electric plant - Net 1,742,394 1,710,696 1,716,927
INVESTMENTS AND OTHER PROPERTY 117,759 105,600 97,065
CURRENT ASSETS:
Cash and cash equivalents 95,038 20,029 6,905
Receivables:
Customer 83,412 102,653 105,204
Allowance for
uncollectible accounts (1,397) (1,397) (1,397)
Notes 345 467 4,613
Employee notes 4,105 4,510 4,757
Related parties 195 3,164 -
Other 7,095 5,338 8,854
Energy marketing assets 29,096 - -
Accrued unbilled revenues 31,994 34,610 33,312
Materials and supplies (at
average cost) 28,960 30,143 29,156
Fuel stock (at average cost) 9,329 7,096 7,172
Prepayments 16,054 16,011 15,381
Regulatory assets associated
with income taxes 893 2,965 3,164
Total current assets 305,119 225,589 217,121
DEFERRED DEBITS:
American Falls and Milner
water rights 31,585 1,830 32,055
Company-owned life insurance 40,480 35,149 51,915
Regulatory assets associated
with income taxes 214,782 201,465 198,521
Regulatory assets - other 52,759 62,013 90,239
Other 54,496 49,448 47,973
Total deferred debits 394,102 379,905 420,703
TOTAL $2,559,374 $2,421,790 $2,451,816
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Capitalization and Liabilities
December 31,
1999 1998 1997
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock, $2.50 par
value (50,000,000 shares
authorized; 37,612,351
shares outstanding) $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,203 362,156 362,328
Capital stock expense (3,819) (3,823) (3,840)
Retained earnings 274,181 252,137 259,299
Accumulated other
comprehensive income 1,534 226 -
Total common stock equity 728,130 704,727 711,818
Preferred stock 105,811 105,968 106,697
Long-term debt 821,558 815,937 746,142
Total capitalization 1,655,499 1,626,632 1,564,657
CURRENT LIABILITIES:
Long-term debt due within one
year 89,101 6,029 33,998
Notes payable 19,757 38,508 57,516
Accounts payable 95,125 101,108 111,938
Notes and accounts payable to
related parties 10,076 28 -
Energy marketing liabilities 25,594 - -
Taxes accrued 21,773 25,164 24,295
Interest accrued 19,122 18,364 17,918
Deferred income taxes 893 2,965 3,164
Other 16,069 12,117 13,703
Total current liabilities 297,510 204,283 262,532
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment
tax credits 67,433 69,396 70,196
Deferred income taxes 428,923 420,268 423,736
Regulatory liabilities
associated with income taxe 33,817 28,075 34,072
Regulatory liabilities -
other 3,363 4,161 509
Other 72,829 68,975 96,114
Total deferred credits 606,365 590,875 624,627
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $2,559,374 $2,421,790 $2,451,816
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Capitalization
December 31,
1999 % 1998 % 1997 %
(Thousands of Dollars)
COMMON STOCK EQUITY
Common stock $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,203 362,156 362,328
Capital stock expense (3,819) (3,823) (3,840)
Retained earnings 274,181 252,137 259,299
Accumulated other
comprehensive income 1,534 226 -
Total common stock
equity 728,130 44 704,727 43 711,818 45
PREFERRED STOCK
4% preferred stock 15,811 15,968 16,697
7.68% Series, serial
preferred stock 15,000 15,000 15,000
7.07% Series, serial
preferred stock 25,000 25,000 25,000
Auction rate preferred
stock 50,000 50,000 50,000
Total preferred stock 105,811 6 105,968 7 106,697 7
LONG-TERM DEBT
First mortgage bonds:
5.33 %Series due 1998 - - 30,000
8.65 %Series due 2000 80,000 80,000 80,000
6.93 % Series due 2001 30,000 30,000 30,000
6.85 % Series due 2002 27,000 27,000 27,000
6.40 % Series due 2003 80,000 80,000 80,000
8 %Series due 2004 50,000 50,000 50,000
5.83 % Series due 2005 60,000 60,000 -
7.20 % Series due 2009 80,000 - -
Maturing 2021 through
2031 with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first mortgage
bonds 637,000 557,000 527,000
Amount due within one year (80,000) - (30,000)
Net first mortgage
bonds 557,000 557,000 497,000
Pollution control revenue
bonds:
7.25%Series due 2008 4,360 4,360 4,360
8.30%Series 1984 due 49,800 49,800 49,800
2014
6.05%Series 1996A due 68,100 68,100 68,100
2026
Variable Rate Series
1996B due 2026 24,200 24,200 24,200
Variable Rate Series
1996C due 2026 24,000 24,000 24,000
Total pollution
control revenue bonds 170,460 170,460 170,460
REA notes 1,415 1,489 1,561
Amount due within one
year (76) (74) (72)
Net REA notes 1,339 1,415 1,489
American Falls bond
guarantee 19,885 20,130 20,355
Milner Dam note guarantee 11,700 11,700 11,700
Debt related to investments
in affordable housing with
rates ranging from 6.03%
to 8.77% due 2000 to 2010 71,183 62,103 46,385
Amount due within one
year (9,025) (5,955) (3,926)
Net affordable
housing debt 62,158 56,148 42,459
Other subsidiary debt 457 623 4,316
Unamortized
premium/discount - Net (1,441) (1,539) (1,637)
Total long-term debt 821,558 50 815,937 50 746,142 48
TOTAL CAPITALIZATION $1,655,499 100 $1,626,632 100 $1,564,657 100
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Cash Flows
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 97,528 $ 95,919 $ 92,274
Adjustments to reconcile net
income to net cash:
Unrealized gains from
energy marketing
activities (3,502) - -
Depreciation &
amortization 95,154 87,044 80,485
Deferred taxes and
investment tax credits (1,747) (10,127) 5,978
Accrued PCA costs (891) 21,658 (7,038)
Change in:
Accounts receivable and
prepayments (489) 1,985 (69,589)
Accrued unbilled revenue 2,616 (1,298) (5,603)
Materials and supplies
and fuel stock (1,050) (911) (57)
Accounts payable 28,397 (10,658) 75,731
Taxes accrued (3,391) 1,312 6,991
Other current
assets and
liabilities 4,710 (857) 3,296
Other - net (3,490) (10,340) (5,562)
Net cash provided by
operating activities 213,845 173,727 176,906
INVESTING ACTIVITIES:
Additions to utility plant (108,498) (89,644) (95,633)
Investments in affordable
housing projects (19,554) (19,139) (17,021)
Investments in company -
owned life insurance (5,862) - -
Other - net (3,066) 867 (1,302)
Net cash used in
investing activities (136,980) (107,916) (113,956)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 80,000 60,000 -
Long-term debt related
to affordable housing
projects 18,730 20,556 12,984
Retirement of:
Subsidiary long-term debt (165) (3,316) (4,700)
Long-term debt related to
affordable housing
projects (9,650) (4,838) -
First mortgage bonds - (30,000) -
Dividends on common stock (69,912) (69,889) (69,887)
Dividends on preferred stock (5,572) (5,658) (5,176)
Increase (decrease) in short-
term borrowings (14,607) (18,992) 3,500
Other - net (680) (550) (694)
Net cash used in
financing activities (1,856) (52,687) (63,973)
Net increase (decrease) in cash
and cash equivalents 75,009 13,124 (1,023)
Cash and cash equivalents at
beginning of period 20,029 6,905 7,928
Cash and cash equivalents at end
of period $ 95,038 $ 20,029 $ 6,905
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the period for:
Income taxes $ 50,532 $ 55,527 $ 41,786
Interest (net of amount
capitalized) $ 55,186 $ 53,806 $ 53,319
Net assets of affiliates
transferred to parent - $ 27,534 -
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Retained Earnings
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING OF
YEAR $252,137 $259,299 $242,088
NET INCOME 97,528 95,919 92,274
Total 349,665 355,218 334,362
DIVIDENDS
Common stock ($1.86 per
share) (69,912) (69,889) (69,887)
Preferred stock (5,572) (5,658) (5,176)
TRANSFER TO IDACORP, INC. - (27,534) -
RETAINED EARNINGS, END OF YEAR $274,181 $252,137 $259,299
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
1999 1998 1997
(Thousands of Dollars)
NET INCOME $ 97,528 $ 95,919 $ 92,274
OTHER COMPREHENSIVE INCOME:
Unrealized gains on
securities (net of tax
of $677 and $2,185) 1,017 3,385 -
Minimum pension liability
adjustment (net of tax
of $189 and( $2,054)) 291 (3,159) -
TOTAL COMPREHENSIVE INCOME $ 98,836 $ 96,145 $ 92,274
The accompanying notes are an integral part of these statements.
Idaho Power Company
Notes to the Consolidated Financial Statements
On October 1, 1998, IDACORP, Inc. (IDACORP) became the parent of
Idaho Power Company and subsidiaries (IPC). At that time
ownership interests in two of IPC's subsidiaries were transferred
to IDACORP at book value. IPC's financial statements include the
following amounts attributable to the transferred subsidiaries
for the periods prior to October 1, 1998:
As of/Year Ended
December 31,
1998 1997
(Thousands of
Dollars)
Total assets $ - $31,369
Net assets - 23,311
Net income 3,024 2,057
On January 1, 2000 IPC's ownership interests in two additional
subsidiaries were transferred to IDACORP at book value. IPC's
financial statements include the following amounts attributable
to these transferred subsidiaries for the periods prior to
January 1, 2000:
As of/Year Ended
December 31,
1999 1998 1997
(Thousands of Dollars)
Total assets $107,996 $90,029 $69,294
Net assets 22,090 19,706 15,984
Net income 2,385 2,216 3,362
Except as modified below, the Notes to the Consolidated Financial
Statements of IDACORP included in this 1999 Annual Report on Form
10-K are incorporated herein by reference insofar as they relate
to Idaho Power Company.
