UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2001
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Exact name of registrants as
specified
in their charters, state of I.R.S.
Commission incorporation, address of Employer
File principal executive offices, Identification
Number and telephone number Number
1-14465 IDACORP, Inc. 82-0505802
1-3198 Idaho Power Company 82-0130980
1221 W. Idaho Street
Boise, ID 83702-5627
Telephone: (208) 388-2200
State of Incorporation: Idaho
Web site: www.idacorpinc.com
None
Former name, former address and former fiscal year, if changed
since last report.
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Number of shares of Common Stock outstanding as of September 30, 2001:
IDACORP, Inc.: 37,468,712
Idaho Power Company: 37,612,351 shares, all of which are
held by IDACORP, Inc.
This combined Form 10-Q 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.
INDEX
Page
Definitions 2
Part I. Financial Information:
Item 1. Financial Statements
IDACORP, Inc.:
Consolidated Statements of Income 3-4
Consolidated Balance Sheets 5-6
Consolidated Statements of Capitalization 7
Consolidated Statements of Cash Flows 8
Consolidated Statements of Comprehensive
Income 9
Notes to Consolidated Financial Statements 10-19
Independent Accountants' Report 20
Idaho Power Company:
Consolidated Statements of Income 21-22
Consolidated Balance Sheets 23-24
Consolidated Statements of Capitalization 25
Consolidated Statements of Cash Flows 26
Consolidated Statements of Comprehensive
Income 27
Notes to Consolidated Financial Statements 28-29
Independent Accountants' Report 30
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 31-44
Item 3. Quantitative and Qualitative Disclosures
about Market Risk 44
Part II. Other Information:
Item 6. Exhibits and Reports on Form 8-K 45-50
Signatures 51-52
DEFINITIONS
BPA - Bonneville Power MAF - Million Acre-Feet
Administration
Cal - California Independent MMbtu- Million British
ISO System Operator Thermal Units
MW - Megawatt
CalPX- California Power MWH - Megawatt-hour
Exchange
DIG - Derivatives OPUC - Oregon Public
Implementation Group Utility Commission
FASB - Financial Accounting PCA - Power Cost
Standards Board Adjustment
FERC - Federal Energy PUCN - Public Utility
Regulatory Commission Commission of
IE - IDACORP Energy Nevada
IPC - Idaho Power Company REA - Rural Electrification
Administration
IPUC - Idaho Public Utilities SFAS - Statement of
Commission Financial Accounting
kWh - kilowatt-hour Standards
FORWARD LOOKING INFORMATION
This Form 10-Q contains "forward-looking statements"
intended to qualify for the 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-Q at Part I, Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations-
Forward-Looking Information. Forward-looking statements are
all statements other than statements of historical fact,
including without limitation those that are identified by
the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," and similar expressions.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
IDACORP, Inc.
Consolidated Statements of Income
Three Months Ended
September 30,
2001 2000
(Thousands of Dollars
Except Per Share Amounts)
OPERATING REVENUES:
Electric utility:
General business $185,830 $158,611
Off system sales 91,654 61,179
Equity in earnings of partnerships 2,475 2,529
Other revenues 9,322 12,145
Total electric utility revenues 289,281 234,464
Energy marketing 104,985 72,881
Other 3,735 9,038
Total operating revenues 398,001 316,383
OPERATING EXPENSES:
Electric Utility:
Purchased power 228,460 139,243
Fuel expense 25,947 23,811
Power cost adjustment (57,770) (45,612)
Other operations and maintenance 50,004 49,629
Depreciation 21,894 19,933
Taxes other than income taxes 4,947 5,024
Total electric utility expenses 273,482 192,028
Energy marketing 48,216 30,878
Other 7,305 10,909
Total operating expenses 329,003 233,815
OPERATING INCOME:
Electric utility 15,799 42,436
Energy marketing 56,769 42,003
Other (3,570) (1,871)
Total operating income 68,998 82,568
OTHER INCOME:
Allowance for equity funds used
during construction 173 696
Other - net 894 (3,357)
Total other income 1,067 (2,661)
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 13,788 13,239
Other interest 4,804 2,366
Allowance for borrowed funds used
during construction (879) (609)
Preferred dividends of Idaho Power
Company 1,374 1,511
Total interest expense and other 19,087 16,507
INCOME BEFORE INCOME TAXES 50,978 63,400
INCOME TAXES 17,055 21,839
NET INCOME $ 33,923 $ 41,561
AVERAGE COMMON SHARES OUTSTANDING
(000's) 37,410 37,524
EARNINGS PER SHARE OF COMMON STOCK $ 0.91 $ 1.11
(basic and diluted)
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Income
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars
Except Per Share
Amounts)
OPERATING REVENUES:
Electric utility:
General business $475,158 $420,993
Off system sales 205,552 161,158
Equity in earnings of partnerships 7,522 9,240
Other revenues 34,763 29,820
Total electric utility revenues 722,995 621,211
Energy marketing 306,568 124,019
Other 10,189 19,940
Total operating revenues 1,039,752 765,170
OPERATING EXPENSES:
Electric utility:
Purchased power 523,165 253,762
Fuel expense 73,545 68,526
Power cost adjustment (184,102) (64,297)
Other operations and maintenance 149,383 146,317
Depreciation 64,293 59,769
Taxes other than income taxes 15,591 15,914
Total electric utility expenses 641,875 479,991
Energy marketing 159,969 45,406
Other 24,089 26,261
Total operating expenses 825,933 551,658
OPERATING INCOME:
Electric utility 81,120 141,220
Energy marketing 146,599 78,613
Other (13,900) (6,321)
Total operating income 213,819 213,512
OTHER INCOME:
Allowance for equity funds used
during construction 758 1,787
Gains on sales of assets 1,605 14,000
Other - net 1,098 (2,082)
Total other income 3,461 13,705
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 42,003 39,654
Other interest 13,464 7,051
Allowance for borrowed funds used
during construction (3,295) (1,620)
Preferred dividends of Idaho Power
Company 4,128 4,423
Total interest expense and other 56,300 49,508
INCOME BEFORE INCOME TAXES 160,980 177,709
INCOME TAXES 56,198 61,546
NET INCOME $104,782 $116,163
AVERAGE COMMON SHARES OUTSTANDING
(000's) 37,413 37,581
EARNINGS PER SHARE OF COMMON STOCK
(basic and diluted) $ 2.80 $ 3.09
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Assets
September 30, December 31,
2001 2000
(Thousands of Dollars)
CURRENT ASSETS:
Cash and cash equivalents $ 62,415 $ 106,795
Receivables:
Customer 330,549 243,647
Allowance for uncollectible
accounts (42,426) (23,079)
Employee notes 5,170 4,742
Other 10,849 15,611
Energy marketing assets 294,825 1,060,128
Derivative assets 1,133 -
Taxes receivable 19,621 -
Accrued unbilled revenues 32,427 44,825
Materials and supplies (at average
cost) 26,486 29,731
Fuel stock (at average cost) 6,797 5,105
Prepayments 26,845 24,575
Regulatory assets associated with
income taxes 13,054 8,672
Regulatory assets - derivatives 55,136 -
Total current assets 842,881 1,520,752
INVESTMENTS AND OTHER ASSETS 187,750 157,068
PROPERTY, PLANT AND EQUIPMENT:
Utility plant in service 2,941,236 2,799,874
Accumulated provision for
depreciation (1,201,079) (1,142,572)
Utility plant in service - net 1,740,157 1,657,302
Construction work in progress 112,266 136,388
Utility plant held for future use 2,232 2,167
Other property, net of accumulated
depreciation 18,893 9,179
Property, plant and equipment -
net 1,873,548 1,805,036
DEFERRED DEBITS:
American Falls and Milner water
rights 31,585 31,585
Company-owned life insurance 39,627 39,554
Energy marketing assets - long-term 345,466 43,556
Regulatory assets associated with
income taxes 198,240 204,880
Regulatory assets - PCA 308,107 119,905
Regulatory assets - long-term
derivatives 15,229 -
Regulatory assets - other 38,816 45,750
Other 67,952 71,620
Total deferred debits 1,045,022 556,850
TOTAL $3,949,201 $4,039,706
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Liabilities and Capitalization
September 30, December 31,
2001 2000
(Thousands of Dollars)
CURRENT LIABILITIES:
Current maturities of long-term
debt $ 9,110 $ 39,774
Notes payable 325,500 120,600
Accounts payable 353,466 272,376
Energy marketing liabilities 356,690 1,060,180
Derivative liabilities 56,270 -
Taxes accrued - 15,631
Interest accrued 20,576 16,985
Deferred income taxes 13,054 8,672
Other 48,777 28,104
Total current liabilities 1,183,443 1,562,322
DEFERRED CREDITS:
Deferred income taxes 567,733 460,464
Energy marketing liabilities - long-
term 170,711 46,769
Derivative liabilities - long-term 15,229 -
Regulatory liabilities associated
with deferred investment tax credits 65,856 66,050
Regulatory liabilities associated
with income taxes 39,979 40,230
Regulatory liabilities - other 4,178 4,621
Other 62,395 69,259
Total deferred credits 926,081 687,393
LONG-TERM DEBT 870,140 864,114
COMMITMENTS AND CONTINGENT
LIABILITIES
PREFERRED STOCK OF IDAHO POWER
COMPANY 104,524 105,066
COMMON STOCK EQUITY:
Common stock, no par value (shares
authorized 120,000,000;
37,614,798 shares issued) 451,530 453,102
Retained earnings 422,565 370,126
Accumulated other comprehensive
income (loss) (3,536) (921)
Treasury stock (146,086 and 44,425
shares at cost, respectively) (5,546) (1,496)
Total common stock equity 865,013 820,811
TOTAL $3,949,201 $4,039,706
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Capitalization
September 30, December 31,
2001 % 2000 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 451,530 $ 453,102
Retained earnings 422,565 370,126
Accumulated other
comprehensive income (loss) (3,536) (921)
Treasury stock (5,546) (1,496)
Total common stock equity 865,013 47 820,811 46
PREFERRED STOCK OF IDAHO POWER
COMPANY:
4% preferred stock 14,524 15,066
7.68% Series, serial preferred
stock 15,000 15,000
7.07% Series, serial preferred
stock 25,000 25,000
Auction rate preferred stock 50,000 50,000
Total preferred stock 104,524 6 105,066 6
LONG-TERM DEBT:
First mortgage bonds:
6.93% Series due 2001 - 30,000
6.85% Series due 2002 27,000 27,000
6.40% Series due 2003 80,000 80,000
8 % Series due 2004 50,000 50,000
5.83% Series due 2005 60,000 60,000
7.38% Series due 2007 80,000 80,000
7.20% Series due 2009 80,000 80,000
6.60% Series due 2011 120,000 -
Maturing 2021 through 2031
with rates ranging
from 7.5% to 9.52% 130,000 230,000
Total first mortgage
bonds 627,000 637,000
Amount due within one
year - (30,000)
Net first mortgage
bonds 627,000 607,000
Pollution control revenue
bonds:
8.30% Series 1984 due 2014 49,800 49,800
6.05% Series 1996A due 2026 68,100 68,100
Variable Rate Series 1996B
due 2026 24,200 24,200
Variable Rate Series 1996C
due 2026 24,000 24,000
Variable Rate Series 2000
due 2027 4,360 4,360
Total pollution control
revenue bonds 170,460 170,460
REA notes 1,282 1,339
Amount due within one year (77) (77)
Net REA notes 1,205 1,262
American Falls bond guarantee 19,885 19,885
Milner Dam note guarantee 11,700 11,700
Unamortized premium/discount -
net (1,048) (1,330)
Debt related to investments in
affordable housing with
rates ranging from 6.03% to
8.59% due 2001 to 2011 49,673 64,063
Amount due within one year (9,033) (9,697)
Net affordable housing
debt 40,640 54,366
Other subsidiary debt 298 771
Total long-term debt 870,140 47 864,114 48
TOTAL CAPITALIZATION $1,839,677 100 $1,789,991 100
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $104,782 $116,163
Adjustments to reconcile net income
to net cash provided by (used in)
operating activities:
Allowance for uncollectible
accounts 19,347 -
Unrealized gains from energy
marketing activities (116,299) (11,904)
Gains on sales of assets (1,605) (14,000)
Depreciation and amortization 82,324 73,996
Deferred taxes and investment tax
credits 115,045 29,741
Accrued PCA costs (188,202) (65,190)
Undistributed earnings (losses) of
affiliates 2,314 (558)
Change in:
Accounts receivable and
prepayments (85,804) (98,296)
Accrued unbilled revenue 12,398 (2,175)
Materials and supplies and fuel
stock (510) 3,021
Accounts payable 64,569 80,613
Taxes accrued (35,252) 2,711
Other current assets and
liabilities 3,591 (5,823)
Other - net (5,821) (4,608)
Net cash provided by (used in)
operating activities (29,123) 103,691
INVESTING ACTIVITIES:
Additions to property, plant and
equipment (138,260) (88,944)
Investments in affordable housing
projects - (15,813)
Proceeds from sales of assets 11,126 17,500
Other - net (3,266) (8,012)
Net cash used in investing
activities (130,400) (95,269)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 120,000 -
Pollution control revenue bonds - 4,360
Long-term debt related to
affordable housing projects - 6,995
Retirement of:
First mortgage bonds (130,000) (80,000)
Long-term debt related to
affordable housing projects (14,390) (15,173)
Pollution control revenue bonds - (4,360)
Reacquisition of common shares (7,969) (8,014)
Dividends on common stock (52,343) (52,386)
Increase in short-term borrowings 204,900 47,418
Other - net (5,055) (109)
Net cash provided by (used in)
financing activities 115,143 (101,269)
Net decrease in cash and cash
equivalents (44,380) (92,847)
Cash and cash equivalents at beginning
of period 106,795 111,338
Cash and cash equivalents at end of
period $ 62,415 $ 18,491
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash (received) paid during the
period for:
Income taxes $(17,241) $ 30,928
Interest (net of amount
capitalized) $ 46,772 $ 45,960
Distribution of treasury stock to
affiliates $ 8,249 $ -
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
Three Months Ended
September 30,
2001 2000
(Thousands of Dollars)
NET INCOME $33,923 $41,561
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on (1,008) 249
securities (net of tax of ($655) and
$162)
TOTAL COMPREHENSIVE INCOME $32,915 $41,810
The accompanying notes are an integral part of these statements.
