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 March 31,September 30, 1998
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-3198
IDAHO POWER COMPANY
(Exact name of registrant as specified in its charter)
Idaho 82-0130980
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1221 W. Idaho Street, Boise, Idaho 83702-5627
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (208) 388-2200
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
Indicate the number of shares outstanding of each
of the issuer's classes of common stock, as of the
latest practicable date.
Number of shares of Common Stock, $2.50 par value,
outstanding as of March 31,September 30, 1998 is 37,612,351.
IDAHO POWER COMPANY
Index
Page No
Definitions 2
Part I. Financial Information:
Item 1.
Financial Statements
Consolidated Statements of Income 33-4
Consolidated Balance Sheets 4-55-6
Consolidated Statements of Cash Flows 67
Consolidated Statements of Capitalization 78
Notes to Consolidated Financial Statements 8-109-12
Independent Accountants' Report 1113
Item 2.
Management's Discussion and Analysis of Financial Condition and
Results of Operations 12-1414-20
Part II. Other Information:
Item 1.
Legal Proceedings 21
Item 6.
Exhibits and Reports on Form 8-K 15-1922-25
Signatures 2026
DEFINITIONS
AFDC Allowance For Funds Used During Construction
BPA Bonneville Power Administration
CSPP Cogeneration and Small Power Production
DSM Demand Side Management
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
IPUC Idaho Public Utilities Commission
OPUC Oregon Public Utilities Commission
kWh kilowatt-hour
MAF Million Acre-Feet
MMbtu Million British Thermal Units
MOU Memorandum of Understanding
MWH Megawatt-Hour
OPUC Oregon Public Utilities Commission
PCA Power Cost Adjustment
REA Rural Electrification Administration
SFAS Statement of Financial Accounting 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.expressions
and includes but are not limited to statements under the heading
"Other Matters" concerning the outcome of the Company's Year 2000
efforts.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
IDAHO POWER COMPANY
Consolidated Statements of Income
Three Months Ended
March 31,September 30,
1998 1997
(Thousands of Dollars)
REVENUES:
Total general business $112,223 $112,961$149,411 $125,407
Off system sales 116,413 34,839236,738 84,776
Other 6,229 6,991
Total revenues 9,534 7,647
Total Revenues 238,170 155,447392,378 217,174
EXPENSES:
Operation:
Purchased power 94,206 19,559251,641 88,392
Fuel expense 20,720 14,48525,054 22,756
Power cost adjustment 475 (1,244)(1,338) (6,893)
Other 32,947 29,91834,455 33,652
Maintenance 9,028 10,30310,709 11,958
Depreciation 18,895 17,52219,140 18,099
Taxes other than income taxes 5,344 5,8315,258 5,333
Total expenses 181,615 96,374344,919 173,297
INCOME FROM OPERATIONS 56,555 59,07347,459 43,877
OTHER INCOME:
Allowance for equity funds used
during construction 46 4
Gas trading activities - Net (718) -net (1,380) (523)
Other - Net 1,705 3,389net 5,037 2,646
Total other income 987 3,3893,703 2,127
INTEREST CHARGES:
Interest on long-term debt 13,037 13,80513,106 13,147
Other interest 2,086 2,0482,223 1,120
Total interest charges 15,123 15,85315,329 14,267
Allowance for borrowed funds used
during construction (161) (132)(274) (119)
Net interest charges 14,962 15,72115,055 14,148
INCOME BEFORE INCOME TAXES 42,580 46,74136,107 31,856
INCOME TAXES 13,125 16,36112,392 10,715
NET INCOME 29,455 30,38023,715 21,141
Dividends on preferred stock 1,405 1,3941,410 1,422
EARNINGS ON COMMON STOCK $28,050 $28,986$ 22,305 $ 19,719
AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612
Earnings per share of common stock
(basic and diluted) 0.75 0.770.59 0.52
Dividends paid per share of common stock $ 0.465 $ 0.465
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
Consolidated Statements of Income
Nine Months Ended
September 30,
1998 1997
(Thousands of Dollars)
REVENUES:
Total general business $382,631 $363,497
Off system sales 446,129 155,053
Other 23,411 21,045
Total revenues 852,171 539,595
EXPENSES:
Operation:
Purchased power 421,893 145,019
Fuel expense 60,077 48,030
Power cost adjustment 12,951 (5,961)
Other 106,008 101,567
Maintenance 31,262 35,830
Depreciation 57,080 53,664
Taxes other than income taxes 16,103 16,721
Total expenses 705,374 394,870
INCOME FROM OPERATIONS 146,797 144,725
OTHER INCOME:
Allowance for equity funds used
during construction 71 2
Gas trading - net (3,005) (662)
Other - net 10,665 8,430
Total other income 7,731 7,770
INTEREST CHARGES:
Interest on long-term debt 39,204 40,110
Other 6,368 5,001
Total interest charges 45,572 45,111
Allowance for borrowed funds used
during construction (714) (379)
Net interest charges 44,858 44,732
INCOME BEFORE INCOME TAXES 109,670 107,763
INCOME TAXES 34,730 36,202
NET INCOME 74,940 71,561
Dividends on preferred stock 4,232 3,481
EARNINGS ON COMMON STOCK $ 70,708 $68,080
AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612
Earnings per share of common stock
(basic and diluted) 1.88 1.81
Dividends paid per share of common stock $ 1.395 $ 1.395
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
Consolidated Balance Sheets
ASSETS
March 31,September 30, December 31,
1998 1997
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,630,643$2,627,264 $2,605,697
Accumulated provision for depreciation (960,926)(1,000,692) (942,400)
In service - Net 1,669,717net 1,626,572 1,663,297
Construction work in progress 47,66272,080 51,892
Held for future use 1,738 1,738
Electric plant - Net 1,719,117net 1,700,390 1,716,927
INVESTMENTS AND OTHER PROPERTY 104,926128,504 97,065
CURRENT ASSETS:
Cash and cash equivalents 3,3384,916 6,905
Receivables:
Customer 79,113142,228 63,076
Allowance for uncollectible accounts (1,397) (1,397)
Gas Operations 28,403trading 22,493 42,128
Notes 4,6885,059 4,613
Employee notes receivable 4,6524,551 4,757
Other 9,6135,351 8,854
Accrued unbilled revenue 23,79626,465 33,312
Materials and supplies (at average cost) 29,79229,776 29,156
Fuel stock (at average cost) 8,2536,268 7,172
Prepayments 14,09215,186 15,381
Regulatory assets associated with income taxes 3,0323,063 3,164
Total current assets 207,375263,959 217,121
DEFERRED DEBITS:
American Falls and Milner water rights 32,05531,830 32,055
Company-owned life insurance 50,79335,323 51,915
Regulatory assets associated with income taxes 200,661200,813 198,521
Regulatory assets - other 87,80873,970 90,239
Other 44,51165,630 47,973
Total deferred debits 415,828407,566 420,703
TOTAL $2,447,246$2,500,419 $2,451,816
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
Consolidated Balance Sheets
CAPITALIZATION & LIABILITIES
March 31,September 30, December 31,
1998 1997
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity - $2.50 par value
(shares authorized 50,000,000;
shares outstanding - 37,612,351) $722,011 $711,818$ 730,045 $ 711,818
Preferred stock 106,627106,208 106,697
Long-term debt 750,116816,035 746,142
Total capitalization 1,578,7541,652,288 1,564,657
CURRENT LIABILITIES:
Long-term debt due within one year 33,9996,285 33,998
Notes payable 48,81622,439 57,516
Accounts payable 60,928130,037 69,064
Accounts payable gas operations 28,817trading 27,642 42,874
Taxes accrued 38,26527,482 24,295
Interest accrued 16,51814,719 17,918
Deferred income taxes 3,0323,063 3,164
Other 13,90211,450 13,703
Total current liabilities 244,277243,117 262,532
DEFERRED CREDITS:
Regulatory liabilities associated with
accumulated
deferred investment tax credits 70,32069,706 70,196
Deferred income taxes 433,234432,369 423,736
Regulatory liabilities associated
with income taxes 27,62227,635 34,072
Regulatory liabilities - other 4835,050 509
Other 92,55670,254 96,114
Total deferred credits 624,215605,014 624,627
COMMITMENTS AND CONTINGENT LIABILITIES
TOTAL $2,447,246$2,500,419 $2,451,816
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
Consolidated Statements Of Cash Flows
ThreeNine Months Ended
March 31,September 30,
1998 1997
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $29,455 $30,380$ 74,940 $ 71,561
Adjustments to reconcile net income to net cash:
Depreciation & amortization 21,654 19,40062,895 60,141
Deferred taxes and investment tax credits 1,997 1,360(656) 7,497
Accrued PCA costs 12,743 (5,995)
Change in:
Accounts receivable and prepayments (1,752) (5,704)(56,060) (42,339)
Accrued unbilled revenue 9,516 7,0166,847 2,258
Increase in margin accounts at brokers (7,157) (106)
Materials &and supplies and fuel stock (1,717) (1,676)284 (1,242)
Accounts payable (22,193) (10,876)45,741 24,663
Taxes payable 13,969 18,650Accrued 3,187 13,167
Other current assets and liabilities (1,172) 3,047(5,327) 4,669
Other - net (1,255) (2,964)(2,594) (4,030)
Net cash provided by operating activities 48,502 58,633134,843 130,244
INVESTING ACTIVITIES:
Additions to utility plant (21,324) (24,586)(60,136) (69,855)
Investments in affordable housing (5,000) (9,896)projects (19,139) (17,021)
Other (2,024) (448)- net (7,486) 598
Net cash used in investing activities (28,348) (34,930)(86,761) (86,278)
FINANCING ACTIVITIES:
Proceeds from issuance of:
Long-term debt-relateddebt related to affordable
housing 4,084 8,909projects 15,088 12,984
First mortgage bonds 60,000 -
Retirement of subsidiary long-term debt (3,316) (2,250)
Retirement of first mortgage bonds (30,000) -
Dividends on common stock (17,490) (17,971)(52,399) (52,415)
Dividends on preferred stock (1,405) (1,394)(4,232) (4,086)
Increase (decrease) in short-term borrowings (8,700) (12,423)(35,077) 4,254
Other - net (210) 75(135) (126)
Net cash provided by (used in)used in financing activities (23,721) (22,804)(50,071) (41,639)
Net increase (decrease) in cash and
cash equivalents (3,567) 899(1,989) 2,327
Cash and cash equivalents at beginning of period 6,905 7,928
Cash and cash equivalents at end of period $ 3,3384,916 $ 8,82710,255
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Income taxes 1,200 309$ 44,773 $ 27,429
Interest (net of amount capitalized) 15,102 14,60540,712 42,304
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
Consolidated Statements Of Capitalization
March 31,September 30,December 31,
1998 1997
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $94,031 $94,031
Premium on capital stock 361,849362,126 362,328
Capital stock expense (3,838)(3,828) (3,840)
Retained earnings 269,860277,607 259,299
Accumulated otherOther comprehensive income 109 -
Total common stock equity 722,011 45.7%730,045 44.2% 711,818 45.5%
PREFERRED STOCK:
4% preferred stock 16,62716,208 16,697
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 106,627 6.8106,208 6.4 106,697 6.8
LONG-TERM DEBT:
Utility:
First mortgage bonds:
5.33 % Series due 1998 30,000- 30,000
8.65 % Series due 2000 80,000 80,000
6.93 % Series due 2001 30,000 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 -
Maturing 2021 through 2031 with
rates from 7.5% to 9.52% 230,000 230,000
Total first mortgage bonds 527,000557,000 527,000
Amount due within one year (30,000)- (30,000)
Net first mortgage bonds 497,000557,000 497,000
Pollution control revenue bonds:
7 1/4% Series due 2008 4,360 4,360
8.30 % Series 1984 due 2014 49,800 49,800
6.05 % Series 1996A due 2026 68,100 68,100
Variable Rate Series 1996 B
and C due 2026 48,200 48,200
Total pollution control
revenue bonds 170,460 170,460
REA Notes 1,5431,507 1,561
Amount due within one year (73)(74) (72)
Net REA Notes 1,4701,433 1,489
American Falls bond guarantee 20,35520,130 20,355
Milner Dam note guarantee 11,700 11,700
Unamortized premium/discount - Net (1,612)(1,563) (1,637)
Net utility debt 699,373759,160 699,367
Subsidiaries:
Debt related to investments in
affordable housing with rates
ranging from 6.95%6.97% to 8.65%8.59% due
1998 to 2008 50,4692009 61,473 46,385
Other subsidiary debt 4,2001,613 4,316
Total subsidiary debt 54,66963,086 50,701
Amount due within one year (3,926)(6,211) (3,926)
Net subsidiary debt 50,74356,875 46,775
Total long-term debt 750,116 47.5816,035 49.4 746,142 47.7
TOTAL CAPITALIZATION $1,578,754$1,652,288 100.0% $1,564,657 100.0%
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF ACCOUNTING POLICIES:
Financial Statements
In the opinion of the Company, the accompanying unaudited