Note 1 - Summary of Significant Accounting Policies
Note 3 - Common Stock
Note 4 - Preferred Stock of Idaho Power Company
Note 5 - Long-Term Debt
Note 7 - Notes Payable
Note 8 - Commitments and Contingent Liabilities
Note 9 - Benefit Plans
Note 10 - Electric Plant in Service and Jointly-Owned
Projects
Note 1 - Derivative Financial Instruments
The following table shows a summary of the notional amounts of
IPC's forward exposure as of December 31, 1999. The maximum term
related to any forward position is two years.
Electricity
MWh's
Payable 4,739
Receivable 6,079
The following table displays the fair value of IPC's energy
marketing assets and liabilities (all electricity) at December
31, 1999, and the average values for the year ended December 31,
1999 (in thousands of dollars):
1999 End of Year Balance 1999 Average Balance
Assets Liabilities Assets Liabilities
$ 29,096 $ 25,594 $ 40,450 $ 43,320
The gain in fair value of energy trading contract positions
(including electricity forwards, futures, options and swaps)
included in income before income taxes for the year ended
December 31, 1999 was $23.2 million.
Note 2 - Income Taxes
IPC has settled Federal and Idaho tax liabilities on all open
years through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued.
A reconciliation between the statutory federal income tax rate
and the effective rate is as follows:
1999 1998 1997
(Thousands of Dollars)
Computed income taxes based
on statutory federal
income tax rate $ 50,077 $ 49,344 $ 48,561
Change in taxes resulting
from:
Investment tax credits (3,032) (2,934) (2,887)
Repair allowance (2,800) (2,800) (2,800)
Settlement of prior
years tax returns (478) (1,965) 23
Current state income
taxes 5,833 6,309 3,587
Depreciation 7,292 5,237 5,766
Affordable housing tax
credits (9,529) (6,880) (4,519)
Other (1,813) (1,246) (1,259)
Total provision for federal
and state income taxes $ 45,550 $ 45,065 $ 46,472
Effective tax rate 31.8% 32.0% 33.5%
The provision for income taxes consists of the following:
1999 1998 1997
(Thousand of Dollars)
Income taxes currently payable:
Federal $ 38,169 $ 45,909 $ 35,038
State 9,128 9,283 5,456
Total 47,297 55,192 40,494
Income taxes deferred - Net
of amortization:
Federal 2,246 (8,006) 6,717
State (2,030) (1,321) 348
Total 216 (9,327) 7,065
Investment tax credits:
Deferred 1,069 2,134 1,800
Restored (3,032) (2,934) (2,887)
Total (1,963) (800) (1,087)
Total provision for income
taxes $ 45,550 $ 45,065 $ 46,472
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
1999 1998 1997
(Thousands of Dollars)
Deferred tax assets:
Regulatory liabilities $ 33,817 $ 28,075 $ 34,072
Advances for construction 9,646 10,401 18,665
Other 18,890 20,457 16,536
Total 62,353 58,933 69,273
Deferred tax liabilities:
Electric plant 249,597 247,270 251,938
Regulatory assets 215,675 204,430 201,685
Conservation programs 17,396 16,866 14,377
Other 9,501 13,600 28,173
Total 492,169 482,166 496,173
Net deferred tax liabilities $429,816 $423,233 $426,900
Note 6 - Fair Value of Financial Instruments
The estimated fair value of the Company's financial instruments
has been determined by the Company using available market
information and appropriate valuation methodologies. The use of
different market assumptions and/or estimation methodologies may
have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued
are reported at their carrying value as these are a reasonable
estimate of their fair value. The estimated fair values for long-
term debt and investments are based upon quoted market prices of
the same or similar issues or discounted cash flow analyses as
appropriate.
The total estimated fair value of the Company's debt was
approximately $898.1 million in 1999, $877.4 million in 1998,
and $801.8 million in 1997. Included in investments and other
property were financial instruments totaling $11.9 million in
1999, $0.0 in 1998, and $16.5 million in 1997. Estimated fair
value of these instruments was $11.8 million in 1999, $0.0 in
1998, and $19.9 million in 1997.
Note 11 - Industry Segment Information
IPC is predominantly a one operating segment company with its
regulated electric operations being the most dominant segment.
IPC's primary business is the generation, transmission,
distribution, purchase and sale of electricity. The Company's
primary non-utility segments involve electricity trading and
renewable energy products.
The following table summarizes the segment information for IPC's
regulated electric operations and the total of all other
segments, and reconciles this information to total enterprise
amounts:
Regulated
Electric Consolidated
Operations Other Total
(Thousands of Dollars)
1999
Revenues $ 658,336 $ - $ 658,336
Income from operations 172,458 - 172,458
Other income 5,120 26,122 31,242
Interest expense 56,679 3,943 60,622
Income before income
taxes 120,899 22,179 143,078
Income taxes 46,395 (845) 45,550
Net income 74,504 23,024 97,528
Total assets 2,355,907 203,467 2,559,374
Expenditures for long-
lived assets 112,772 22,685 135,457
1998
Revenues $ 756,410 $ - $ 756,410
Income from operations 180,584 - 180,584
Other income 5,909 14,184 20,093
Interest expense 56,646 3,047 59,693
Income before income
taxes 135,505 5,479 140,984
Income taxes 47,552 (2,487) 45,065
Net income 87,953 7,966 95,919
Total assets 2,251,077 170,713 2,421,790
Expenditures for long-
lived assets 91,803 19,197 111,000
1997
Revenues $ 605,183 $ - $ 605,183
Income from operations 180,731 - 180,731
Other income 3,894 14,379 18,273
Interest expense 57,653 2,605 60,258
Income before income
taxes 132,148 6,598 138,746
Income taxes 47,618 (1,146) 46,472
Net income 84,530 7,744 92,274
Total assets 2,272,752 179,064 2,451,816
Expenditures for long-
lived assets 98,219 17,457 115,676
Substantially all of the Company's revenues come from the sale of
electricity and related services, predominately in the United
States. The Company also trades electricity and sells renewable
energy products and other miscellaneous services. Revenues from
these operations are not significant.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowner of
Idaho Power Company
Boise, Idaho
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Idaho Power Company and its
subsidiaries as of December 31, 1999, 1998 and 1997, and the
related consolidated statements of income, cash flows, retained
earnings, and comprehensive income for the years then ended. Our
audits also included the consolidated financial statement
schedule listed in the Index at Item 8. These financial
statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Idaho
Power Company and subsidiaries at December 31, 1999, 1998 and
1997, and the results of their operations and their cash flows
for the years then ended in conformity with generally accepted
accounting principles. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents
fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
January 31, 2000
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1999, 1998 and 1997 (in thousands of dollars, except for per
share amounts). In the opinion of the Companies, all adjustments
necessary for a fair statement of such amounts for such periods
have been included. The results of operations for the interim
periods are not necessarily indicative of the results to be
expected for the full year. Accordingly, earnings information for
any three-month period should not be considered as a basis for
estimating operating results for a full fiscal year. Amounts are
based upon quarterly statements and the sum of the quarters may not
equal the annual amount reported.
IDACORP, INC. Quarter Ended
March 31 June 30 September 30 December 31
1999
Revenues $174,149 $165,072 $161,978 $157,136
Income from
operations 59,829 39,724 39,942 32,963
Income taxes 16,700 10,525 10,574 7,874
Net income 29,501 21,242 22,019 18,588
Earnings per share
of common stock 0.78 0.56 0.59 0.49
1998
Revenues $170,913 $167,132 $230,200 $188,164
Income from
operations 55,769 39,097 44,037 41,681
Income taxes 13,125 9,213 12,392 9,900
Net income 28,050 20,351 22,305 18,468
Earnings per share
of common stock 0.75 0.54 0.59 0.49
1997
Revenues $145,735 $147,133 $159,702 $152,614
Income from
operations 58,459 41,019 41,889 39,365
Income taxes 16,361 9,126 10,715 10,270
Net income 28,986 19,377 19,719 19,018
Earnings per share
of common stock 0.77 0.52 0.52 0.51
Idaho Power Company Quarter Ended
March 31 June 30 September 30 December 31
1999
Revenues $174,149 $165,072 $161,978 $157,136
Income from
operations 59,829 39,724 39,942 32,963
Income taxes 16,582 10,479 10,419 8,071
Net income 30,784 22,796 23,371 20,576
Dividends on
preferred stock 1,368 1,352 1,401 1,451
Earnings on common
stock 29,416 21,444 21,970 19,125
1998
Revenues $170,913 $167,132 $230,200 $188,164
Income from
operations 55,769 39,097 44,037 41,681
Income taxes 13,125 9,213 12,392 10,335
Net income 29,455 21,768 23,715 20,979
Dividends on
preferred stock 1,405 1,417 1,410 1,426
Earnings on common
stock 28,050 20,351 22,305 19,553
1997
Revenues $145,735 $147,133 $159,702 $152,614
Income from
operations 58,459 41,019 41,889 39,365
Income taxes 16,361 9,126 10,715 10,270
Net income 30,380 20,042 21,141 20,715
Dividends on
preferred stock 1,394 665 1,422 1,696
Earnings on common
stock 28,986 19,377 19,719 19,018
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrants will file a
definitive proxy statement pursuant to Regulation 14A, which
involves the election of Directors, with the Commission within 120
days after the close of the fiscal year portions of which are
hereby incorporated by reference (except for information with
respect to executive officers which is set forth in Part I hereof).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM
8-K
(a) Please refer to Item 8, "Financial Statements and
Supplementary Data" for a complete listing of all consolidated
financial statements and financial statement schedules.
(b) Reports on SEC Form 8-K. The following Report on Form 8-K was
filed for the three months ended December 31, 1999
Items Reported Date of Report Filed by
Item 7 - Financial November 17,1999 IPC
Statements and Exhibits
(c) Exhibits.
*Previously Filed and Incorporated Herein by Reference
Exhibit File Number As
Exhibit
*2 333-48031 2 Agreement and Plan of Exchange
between IDACORP, Inc., and IPC dated
as of February 2, 1998.