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars)
NET INCOME $104,782 $116,163
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on (2,615) 992
securities (net of tax of ($1,580) and
$67)
TOTAL COMPREHENSIVE INCOME $102,167 $117,155
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Notes to Consolidated Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
IDACORP, Inc. (IDACORP or the Company) is a holding company
whose principal operating subsidiaries are Idaho Power
Company (IPC) and IDACORP Energy (IE). IPC is regulated by
the FERC and the state regulatory commissions of Idaho,
Oregon, Nevada and Wyoming, and is engaged in the
generation, transmission, distribution, sale and purchase of
electric energy. IPC is the parent of Idaho Energy
Resources Co., a joint venturer in Bridger Coal Company,
which supplies coal to IPC's Jim Bridger generating plant.
IE is a marketer of electricity and natural gas, trading in
31 states and two Canadian provinces.
IDACORP's other subsidiaries include:
Ida-West Energy - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services - affordable housing and
other real estate investments;
Rocky Mountain Communications (RMC) - commercial and
residential Internet service provider;
IDACOMM - provider of telecommunications services;
IDACORP Services - products and services for homes and
businesses.
Financial Statements
In the opinion of the Company, the accompanying unaudited
consolidated financial statements contain all adjustments
necessary to present fairly its consolidated financial
position as of September 30, 2001, and its consolidated
results of operations for the three and nine months ended
September 30, 2001 and 2000 and consolidated cash flows for
the nine months ended September 30, 2001 and 2000. These
financial statements do not contain the complete detail or
footnote disclosure concerning accounting policies and other
matters that would be included in full year financial
statements and therefore they should be read in conjunction
with the Company's audited consolidated financial statements
included in the Company's Annual Report on Form 10-K for the
year ended December 31, 2000. The results of operations for
the interim periods are not necessarily indicative of the
results to be expected for the full year.
Planned Major Maintenance
The Company records repair and maintenance costs associated
with planned major maintenance activities as these costs are
incurred.
Regulatory Assets
IPC has $4.5 million of regulatory assets that are not
earning a return. These assets are predominately related to
reorganization costs and post-employment benefits, and have
remaining amortization periods of less than five years.
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.
Reclassifications
Certain items previously reported for periods prior to
September 30, 2001 have been reclassified to conform with
the current period's presentation. Net income and common
stock equity were not affected by these reclassifications.
New Accounting Pronouncements
In July 2001 the FASB issued SFAS 141, "Business
Combinations," which addresses accounting and reporting for
business combinations. SFAS 141 requires that all business
combinations initiated after June 30, 2001 be accounted for
using one method, the purchase method. The Company does not
believe the adoption will have a significant effect on its
financial statements.
Also in July 2001 the FASB issued SFAS 142 "Goodwill and
Other Intangible Assets," which is effective January 1,
2002. SFAS 142 requires, among other things, that goodwill
can no longer be amortized. In addition, the standard
includes provisions for the reclassification of certain
existing recognized intangibles as goodwill, reassessment of
the useful lives of existing recognized intangibles,
reclassification of certain intangibles out of previously
reported goodwill and the identification of reporting units
for purposes of assessing potential future impairments of
goodwill. SFAS 142 also requires the Company to complete a
transitional goodwill impairment test six months from the
date of adoption. The Company is currently assessing but
has not yet determined the impact of SFAS 142 on its
financial position and results of operations.
In August 2001 the FASB issued SFAS 143 "Accounting for
Asset Retirement Obligations" which is effective for fiscal
years beginning after June 15, 2002. This Statement
addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. An obligation
may result from the acquisition, construction, development
and the normal operation of a long-lived asset. The Company
is currently assessing but has not yet determined the impact
of SFAS 143 on its financial position and results of
operations.
Also in August 2001 the FASB issued SFAS 144 "Accounting for
the Impairment or Disposal of Long-Lived Assets" which is
effective for fiscal years beginning after December 15,
2001. SFAS 144 addresses financial accounting and reporting
for the impairment or disposal of long-lived assets
superseding SFAS 121 "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed of."
The Company is currently assessing but has not yet
determined the impact of SFAS 144 on its financial position
and results of operations.
2. INCOME TAXES
The Company's effective tax rate for the first nine months
increased from 34.6 percent in 2000 to 34.9 percent in 2001.
Reconciliations between the statutory income tax rate and
the effective rates are as follows (in thousands of
dollars):
Nine Months Ended September 30,
2001 2000
Amount Rate Amount Rate
Computed income taxes
based on statutory
federal income tax rate $ 56,343 35.0% $ 62,198 35.0%
Changes in taxes
resulting from:
Investment tax credits (2,329) (1.4) (2,313) (1.3)
Repair allowance (2,100) (1.3) (2,100) (1.2)
Pension expense (1,368) (0.9) (1,420) (0.8)
State income taxes 8,734 5.4 8,841 4.9
Depreciation 6,325 3.9 5,154 2.9
Affordable housing tax
credits (10,034) (6.2) (10,257) (5.8)
Preferred dividends of
IPC 1,444 0.9 1,548 0.9
Other (817) (0.5) (105) 0.0
Total provision for
federal and state
income taxes $ 56,198 34.9% $ 61,546 34.6%
3. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding were
as follows:
September 30, December 31,
2001 2000
Cumulative, $100 par value:
4% preferred stock (authorized
215,000 shares) 145,244 150,656
Serial preferred stock, 7.68%
Series (authorized
150,000 shares) 150,000 150,000
Serial preferred stock,
cumulative, without par
value; total of 3,000,000
shares authorized:
7.07% Series, $100 stated
value, (authorized
250,000 shares) 250,000 250,000
Auction rate preferred stock,
$100,000 stated
value, (authorized 500
shares) 500 500
4. FINANCING:
At September 30, 2001, IPC had regulatory authority to incur
up to $500 million of short-term indebtedness. On September
12, 2001, IPC issued $100 million Floating Rate Notes, Due
September 1, 2002. Proceeds from this issuance were used to
retire other short-term borrowings. At September 30, 2001,
IPC's short-term borrowing totaled $244 million.
The Company has bank line of credit facilities established
at both IPC and IDACORP. IPC has a $120 million multi-year
revolving credit facility that expires in December 2001
under which it pays a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond
rating. IPC also established on April 27, 2001 a 364-day
credit facility for up to $165 million in support of its
ongoing operations. IPC commercial paper may be issued
subject to the regulatory maximum.
IDACORP has separately established a $50 million three-year
credit facility that expires in December 2001, and a $375
million 364-day credit facility that expires in March 2002.
Under these facilities IDACORP pays a facility fee on the
commitment, quarterly in arrears, based on IPC's First
Mortgage Bond rating. At September 30, 2001, short-term
borrowing on these facilities totaled $81.5 million.
IDACORP currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured
debt and preferred or common stock. At September 30, 2001,
none had been issued.
On March 23, 2000, IPC filed a $200 million shelf
registration statement that could be used for First Mortgage
Bonds (including medium term notes), unsecured debt, or
preferred stock. On December 1, 2000, IPC issued $80
million principal amount of Secured Medium Term Notes,
Series C, 7.38% Series due 2007. Proceeds were used for the
early redemption in January 2001 of the $75 million First
Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC
issued $120 million principal amount of Secured Medium Term
Notes, Series C, 6.60% Series due 2011 with the proceeds
used to reduce short-term borrowing incurred in support of
ongoing long-term construction requirements. At September
30, 2001, no amount remained to be issued on this shelf
registration statement.
On August 16, 2001, IPC filed a $200 million shelf
registration statement that can be used for First Mortgage
Bonds (including medium-term notes), unsecured debt or
preferred stock. At September 30, 2001, no amounts had been
issued.
5. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to
IPC's program for construction and operation of facilities
amounted to approximately $6.5 million at September 30,
2001. Additionally, Ida-West Energy has commitments
totaling $30.5 million. The commitments are generally
revocable by the Company subject to reimbursement of
manufacturers' expenditures incurred and/or other
termination charges.
From time to time the Company is party to various legal
claims, actions, and complaints, certain of which may
involve material amounts. Although the Company is unable to
predict with certainty whether or not it will ultimately be
successful in these legal proceedings, or, if not, what the
impact might be, based upon the advice of legal counsel,
management presently believes that disposition of these
matters will not have a material adverse effect on the
Company's financial position, results of operation, or cash
flows.
IE also has approximately $0.4 million in receivables from
less-than-investment grade entities at September 30, 2001.
California Energy Situation
As a component of IPC's non-utility energy trading in the
state of California, IPC, in January 1999, entered into a
participation agreement with the California Power Exchange
(CalPX), a California non-profit public benefit corporation.