consolidated financial statements contain all adjustments
necessary to present fairly theits consolidated financial
position as of March 31,September 30, 1998 and theits consolidated
results of operations for the three and nine months ended
March 31,September 30, 1998 and 1997 and theits consolidated cash
flows for the threenine months ended March 31,September 30, 1998 and
1997. These financial statements do not contain the
complete detail or footnote disclosure concerning
accounting policies and other matters which would be
included in full year financial statements and, therefore,
they should be read in conjunction with the Company's
audited financial statements included in the Company's
Annual Report on Form 10-K for the year ended December 31,
1997. The results of operations for the interim periods
are not necessarily indicative of the results to be
expected for the full year.
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.
Revenues
In order to match revenues with associated expenses, the
Company accrues unbilled revenues for electric services
delivered to customers but not yet billed at month-end.
Comprehensive Income
The Company adopted SFAS 130, Reporting Comprehensive
Income, on January 1, 1998. The statement establishes
a
standardstandards for the reporting and displaying of
comprehensive income and its components in the Company's
financial statements.
For the quarterthree and nine months ended March 31,September 30, 1998,
the Company's total comprehensive income was not materially
different from net income. The components of total
comprehensive income include net income, the Company's
proportionate share of unrealized holding gains on
marketable securities held by an equity investee, and the
changes in the Company's additional minimum liability under a deferred
compensation plan for certain senior management employees
and directors.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash
equivalents include cash on hand and highly liquid
temporary investments with original maturity dates of
three months or less. The Company has changed the
presentation of operating activities in its statement of
cash flows from the direct method to the indirect method
effective for the quarter ended March 31,all periods reported in 1998. Previous
year's presentation has been restatedreclassified to conform with
the new method.presentation.
Management Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires
management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts
of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Gas OperationsTrading
The Company intends to be a competitive energy provider,
including both electricity and gas. In April 1997 the
Company opened a gas trading office in Houston, Texas to
serve the southern and eastern United States gas markets
and a Boise, Idaho office that serves the Northwest and
Canadian markets. The following table shows gas trading
activities for the quarterthree and nine month periods ended
March 31,September 30, 1998 and 1997 (thousands of dollars):
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
Gas revenues $ 97,158$77,544 $29,736 $258,022 $39,197
Cost of gas (97,166)
Administrative and General expenses (710)other - net (78,924) (30,259) (261,027) (39,859)
Gas trading activities - Net $(1,380) $ (718)(523) $ (3,005) $ (662)
Reclassifications
Certain items previously reported for periods prior to
March 31,September 30, 1998 have been reclassified to conform with
the current periodsperiod's presentation. Net income was not
affected by these reclassifications.
2. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating
to the Company's program for construction and operation of
facilities amounted to approximately $2.8$2.4 million at
March
31,September 30, 1998. The commitments are generally
revocable by the Company subject to reimbursement of
manufacturers' expenditures incurred and/or other
termination charges.
The Company is party to various legal claims, actions, and
complaints, certain of which 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 flow.