*3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation
of IPC as filed with the Secretary
of State of Idaho on June 30, 1989.
*3(a)(i) 33-65720 4(a)(ii) Statement of Resolution Establishing
Terms of Flexible Auction Series A,
Serial Preferred Stock, Without Par
Value (cumulative stated value of
$100,000 per share) of IPC, as filed
with the Secretary of State of Idaho
on November 5, 1991.
*3(a)(ii) 33-65720 4(a)(iii) Statement of Resolution Establishing
Terms of 7.07% Serial Preferred
Stock, Without Par Value (cumulative
stated value of $100 per share) of
IPC, as filed with the Secretary of
State of Idaho on June 30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation of IPC
adopted by Shareholders on May 1,
1991.
*3(c) 1-3198 4(b) By-laws of IPC amended on September
Form 10-Q 9, 1999, and presently in effect.
*3(d) 33-56071 3(d) Articles of Share Exchange, as filed
with the Secretary of State of Idaho
on September 29, 1998.
*3(e) 333-64737 3.1 Articles of Incorporation of
IDACORP, Inc.
*3(f) 333-64737 3.2 Articles of Amendment to Articles of
Incorporation of IDACORP, Inc. as
filed with the Secretary of State of
Idaho on March 9, 1998.
*3(g) 333-00139 3(b) Articles of Amendment to Articles of
Incorporation of IDACORP, Inc.
creating A Series Preferred Stock,
without par value, as filed with the
Secretary of State of Idaho on
September 17, 1998.
*3(h) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as
Form 10-Q of July 8, 1999.
for 6/30/99
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as
of October 1, 1937, between IPC and
Bankers Trust Company and
R. G. Page, as Trustees.
*4(a)(ii) IPC Supplemental Indentures to
Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 1, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
*4(b) Instruments relating to IPC American
Falls bond guarantee. (see Exhibit
10(c)).
*4(c) 33-65720 4(f) Agreement of IPC to furnish certain
debt instruments.
*4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated
March 10, 1989, between Idaho Power
Company, a Maine Corporation, and
Idaho Power Migrating Corporation.
*4(e) 1-14465 4 Rights Agreement, dated as of
Form 8-K September 10, 1998, between IDACORP,
dated Inc. and the Bank of New York as
September Rights Agent.
15, 1998
*10(a) 2-49584 5(b) Agreements, dated September 22,
1969, between IPC and Pacific
Power & Light Company relating to
the operation, construction and
ownership of the Jim Bridger
Project.
*10(a)(i) 2-51762 5(c) Amendment, dated February 1, 1974,
relating to operation agreement
filed as Exhibit 10(a).
*10(b) 2-49584 5(c) Agreement, dated as of October 11,
1973, between IPC and Pacific
Power & Light Company.
*10(c) 33-65720 10(c) Guaranty Agreement, dated March 1,
1990, between IPC and West One Bank,
as Trustee, relating to $21,425,000
American Falls Replacement Dam Bonds
of the American Falls Reservoir
District, Idaho.
*10(d) 2-62034 5(r) Guaranty Agreement, dated as of
August 30, 1974, between IPC and
Pacific Power & Light Company.
*10(e) 2-56513 5(i) Letter Agreement, dated January 23,
1976, between IPC and Portland
General Electric Company.
*10(e)(i) 2-62034 5(s) Agreement for Construction,
Ownership and Operation of the
Number One Boardman Station on Carty
Reservoir, dated as of October 15,
1976, between Portland General
Electric Company and IPC.
*10(e)(ii) 2-62034 5(t) Amendment, dated September 30, 1977,
relating to agreement filed as
Exhibit 10(e).
*10(e)(iii) 2-62034 5(u) Amendment, dated October 31, 1977,
relating to agreement filed as
Exhibit 10(e).
*10(e)(iv) 2-62034 5(v) Amendment, dated January 23, 1978,
relating to agreement filed as
Exhibit 10(e).
*10(e)(v) 2-62034 5(w) Amendment, dated February 15, 1978,
relating to agreement filed as
Exhibit 10(e).
*10(e)(vi) 2-68574 5(x) Amendment, dated September 1, 1979,
relating to agreement filed as
Exhibit 10(e).
*10(f) 2-68574 5(z) Participation Agreement, dated
September 1, 1979, relating to the
sale and leaseback of coal handling
facilities at the Number One
Boardman Station on Carty Reservoir.
*10(g) 2-64910 5(y) Agreements for the Operation,
Construction and Ownership of the
North Valmy Power Plant Project,
dated December 12, 1978, between
Sierra Pacific Power Company and
IPC.
*10(h)(i) 1 1-3198 10(n)(i) The Revised Security Plan for Senior
Form 10-K Management Employees - a non-
for 1994 qualified, deferred compensation
plan effective August 1, 1996..
*10(h)(ii) 1 1-3198 10(n)(ii) The Executive Annual Incentive Plan
Form 10-K for senior management employees of
for 1994 IPC effective January 1, 1995.
*10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for
Form 10-K officers and key executives of
for 1994 IDACORP, Inc. and IPC effective July
1, 1994.
10(h)(iv) 1 1-14465 10(h)(iv) The Revised Security Plan for Board
1-3198 of Directors - a non-qualified,
Form 10-K deferred compensation plan effective
for 1998 August 1, 1996, revised March 2,
1999.
*10(h)(v) 1-3198 10(e) IDACORP, Inc. Non-Employee Directors
Form 10-Q Stock Compensation Plan as of May
for 6/30/99 17, 1999.
*10(h)(vi) 1-3198 10(y) Executive Employment Agreement dated
Form 10-K November 20, 1996 between IPC and
for 1997 Richard R. Riazzi.
*10(h)(vii) 1-3198 10(g) Executive Employment Agreement dated
Form 10-Q April 12, 1999 between IPC and
for 6/30/99 Marlene Williams.
*10(h)(viii) 1-14465 10(h) Agreement between IDACORP, Inc. and
Form 10-Q Jan B. Packwood, J. LaMont Keen,
for 9/30/99 James C. Miller, Richard Riazzi,
Darrel T. Anderson, Bryan Kearney,
Cliff N. Olson, Robert W. Stahman
and Marlene K. Williams.
10(h)(ix) 1 IDACORP, Inc. 2000 Long-Term
Incentive and Compensation Plan.
*10(i) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of Idaho
and IPC relating to IPC's Swan Falls
and Snake River water rights.
*10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and IPC
relating to the agreement filed as
Exhibit 10(i).
*10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October
25, 1984, between the State of Idaho
and IPC relating to the agreement
filed as Exhibit 10(i).
*10(j) 33-65720 10(m) Agreement Regarding the Ownership,
Construction, Operation and
Maintenance of the Milner
Hydroelectric Project (FERC No.
2899), dated January 22, 1990,
between IPC and the Twin Falls Canal
Company and the Northside Canal
Company Limited.
*10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February
10, 1992, between IPC and New York
Life Insurance Company, as Note
Purchaser, relating to $11,700,000
Guaranteed Notes due 2017 of Milner
Dam Inc.
12 Statement Re: Computation of Ratio
of Earnings to Fixed Charges.
(IDACORP, Inc.)
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges. (IDACORP, Inc.)
12(b) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements. (IDACORP, Inc.)
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements. (IDACORP,
Inc.)
12(d) Statement Re: Computation of Ratio
of Earnings to Fixed Charges. (IPC)
12(e) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges. (IPC)
12(f) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements. (IPC)
12(g) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements. (IPC)
21 Subsidiaries of IDACORP, Inc. and
IPC.
23 Independent Auditors' Consent.
27(a) Financial Data Schedule for IDACORP,
Inc.
27(b) Financial Data Schedule for IPC.
IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1999, 1998 and 1997
Column A Column B Column C Column D Column E
Additions
Charged
Balance Charged (Credited) Balance
At to to Other Deductions At End
Classification Beginning Income Accounts (1) Of
Of Period Period
(Thousands of Dollars)
1999:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 1,397 $ - $ 3,162(2) $ 3,162 $ 1,397
Other Reserves:
Rate refunds $ 5,356 $10,543 $ - $ 7,006 $ 8,893
Injuries and
damages reserve $ 1,500 $ - $ - $ - $ 1,500
Miscellaneous
operating
reserves $ 6,907 $ 3,242 $ - $ 1,676 $ 8,473
1998:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 1,397 $ - $ 3,299(2) $ 3,299 $ 1,397
Other Reserves:
Rate refunds $ 8,740 $ 4,188 $ - $ 7,572 $ 5,356
Injuries and damages
reserve $ 1,500 $ - $ - $ - $ 1,500
Miscellaneous
operating
reserves $ 8,388 $ 512 $ - $ 1,993 $ 6,907
1997:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 1,394 $ - $ 3,384(2) $ 3,381 $ 1,397
Other Reserves:
Rate refunds $ 4,873 $ 8,740 $ - $ 4,873 $ 8,740
Injuries and damages
reserve $ 1,500 $ - $ - $ - $ 1,500
Miscellaneous
operating
reserves $ 1,774 $ 592 $ 7,245 $ 1,223 $8,388
Notes: (1) Represents deductions from the reserves for purposes
for which the reserves were created.
(2) Represents collections of accounts previously written
off.
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1999, 1998 and 1997
Amounts for Idaho Power Company are same as the above Schedule II
for IDACORP, Inc.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has caused this
report to be signed on its behalf by the undersigned, thereunto
duly authorized.
IDACORP, Inc.