The CalPX, at this time, operated a wholesale electricity
market in California by acting as a clearinghouse through
which electricity was bought and sold. Pursuant to the
participation agreement, IPC could sell power to the CalPX
under the terms and conditions of the CalPX Tariff. Under
the participation agreement, if a participant in the CalPX
exchange defaults on a payment to the exchange, the other
participants are required to pay their allocated share of
the default amount to the exchange. The allocated shares
are based upon the level of trading activity, which includes
both power sales and purchases, of each participant during
the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2.2
million - a "default share invoice" - as a result of an
alleged Southern California Edison (SCE) payment default of
$214.5 million for power purchases. IPC made this payment.
On January 24, 2001, IPC terminated the participation
agreement. On February 8, 2001, the CalPX sent a further
invoice for $5.2 million, due February 20, 2001, as a result
of alleged payment defaults by SCE, Pacific Gas and Electric
Company (PG&E), and others. However, because the CalPX owed
IPC $11.3 million for power sold to the CalPX in November
and December 2000, IPC did not pay the February 8th invoice.
IPC essentially discontinued energy trading with California
entities in December 2000.
IPC believes that the default invoices were not proper and
that IPC owes no further amounts to the CalPX. IPC has
pursued all available remedies in its efforts to collect
amounts owed to it by the CalPX.
On February 20, 2001, IPC filed a petition with FERC to
intervene in a proceeding which requested the FERC to
suspend the use of the CalPX charge back methodology and
provides for further oversight in the CalPX's implementation
of its default mitigation procedures.
A preliminary injunction was granted by a Federal Judge in
the Federal District Court for the Central District of
California enjoining the CalPX from declaring any CalPX
participant in default under the terms of the CalPX Tariff.
On March 9, 2001, the CalPX filed for Chapter 11 protection
with the U.S. Bankruptcy Court, Central District of
California.
In April 2001, PG&E filed for bankruptcy. The CalPX and the
California Independent System Operator (Cal ISO) were also
creditors of PG&E. To the extent that PG&E's bankruptcy
filing affects the collectibility of our receivables from
the CalPX and Cal ISO our receivables from these entities
are at greater risk.
Also in April 2001, the FERC issued an order stating that it
was establishing price mitigation for sales in the
California wholesale electricity market. Subsequently, in
its June 19, 2001 Order, the FERC expanded that price
mitigation plan to the entire western United States
electrically interconnected system. That plan included the
potential for orders directing electricity sellers into
California since October 2, 2000 to refund portions of their
sales prices if the FERC determined that those prices were
not just and reasonable, and therefore not in compliance
with the Federal Power Act. The June 19 Order also required
all buyers and sellers in the Cal ISO market during the
subject time-frame, to participate in settlement discussions
to explore the potential for resolution of these issues
without further FERC action. The settlement discussions
failed to bring resolution of the refund issue and as a
result, the FERC Chief Judge submitted a Report and
Recommendation to the FERC recommending that the FERC adopt
his methodology set forth in his report and set for
evidentiary hearing an analysis of the Cal ISO's and the
CalPX's spot markets to determine what refunds may be due
upon application of that methodology. The Judge recommended
that his methodology should be applied to all sellers except
those who at the evidentiary hearing are able to demonstrate
that their costs exceed the results of the recommended
methodology.
On July 25, 2001, the FERC issued an order establishing
evidentiary hearing procedures related to the scope and
methodology for calculating refunds related to transactions
in the spot markets operated by the Cal ISO and the CalPX
during the period October 2, 2000 through June 20, 2001. As
to potential refunds, if any, the Company believes that its
exposure will be more than offset by amounts due it from
California entities.
In addition, the July 25, 2001 FERC order established
another proceeding to explore whether there may have been
unjust and unreasonable charges for spot market sales in the
Pacific Northwest during the period December 25, 2000
through June 20, 2001. The FERC Administrative Law Judge
(ALJ) submitted her recommendations and findings to the FERC
on September 24, 2001. The ALJ found that the prices were
just and reasonable and therefore no refunds should be
allowed. Procedurally, the ALJ's decision is a
recommendation to the commissioners of the FERC. The FERC
is not bound to accept any or all of it. The next step is
for the FERC to issue an order in response to the ALJ's
recommendation. The FERC has issued a notice soliciting
comments on this case. Although there is no binding
timeframe for the FERC to issue its order, it may issue an
order in the next 30 to 60 days. Actions of the FERC are
appealable to the United States Court of Appeals. The
Company will continue to monitor all proceedings to
determine the impact on the Company. Counsel has been
retained in connection with the CalPX and PG&E bankruptcies
and FERC proceedings.
Effective June 11, 2001, IPC transferred its wholesale
electricity marketing operations to IE. IE is a Delaware
limited partnership with IDACORP, Inc. as its sole general
partner and IDACORP Energy Services Co., a wholly-owned
subsidiary of IDACORP, Inc., as its sole limited partner
(see Note 9 to the Idaho Power Company financial statements
and the MD&A, "Other Matters - Energy Marketing").
Effective with the June 11 transfer, the outstanding
receivables and payables with the CalPX and Cal ISO were
assigned from IPC to IE. At September 30, 2001, the CalPX
and Cal ISO owed $13 million and $31 million respectively
for energy sales made to them by IPC in November and
December 2000. In addition, at September 30, 2001, IE had
accrued but not paid $35.1 million due to the Cal ISO as an
offset to the outstanding receivable. IE has accrued a
reserve of $4 million against these receivables.
These reserves were calculated taking into account the
deterioration of the California energy markets and, for the
less-than-investment-grade receivables, by using a model
that estimates the probability of default and the estimated
recovery amounts of such receivables.
Based on the reserves recorded as of September 30, 2001, the
Company believes that the future collectibility of these
receivables or any potential refunds ordered by the FERC
would not have a significant impact on operations or
liquidity.
6. REGULATORY ISSUES:
Idaho Power Cost Adjustment (PCA)
IPC has a PCA mechanism that provides for annual adjustments
to the rates IPC charges to Idaho retail customers. These
adjustments, which take effect annually in May, are based on
forecasts of net power supply expenses. During the year,
the difference between actual and forecasted costs is
deferred with interest. The balance of this deferral,
called a true-up, is then included in the calculation of the
next year's PCA adjustment.
In its 2001 PCA filing, IPC requested recovery of $227.4
million of power supply costs. In May, the IPUC authorized
recovery of $168.3 million, but deferred recovery of $59.1
million pending further review. The approved amount
resulted in an average rate increase of 31.6 percent. After
conducting hearings on the remaining $59.1 million, the IPUC
authorized recovery of $47.7 million plus $1.2 million of
accrued interest, beginning in October 2001. The remaining
$11.4 million not recovered in rates from the PCA filing was
written off in September 2001.
Of the $227 million requested by IPC, $185 million related
to the true-up of power supply costs incurred in the 2000-
2001 PCA year and $42 million was for recovery of excess
power supply costs forecasted in the 2001-2002 PCA year.
The forecast amount, however, underestimates expected power
supply costs. Reservoir water is significantly lower than
forecast, necessitating the use of higher cost alternatives
to hydro generation.
As part of the May 2001 PCA, the IPUC required IPC to
implement a three-tiered rate structure for Idaho
residential customers. The IPUC determined that the
approved rates for residential customers should increase as
a customer's electricity consumption increases. The
residential rate increases are 14.4 percent for the first
800 kWh of usage, 28.8 percent for the next 1,200 kWh, and
62 percent for usage over 2,000 kWh.
On August 31, IPC filed a request with the IPUC to implement
a rate credit to qualifying residential and small farm
customers. The credit is the result of a settlement
agreement between IPC and the Bonneville Power
Administration (BPA), which will pass on the benefits of the
Federal Columbia River Power System. IPC estimates the
credit could be as much as $3.60 per month for residential
customers who use 1,200 kWh per month and $300 per month for
farm customers that use 100,000 kWh. The IPUC, by Order No.
28868, approved the credit to be passed to the qualified
customers effective October 1, 2001.
In its May 2001 rate authorization the IPUC also directed
IPC to reinstate a comprehensive conservation program given
the current volatility of market prices and the opportunity
to incorporate long-term conservation. In response to that
directive, IPC filed a report of present energy efficiency
activities, a list of conservation measures, an examination
of funding options and a detailed program structure that
could be implemented should the Commission determine that
additional conservation programs, including the funding of
these programs, is in the public interest.
On October 18, 2001 IPC filed an application with the IPUC
for an order approving the costs to be included in the 2002-
2003 PCA for the Irrigation Load Reduction Program and
Astaris Load Reduction Agreement. These two programs were
implemented in 2001 to reduce demand and were approved by
the IPUC and OPUC. The costs included in the application
were $58.6 million for the Irrigation Load Reduction Program
and $42.2 million for the Astaris Load Reduction Agreement,
representing total costs through September 2001. IPC will
file a second application requesting approval for
subsequently incurred costs.
Oregon Excess Power Costs
IPC filed an application with the OPUC to begin recovering
extraordinary 2001 power supply costs in its Oregon
jurisdiction. On June 18, 2001, the OPUC approved new rates
that will recover $0.8 million over the next year. Under
the provisions of the deferred accounting statute,
ORS757.259(6), annual rate recovery of deferred amounts is
limited to $0.8 million or 3% of IPC's 2000 gross revenues
in Oregon. IPC filed on October 5, 2001 to recover an
additional 3% of extraordinary power supply costs deferred
for 2001. The OPUC will hear the request November 20, 2001
and a decision could be made as early as November 28, 2001.
The Oregon deferral balance is $12.2 as of September 30,
2001, net of the June 18th recovery.
IPC filed with the OPUC a request to implement the same BPA
program as in Idaho. The OPUC held a public meeting on
October 22, 2001. The OPUC approved the Company's request
to implement the BPA residential and small farm energy
credit (BPA Credit) for the benefits derived during the
period October 1, 2001 though September 30, 2006.
IPC is also planning to file for a comprehensive
conservation program in its Oregon jurisdiction.
7. DERIVATIVE FINANCIAL INSTRUMENTS:
The Company uses financial instruments such as commodity
futures, forwards, options and swaps to manage exposure to
commodity price risk in the electricity and natural gas
markets. The objective of the Company's risk management
program is to mitigate the risk associated with the purchase
and sale of electricity and natural gas as well as to
optimize its energy marketing portfolio. The accounting for
derivative financial instruments that are used to manage
risk is in accordance with the concepts established in
Emerging Issues Task Force (EITF) 98-10, "Accounting for
Contracts Involved in Energy Trading Activities," and SFAS
133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by SFAS 138 "Accounting for Certain
Derivative Instruments and Certain Hedging Activities."
Energy Trading Contracts
All contracts classified as energy trading contracts, under
the guidance provided by EITF 98-10, including forward
transmission contracts, are marked to market and the
resulting change in fair value from the previous period is
presented on IDACORP'S Statement of Income in "Energy
marketing revenues." The same accounting treatment is
applied for all energy trading contracts regardless of
whether they are anticipated to be physically scheduled for
delivery or net settled for cash. In the settlement month
of these energy contracts, the gains and losses from
settlement are recorded and the previously recognized mark-
to-market values are reversed in the same financial
statement line item. Transmission costs associated with the
physical delivery of energy are reported as "Energy
marketing expenses" in the month of settlement.
The fair value of positions recorded on the balance sheet is
dependent on the price, volatility, and other uncertainties
of the energy markets. As such, these items on the balance
sheet can fluctuate greatly without large changes in volumes
or positions. Cash flows from energy trading contracts are
recognized in the statement of cash flows as an operating
activity.