3. REGULATORY ISSUES:
The Company has a PCA mechanism that provides for annual
adjustments to the electric rates charged to Idaho retail
customers. These adjustments are based on forecasts of net
power supply costs, and take effect annually on May 16. The
difference between the actual costs incurred and the
forecasted costs are deferred, with interest, and trued-up in
the next annual rate adjustment.
So farThe May 16, 1998 adjustment increased electric rates $34.0
million over the 1997 rates and $17.3 million over base
rates. The increase was due primarily to the forecasted
return to more normal streamflow conditions from the near-
record conditions experienced in 1997, and rising costs
associated with mandatory purchases from CSPP projects.
Good water conditions and mild weather since the forecast
date have resulted in the current rate period, actualCompany currently recording a true-
up credit of $5.2 million at September 30, 1998. The credit
reflects power cost expenses have exceededsupply costs below those projected for the
1998 PCA forecast. The Company
has recorded a regulatory asset of $15.4 million as of March
31, 1998. TheAny additional variance that exists at
the end of the current rate period will be trued-up in the
next annual PCA adjustment.
On April 15, 1998 the Company filed its annual PCA request
with the IPUC. The filing requests a $37.1 million increase
over the 1997 rates. The increase is largely due to the
return to more normal streamflow conditions and rising costs
associated with mandatory purchases from CSPP projects. If
this request is approved, revenue from Idaho retail customers
will be $20.4 million greater than what would be recovered if
the Company was charging the base rates during this rate
period.
Under IPUC Order No. 26216, when the Company's actual
earnings in the Idaho jurisdiction in a given year exceed
an 11.75 percent return on year-end common equity through
1999, the Company will refund 50 percent of the excess at the same
time it makes its next PCA adjustment.excess.
In 1997, the
Company set aside an estimated $8.7$7.6 million of revenue accrued for the benefit
of its Idaho customers. Subsequently, this
amount was revised to $7.6 million,customers based on actual data. In the April 15, 1998 PCA filing, the Company requestedThe IPUC
ordered that this revised amountapproximately $5.0 million be applied against
the balance of demand-side conservation expenditures which are currently
recordedin
order to defer any rate increase associated with
conservation recovery until May 16, 1999, the same time as
the next PCA adjustment to rates. The Company has applied
to the IPUC to use approximately $2.4 million of the
remaining $2.6 million as reimbursement of deferred
expenses related to its participation in the Northwest
Energy Efficiency Alliance during 1997 and 1998.
The Company has sought changes to the regulatory treatment
of previously deferred DSM (conservation) expenses in both
Idaho and Oregon. In Idaho the Company requested in Case
No. IPC-E-97-12 that the IPUC authorize recovery of post-
1993 DSM expenses and an acceleration of the recovery of
DSM expenditures authorized in the last general rate case.
The Company requested a regulatory asset.five-year amortization instead of
the 24-year period previously adopted. In its Order No.
27660 issued on July 31, 1998, the IPUC set a new
amortization period of 12 years. The IPUC order reflects
an increase in annual revenue requirement of $3.1 million
for twelve years. As noted above, the Company is funding
the annual revenue requirement with revenue sharing
amounts until May 16, 1999. A notice of appeal has been
filed with the IPUC by a group of the Company's industrial
customers notifying the IPUC that its order has been
appealed to the Idaho Supreme Court.
In Oregon, the OPUC, in case No. UE 107, authorized the
amortization of the Oregon allocated share of the DSM
expenditures over five years. The OPUC allowed a rate
surcharge for extraordinary purchases to be replaced by an
identical charge to recover the amortization of the DSM
expenditures. This charge will recover approximately
$540,000 per year.
4. FINANCING:
The Company currently has a $200,000,000 shelf
registration statement that can be used for both First
Mortgage Bonds (including Medium Term Notes) and Preferred
StockStock. In September 1998, the Company issued $60,000,000
principal amount of which $143 million remains availableSecured Medium Term Notes 5.83% Series
due September 9, 2005. The proceeds from this issuance
was used to redeem at March 31,maturity, the $30,000,000 First
Mortgage Bonds 5.33% Series due September 1998, with the
balance used for repayment of commercial paper issued in
connection with the Company's ongoing business. This
issuance, combined with two issuances in 1996, has reduced
the remaining balance of the shelf registration to
$83,000,000 at September 30, 1998.