(Registrant)
March 16, 2000 By: /s/Jan B. Packwood
Jan B. Packwood
President, Chief
Executive Officer and
Director
Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
By: /s/ Jon H. Miller /s/ Chairman of the Board March 16,
2000
Jon H. Miller
By: /s/ Jan B. Packwood /s/ President and Chief "
Executive
Jan B. Packwood Officer and Director
By: /s/ J. LaMont Keen /s/ Senior Vice President, "
Administration
J. LaMont Keen and Chief Financial
Officer
(Principal Financial
Officer)
By: /s/ Darrel T. Anderson /s/ Vice President, Finance "
and Treasurer
Darrel T. Anderson (Principal Accounting
Officer)
By: /s/ Rotchford L. Barker By: /s/ Jack K. Lemley "
Rotchford L. Barker Jack K. Lemley
Director Director
By: /s/ Robert D. Bolinder By: /s/ Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By: /s/ Roger L. Breezley By: /s/ Peter S. O'Neill "
Roger L. Breezley Peter S. O'Neill
Director Director
By: /s/ John B. Carley By: /s/ Robert A. Tinstman "
John B. Carley Robert A. Tinstman
Director Director
By: /s/ Peter T. Johnson "
Peter T. Johnson
Director
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has caused this
report to be signed on its behalf by the undersigned, thereunto
duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 16, 2000 By: /s/Jan B. Packwood
Jan B. Packwood
President, Chief Executive
Officer and Director
Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
By: /s/ Jon H. Miller /s/ Chairman of the Board March 16,
2000
Jon H. Miller
By: /s/ Jan B. Packwood /s/ President and Chief "
Executive
Jan B. Packwood Officer and Director
By: /s/ J. LaMont Keen /s/ Senior Vice President, "
Administration
J. LaMont Keen and Chief Financial
Officer
(Principal Financial
Officer)
By: /s/ Darrel T. Anderson /s/ Vice President, Finance "
and Treasurer
Darrel T. Anderson (Principal Accounting
Officer)
By: /s/ Rotchford L. Barker By: /s/ Jack K. Lemley "
Rotchford L. Barker Jack K. Lemley
Director Director
By: /s/ Robert D. Bolinder By: /s/ Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By: /s/ Roger L. Breezley By: /s/ Peter S. O'Neill "
Roger L. Breezley Peter S. O'Neill
Director Director
By: /s/ John B. Carley By: /s/ Robert A. Tinstman "
John B. Carley Robert A. Tinstman
Director Director
By: /s/ Peter T. Johnson "
Peter T. Johnson
Director
EXHIBIT INDEX
Exhibit Page
Number Number
10(h)(ix) IDACORP, Inc. 2000 Long-Term
Incentive and Compensation
Plan.
12 Statements Re: Computation of
Ratio of Earnings to Fixed
Charges. (IDACORP, Inc.)
12(a) Statements Re: Computation of
Supplemental Ratio of
Earnings to Fixed Charges.
(IDACORP, Inc.)
12(b) Statements Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(c) Statements Re: Computation of
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(d) Statements Re: Computation of
Ratio of Earnings to Fixed
Charges. (IPC)
12(e) Statements Re: Computation of
Supplemental Ratio of
Earnings to Fixed Charges.
(IPC)
12(f) Statements Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements. (IPC)
12(g) Statements Re: Computation of
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements. (IPC)
21 Subsidiaries of IDACORP, Inc.
and IPC
23 Independent Auditors'
Consent.
27(a) Financial Data Schedule for
IDACORP, Inc.
27(b) Financial Data Schedule for
IPC
_______________________________
1 Compensatory plan
1
1 Compensatory plan
1
-1-
Exhibit 10(h)(ix)1
IDACORP, INC.
2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN
1. Article Establishment, Purpose and Duration
1.1 Establishment of the Plan. IDACORP, Inc., an Idaho
corporation (hereinafter referred to as the "Company"), hereby
establishes an incentive and compensation plan for officers, key
employees and directors, to be known as the "IDACORP, Inc. 2000
Long-Term Incentive and Compensation Plan" (hereinafter referred
to as the "Plan"), as set forth in this document. The Plan
permits the grant of nonqualified stock options (NQSO), incentive
stock options (ISO), stock appreciation rights (SAR), restricted
stock, restricted stock units, performance units, performance
shares and other awards.
The Plan shall become effective when approved by the
shareholders at the 2000 Annual Meeting of Shareholders (the
"Effective Date") and shall remain in effect as provided in
Section 1.3 herein.
1.1 Purpose of the Plan. The purpose of the Plan is
to promote the success and enhance the value of the Company by
linking the personal interests of Participants to those of
Company shareholders and customers.
The Plan is further intended to provide flexibility to the
Company in its ability to motivate, attract and retain the
services of Participants upon whose judgment, interest and
special effort the successful conduct of its operations is
largely dependent.
1.1 Duration of the Plan. The Plan shall commence on
the Effective Date, as described in Section 1.1 herein, and shall
remain in effect, subject to the right of the Board of Directors
to terminate the Plan at any time pursuant to Article 15 herein,
until all Shares subject to it shall have been purchased or
acquired according to the Plan's provisions.
1. Article Definitions
Whenever used in the Plan, the following terms shall have
the meanings set forth below and, when such meaning is intended,
the initial letter of the word is capitalized:
1.1 Award means, individually or collectively, a grant
under the Plan of NQSOs, ISOs, SARs, Restricted Stock, Restricted
Stock Units, Performance Units, Performance Shares or any other
type of award permitted under Article 10 of the Plan.
1.1 Award Agreement means an agreement entered into by
each Participant and the Company, setting forth the terms and
provisions applicable to an Award granted to a Participant under
the Plan.
1.1 Base Value of an SAR shall have the meaning set
forth in Section 7.1 herein.
1.2 Board or Board of Directors means the Board of
Directors of the Company.
1.1 Change in Control means the earliest of the
following to occur:
(a) the public announcement by the Company or by any
person (which shall not include the Company, any subsidiary of
the Company or any employee benefit plan of the Company or of any
subsidiary of the Company) ("Person") that such Person, who or
which, together with all Affiliates and Associates (within the
meanings ascribed to such terms in Rule 12b-2 of the Exchange
Act) of such Person, shall be the beneficial owner of twenty
percent (20%) or more of the voting stock then outstanding;
(a) the commencement of, or after the first public
announcement of any Person to commence, a tender or exchange
offer the consummation of which would result in any Person
becoming the beneficial owner of voting stock aggregating thirty
percent (30%) or more of the then outstanding voting stock;
(a) the announcement of any transaction relating to the
Company required to be described pursuant to the requirements of
Item 6(e) of Schedule 14A of Regulation 14A of the Securities and
Exchange Commission under the Exchange Act;
(a) a proposed change in the constituency of the Board
such that, during any period of two (2) consecutive years,
individuals who at the beginning of such period constitute the
Board cease for any reason to constitute at least a majority
thereof, unless the election or nomination for election by the
shareholders of the Company of each new director was approved by
a vote of at least two-thirds (2/3) of the directors then still
in office who were members of the Board at the beginning of the
period;
(a) the Company enters into an agreement of merger,
consolidation, share exchange or similar transaction with any
other corporation other than a transaction which would result in
the Company's voting stock outstanding immediately prior to the
consummation of such transaction continuing to represent (either
by remaining outstanding or by being converted into voting stock
of the surviving entity) at least two-thirds of the combined
voting power of the Company's or such surviving entity's
outstanding voting stock immediately after such transaction;
(a) the Board approves a plan of liquidation or
dissolution of the Company or an agreement for the sale or
disposition by the Company (in one transaction or a series of
transactions) of all or substantially all of the Company's assets
to a person or entity which is not an affiliate of the Company
other than a transaction(s) for the purpose of dividing the
Company's assets into separate distribution, transmission or
generation entities or such other entities as the Company may
determine; or
(a) any other event which shall be deemed by a majority
of the Executive Committee of the Board to constitute a "Change
in Control."
1.1 Code means the Internal Revenue Code of 1986, as
amended from time to time.
1.1 Committee means the committee, as specified in
Article 3, appointed by the Board to administer the Plan with
respect to Awards.
1.1 Company means IDACORP, Inc., an Idaho corporation,
or any successor thereto as provided in Article 17 herein.
1.1 Covered Employee means any Participant who would
be considered a "covered employee" for purposes of Section 162(m)
of the Code.
1.1 Director means any individual who is a member of
the Board of Directors of the Company.
1.1 Disability means the continuous inability of an
Employee because of illness or injury to engage in any occupation
or employment for wage or profit with the Company or any other
employer (including self-employment) for which he is reasonably
qualified by education, training or experience. An Employee will
not be considered disabled during any period unless he is under
the regular care and attendance of a duly qualified physician.
1.1 Dividend Equivalent means, with respect to Shares
subject to an Award, a right to be paid an amount equal to
dividends declared on an equal number of outstanding Shares.
1.1 Eligible Person means a Person who is eligible to
participate in the Plan, as set forth in Section 5.1 herein.
1.1 Employee means an individual who is paid on the
payroll of the Company or of the Company's Subsidiaries, who is
not covered by any collective bargaining agreement to which the
Company or any of its Subsidiaries is a party, and is classified
in the payroll system as a regular full-time, part-time or
temporary employee. For purposes of the Plan, transfer of
employment of a Participant between the Company and any one of
its Subsidiaries (or between Subsidiaries) shall not be deemed a
termination of employment.
1.1 Exchange Act means the Securities Exchange Act of
1934, as amended from time to time, or any successor act thereto.
1.1 Exercise Period means the period during which an
SAR or Option is exercisable, as set forth in the related Award
Agreement.
1.1 Fair Market Value means the average of the high
and low sale prices as reported in the consolidated transaction
reporting system, or, if there was no such sale on the relevant
date, then on the last previous day on which a sale was reported.
1.1 Freestanding SAR means an SAR that is not a Tandem
SAR.
1.1 Incentive Stock Option or ISO means an option to
purchase Shares, granted under Article 6 herein, which is
designated as an Incentive Stock Option and satisfies the
requirements of Section 422 of the Code.
1.1 Nonqualified Stock Option or NQSO means an option
to purchase Shares, granted under Article 6 herein, which is not
intended to be an Incentive Stock Option under Section 422 of the
Code.
1.1 Option means an Incentive Stock Option or a
Nonqualified Stock Option.
1.1 Option Exercise Price means the price at which a
Share may be purchased by a Participant pursuant to an Option, as
determined by the Committee and set forth in the Option Award
Agreement.