Derivative Assets and Liabilities
The Company adopted SFAS 133, as amended, effective January
1, 2001. Contracts company-wide were evaluated based upon
the SFAS 133 derivative definitions and requirements. Most
of the Company's contracts that meet the derivative
definition are the energy trading contracts that were
already recorded at fair value under EITF 98-10 as discussed
above. Most of the remaining energy contracts meet the
definition of a normal purchase or sale as described in SFAS
138 and therefore are not considered derivatives. However,
IPC has certain electricity contracts that are periodically
net settled with the counterparty (booked out). Booking out
of electricity contracts is a normal business transaction
within the electric utility industry; however the FASB and
the Derivative Implementation Group (DIG) initially
interpreted that book outs did not qualify for the normal
purchase and sales exception. The Company has recorded the
fair market value of the booked out system electricity
contracts within the financial statements as "Derivative
assets" and "Derivative liabilities".
Such assets and liabilities at January 1 and September 30,
2001 are as follows:
January 1, 2001 September 30, 2001
(Thousands of Dollars)
Assets $ 108,909 $ 1,133
Liabilities (207,407) (71,499)
Net $ (98,498) $ (70,366)
The electricity contracts identified above are subject to
IPC regulatory processes. Accordingly, SFAS 71, "Accounting
for the Effects of Certain Types of Regulation" allows the
net amount of these Derivative assets and liabilities to be
offset by regulatory assets or liabilities. The IPUC
granted approval of this use of SFAS 71 regulatory assets or
liabilities in its Order 28661 issued March 12, 2001.
In June 2001 the DIG issued Interpretation C-15 that
tentatively concludes that certain booked out contracts now
qualify for the normal purchase and sales exception. IPC is
evaluating the effect of this new conclusion on its
treatment of booked out contracts but expects that some
contracts previously classified as derivatives will be
exempt when C-15 becomes final. The effect of this change
will not have a material effect on IPC's financial position,
results of operations, or cash flows.
As a result of the items discussed above, the Company's
adoption of SFAS 133, as amended, did not have a material
effect on its financial position, results of operations, or
cash flows.
8. INDUSTRY SEGMENT INFORMATION:
The Company has identified two reportable operating
segments, Utility Operations and Energy Marketing.
The following table summarizes the segment information for
the Company's utility operations and energy marketing
segments and the total of all other segments, and reconciles
this information to total enterprise amounts.
Utility Energy Consolidated
Operations Marketing Other Eliminations Total
(Thousands of Dollars)
Three months ended
September 30, 2001:
Revenues $ 289,281 $ 105,886 $ 3,735 $ (901) $ 398,001
Net income (loss) (100) 34,798 (775) - 33,923
Total assets at
September 30, 2001 $2,913,304 $1,014,331 $319,974 $(298,408) $3,949,201
Three months ended
September 30, 2000:
Revenues $ 234,464 $ 72,881 $ 9,038 $ - $ 316,383
Net income (loss) 16,281 25,869 (589) - 41,561
Total assets at $2,530,312 $1,312,045 $197,349 $ - $4,039,706
December 31, 2000
Nine months ended
September 30, 2001:
Revenues $ 722,995 $ 307,469 $ 10,189 $ (901) $1,039,752
Net income (loss) 19,598 88,869 (3,685) - 104,782
Nine months ended
September 30, 2000:
Revenues $ 621,211 $ 124,019 $ 19,940 $ - $ 765,170
Net income (loss) 58,932 48,423 8,808 - 116,163
INDEPENDENT ACCOUNTANTS' REPORT
IDACORP, Inc.
Boise, Idaho
We have reviewed the accompanying consolidated balance sheet
and statement of capitalization of IDACORP, Inc. and
subsidiaries as of September 30, 2001, and the related
consolidated statements of income and comprehensive income
for the three and nine month periods ended September 30,
2001 and 2000 and consolidated statements of cash flows for
the nine month periods ended September 30, 2001 and 2000.
These financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with standards
established by the American Institute of Certified Public
Accountants. A review of interim financial information
consists principally of applying analytical procedures to
financial data and of making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the
United States of America, the objective of which is the
expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an
opinion.
Based on our review, we are not aware of any material
modifications that should be made to such consolidated
financial statements for them to be in conformity with
accounting principles generally accepted in the United
States of America.
We have previously audited, in accordance with auditing
standards generally accepted in the United States of
America, the consolidated balance sheet and statement of
capitalization of IDACORP, Inc. and subsidiaries as of
December 31, 2000, and the related consolidated statements
of income, comprehensive income, retained earnings, and cash
flows for the year then ended (not presented herein); and in
our report dated February 1, 2001, we expressed an
unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in
the accompanying consolidated balance sheet and statement of
capitalization as of December 31, 2000 is fairly stated, in
all material respects, in relation to the consolidated
balance sheet and statement of capitalization from which it
has been derived.
DELOITTE & TOUCHE LLP
Boise, Idaho
October 24, 2001
Idaho Power Company
Consolidated Statements of Income
Three Months Ended
September 30,
2001 2000
(Thousands of Dollars)
REVENUES:
General business $185,830 $158,611
Off system sales 91,654 61,179
Other revenues 8,808 11,749
Total revenues 286,292 231,539
EXPENSES:
Operation:
Purchased power 228,460 139,243
Fuel expense 25,947 23,811
Power cost adjustment (57,770) (45,612)
Other 36,515 35,505
Maintenance 13,829 13,676
Depreciation 21,894 19,933
Taxes other than income taxes 4,947 5,024
Total expenses 273,822 191,580
INCOME FROM OPERATIONS 12,470 39,959
OTHER INCOME:
Allowance for equity funds used
during construction 173 696
Other - Net 4,930 2,206
Total other income 5,103 2,902
INTEREST CHARGES:
Interest on long-term debt 13,770 13,217
Other interest 2,450 1,042
Allowance for borrowed funds
used during construction (879) (609)
Total interest charges 15,341 13,650
INCOME BEFORE INCOME TAXES 2,232 29,211
INCOME TAXES 958 11,419
INCOME FROM CONTINUING OPERATIONS 1,274 17,792
DISCONTINUED OPERATIONS:
Income from operations of energy
marketing transferred to parent
(net of income taxes of $17,010) - 25,303
NET INCOME 1,274 43,095
Dividends on preferred stock 1,374 1,511
EARNINGS (LOSS) ON COMMON STOCK $ (100) $ 41,584
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Income
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars)
REVENUES:
General business $475,158 $420,993
Off system sales 205,552 161,158
Other revenues 33,828 28,803
Total revenues 714,538 610,954
EXPENSES:
Operation:
Purchased power 523,165 253,762
Fuel expense 73,545 68,526
Power cost adjustment (184,102) (64,297)
Other 108,055 108,626
Maintenance 41,046 36,589
Depreciation 64,293 59,769
Taxes other than income taxes 15,591 15,914
Total expenses 641,593 478,889
INCOME FROM OPERATIONS 72,945 132,065
OTHER INCOME:
Allowance for equity funds used
during construction 758 1,787
Other - Net 12,108 9,018
Total other income 12,866 10,805
INTEREST CHARGES:
Interest on long-term debt 41,943 39,575
Other interest 7,270 3,433
Allowance for borrowed funds
used during construction (3,295) (1,620)
Total interest charges 45,918 41,388
INCOME BEFORE INCOME TAXES 39,893 101,482
INCOME TAXES 15,549 38,127
INCOME FROM CONTINUING OPERATIONS 24,344 63,355
DISCONTINUED OPERATIONS:
Income from operations of energy
marketing transferred to parent
(net of income taxes of $33,574
in 2001 and $30,668 in 2000) 49,943 45,620
NET INCOME 74,287 108,975
Dividends on preferred stock 4,128 4,423
EARNINGS ON COMMON STOCK $ 70,159 $104,552
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Assets
September 30, December 31,
2001 2000
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,941,236 $2,799,590
Accumulated provision for
depreciation (1,201,079) (1,142,572)
In service - Net 1,740,157 1,657,018
Construction work in progress 102,852 130,477
Held for future use 2,232 2,167
Electric plant - Net 1,845,241 1,789,662
INVESTMENTS AND OTHER PROPERTY 18,368 21,502
CURRENT ASSETS:
Cash and cash equivalents 26,918 83,494
Receivables:
Customer 93,786 74,225
Allowance for uncollectible
accounts (1,397) (1,397)
Notes 2,895 2,945
Employee notes 5,170 4,742
Related parties 62,058 311
Other 2,306 4,943
Derivative assets 1,133 -
Taxes receivable 16,566 -
Accrued unbilled revenues 32,427 44,825
Materials and supplies (at average
cost) 22,599 24,685
Fuel stock (at average cost) 6,797 5,105
Prepayments 26,611 24,145
Regulatory assets associated with
income taxes 13,054 8,672
Regulatory assets - derivatives 55,136 -
Net assets of discontinued
operations - 37,702
Total current assets 366,059 314,397
DEFERRED DEBITS:
American Falls and Milner water
rights 31,585 31,585
Company-owned life insurance 39,627 39,554
Regulatory assets associated with
income taxes 198,240 204,880
Regulatory assets - PCA 308,107 119,905
Regulatory assets - long-term
derivatives 15,229 -
Regulatory assets - other 38,816 45,750
Other 52,032 49,857
Total deferred debits 683,636 491,531
TOTAL $2,913,304 $2,617,092
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Liabilities and Capitalization
September 30, December 31,
2001 2000
(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
Premium on capital stock 362,570 362,430
Capital stock expense (4,113) (4,024)
Retained earnings 331,615 313,800
Accumulated other comprehensive
income (loss) (3,536) (921)
Total common stock equity 780,567 765,316
Preferred stock 104,524 105,066
Long-term debt 829,202 808,977
Total capitalization 1,714,293 1,679,359
CURRENT LIABILITIES:
Long-term debt due within one year 77 30,077
Notes payable 244,000 59,700
Accounts payable 123,354 164,237
Notes and accounts payable to
related parties 4,516 4,212
Derivative liabilities 56,270 -
Taxes accrued - 12,983
Interest accrued 19,793 15,002
Deferred income taxes 13,054 8,672
Other 11,688 18,460
Total current liabilities 472,752 313,343
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment tax credits 65,856 66,050
Deferred income taxes 544,020 452,404
Derivative liabilities - long-term 15,229 -
Regulatory liabilities associated
with income taxes 39,979 40,230
Regulatory liabilities - other 4,178 4,621
Other 56,997 61,085
Total deferred credits 726,259 624,390
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $2,913,304 $2,617,092
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Capitalization
September 30, December 31,
2001 % 2000 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 94,031 $ 94,031
Premium on capital stock 362,570 362,430
Capital stock expense (4,113) (4,024)
Retained earnings 331,615 313,800
Accumulated other
comprehensive income (loss) (3,536) (921)
Total common stock equity 780,567 46 765,316 46
PREFERRED STOCK:
4% preferred stock 14,524 15,066
7.68% Series, serial preferred
stock 15,000 15,000
7.07% Series, serial preferred
stock 25,000 25,000
Auction rate preferred stock 50,000 50,000
Total preferred stock 104,524 6 105,066 6
LONG-TERM DEBT:
First mortgage bonds:
6.93% Series due 2001 - 30,000
6.85% Series due 2002 27,000 27,000
6.40% Series due 2003 80,000 80,000
8 % Series due 2004 50,000 50,000
5.83% Series due 2005 60,000 60,000
7.38% Series due 2007 80,000 80,000
7.20% Series due 2009 80,000 80,000
6.60% Series due 2011 120,000 -
Maturing 2021 through
2031 with rates ranging
from 7.5% to 9.52% 130,000 230,000
Total first mortgage
bonds 627,000 637,000
Amount due within one year - (30,000)
Net first mortgage bonds 627,000 607,000
Pollution control revenue
bonds:
8.30% Series 1984 due 2014 49,800 49,800
6.05% Series 1996A due 2026 68,100 68,100
Variable Rate Series 1996B
due 2026 24,200 24,200
Variable Rate Series 1996C
due 2026 24,000 24,000
Variable Rate Series 2000
due 2007 4,360 4,360
Total pollution control
revenue bonds 170,460 170,460
REA notes 1,282 1,339
Amount due within one year (77) (77)
Net REA notes 1,205 1,262
American Falls bond guarantee 19,885 19,885
Milner Dam note guarantee 11,700 11,700
Unamortized premium/discount - (1,048) (1,330)
Net
Total long-term debt 829,202 48 808,977 48
TOTAL CAPITALIZATION $1,714,293 100 $1,679,359 100
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Cash Flows
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 74,287 $108,975
Adjustments to reconcile net income
to net cash provided by (used
in) operating activities:
Allowance for uncollectible
accounts 20,174 -
Unrealized gains from energy
marketing activities (101,461) (4,022)
Depreciation and amortization 73,740 67,750
Deferred taxes and investment tax
credits 99,391 28,355
Undistributed earnings of
affiliates 1,897 (1,490)
Accrued PCA costs (188,202) (65,190)
Changes in (net of effects of
transfers to parent):
Accounts receivable and
prepayments (13,047) (97,311)
Accrued unbilled revenue 12,398 (2,175)
Materials and supplies and
fuel stock 394 2,621
Accounts payable 8,276 102,452
Taxes accrued (29,549) 1,288
Other current assets and
liabilities 167 (7,117)
Other - net (4,892) (6,341)
Net cash provided by (used in)
operating activities (46,427) 127,795
INVESTING ACTIVITIES:
Additions to utility plant (120,871) (88,944)
Net cash of affiliates transferred
to parent - (4,737)
Other - net (3,182) 1,722
Net cash used in investing
activities (124,053) (91,959)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 120,000 -
Pollution control revenue bonds - 4,360
Retirement of:
First mortgage bonds (130,000) (80,000)
Pollution control revenue bonds - (4,360)
Dividends on common stock (52,343) (52,386)
Dividends on preferred stock (4,128) (4,423)
Increase (decrease) in short-term
borrowings 184,300 13,277
Other - net (3,925) (504)
Net cash provided by (used in)
financing activities 113,904 (124,036)
Net decrease in cash and cash
equivalents (56,576) (88,200)
Cash and cash equivalents at
beginning of period 83,494 95,038
Cash and cash equivalents at end of
period $ 26,918 $ 6,838
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash (received) paid during the
period for:
Income taxes $(15,059) $ 43,483
Interest (net of amount
capitalized) 39,058 41,263
Net assets of affiliates
transferred to parent as
dividend - 22,090
Net assets transferred to parent
for notes receivable 76,250 -
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Comprehensive Income
Three Months Ended
September 30,
2001 2000
(Thousands of Dollars)
NET INCOME $ 1,274 $43,095
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on (1,008) 249
securities (net of tax of ($655) and
$162)
TOTAL COMPREHENSIVE INCOME $ 266 $43,344
The accompanying notes are an integral part of these statements.
Nine Months Ended
September 30,
2001 2000
(Thousands of Dollars)
NET INCOME $74,287 $108,975
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on (2,615) 992
securities (net of tax of ($1,580)
and $67)
TOTAL COMPREHENSIVE INCOME $71,672 $109,967
The accompanying notes are an integral part of these statements.
Idaho Power Company
Notes to the Consolidated Financial Statements
On January 1, 2000 IPC's ownership interests in two
subsidiaries were transferred to IDACORP at book value,
total assets of $108 million and net assets of $22 million.
Except as modified below, the Notes to the Consolidated
Financial Statements of IDACORP also contained in this Form
10-Q are incorporated herein by reference insofar as they
relate to IPC.
Note 1 - Summary of Significant Accounting
Policies
Note 3 - Preferred Stock of Idaho Power
Company
Note 4 - Financing
Note 5 - Commitments and Contingent
Liabilities
Note 6 - Regulatory Issues
Note 7 - Derivative Financial Instruments
2. INCOME TAXES:
IPC's effective tax rate for the first nine months increased
from 38.7 percent in 2000 to 39.8 percent in 2001.
Reconciliations between the statutory income tax rate and
the effective rates are as follows (in thousands of
dollars):
Nine Months Ended September 30,
2001 2000
Amount Rate Amount Rate
Computed income taxes
based on statutory federal
income tax rate $ 43,193 35.0% $ 62,220 35.0%
Changes in taxes resulting
from:
Investment tax credits (2,329) (1.9) (2,313) (1.3)
Repair allowance (2,100) (1.7) (2,100) (1.2)
Pension expense (1,368) (1.1) (1,420) (0.8)
State income taxes 6,604 5.4 9,154 5.1
Depreciation 6,325 5.1 5,154 2.9
Other (1,202) (1.0) (1,900) (1.0)
Total provision for
federal and state
income taxes $ 49,123 39.8% $ 68,795 38.7%
8. INDUSTRY SEGMENT INFORMATION:
Based on the transfer of Energy Marketing discussed in Note
9, substantially all of IPC consists of one operating
segment, Utility Operations. The Utility Operations segment
has two primary sources of income, the regulated operation
of IPC and income from Bridger Coal Company, an
unconsolidated joint venture also subject to regulation.
IPC's regulated operations include the generation,
transmission, distribution, purchase and sale of
electricity.
9. DISCONTINUED OPERATIONS
Effective June 11, 2001, IPC transferred its wholesale
electricity marketing operations ("Energy Marketing") to
IDACORP Energy L.P. (IE). IE is a Delaware limited
partnership with IDACORP, Inc. as its sole general partner
and IDACORP Energy Services Co., a wholly owned subsidiary
of IDACORP, Inc. as its sole limited partner.
Energy Marketing net assets transferred consist primarily of
energy trading contracts and trading accounts receivable and
accounts payable. The results of operations of Energy
Marketing were previously reported on IPC's Statements of
Income as "Energy marketing activities - net." For all
periods presented, Energy Marketing is reported as a
discontinued operation. The Consolidated Financial
Statements have been restated to conform to the discontinued
operations presentation.
In exchange for the transfer of Energy Marketing to IE, IPC
received a partnership interest in IE, which was transferred
to IDACORP in exchange for notes receivable from IDACORP
totaling approximately $76 million. This amount
approximates the historical book value of the transferred
Energy Marketing net assets on May 31, 2001 of $21 million
and retained intercompany tax liabilities of $55 million.
The notes receivable are due over periods of one to ten
years and bear interest at IDACORP's overall variable short-
term borrowing rate which was 4.56% at September 30, 2001.
The net assets identified as part of the disposition of
Energy Marketing are reported as "Net assets of discontinued
operations" on IPC's consolidated balance sheet and
consisted of the following at:
May 31, December 31,
2001 2000
(Thousands of Dollars)
Property, plant and equipment $ 551 $ 1,021
- net
Investments and other property 864 382
Current assets 489,526 1,070,645
Current liabilities (481,762) (1,031,686)
Other net noncurrent assets 67,071 (2,660)
and liabilities
Net assets of discontinued $ 76,250 $ 37,702
operations
INDEPENDENT ACCOUNTANTS' REPORT
Idaho Power Company
Boise, Idaho
We have reviewed the accompanying consolidated balance sheet
and statement of capitalization of Idaho Power Company and
subsidiaries as of September 30, 2001, and the related
consolidated statements of income and comprehensive income
for the three and nine month periods ended September 30,
2001 and 2000 and consolidated statements of cash flows for
the nine month periods ended September 30, 2001 and 2000.
These financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with standards
established by the American Institute of Certified Public
Accountants. A review of interim financial information
consists principally of applying analytical procedures to
financial data and of making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the
United States of America, the objective of which is the
expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an
opinion.
Based on our review, we are not aware of any material
modifications that should be made to such consolidated
financial statements for them to be in conformity with
accounting principles generally accepted in the United
States of America.
We have previously audited, in accordance with auditing
standards generally accepted in the United States of
America, the consolidated balance sheet and statement of
capitalization of Idaho Power Company and subsidiaries as of
December 31, 2000, and the related consolidated statements
of income, comprehensive income, retained earnings, and cash
flows for the year then ended (not presented herein); and in
our report dated February 1, 2001, we expressed an
unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in
the accompanying consolidated balance sheet and statement of
capitalization as of December 31, 2000 is fairly stated, in
all material respects, in relation to the consolidated
balance sheet and statement of capitalization from which it
has been derived.
DELOITTE & TOUCHE LLP
Boise, Idaho
October 24, 2001
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERTIONS
In Management's Discussion and Analysis (MD&A) we explain
the general financial condition and results of operations
for IDACORP, Inc. and subsidiaries (IDACORP or the Company)
and for Idaho Power Company and subsidiaries (IPC). IDACORP
is a holding company formed in 1998 as the parent of IPC and
several other entities.
IPC is an electric utility with a service territory covering
over 20,000 square miles in southern Idaho and eastern
Oregon, and is the parent of Idaho Energy Resources, Co., a
joint venturer in Bridger Coal Company, which supplies coal
to IPC's Jim Bridger generating plant. Until June 2001, IPC
also conducted electricity marketing operations. In that
month, those operations were transferred to IDACORP's
subsidiary IDACORP Energy. IPC's financial statements show
these transferred operations as Discontinued Operations.
IDACORP's other significant operating subsidiaries are:
IDACORP Energy - marketer of electricity and natural
gas in 31 states and two Canadian provinces;
Ida-West Energy - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services - affordable housing and
other real estate investments;
Rocky Mountain Communications (RMC) - commercial and
residential Internet service provider;
IDACOMM - provider of telecommunications services;
IDACORP Services - products and services for homes and
businesses.
Except where we indicate otherwise, this discussion explains
the material changes in results of operations and the
financial condition of both IDACORP and IPC. This MD&A
should be read in conjunction with the accompanying
consolidated financial statements of both IDACORP and IPC.
This discussion updates our MD&A included in our Annual
Report on Form 10-K for the year ended December 31, 2000.
This discussion should be read in conjunction with the
discussion in the annual report.
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 and IPC in this 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 FERC, the IPUC, the OPUC,
and the PUCN, with respect to allowed rates of return,
industry and rate structure, acquisition and disposal of
assets and facilities, operations and construction of plant
facilities, recovery of purchased power and other capital
investments, and present or prospective wholesale and retail
competition (including but not limited to retail wheeling
and transmission costs);
the current energy situation in the western United
States;
economic and geographic factors including political and
economic risks;
the occurrence of significant disasters, such as the
attack on September 11, 2001;
changes in and compliance with environmental and safety
laws and policies;
weather conditions;
population growth rates and demographic patterns;
competition for retail and wholesale customers;
pricing and transportation of commodities;
market demand, including structural market changes;
changes in tax rates or policies or in rates of
inflation;
changes in project costs;
unanticipated changes in operating expenses and capital
expenditures;
capital market conditions;
competition for new energy development opportunities;and
legal and administrative proceedings (whether civil or
criminal) and settlements that influence the business and
profitability of the Company.
Any forward-looking statement speaks only as of the date on
which such statement is made. New factors emerge from time
to time and it is not possible for management to predict all
such factors, nor can it assess the impact of any such
factor on the business, or the extent to which any factor,
or combination of factors, may cause results to differ
materially from those contained in any forward-looking
statement.
RESULTS OF OPERATIONS
In this section we discuss the factors that affected our
earnings, beginning with a general overview, then discussing
results for each of our operating segments.