1.1 Participant means an Eligible Person who has
outstanding an Award granted under the Plan.
1.1 Performance Goals means the performance goals
established by the Committee, which shall be based on one or more
of the following measures: sales or revenues, earnings per
share, shareholder return and/or value, funds from operations,
operating income, gross income, net income, cash flow, return on
equity, return on capital, earnings before interest, operating
ratios, stock price, customer satisfaction, accomplishment of
mergers, acquisitions, dispositions or similar extraordinary
business transactions, profit returns and margins, financial
return ratios and/or market performance. Performance goals may
be measured solely on a corporate, subsidiary or business unit
basis, or a combination thereof. Performance goals may reflect
absolute entity performance or a relative comparison of entity
performance to the performance of a peer group of entities or
other external measure.
1.1 Performance Period means the time period during which
Performance Unit/Performance Share Performance Goals must be met.
1.1 Performance Share means an Award described in
Article 9 herein.
1.1 Performance Unit means an Award described in
Article 9 herein.
1.1 Period of Restriction means the period during
which the transfer of Restricted Stock is limited in some way, as
provided in Article 8 herein.
1.1 Person shall have the meaning ascribed to such
term in Section 3(a)(9) of the Exchange Act, as used in Sections
13(d) and 14(d) thereof, including usage in the definition of a
"group" in Section 13(d) thereof.
1.1 Plan means the IDACORP, Inc. 2000 Long-Term
Incentive and Compensation Plan.
1.1 Qualified Restricted Stock means an Award of
Restricted Stock designated as Qualified Restricted Stock by the
Committee at the time of grant and intended to qualify for the
exemption from the limitation on deductibility imposed by Section
162(m) of the Code that is set forth in Section 162(m)(4)(C).
1.1 Qualified Restricted Stock Unit means an Award of
Restricted Stock Units designated as Qualified Restricted Stock
Units by the Committee at the time of grant and intended to
qualify for the exemption from the limitation on deductibility
imposed by Section 162(m) of the Code that is set forth in
Section 162(m)(4)(C).
1.1 Restricted Stock means an Award described in
Article 8 herein.
1.1 Restricted Stock Unit means an Award described
in Article 8 herein.
1.1 Retirement means a Participant's termination
from employment with the Company or a Subsidiary at the
Participant's Early or Normal Retirement Date, as applicable.
(a) Early Retirement Date -- shall mean the
date on which a Participant terminates employment,
if such termination date occurs on or after
Participant's attainment of age fifty-five (55)
but prior to Participant's Normal Retirement Date.
(b) Normal Retirement Date -- shall mean the
date on which the Participant terminates
employment, if such termination date occurs on or
after the Participant attains age sixty-two (62).
1.1 Securities Act means the Securities Act of 1933,
as amended.
1.1 Shares means the shares of common stock, no par
value, of the Company.
1.1 Stock Appreciation Right or SAR means a right,
granted alone or in connection with a related Option, designated
as an SAR, to receive a payment on the day the right is
exercised, pursuant to the terms of Article 7 herein. Each SAR
shall be denominated in terms of one Share.
1.1 Subsidiary means any corporation (other than the
Company) in an unbroken chain of corporations beginning with the
Company if each of the corporations other than the last
corporation in the unbroken chain owns stock possessing 50
percent or more of the total combined voting power of all classes
of stock in one of the other corporations in such chain.
1.1 Tandem SAR means an SAR that is granted in
connection with a related Option, the exercise of which shall
require forfeiture of the right to purchase a Share under the
related Option (and when a Share is purchased under the Option,
the Tandem SAR shall be similarly canceled).
2. Article Administration
1.1 The Committee. The Plan shall be administered by
the Compensation Committee or such other committee (the
"Committee") as the Board of Directors shall select consisting
solely of two or more members of the Board. The members of the
Committee shall be appointed from time to time by, and shall
serve at the discretion of, the Board of Directors.
1.1 Authority of the Committee. The Committee shall
have full power except as limited by law, the Articles of
Incorporation or the Bylaws of the Company, subject to such other
restricting limitations or directions as may be imposed by the
Board and subject to the provisions herein, to determine the
Eligible Persons to receive Awards; to determine the size and
types of Awards; to determine the terms and conditions of such
Awards; to construe and interpret the Plan and any agreement or
instrument entered into under the Plan; to establish, amend or
waive rules and regulations for the Plan's administration; and
(subject to the provisions of Article 15 herein) to amend the
terms and conditions of any outstanding Award. Further, the
Committee shall make all other determinations which may be
necessary or advisable for the administration of the Plan. As
permitted by law, the Committee may delegate its authorities as
identified hereunder.
1.1 Restrictions on Distribution of Shares and Share
Transferability. Notwithstanding any other provision of the
Plan, the Company shall have no liability to deliver any Shares
or benefits under the Plan unless such delivery would comply with
all applicable laws (including, without limitation, the
Securities Act) and applicable requirements of any securities
exchange or similar entity and unless the Participant's tax
obligations have been satisfied as set forth in Article 16. The
Committee may impose such restrictions on any Shares acquired
pursuant to Awards under the Plan as it may deem advisable,
including, without limitation, restrictions to comply with
applicable Federal securities laws, with the requirements of any
stock exchange or market upon which such Shares are then listed
and/or traded and with any blue sky or state securities laws
applicable to such Shares.
1.1 Decisions Binding. All determinations and
decisions made by the Committee pursuant to the provisions of the
Plan and all related orders or resolutions of the Board shall be
final, conclusive and binding on all persons, including the
Company, its shareholders, Eligible Persons, Employees,
Participants and their estates and beneficiaries.
1.1 Costs. The Company shall pay all costs of
administration of the Plan.
1. Article Shares Subject to the Plan
1.1 Number of Shares. Subject to Section 4.2 herein,
the maximum number of Shares available for grant under the Plan
shall be 750,000. Shares underlying lapsed or forfeited Awards,
or Awards that are not paid in Shares, may be reused for other
Awards; if the Option Exercise Price is satisfied by tendering
Shares, only the number of Shares issued net of the Shares
tendered shall be deemed issued under the Plan. Shares granted
pursuant to the Plan may be (i) authorized but unissued Shares of
common stock, (ii) treasury shares or (iii) Shares purchased on
the open market.
1.2 Adjustments in Authorized Shares and Awards. In
the event of any merger, reorganization, consolidation,
recapitalization, liquidation, stock dividend, split-up, spin-
off, stock split, reverse stock split, share combination, share
exchange or other change in the corporate structure of the
Company affecting the Shares, such adjustment shall be made in
the outstanding Awards, the number and class of Shares which may
be delivered under the Plan, and in the number and class of
and/or price of Shares subject to outstanding Awards granted
under the Plan, as may be determined to be appropriate and
equitable by the Committee, in its sole discretion, to prevent
dilution or enlargement of rights. Notwithstanding the
foregoing, (i) each such adjustment with respect to an Incentive
Stock Option shall comply with the rules of Section 424(a) of the
Code and (ii) in no event shall any adjustment be made which
would render any Incentive Stock Option granted hereunder to be
other than an incentive stock option for purposes of Section 422
of the Code. In no event shall the Committee have the right to
amend an outstanding Option Award for the sole purpose of
reducing the exercise price thereof.
1.1 Individual Limitations. Subject to Section 4.2
above, (i) the total number of Shares with respect to which
Options or SARs may be granted in any calendar year to any
Covered Employee shall not exceed 100,000 Shares; (ii) the total
number of Qualified Restricted Stock Shares or Qualified
Restricted Stock Units that may be granted in any calendar year
to any Covered Employee shall not exceed 100,000 Shares or Units,
as the case may be; (iii) the total number of Performance Shares
or Performance Units that may be granted in any calendar year to
any Covered Employee shall not exceed 100,000 Shares or Units, as
the case may be; (iv) the total number of Shares that are
intended to qualify for deduction under Section 162(m) of the
Code granted pursuant to Article 10 herein in any calendar year
to any Covered Employee shall not exceed 100,000 Shares; (v) the
total cash Award that is intended to qualify for deduction under
Section 162(m) of the Code that may be paid pursuant to Article
10 herein in any calendar year to any Covered Employee shall not
exceed $300,000; and (vi) the aggregate number of Dividend
Equivalents that are intended to qualify for deduction under
Section 162(m) of the Code that a Covered Employee may receive in
any calendar year shall not exceed 400,000.
1. Article Eligibility and Participation
1.1 Eligibility. Persons eligible to participate in
the Plan ("Eligible Persons") include all officers, key employees
and directors of the Company and its Subsidiaries, as determined
by the Committee.
1.1 Actual Participation. Subject to the provisions of
the Plan, the Committee may, from time to time, select from all
Eligible Persons those to whom Awards shall be granted.
1. Article Stock Options
1.1 Grant of Options. Subject to the terms and
conditions of the Plan, Options may be granted to an Eligible
Person at any time and from time to time, as shall be determined
by the Committee.
The Committee shall have complete discretion in determining
the number of Shares subject to Options granted to each Eligible
Person (subject to Article 4 herein) and, consistent with the
provisions of the Plan, in determining the terms and conditions
pertaining to such Options. The Committee may grant ISOs, NQSOs
or a combination thereof.
1.1 Option Award Agreement. Each Option grant shall
be evidenced by an Option Award Agreement that shall specify the
Option Exercise Price, the term of the Option, the number of
Shares to which the Option pertains, the Exercise Period and such
other provisions as the Committee shall determine, including but
not limited to any rights to Dividend Equivalents. The Option
Award Agreement shall also specify whether the Option is intended
to be an ISO or a NQSO.
1.1 Exercise of and Payment for Options. Options
granted under the Plan shall be exercisable at such times and
shall be subject to such restrictions and conditions as the
Committee shall in each instance approve.
A Participant may exercise an Option at any time during the
Exercise Period. Options shall be exercised by the delivery of a
written notice of exercise to the Company, setting forth the
number of Shares with respect to which the Option is to be
exercised, accompanied by provision for full payment for the
Shares.