Earnings per share 3rd Quarter Year-to-date
(EPS)
2001 2000 2001 2000
Utility operations $0.00 $0.43 $0.52 $1.57
Energy marketing 0.93 0.69 2.38 1.29
Other (0.02) (0.01) (0.10) 0.23
Total $0.91 $1.11 $2.80 $3.09
EPS from utility operations decreased due to increased power
supply costs resulting from a decline in hydroelectric
generating conditions and increased prices paid for
purchased power. These increased costs are partially offset
by increased general business revenues resulting from rate
increases and customer growth, and the deferral of expenses
related to our power cost adjustment mechanism. In the
third quarter IPC's earnings per share were reduced $0.18 by
an $11.4 million write-off of amounts disallowed in IPC's
PCA rate case.
Our net income from energy marketing activities increased 34
percent, or $9 million, for the quarter and 83 percent, or
$40 million, year-to-date, reflecting the expansion of
marketing activities in terms of volume, services and
geographic area.
EPS from IDACORP's other businesses decreased year-to-date
due to the sale of our Hermiston project in 2000, which
contributed approximately $0.22 per share in 2000 and due to
increased losses at IdaTech and RMC in 2001.
Utility Operations
This section discusses IPC's utility operations, which are
subject to regulation by, among others, the state regulatory
commissions of Idaho and Oregon and the FERC.
General Business Revenue
The following table presents IPC's general business revenue
and sales for the quarters and nine months ended September
30, 2001 and 2000 (in thousands):
3rd Quarter Year-to-date
Revenue MWH Revenue MWH
2001 2000 2001 2000 2001 2000 2001 2000
Residential $ 60,593 $ 52,187 934 996 $180,739 $156,939 3,111 3,081
Commercial 45,339 34,928 883 894 117,046 95,088 2,526 2,475
Industrial 40,921 31,199 939 1,099 109,491 96,085 3,001 3,596
Irrigation 38,977 40,297 769 1,074 67,882 72,881 1,342 1,926
Total $185,830 $158,611 3,525 4,063 $475,158 $420,993 9,980 11,078
Our general business revenue is dependent on many factors,
including the number of customers we serve, the rates we
charge, and economic and weather conditions. The increases
in revenues in 2001 are due primarily to the following:
our annual power cost adjustment increased average
rates from Idaho customers subject to the PCA, resulting in
increased revenues of $39 million for the quarter and $72
million year-to-date. We discuss the PCA in more detail
below in "Regulatory Issues - PCA."
population growth in our service territory increased
our customer count by 2.6 percent. This increase resulted
in a $6 million increase in revenues for the quarter and $14
million year-to-date.
we implemented programs to reduce system load. Our
load-reduction program with irrigators was the main factor
in the reductions in sales to irrigation customers of 28
percent for the quarter and 30 percent year-to-date. These
reductions decreased revenues approximately $14 million for
the quarter and $26 million year-to-date.
conservation and other usage factors affected sales to
residential, commercial and small industrial customers,
decreasing revenue by $6 million for the quarter and $3
million year-to-date.
changes in contract provisions and sales volumes to
certain large industrial customers resulted in increased
revenues from these customers of $3 million for the quarter.
Year-to-date revenues from these customers did not change
significantly from last year.
Off-system sales
Off-system sales consist primarily of long-term sales
contracts and opportunity sales of surplus system energy.
The changes in 2001 are the result of two factors,
substantial increases in electricity prices in the IPC
region, and changes in availability of excess energy due to
hydroelectric generating conditions and system requirements.
The following table presents IPC's off-system sales for the
quarters and nine-month periods ended September 30, 2001 and
2000 (in thousands):
3rd Quarter Year-to-date
Revenues MWHs Revenues MWHs
2001 2000 2001 2000 2001 2000 2001 2000
$91,654 $61,179 744 670 $205,552 $161,158 1,674 3,910
Power Supply
Power supply components of income from operations include
off-system sales (described above) and purchased power,
fuel, and PCA expenses (analyzed below).
Net power supply costs increased $79 million for the quarter
and $155 million year-to-date. The portion of net power
supply costs not recoverable through the PCA and Oregon
excess power cost mechanisms increased by $14 million for
the quarter and $51 million year-to-date.
Purchased power
Purchased power expenses increased $89 million for the
quarter and $269 million year-to-date. The increase for the
quarter is due primarily to a 64 percent increase in the
average cost per MWH purchased, and the year-to-date
increase is due primarily to a 126 percent increase in the
average cost per MWH, offset by a nine percent decrease in
MWH purchased. The price increases are the result of the
volatile western United States electricity markets. The
following table presents IPC's purchased power expense for
the quarters and nine-month periods ended September 30, 2001
and 2000 (in thousands):
3rd Quarter Year-to-date
Expense MWHs Expense MWHs
2001 2000 2001 2000 2001 2000 2001 2000
$228,460 $139,243 1,762 1,762 $523,165 $253,762 3,424 3,753
Fuel expense
Fuel expenses increased moderately in 2001, due to increases
in the average price of coal used. The following table
presents IPC's fuel expense and thermal generation for the
quarters and nine-month periods ended September 30, 2001 and
2000 (in thousands):
3rd Quarter Year-to-date
Expense MWHs generated Expense MWHs generated
2001 2000 2001 2000 2001 2000 2001 2000
$25,947 $23,811 1,993 1,933 $73,545 $68,526 5,640 5,562
PCA
The PCA decreased $12 million for the quarter and $120
million year-to-date. The PCA expense component is related
to our PCA regulatory mechanism. Under this mechanism, we
record an expense when actual power supply costs are below
the costs forecasted in the annual PCA filing, and record a
reduction of expense when actual power supply costs are
above the forecast. In 2001, actual power supply costs
have been significantly greater than forecasted, resulting
in a large PCA credit. Our PCA credits would have been
larger, except that in September 2001 we wrote off $11
million of accrued PCA costs that have not been authorized
for recovery by the IPUC. We discuss the PCA in more detail
below in "Regulatory Issues."
Other expenses
Other operating and maintenance expenses were substantially
unchanged for the quarter and increased $3 million year-to-
date. Quarterly increases of $3 million for both
transmission costs and generator rent were offset by smaller
decreases in administrative and general, thermal plant and
distribution expenses. The year-to-date increase results
from increases of $4 million for generator rent and $3
million for customer expenses, primarily for our new
customer information system. These increases were partially
offset by decreases in administrative and general and
distribution expenses.
Energy Marketing
Energy marketing revenues increased $32 million for the
quarter and $183 million year-to-date. This increase
reflects the increase in volumes traded and the market price
for power. Physical electricity transactions that settled
during the quarter totaled 11.4 million MWH in 2001 compared
to 7 million MWH in 2000. Year-to-date, volumes increased
from 16.3 million MWH to 24.5 million MWH. Average
transaction prices in 2001 were approximately 50 percent
higher for the quarter and nearly three times higher year-to-
date. IE transacts business in 31 states and two Canadian
provinces. Products offered include physical energy
commodities, risk management services, asset optimization
services and structured products designed specific to
customer preferences.
Energy marketing expenses increased $17 million for the
quarter and $115 million year-to-date. The increase for the
quarter is due primarily to increased transmission costs of
$19 million. The year-to-date increase is due to increased
transmission costs of $80 million, $22 million in reserves
recorded in 2001 related to trading activities conducted
with California entities in 2000 and a $13 million increase
in general and administrative costs.
We discuss the ongoing California energy situation,
including its effect on operations and liquidity, below in
"California Energy Situation."
Other Operations
Other operations include the results of operations of
IDACORP's diversified subsidiaries, including Ida-West
Energy, IdaTech, IDACORP Financial Services, RMC, IDACOMM
and IDACORP Services.
Revenues
Revenues from other diversified operations decreased $5
million for the quarter and $10 million year-to-date.
Applied Power Company (APC), sold in January 2001, had
contributed $5 million for the quarter and $13 million year-
to-date in 2000. Loss of this revenue was partially offset
by revenues from RMC, which we acquired in August 2000. RMC
revenue increased $1 million in the quarter, and $5 million
year-to-date.
Expenses
Other operating expenses decreased $4 million for the
quarter, and $2 million year-to-date. For the quarter, a $5
million decrease in expenses due to the sale of APC was
offset by $1 million of expenses at RMC, which was acquired
in August 2000, and $1 million from increased product
development activities at IdaTech, our fuel cell technology
subsidiary. Year-to-date, expense decreases of $13 million
related to APC were offset by a $7 million increase from RMC
and $5 million increase from IdaTech.
Other Income
IDACORP's other income decreased $10 million year-to-date.
In March 2000 we recorded a pre-tax gain of $14 million on
the sale of our interest in the Hermiston Power Project, a
536-MW, gas-fired cogeneration project located near
Hermiston, Oregon.
Income Taxes
Income taxes decreased for the quarter and year-to-date due
primarily to the decrease in net income before taxes.
LIQUIDITY AND CAPITAL RESOURCES:
Cash Flow
IDACORP's net cash used by operations totaled $29 million
for the nine months ended September 30, 2001. The most
significant factor affecting operating cash flows was
increased power supply costs in excess of amounts recovered
through the PCA rate adjustments. The balance in our PCA
regulatory asset has increased $188 million year-to-date.
In addition, power supply costs not recoverable through the
PCA or Oregon excess power cost mechanism were $68 million
year-to-date.
Though cash flows from operations were positively affected
when we begin realizing increased revenues from the May 2001
PCA adjustment (see "PCA" below), we also expect that
continuing poor water conditions and high purchased power
costs will result in power supply costs that continue to
exceed the amounts we are recovering in rates in the 2001-
2002 PCA rate year. These conditions have had an adverse
effect on our operating cash flows and have required
additional short-term borrowing and may require other
financing options.
Working Capital
The changes in IDACORP's customer receivables and accounts
payable are attributed primarily to trading volumes and
prices on settled energy trading contracts. The increase in
IDACORP's allowance for uncollectible accounts of $19
million is due to additional reserves against settled energy
trading contracts related to trading activities in the
California markets.
The remaining changes in working capital are attributed to
timing and normal business activity.
Cash Expenditures
We forecast that internal cash generation after dividends
will provide approximately 154 percent of total capital
requirements for the remainder of 2001 and 77 percent during
the three-year period 2002-2004. We expect to finance our
utility construction programs and other capital requirements
with both internally generated funds and, to the extent
necessary, externally financed capital.
Financing Program
At September 30, 2001, IPC had regulatory authority to incur
up to $500 million of short-term indebtedness. In September
2001 IPC issued $100 million of floating-rate notes due in
September 2002. At September 30, 2001, IPC's short term
borrowing totaled $244 million.
We have bank line of credit facilities established at both
IPC and IDACORP. IPC has a $120 million multi-year
revolving credit facility that expires in December 2001
under which we pay a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond
rating. We also established on April 27, 2001, a 364-day
credit facility for up to $165 million in support of IPC's
ongoing operations. IPC's commercial paper may be issued
subject to the regulatory maximum.
IDACORP has separately established a $50 million three-year
credit facility that expires in December 2001, and a $375
million 364-day credit facility that expires in March 2002.
Under these facilities we pay a facility fee on the
commitment, quarterly in arrears, based on IPC's First
Mortgage Bond rating. At September 30, 2001, short-term
borrowing on these facilities totaled $81.5 million.
IDACORP currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured
debt (including medium-term notes) and preferred or common
stock. At September 30, 2001 none had been issued.
In March 2000 IPC filed a $200 million shelf registration
statement that could be used for both first mortgage bonds
(including medium-term notes), unsecured debt or preferred
stock. In December 2000, IPC issued $80 million of Secured
Medium Term Notes. Proceeds were used in January 2001 for
the early redemption of $75 million of First Mortgage Bonds
originally due in 2021. In March 2001, IPC issued $120
million of Secured Medium Term Notes, with the proceeds used
to reduce short-term borrowing incurred in support of
ongoing long-term construction requirements. At September
30, 2001, no amounts remain to be issued on this shelf
registration.
In August 2001 IPC filed a $200 million shelf registration
that can be used for both first mortgage bonds (including
medium-term notes), unsecured debt or preferred stock. At
September 30, 2001, no amounts had been issued.
OTHER MATTERS:
Regulatory Issues:
Idaho 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 May, are based on
forecasts of net power supply expenses. During the year,
the difference between actual and forecasted costs is
deferred with interest. The balance of this deferral,
called a true-up, is then included in the calculation of the
next year's PCA adjustment.
In its 2001 PCA filing, IPC requested recovery of $227.4
million of power supply costs. In May, the IPUC authorized
recovery of $168.3 million, but deferred recovery of $59.1
million pending further review. The approved amount
resulted in an average rate increase of 31.6 percent. After
conducting hearings on the remaining $59.1 million, the IPUC
authorized recovery of $47.7 million plus $1.2 million of
accrued interest, beginning in October 2001. The remaining
$11.4 million not recovered in rates from the PCA filing was
written off in September 2001.
Of the $227 million requested by IPC, $185 million related
to the true-up of power supply costs incurred in the 2000-
2001 PCA year and $42 million was for recovery of excess
power supply costs forecasted in the 2001-2002 PCA year.
The forecast amount, however, underestimates expected power
supply costs. Reservoir water is significantly lower than
forecast, necessitating the use of higher cost alternatives
to hydro generations.
As part of the May 2001 PCA, the IPUC required IPC to
implement a three-tiered rate structure for Idaho
residential customers. The IPUC determined that the
approved rates for residential customers should increase as
a customer's electricity consumption increases. The
residential rate increases are 14.4 percent for the first
800 kWh of usage, 28.8 percent for the next 1,200 kWh, and
62 percent for usage over 2,000 kWh.
On August 31, IPC filed a request with the IPUC to implement
a rate credit to qualifying residential and small farm
customers. The credit is the result of a settlement
agreement between IPC and the Bonneville Power
Administration (BPA), which will pass on the benefits of the
Federal Columbia River Power System. IPC estimates the
credit could be as much as $3.60 per month for residential
customers who use 1,200 kWh per month and $300 per month for
farm customers that use 100,000 kWh. The IPUC, by Order No.
28868, approved the credit to be passed to the qualified
customers effective October 1, 2001.
In its May 2001 rate authorization the IPUC also directed
IPC to reinstate a comprehensive conservation program given
the current volatility of market prices and the opportunity
to incorporate long-term conservation. In response to that
directive, IPC filed a report of present energy efficiency
activities, a list of conservation measures, an examination
of funding options and a detailed program structure that
could be implemented should the Commission determine that
additional conservation programs, including the funding of
these programs, is in the public interest.
On October 18, 2001 IPC filed an application with the IPUC
for an order approving the costs to be included in the 2002-
2003 PCA for the Irrigation Load Reduction Program and
Astaris Load Reduction Agreement. These two programs were
implemented in 2001 to reduce demand and approved by the
IPUC and OPUC. The costs included in the application were
$58.6 million for the Irrigation Load Reduction Program and
$42.2 million for the Astaris Load Reduction Agreement,
representing total costs through September 2001. IPC will
file a second application requesting approval for
subsequently incurred costs.
Oregon Excess Power Costs
IPC filed an application with the OPUC to begin recovering
extraordinary 2001power supply costs in its Oregon
jurisdiction. On June 18, 2001, the OPUC approved new rates
that will recover $0.8 million over the next year. Under
the provisions of the deferred accounting statute,
ORS757.259(6), annual rate recovery of deferred amounts is
limited to $0.8 million or 3% of IPC's 2000 gross revenues
in Oregon. IPC filed on October 5, 2001 to recovery an
additional 3% of extraordinary supply costs deferred for
2001. The OPUC will hear the request November 20, 2001 and
a decision could be made as early as November 28, 2001. The
Oregon deferral balance is $12.2 million as of September 30,
2001 net of the June 18th recovery.
IPC filed with the OPUC a request to implement the same BPA
program as in Idaho. The OPUC held a public meeting on
October 22, 2001. The OPUC approved the Company's request
to implement the BPA residential and small farm energy
credit (BPA Credit) for the benefits derived during the
period October 1, 2001 though September 30, 2006.
IPC is also planning to file for a comprehensive
conservation program in its Oregon jurisdiction.
New Idaho Legislation
Idaho Senate Bill No. 1255, chapter 15, title 61, Idaho Code
(the Act), was signed into law on April 10, 2001. It
authorizes the IPUC to allow public utilities or their
assignees to issue energy cost recovery bonds to finance,
among other things, significant increases in the cost of
electricity resulting from shortfalls in available
hydroelectric power for which higher-cost replacement power
must be substituted. The legislative intent of the Act is
to provide utilities with a mechanism for recovery of these
increased costs while leveling the rate impact of such
increases on the utilities' customers. Energy cost recovery
bonds must have an expected maturity date no later than five
years after issuance and a legal maturity date no later than
seven years after issuance.
Under the Act, the IPUC may issue an energy cost financing
order in favor of the utility, pursuant to which a charge,
known as an energy cost bond charge, would be included on
the bills of the utility's Idaho customers. The Act
requires the energy cost bond charge to remain in effect
until the energy cost recovery bonds are paid in full. In
addition, the charge is subject to periodic adjustment to
ensure the timely payment of principal and interest on the
energy cost recovery bonds and the recovery of certain
related expenses.
An energy cost financing order creates energy cost property,
which includes the right to receive revenues arising from
the energy cost bond charge. Energy cost property may be
sold or otherwise transferred to, among others, the assignee
of the public utility that issues energy cost recovery
bonds, and it may be pledged as security for such bonds.
The Act requires that, before it issues an energy cost
financing order, the IPUC must find that the public interest
would be better served if increased costs reflected in a
fuel or power cost adjustment and related expenses were
recovered through the issuance of energy cost recovery bonds
than if these amounts were recovered over a one-year period
assuming a conventional financing.
Before seeking to recover costs through the issuance of
energy bonds, IPC must file with the IPUC a proposal to
establish a threshold energy cost amount, or trigger. In
June 2001, the IPUC approved IPC's application, establishing
a one cent per kWh trigger amount.
California Energy Situation
As a component of IPC's non-utility energy trading in the
state of California, IPC, in January 1999, entered into a
participation agreement with the California Power Exchange
(CalPX), a California non-profit public benefit corporation.
The CalPX, at that time, operated a wholesale electricity
market in California by acting as a clearinghouse through
which electricity was bought and sold. Pursuant to the
participation agreement, IPC could sell power to the CalPX
under the terms and conditions of the CalPX Tariff. Under
the participation agreement, if a participant in the CalPX
defaults on a payment to the exchange, the other
participants are required to pay their allocated share of
the default amount to the exchange. The allocated shares
are based upon the level of trading activity, which includes
both power sales and purchases, of each participant during
the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2.2
million - a "default share invoice" - as a result of an
alleged Southern California Edison (SCE) payment default of
$214.5 million for power purchases. We made this payment.
On January 24, 2001, IPC terminated the participation
agreement. On February 8, 2001, the CalPX sent a further
invoice for $5.2 million, due February 20, 2001, as a result
of alleged payment defaults by SCE, Pacific Gas and Electric
Company (PG&E), and others. However, because the CalPX owed
IPC $11.3 million for power sold to the CalPX in November
and December 2000, IPC did not pay the February 8th invoice.
IPC essentially discontinued energy trading with California
entities in December 2000.
IPC believes that the default invoices were not proper and
that it owes no further amounts to the CalPX. IPC has
pursued all available remedies in its efforts to collect
amounts owed to it by the CalPX.
On February 20, 2001, IPC filed a petition with FERC to
intervene in a proceeding which requested the FERC to
suspend the use of the CalPX charge back methodology and
provides for further oversight in the CalPX's implementation
of its default mitigation procedures.
A preliminary injunction was granted by a Federal Judge in
the Federal District Court for the Central District of
California enjoining the CalPX from declaring any CalPX
participant in default under the terms of the CalPX Tariff.
On March 9, 2001, the CalPX filed for Chapter 11 protection
with the U.S. Bankruptcy Court, Central District of
California.
In April 2001, PG&E filed for bankruptcy. The CalPX and the
California Independent System Operator (Cal ISO) were also
creditors of PG&E. To the extent that PG&E's bankruptcy
filing affects the collectibility of our receivables from
the CalPX and Cal ISO our receivables from these entities
are at greater risk.
Also in April 2001, the FERC issued an order stating that it
was establishing price mitigation for sales in the
California wholesale electricity market. Subsequently, in
its June 19, 2001 Order, the FERC expanded that price
mitigation plan to the entire western United States
electrically interconnected system. That plan included the
potential for orders directing electricity sellers into
California since October 2, 2000 to refund portions of their
sales prices if the FERC determined that those prices were
not just and reasonable, and therefore not in compliance
with the Federal Power Act. The June 19 Order also required
all buyers and sellers in the Cal ISO market during the
subject time-frame, to participate in settlement discussions
to explore the potential for resolution of these issues
without further FERC action. The settlement discussions
failed to bring resolution of the refund issue and as a
result, the FERC Chief Judge submitted a Report and
Recommendation to the FERC recommending that the FERC adopt
his methodology set forth in his report and set for
evidentiary hearing an analysis of the Cal ISO's and the
CalPX's spot markets to determine what refunds may be due
upon application of that methodology. The Judge recommended
that his methodology should be applied to all sellers except
those who at the evidentiary hearing are able to demonstrate
that their costs exceed the results of the recommended
methodology.
On July 25, 2001, the FERC issued an order establishing
evidentiary hearing procedures related to the scope and
methodology for calculating refunds related to transactions
in the spot markets operated by the Cal ISO and the CalPX
during the period October 2, 2000 through June 20, 2001. As
to potential refunds, if any, the Company believes that its
exposure will be more than offset by amounts due it from
California entities.
In addition, the July 25, 2001 FERC order established
another proceeding to explore whether there may have been
unjust and unreasonable charges for spot market sales in the
Pacific Northwest during the period December 25, 2000
through June 20, 2001. The FERC Administrative Law Judge
(ALJ) submitted her recommendations and findings to the FERC
on September 24, 2001. The ALJ found that the prices were
just and reasonable and therefore no refunds should be
allowed. Procedurally, the ALJ's decision is a
recommendation to the commissioners of the FERC. The FERC
is not bound to accept any or all of it. The next step is
for the FERC to issue an order in response to the ALJ's
recommendation. The FERC has issued a notice soliciting
comments on this case. Although there is no binding
timeframe for the FERC to issue its order, it may issue an
order in the next 30 to 60 days. Actions of the FERC are
appealable to the United States Court of Appeals. The
Company will continue to monitor all proceedings to
determine the impact on the Company. Counsel has been
retained in connection with the CalPX and PG&E bankruptcies
and FERC proceedings.
Effective June 11, 2001, IPC transferred its wholesale
electricity marketing operations to IE. IE is a Delaware
limited partnership with IDACORP, Inc. as its sole general
partner and IDACORP Energy Services Co., a wholly-owned
subsidiary of IDACORP, Inc., as its sole limited partner.
(See Note 9 to the Idaho Power Company financial
statements.)
Effective with the June 11 transfer, the outstanding
receivables and payables with the CalPX and Cal ISO were
assigned from IPC to IE. At September 30, 2001, the CalPX
and Cal ISO owed $13 million and $31 million respectively
for energy sales made to them by IPC in November and
December 2000. In addition, at September 30, 2001, IE had
accrued but not paid $35.1 million due to the Cal ISO as an
offset to the outstanding receivable. IE has accrued a
reserve of $41 million against these receivables.