The Option Exercise Price shall be payable: (a) in cash or
its equivalent, (b) by tendering previously acquired Shares
having an aggregate Fair Market Value at the time of exercise
equal to the total Option Exercise Price, (c) by broker-assisted
cashless exercise or (d) by a combination of (a), (b) and/or (c).
1.1 Termination. Each Option Award Agreement shall
set forth the extent to which the Participant shall have the
right to exercise the Option following termination of the
Participant's employment with or service on the Board of the
Company and its Subsidiaries. Such provisions shall be
determined in the sole discretion of the Committee (subject to
applicable law), shall be included in the Option Award Agreement
entered into with Participants, need not be uniform among all
Options granted pursuant to the Plan or among Participants and
may reflect distinctions based on the reasons for termination.
1.1 Transferability of Options. Except as otherwise
determined by the Committee, all Options granted to a Participant
under the Plan shall be exercisable during his or her lifetime
only by such Participant, and no Option granted under the Plan
may be sold, transferred, pledged, assigned, or otherwise
alienated or hypothecated, other than by will or by the laws of
descent and distribution. ISOs are not transferable other than
by will or by the laws of descent and distribution.
1. Article Stock Appreciation Rights
1.1 Grant of SARs. Subject to the terms and
conditions of the Plan, an SAR may be granted to an Eligible
Person at any time and from time to time as shall be determined
by the Committee. The Committee may grant Freestanding SARs,
Tandem SARs or any combination of these forms of SARs.
The Committee shall have complete discretion in determining
the number of SARs granted to each Eligible Person (subject to
Article 4 herein) and, consistent with the provisions of the
Plan, in determining the terms and conditions pertaining to such
SARs.
The Base Value of a Freestanding SAR shall equal the Fair
Market Value of a Share on the date of grant of the SAR. The Base
Value of Tandem SARs shall equal the Option Exercise Price of the
related Option.
1.1 SAR Award Agreement. Each SAR grant shall be
evidenced by an SAR Award Agreement that shall specify the number
of SARs granted, the Base Value, the term of the SAR, the
Exercise Period and such other provisions as the Committee shall
determine.
1.1 Exercise and Payment of SARs. Tandem SARs may be
exercised for all or part of the Shares subject to the related
Option upon the surrender of the right to exercise the equivalent
portion of the related Option. A Tandem SAR may be exercised
only with respect to the Shares for which its related Option is
then exercisable.
Notwithstanding any other provision of the Plan to the
contrary, with respect to a Tandem SAR granted in connection with
an ISO: (i) the Tandem SAR will expire no later than the
expiration of the underlying ISO; (ii) the value of the payout
with respect to the Tandem SAR may be for no more than one
hundred percent (100%) of the difference between the Option
Exercise Price of the underlying ISO and the Fair Market Value of
the Shares subject to the underlying ISO at the time the Tandem
SAR is exercised; and (iii) the Tandem SAR may be exercised only
when the Fair Market Value of the Shares subject to the ISO
exceeds the Option Exercise Price of the ISO.
Freestanding SARs may be exercised upon whatever terms and
conditions the Committee, in its sole discretion, imposes upon
them.
A Participant may exercise an SAR at any time during the
Exercise Period. SARs shall be exercised by the delivery of a
written notice of exercise to the Company, setting forth the
number of SARs being exercised. Upon exercise of an SAR, a
Participant shall be entitled to receive payment from the Company
in an amount equal to the product of:
(a) the excess of (i) the Fair Market Value of a Share
on the date of exercise over (ii) the Base Value multiplied by
(a) the number of Shares with respect to which the SAR
is exercised.
At the sole discretion of the Committee, the payment to the
Participant upon SAR exercise may be in cash, in Shares of
equivalent value or in some combination thereof.
1.1 Termination. Each SAR Award Agreement shall set
forth the extent to which the Participant shall have the right to
exercise the SAR following termination of the Participant's
employment with or service on the Board of the Company and its
Subsidiaries. Such provisions shall be determined in the sole
discretion of the Committee, shall be included in the SAR Award
Agreement entered into with Participants, need not be uniform
among all SARs granted pursuant to the Plan or among Participants
and may reflect distinctions based on the reasons for
termination.
1.1 Transferability of SARs. Except as otherwise
determined by the Committee, all SARs granted to a Participant
under the Plan shall be exercisable during his or her lifetime
only by such Participant or his or her legal representative, and
no SAR granted under the Plan may be sold, transferred, pledged,
assigned, or otherwise alienated or hypothecated, other than by
will or by the laws of descent and distribution.
1. Article Restricted Stock and Restricted Stock Units
1.1 Grant of Restricted Stock and Restricted Stock
Units. Subject to the terms and conditions of the Plan,
Restricted Stock and/or Restricted Stock Units may be granted to
an Eligible Person at any time and from time to time, as shall be
determined by the Committee.
The Committee shall have complete discretion in determining
the number of shares of Restricted Stock and/or Restricted Stock
Units granted to each Eligible Person (subject to Article 4
herein) and, consistent with the provisions of the Plan, in
determining the terms and conditions pertaining to such Awards.
In addition, the Committee may, prior to or at the time of
grant, designate an Award of Restricted Stock or Restricted Stock
Units as Qualified Restricted Stock or Qualified Restricted Stock
Units, as the case may be, in which event it will condition the
grant or vesting, as applicable, of such Qualified Restricted
Stock or Qualified Restricted Stock Units, as the case may be,
upon the attainment of the Performance Goals selected by the
Committee.
1.1 Restricted Stock/Restricted Stock Unit Award
Agreement. Each grant of Restricted Stock and/or Restricted
Stock Units grant shall be evidenced by a Restricted Stock and/or
Restricted Stock Unit Award Agreement that shall specify the
number of shares of Restricted Stock and/or Restricted Stock
Units granted, the initial value (if applicable), the Period or
Periods of Restriction, and such other provisions as the
Committee shall determine.
1.1 Transferability. Restricted Stock and Restricted
Stock Units granted hereunder may not be sold, transferred,
pledged, assigned, or otherwise alienated or hypothecated until
the end of the applicable Period of Restriction established by
the Committee and specified in the Award Agreement. During the
applicable Period of Restriction, all rights with respect to the
Restricted Stock and Restricted Stock Units granted to a
Participant under the Plan shall be available during his or her
lifetime only to such Participant or his or her legal
representative.
1.1 Certificates. No certificates representing Stock
shall be issued until such time as all restrictions applicable to
such Shares have been satisfied.
1.1 Removal of Restrictions. Restricted Stock shall
become freely transferable by the Participant after the last day
of the Period of Restriction applicable thereto. Once Restricted
Stock is released from the restrictions, the Participant shall be
entitled to receive a certificate. Payment of Restricted Stock
Units shall be made after the last day of the Period of
Restriction applicable thereto. The Committee, in its sole
discretion, may pay Restricted Stock Units in cash or in Shares
(or in a combination thereof), which have an aggregate Fair
Market Value equal to the value of the Restricted Stock Units.
1.1 Voting Rights. During the Period of Restriction,
Participants may exercise full voting rights with respect to the
Restricted Stock.
1.1 Dividends and Other Distributions. Subject to the
Committee's right to determine otherwise at the time of grant,
during the Period of Restriction, Participants shall receive all
regular cash dividends paid with respect to the Shares while they
are so held. All other distributions paid with respect to such
Restricted Stock shall be credited to Participants subject to the
same restrictions on transferability and forfeitability as the
Restricted Stock with respect to which they were paid and shall
be paid to the Participant promptly after the full vesting of
the Restricted Stock with respect to which such distributions
were made.
Rights, if any, to Dividend Equivalents on Restricted
Stock Units shall be established by the Committee at the time of
grant and set forth in the Award Agreement.
1.1 Termination. Each Restricted Stock/Restricted
Stock Unit Award Agreement shall set forth the extent to which
the Participant shall have the right to receive Restricted Stock
and/or a Restricted Stock Unit payment following termination of
the Participant's employment with or service on the Board of the
Company and its Subsidiaries. Such provisions shall be
determined in the sole discretion of the Committee, shall be
included in the Award Agreement entered into with Participants,
need not be uniform among all grants of Restricted
Stock/Restricted Stock Units or among Participants and may
reflect distinctions based on the reasons for termination.
1. Article Performance Units and Performance Shares
1.1 Grant of Performance Units and Performance Shares.
Subject to the terms and conditions of the Plan, Performance
Units and/or Performance Shares may be granted to an Eligible
Person at any time and from time to time, as shall be determined
by the Committee.
The Committee shall have complete discretion in determining
the number of Performance Units and/or Performance Shares granted
to each Eligible Person (subject to Article 4 herein) and,
consistent with the provisions of the Plan, in determining the
terms and conditions pertaining to such Awards.
1.1 Performance Unit/Performance Share Award
Agreement. Each grant of Performance Units and/or Performance
Shares shall be evidenced by a Performance Unit and/or
Performance Share Award Agreement that shall specify the number
of Performance Units and/or Performance Shares granted, the
initial value (if applicable), the Performance Period, the
Performance Goals and such other provisions as the Committee
shall determine, including but not limited to any rights to
Dividend Equivalents.
1.1 Value of Performance Units/Performance Shares.
Each Performance Unit shall have an initial value that is
established by the Committee at the time of grant. The value of
a Performance Share shall be equal to the Fair Market Value of a
Share. The Committee shall set Performance Goals in its
discretion which, depending on the extent to which they are met,
will determine the number and/or value of Performance
Units/Performance Shares that will be paid out to the
Participants.
1.1 Earning of Performance Units/Performance Shares.
After the applicable Performance Period has ended, the
Participant shall be entitled to receive a payout with respect to
the Performance Units/Performance Shares earned by the
Participant over the Performance Period, to be determined as a
function of the extent to which the corresponding Performance
Goals have been achieved.
1.1 Form and Timing of Payment of Performance
Units/Performance Shares. Payment of earned Performance
Units/Performance Shares shall be made following the close of the
applicable Performance Period. The Committee, in its sole
discretion, may pay earned Performance Units/Shares in cash or in
Shares (or in a combination thereof), which have an aggregate
Fair Market Value equal to the value of the earned Performance
Units/Shares at the close of the applicable Performance Period.
Such Shares may be granted subject to any restrictions deemed
appropriate by the Committee.
1.1 Termination. Each Performance Unit/Performance
Share Award Agreement shall set forth the extent to which the
Participant shall have the right to receive a Performance
Unit/Performance Share payment following termination of the
Participant's employment with or service on the Board of the
Company and its Subsidiaries during a Performance Period. Such
provisions shall be determined in the sole discretion of the
Committee, shall be included in the Award Agreement entered into
with Participants, need not be uniform among all grants of
Performance Units/Performance Shares or among Participants and
may reflect distinctions based on reasons for termination.
1.1 Transferability. Except as otherwise determined
by the Committee, a Participant's rights with respect to
Performance Units/Performance Shares granted under the Plan shall
be available during the Participant's lifetime only to such
Participant or the Participant's legal representative and
Performance Units/Performance Shares may not be sold,
transferred, pledged, assigned or otherwise alienated or
hypothecated, other than by will or by the laws of descent and
distribution.
1. Article Other Awards
The Committee shall have the right to grant other Awards
which may include, without limitation, the grant of Shares based
on attainment of Performance Goals established by the Committee,
the payment of Shares in lieu of cash or cash based on attainment
of Performance Goals established by the Committee, and the
payment of Shares in lieu of cash under other Company incentive
or bonus programs. Payment under or settlement of any such Awards
shall be made in such manner and at such times as the Committee
may determine.
1. Article Beneficiary Designation
Each Participant under the Plan may, from time to time, name
any beneficiary or beneficiaries (who may be named contingently
or successively) to whom any benefit under the Plan is to be paid
in case of the Participant's death before the Participant
receives any or all of such benefit. Each such designation shall
revoke all prior designations by the same Participant, shall be
in a form prescribed by the Company and will be effective only
when filed by the Participant in writing with the Company during
the Participant's lifetime. In the absence of any such
designation, benefits remaining unpaid at the Participant's death
shall be paid to the Participant's estate.
The spouse of a married Participant domiciled in a community
property jurisdiction shall join in any designation of
beneficiary or beneficiaries other than the spouse.
1. Article Deferrals
The Committee may permit a Participant to defer the
Participant's receipt of the payment of cash or the delivery of
Shares that would otherwise be due to such Participant under the
Plan. If any such deferral election is permitted, the Committee
shall, in its sole discretion, establish rules and procedures for
such payment deferrals.
1. Article Rights of Participants
1.1 Termination. Nothing in the Plan shall interfere
with or limit in any way the right of the Company or any
Subsidiary to terminate any Participant's employment or other
relationship with the Company or any Subsidiary at any time, for
any reason or no reason in the Company's or the Subsidiary's sole
discretion, nor confer upon any Participant any right to continue
in the employ of, or otherwise in any relationship with, the
Company or any Subsidiary.
1.1 Participation. No Eligible Person shall have the
right to be selected to receive an Award under the Plan, or,
having been so selected, to be selected to receive a future
Award.
1.1 Limitation of Implied Rights. Neither a
Participant nor any other Person shall, by reason of the Plan,
acquire any right in or title to any assets, funds or property of
the Company or any Subsidiary whatsoever, including, without
limitation, any specific funds, assets or other property which
the Company or any Subsidiary, in their sole discretion, may set
aside in anticipation of a liability under the Plan. A
Participant shall have only a contractual right to the Shares or
amounts, if any, payable under the Plan, unsecured by any assets
of the Company or any Subsidiary. Nothing contained in the Plan
shall constitute a guarantee that the assets of such companies
shall be sufficient to pay any benefits to any Person.
Except as otherwise provided in the Plan, no Award
under the Plan shall confer upon the holder thereof any right as
a shareholder of the Company prior to the date on which the
individual fulfills all conditions for receipt of such rights.
1. Article Change in Control
The terms of this Article 14 shall immediately become
operative, without further action or consent by any person or
entity, upon a Change in Control, and once operative shall
supersede and take control over any other provisions of this
Plan.
Upon a Change in Control
(a) Any and all Options and SARs granted hereunder shall
become immediately vested and exercisable;
(a) Any restriction periods and restrictions imposed on
Restricted Stock, Restricted Stock Units, Qualified Restricted
Stock or Qualified Restricted Stock Units shall be deemed to have
expired; any Performance Goals shall be deemed to have been met
at the target level; such Restricted Stock and Qualified
Restricted Stock shall become immediately vested in full, and
such Restricted Stock Units and Qualified Restricted Stock Units
shall be paid out in cash; and
(a) The target payout opportunity attainable under all
outstanding Awards of Performance Units and Performance Shares
and any other Awards shall be deemed to have been fully earned
for the entire Performance Period(s) as of the effective date of
the Change in Control. All Awards shall become immediately
vested. All Performance Shares and other Awards denominated in
Shares shall be paid out in Shares, and all Performance Units and
other Awards shall be paid out in cash.
1. Article Amendment, Modification and Termination
1.1 Amendment, Modification and Termination. The
Board may, at any time and from time to time, alter, amend,
suspend or terminate the Plan in whole or in part.
1.1 Awards Previously Granted. No termination,
amendment or modification of the Plan shall adversely affect in
any material way any Award previously granted under the Plan
without the written consent of the Participant holding such
Award, unless such termination, modification or amendment is
required by applicable law and except as otherwise provided
herein.
1. Article Withholding
1.1 Tax Withholding. The Company shall have the power
and the right to deduct or withhold, or require a Participant to
remit to the Company, an amount (including any Shares withheld as
provided below) sufficient to satisfy Federal, state and local
taxes (including the Participant's FICA obligation) required by
law to be withheld with respect to an Award made under the Plan.
1.1 Share Withholding. With respect to tax
withholding required upon the exercise of Options or SARs, upon
the lapse of restrictions on Restricted Stock, or upon any other
taxable event arising out of or as a result of Awards granted
hereunder, Participants may elect to satisfy the withholding
requirement, in whole or in part, by tendering Shares held by the
Participant or by having the Company withhold Shares having a
Fair Market Value equal to the minimum statutory total tax which
could be imposed on the transaction. All elections shall be
irrevocable, made in writing and signed by the Participant.
1. Article Successors
All obligations of the Company under the Plan, with respect
to Awards granted hereunder, shall be binding on any successor to
the Company, whether the existence of such successor is the
result of a direct or indirect purchase, merger, consolidation or
otherwise of all or substantially all of the business and/or
assets of the Company.
1. Article Legal Construction
1.1 Gender and Number. Except where otherwise
indicated by the context, any masculine term used herein also
shall include the feminine, the plural shall include the singular
and the singular shall include the plural.
1.1 Severability. In the event any provision of the
Plan shall be held illegal or invalid for any reason, the
illegality or invalidity shall not affect the remaining parts of
the Plan, and the Plan shall be construed and enforced as if the
illegal or invalid provision had not been included.
1.1 Requirements of Law. The granting of Awards and
the issuance of Shares under the Plan shall be subject to all
applicable laws, rules and regulations, and to such approvals by
any governmental agencies or national securities exchanges as may
be required.
Governing Law. To the extent not preempted by Federal
law, the Plan, and all agreements hereunder, shall be construed
in accordance with, and governed by, the laws of the State of
Idaho.
<TABLE>
<CAPTION>
Ex12
IDACORP, Inc.
Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method 0 0 0 458 435
investments
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) (37)
Fixed charges, as below 70,215 70,418 69,634 69,923 72,243
Total earnings, as defined $ 195,499 $ 204,252 $ 199,261 $ 199,365 $ 208,825
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975
Preferred stock dividends of
subsidiaries-
gross up-IDACORP rate 12,834 12,079 7,891 8,445 8,313
Rental interest factor 925 991 982 801 955
Total fixed charges, as defined $ 70,215 $ 70,418 $ 69,634 $ 69,923 $ 72,243
Ratio of earnings to fixed charges 2.78x 2.90x 2.86x 2.85x 2.89x
</TABLE>
<TABLE>
<CAPTION>
Ex12a
IDACORP, Inc.
Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 458 435
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) (37)
Supplemental fixed charges, as
below 72,826 73,018 72,208 72,496 74,800
Total earnings, as defined $ 198,110 $ 206,852 $ 201,835 $ 201,938 $ 211,382
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975
Preferred stock dividends of
subsidiaries- gross up-IDACORP
rate 12,834 12,079 7,891 8,445 8,313
Rental interest factor 925 991 982 801 955
Total fixed charges 70,215 70,418 69,634 69,923 72,243
Supplemental increment to fixed
charges* 2,611 2,600 2,574 2,573 2,557
Total supplemental fixed charges $ 72,826 $ 73,018 $ 72,208 $ 72,496 $ 74,800
Supplemental ratio of earnings to
fixed charges 2.72 x 2.83 x 2.80 x 2.79 x 2.83 x
*Explanation of increment - Interest on the guaranty of American Falls
Reservoir District bonds and Milner Dam, Inc. notes which are already
included in operation expenses.
</TABLE>
<TABLE>
<CAPTION>
Ex12b
IDACORP, Inc.
Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 458 435
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) (37)
Fixed charges, as below 70,215 70,418 69,634 69,923 72,243
Total earnings, as defined $ 195,499 $ 204,252 $ 199,261 $ 199,365 $ 208,825
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975
Preferred stock dividends of
subsidiaries- gross up-IDACORP
rate 12,834 12,079 7,891 8,445 8,313
Rental interest factor 925 991 982 801 955
Total fixed charges 70,215 70,418 69,634 69,923 72,243
Preferred dividends requirements 0 0 0 0 0
Total combined fixed charges
and preferred dividends $ 70,215 $ 70,418 $ 69,634 $ 69,923 $ 72,243
Ratio of earnings to combined fixed
charges and preferred dividends 2.78x 2.90x 2.86x 2.85x 2.89x
</TABLE>
<TABLE>
<CAPTION>
Ex12c
IDACORP, Inc.
Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 458 435
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) (37)
Supplemental fixed charges and
preferred dividends, as below 72,826 73,018 72,208 72,496 74,800
Total earnings, as defined $ 198,110 $ 206,852 $ 201,835 $ 201,938 $ 211,382
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975
Preferred stock dividends of
subsidiaries-gross up-IDACORP
rate 12,834 12,079 7,891 8,445 8,313
Rental interest factor 925 991 982 801 955
Total fixed charges 70,215 70,418 69,634 69,923 72,243
Supplemental increment to fixed
charges* 2,611 2,600 2,574 2,573 2,557
Supplemental fixed charges 72,826 73,018 72,208 72,496 74,800
Preferred dividends requirements 0 0 0 0 0
Total combined supplemental
fixed charges and preferred
dividends $ 72,826 $ 73,018 $ 72,208 $ 72,496 $ 74,800
Supplemental ratio of earnings to
combined fixed charges and
preferred dividends 2.72x 2.83x 2.80x 2.79x 2.83x
*Explanation of increment - Interest on the guaranty of American Falls
Reservoir District bonds and Milner Dam, Inc. notes which are
already included in operation expenses.
</TABLE>
<TABLE>
<CAPTION>
Ex12d
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 476 0
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) 0
Fixed charges, as below 57,381 58,339 61,743 61,394 62,969
Total earnings, as defined $ 190,656 $ 199,636 $ 196,546 $ 198,032 $ 205,210
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014
Rental interest factor 925 991 982 801 955
Total fixed charges, as
defined $ 57,381 $ 58,339 $ 61,743 $ 61,394 $ 62,969
Ratio of earnings to fixed charges 3.32x 3.42x 3.18x 3.23x 3.26x
</TABLE>
<TABLE>
<CAPTION>
Ex12e
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 476 0
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) 0
Supplemental fixed charges, as
below 59,992 60,939 64,317 63,967 65,526
Total earnings, as defined $ 193,267 $ 202,236 $ 199,120 $ 200,605 $ 207,767
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014
Rental interest factor 925 991 982 801 955
Total fixed charges 57,381 58,339 61,743 61,394 62,969
Supplemental increment to fixed
charges* 2,611 2,600 2,574 2,573 2,557
Total supplemental fixed
charges $ 59,992 $ 60,939 $ 64,317 $ 63,967 $ 65,526
Supplemental ratio of earnings to
fixed charges 3.22x 3.32 x 3.10x 3.14x 3.17x
*Explanation of increment - Interest on the guaranty of American Falls
Reservoir District bonds and Milner Dam, Inc. notes which are
already included in operation expenses.
</TABLE>
<TABLE>
<CAPTION>
Ex12f
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 476 0
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) 0
Fixed charges, as below 57,381 58,339 61,743 61,394 62,969
Total earnings, as defined $ 190,656 $ 199,636 $ 196,546 $ 198,032 $ 205,210
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014
Rental interest factor 925 991 982 801 955
Total fixed charges 57,381 58,339 61,743 61,394 62,969
Preferred stock dividends-gross
up Idaho Power rate 12,392 12,146 7,803 8,275 8,133
Total combined fixed charges
and preferred dividends $ 69,773 $ 70,485 $ 69,546 $ 69,669 $ 71,102
Ratio of earnings to combined fixed
charges and preferred dividends 2.73x 2.83x 2.83x 2.84x 2.89x
</TABLE>
<TABLE>
<CAPTION>
Ex12g
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078
Adjust for distributed income of
equity investees (2,058) (1,413) (3,943) (4,697) (837)
Equity in loss of equity method
investments 0 0 0 476 0
Minority interest in losses of
majority owned subsidiaries 0 0 0 (125) 0
Supplemental fixed charges and
preferred dividends, as below 59,992 60,939 64,317 63,967 65,526
Total earnings, as defined $ 193,267 $ 202,236 $ 199,120 $ 200,605 $ 207,767
Fixed charges, as defined:
Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014
Rental interest factor 925 991 982 801 955
Total fixed charges 57,381 58,339 61,743 61,394 62,969
Supplemental increment to fixed
charges* 2,611 2,600 2,574 2,573 2,557
Supplemental fixed charges 59,992 60,939 64,317 63,967 65,526
Preferred stock dividends-gross
up Idaho Power rate 12,392 12,146 7,803 8,275 8,133
Total combined supplemental
fixed charges and preferred
dividends $ 72,384 $ 73,085 $ 72,120 $ 72,242 $ 73,659
Supplemental ratio of earnings to
combined fixed charges and
preferred dividends 2.67x 2.77x 2.76x 2.78x 2.82x
*Explanation of increment - Interest on the guaranty of American Falls
Reservoir District bonds and Milner Dam, Inc. notes which are
already included in operation expenses.
</TABLE>
EXHIBIT 21
SUBSIDIARIES OF REGISTRANTS
IDACORP, Inc:
1. Idaho Power Company, an Idaho Corporation
2. Ida-West Energy Company, an Idaho Corporation
3. IDACORP Energy Solutions Company, a Nevada Corporation,
doing business as Idaho Power Services
4. IDACORP Energy Solutions L.P., A Delaware Limited
Partnership
5. IDACORP Energy Services Company, a Nevada Corporation
6. IDACORP Retail Enterprises Co., an Idaho Corporation
7. IDACORP Technologies, Inc., an Idaho Corporation
8. Northwest Power Systems LLC, an Oregon Limited
Liability Company
Idaho Power Company
1. Applied Power Corporation, a Washington Corporation
(see note)
2. IDACORP Financial Services, Inc., an Idaho Corporation
(see note)
3. Idaho Energy Resources Company, a Wyoming Corporation
4. Idaho Power Resources Corporation, an Idaho Corporation
5. Idaho Power Diversified Enterprises Company, an Idaho
Corporation
6. Pathnet/Idaho Equipment, LLC., an Idaho Limited
Liability Company
Note: on January 1, 2000 ownership of this subsidiary was
transferred to IDACORP, Inc.
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in
Idaho Power Company's Registration Statement No. 33-
51215 on Form S-3 and IDACORP, Inc's Registration
Statement Nos. 333-00139 and 333-64737 on Form S-3
and Registration Statement Nos. 33-56071, 333-89445
and 333-65157 on Form S-8 of our reports dated
January 31, 2000 on IDACORP, Inc. and Idaho Power
Company, appearing in this Annual Report on Form 10-
K of IDACORP, Inc. and Idaho Power Company for the
year ended December 31, 1999.
DELOITTE & TOUCHE LLP
Boise, Idaho
March 20, 2000
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information
extracted from IDACORP,
Inc.(Ex-27A) and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,745,683
<OTHER-PROPERTY-AND-INVEST> 146,019
<TOTAL-CURRENT-ASSETS> 350,408
<TOTAL-DEFERRED-CHARGES> 394,883
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,636,993
<COMMON> 451,343
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 301,627
<TOTAL-COMMON-STOCKHOLDERS-EQ> 752,970
0
105,811
<LONG-TERM-DEBT-NET> 808,062
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 13,496
<COMMERCIAL-PAPER-OBLIGATIONS> 19,757
<LONG-TERM-DEBT-CURRENT-PORT> 89,101
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 847,796
<TOT-CAPITALIZATION-AND-LIAB> 2,636,993
<GROSS-OPERATING-REVENUE> 658,336
<INCOME-TAX-EXPENSE> 45,672
<OTHER-OPERATING-EXPENSES> 485,878
<TOTAL-OPERATING-EXPENSES> 531,550
<OPERATING-INCOME-LOSS> 126,786
<OTHER-INCOME-NET> 31,718
<INCOME-BEFORE-INTEREST-EXPEN> 158,504
<TOTAL-INTEREST-EXPENSE> 67,155
<NET-INCOME> 91,349
0
<EARNINGS-AVAILABLE-FOR-COMM> 91,349
<COMMON-STOCK-DIVIDENDS> 69,863
<TOTAL-INTEREST-ON-BONDS> 54,294
<CASH-FLOW-OPERATIONS> 230,588
<EPS-BASIC> 2.43
<EPS-DILUTED> 2.43
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information
extracted from Idaho
Power (EX-27B) Company and is qualified in its entirety by
reference to such financial
statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,742,394
<OTHER-PROPERTY-AND-INVEST> 117,759
<TOTAL-CURRENT-ASSETS> 305,119
<TOTAL-DEFERRED-CHARGES> 394,102
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,559,374
<COMMON> 94,031
<CAPITAL-SURPLUS-PAID-IN> 358,384
<RETAINED-EARNINGS> 275,715
<TOTAL-COMMON-STOCKHOLDERS-EQ> 728,130
0
105,811
<LONG-TERM-DEBT-NET> 808,062
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 13,496
<COMMERCIAL-PAPER-OBLIGATIONS> 23,934
<LONG-TERM-DEBT-CURRENT-PORT> 89,101
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 790,840
<TOT-CAPITALIZATION-AND-LIAB> 2,559,374
<GROSS-OPERATING-REVENUE> 658,336
<INCOME-TAX-EXPENSE> 45,550
<OTHER-OPERATING-EXPENSES> 485,878
<TOTAL-OPERATING-EXPENSES> 531,428
<OPERATING-INCOME-LOSS> 126,908
<OTHER-INCOME-NET> 31,242
<INCOME-BEFORE-INTEREST-EXPEN> 158,150
<TOTAL-INTEREST-EXPENSE> 60,622
<NET-INCOME> 97,528
5,572
<EARNINGS-AVAILABLE-FOR-COMM> 91,956
<COMMON-STOCK-DIVIDENDS> 69,912
<TOTAL-INTEREST-ON-BONDS> 54,150
<CASH-FLOW-OPERATIONS> 213,845
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