These reserves were calculated taking into account the
continued deterioration of the California energy markets
and, for the less-than-investment-grade receivables, by
using a model that estimates the probability of default and
the estimated recovery amounts of such receivables.
Based on the reserves recorded as of September 30, 2001, the
Company believes that the future collectibility of these
receivables or any potential refunds ordered by the FERC
would not have a significant impact on operations or
liquidity.
Energy Marketing
Effective June 11, 2001, IPC transferred its wholesale
electricity marketing operations to IDACORP Energy, L.P.
(IE). Prior to June 11, all wholesale electric trading
operations were conducted by IPC. IE is a Delaware limited
partnership with IDACORP, Inc. as its sole general partner
and IDACORP Energy Services Co., a wholly owned subsidiary
of IDACORP, Inc. as its sole limited partner.
Concurrent with the transfer, IE and IPC have entered into
an Electricity Supply Management Services Agreement
(Agreement). IPC has received approval of the Agreement
from the IPUC, the OPUC and the FERC. Under the Agreement,
IPC will continue to own, operate and maintain its electric
generating equipment and transmission facilities (System
Resources) and be responsible for system reliability. IE
will manage and dispatch the System Resources to balance
generation and load within the IPC operating area.
When buying and selling energy, the high volatility of
energy prices can have a significant impact on
profitability. 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 risk
management committees, comprised of Company officers, to
oversee the risk management program as defined in the risk
management policy. The program is intended to manage,
within approved limits, commodity price risk, credit risk,
and other risks related to the energy trading business.
As of September 30, 2001, the aggregate potential daily loss
from our energy trading activity due to adverse market price
movements is estimated to be $0.8 million at a 95 percent
confidence interval and for a holding period of one business
day (common industry parameters). This potential loss in
earnings was estimated using an analytic value-at-risk
methodology. This methodology computes value-at-risk based
upon forward market prices and historical volatilities as of
September 30, 2001. Value-at-risk is a statistical
calculation of potential loss and not a forecast of expected
loss and as such, is not guaranteed to occur. The
confidence level and holding period imply that there is a
five percent chance that the daily loss could exceed $0.8
million. The daily value-at-risk estimate is managed within
approved limits and is reported daily to the Risk Management
Committee.
Power supply and demand management
Our utility operations are being affected by the electricity
market and generation conditions in the western United
States. The tremendous unpredictability of prices for
purchased power, along with increasing demand and reduced
hydroelectric generation, have combined to produce
substantial increases in our costs to supply power.
We monitor the effect of streamflow conditions on Brownlee
Reservoir, the water source for our three Hells Canyon
hydroelectric facilities. In a typical year, these three
projects combine to produce about half of our generated
electricity. Inflows into Brownlee result from a
combination of precipitation, storage and ground water
conditions. Inflows into Brownlee during the April-July
2001 runoff period was 2.4 MAF. This compares to the 73-
year median of 5.1 MAF and last year's 4.4 MAF. Hydro
generation on IPC's system decreased 28 percent or 0.5
million MWH for the quarter and 39 percent or 2.7 million
MWH year-to-date compared to 2000 because of these poor
generating conditions. These conditions are expected to
continue through this water year.
These conditions set in motion a number of programs to
decrease our reliance on potentially volatile wholesale
power markets. These programs are designed to reduce
overall energy use, decrease peak demand levels, and
increase generation within our service territory.
Significant programs include the following:
IPC placed its Danskin Power Plant in service in
September 2001. Danskin is a 90-MW natural gas-fired
combustion turbine located near Mountain Home, Idaho. The
fuel expense associated with the operation of this plant is
included in the PCA. IPC has also sited mobile generators
at various locations in Boise. These generators can supply
up to 40 MW of additional generating capacity if the need
arises. The fuel costs are included in the PCA.
The IPUC approved a two-year agreement through which
IPC will compensate its largest industrial customer,
Astaris, for reducing its load by 50 MW. The load
reduction, effective in April 2001, should provide IPC an
additional 300,000 MWHs in 2001. Astaris gave IPC notice it
will cease production at the end of 2001. Astaris, formerly
FMC, said it is shifting away from elemental phosphorus
production, which relies on the use of high-energy furnaces,
to a process relying on wet, purified phosphoric acid. It
is unclear at this time what impact the plant closure will
have on IPC.
In March 2001, the IPUC and OPUC approved a program
that compensates large customers who voluntarily reduce load
by at least one MW when requested to do so by IPC. There
have been no participants in this program to date.
The IPUC and OPUC have also approved a program that
compensates irrigation customers capable of reducing usage
by at least 100 MWH. The program is projected to reduce
usage by 500,000 MWH, more than 25 percent of normal
irrigation load.
As part of the May 2001 PCA discussed above, the IPUC
required IPC to implement a tiered rate structure for Idaho
residential customers. This rate structure increases rates
as a customer's usage increases.
IPC is also studying residential and commercial
conservation programs, e.g. fluorescent light bulbs, AC heat
pump servicing, and methods of funding such programs.
New accounting pronouncements
In July 2001 the FASB issued SFAS 141, "Business
Combinations," which addresses accounting and reporting for
business combinations. SFAS 141 requires that all business
combinations initiated after June 30, 2001 be accounted for
using one method, the purchase method. The Company does not
believe the adoption will have a significant affect on its
financial statements.
Also in July 2001 the FASB issued SFAS 142 "Goodwill and
Other Intangible Assets," which is effective January 1,
2002. SFAS 142 requires, among other things, the
discontinuance of goodwill amortization. In addition, the
standard includes provisions for the reclassification of
certain existing recognized intangibles as goodwill,
reassessment of the useful lives of existing recognized
intangibles, reclassification of certain intangibles out of
previously reported goodwill and the identification of
reporting units for purposes of assessing potential future
impairments of goodwill. SFAS 142 also requires the Company
to complete a transitional goodwill impairment test six
months from the date of adoption. The Company is currently
assessing but has not yet determined the impact of SFAS 142
on its financial position and results of operations.
In August 2001 the FASB issued SFAS 143 "Accounting for
Asset Retirement Obligations" which is effective for fiscal
years beginning after June 15, 2002. This Statement
addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. An obligation
may result from the acquisition, construction, development
and the normal operation of a long-lived asset. The Company
is currently assessing but has not yet determined the impact
of SFAS 143 on its financial position and results of
operations.
Also in August 2001 the FASB issued SFAS 144 "Accounting for
the Impairment or Disposal of Long-Lived Assets" which is
effective for fiscal years beginning after December 15,
2001. SFAS 144 addresses financial accounting and reporting
for the impairment or disposal of long-lived assets
superseding SFAS 121 "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed of."
The Company is currently assessing but has not yet
determined the impact of SFAS 144 on its financial position
and results of operations.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The information required by this item is included in Item 2
"Management's Discussion and Analysis of Financial Condition
and Results of Operations" under "Other Matters - Energy
Marketing."
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Exhibit File As
Number Exhibit
*2 333-48031 2 Agreement and Plan of Exchange
between IDACORP, Inc., and IPC
dated as of February 2, 1998.
*3(a) 33-00440 4(a)(xiii) Restated Articles of
Incorporation of IPC as filed
with the Secretary of State of
Idaho on June 30, 1989.
*3(a)(i) 33-65720 4(a)(ii) Statement of Resolution
Establishing Terms of Flexible
Auction Series A, Serial
Preferred Stock, Without Par
Value (cumulative stated value of
$100,000 per share) of IPC, as
filed with the Secretary of State
of Idaho on November 5, 1991.
*3(a)(ii) 33-65720 4(a)(iii) Statement of Resolution
Establishing Terms of 7.07%
Serial Preferred Stock, Without
Par Value (cumulative stated
value of $100 per share) of IPC,
as filed with the Secretary of
State of Idaho on June 30, 1993.
*3(a)(iii) 1-3198 3(a)(iii) Articles of Amendment to Restated
Form 10-Q Articles of Incorporation of IPC
for as filed with the Secretary of
6/30/00 State of Idaho on June 15, 2000.
*3(b) 1-3198 3(c) By-laws of IPC amended on
Form 10-Q September 9, 1999, and presently
for in effect.
9/30/99
*3(c) 33-56071 3(d) Articles of Share Exchange, as
filed with the Secretary of State
of Idaho on September 29, 1998.
*3(d) 333-64737 3.1 Articles of Incorporation of
IDACORP, Inc.
*3(e) 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(f) 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(g) 1-14465 3(c) Amended Bylaws of IDACORP, Inc.
Form 10-Q as of July 8, 1999.
for
6/30/99
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated
as of October 1, 1937, between
IPC and Bankers Trust Company and
R. G. Page, as Trustees.
*4(a)(ii) IPC Supplemental Indentures to
Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 1, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
1-3198 4 Thirty-fifth November 1, 2000
Form 8-K
Dated
11/21/00
1-3198 4 Thirty-sixth September 27, 2001
Form 8-K
Dated
9/27/01
*4(b) 33-65720 10(c) 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
dated IDACORP, Inc. and the Bank of New
September York as 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
Form 10-K Senior Management Employees - a
for 1994 non-qualified, deferred
compensation plan effective
August 1, 1996.
*10(h)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive
Form 10-K Plan for senior management
for 1994 employees of IPC effective
January 1, 1995.
*10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan
Form 10-K for officers and key executives
for 1994 of IDACORP, Inc. and IPC
effective July 1, 1994.
*10(h)(iv)1 1-14465 10(h)(iv) The Revised Security Plan for
1-3198 Board of Directors - a non-
Form 10-K qualified, deferred compensation
for 1998 plan effective August 1, 1996,
revised March 2, 1999.
*10(h)(v)1 14465 10(e) IDACORP, Inc. Non-Employee
Form 10-Q Directors Stock Compensation Plan
for as of May 17, 1999.
6/30/99
*10(h)(vi) 1-3198 10(y) Executive Employment Agreement
Form 10-K dated November 20, 1996 between
for 1997 IPC and Richard R. Riazzi.
*10(h)(vii) 1-3198 10(g) Executive Employment Agreement
Form 10-Q dated April 12, 1999 between IPC
for and Marlene Williams.
6/30/99
*10(h)(viii) 1-14465 10(h) Agreement between IDACORP, Inc.
Form 10-Q and Jan B. Packwood, J. LaMont
for Keen, James C. Miller, Richard
9/30/99 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)
15 Letter Re: Unaudited Interim
Financial Information.
21 Subsidiaries of IDACORP, Inc. and
IPC.
1 Compensatory plan
(b)Reports on Form 8-K. The following reports on Form 8-K
were filed for the three months ended September 30,
2001.
Items Reported Date of Filed By
Report
Item 5 - Other Events August 10, 2001 IDACORP, Inc.
Item 5 - Other Events September 27,2001 IPC
Item 7 - Financial Statements
and Exhibits
* Previously filed and Incorporated herein by Reference.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
IDACORP, Inc.
(Registrant)
Date November 8, 2001 By: /s/ J LaMont Keen
J LaMont Keen
Senior Vice President
Administration
and Chief Financial Officer
(Principal Financial
Officer)
Date November 8, 2001 By: /s/ Darrel T Anderson
Darrel T Anderson
Vice President-Finance
and Treasurer
(Principal Accounting
Officer)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
IDAHO POWER COMPANY
(Registrant)
Date November 8, 2001 By: /s/ J LaMont Keen
J LaMont Keen
Senior Vice President
Administration
and Chief Financial Officer
(Principal Financial
Officer)
Date November 8, 2001 By: /s/ Darrel T Anderson
Darrel T Anderson
Vice President-Finance
and Treasurer
(Principal Accounting
Officer)