5. INCOME TAXES:
The effective tax rate for the first threenine months decreased
from 35.033.6 percent in 1997 to 30.831.7 percent in 1998. The table below displays aA
reconciliation between the statutory federal income tax rate of 35.0 percent and
the effective tax ratesrate for the threenine months ended March
31 (dollars are in thousands):September 30
is as follows:
1998 1997
Amount Rate Amount Rate
Computed income taxes based on
statutory federal income tax rate $14,903$38,385 35.0% $16,359$37,717 35.0%
Changes in taxes resulting from:
Current state income taxes 1,715 4.0 1,823 3.95,106 4.7 3,945 3.7
Settlement of prior year tax returns (1,500) (1.4) 0 0.0
Net depreciation 1,350 3.2 1,281 2.74,005 3.6 4,268 4.0
Investment tax credits restored (729) (1.7) (719) (1.5)(2,197) (2.0) (2,161) (2.0)
Removal costs (653) (1.5) (267) (0.6)(1,037) (0.9) (1,025) (0.9)
Repair allowance (782) (1.8) (782) (1.7)
Low income(2,346) (2.1) (2,346) (2.2)
Affordable housing credit (1,593) (3.7) (1,014) (2.2)(5,160) (4.7) (3,444) (3.2)
Other (1,086) (2.7) (320) (0.6)
$13,125 30.8% $16,361 35.0%(526) (0.5) (752) (0.8)
$34,730 31.7% $36,202 33.6%
6. PREFERRED STOCK:
The number of shares of preferred stock outstanding were
as follows:
March 31,September 30, December 31,
1998 1997
Cumulative, $100 par value:
4% preferred stock (authorized 215,000
166,271shares) 162,080 166,972
shares)
Serial preferred stock, 7.68% Series
150,000 150,000
(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,
250,000 250,000
(authorized 250,000 shares) 250,000 250,000
Auction rate preferred stock, $100,000
stated value,
(authorized 500 shares) 500 500
7. NEW ACCOUNTING PRONOUNCEMENTS:
In June 1998 the FASB issued SFAS No. 133 Accounting for
Derivative Instruments and Hedging Transactions. This
statement establishes accounting and reporting standards
for derivative financial instruments and other similar
financial instruments and for hedging activities. It is
effective for fiscal years beginning after June 15, 1999.
The Company is reviewing this statement to determine its
effects on the Company's accounting and reporting
requirements.
8. SUBSEQUENT EVENTS:
On October 1, 1998, the Company officially adopted a
holding company structure with the completion of a
statutory share exchange under which the outstanding
common stock of Idaho Power was exchanged on a share-for-
share basis for the common stock of IDACORP, Inc.
(IDACORP), and Idaho Power became a subsidiary of IDACORP.
The share exchange was effected pursuant to the terms of
an Agreement and Plan of Exchange dated February 2, 1998
and was approved by Idaho Power shareholders, the FERC,
and the regulatory commissions of Idaho, Oregon, Wyoming
and Nevada.
Following the share exchange, in October 1998 Idaho Power
transferred ownership of its subsidiaries Ida-West Energy
Company, IDACORP Energy Solutions Co. and IDACORP Retail
Enterprises Co. to IDACORP.
As has been the case with Idaho Power Company, a
"Shareholders Rights" plan is also in effect for IDACORP.
This plan, authorized by the Board of Directors of IDACORP
on September 10, 1998 and effective at the close of
business on October 1, 1998, is designed to ensure that
all shareholders receive fair and equal treatment in the
event of any proposal to acquire control of the Company.
This plan is substantially similar to the plan already in
effect for Idaho Power Company.
On September 30, 1998, IDACORP filed a $300,000,000 shelf
registration statement that can be used to issue Debt
Securities, Common Stock or Preferred Stock.
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 March 31,September 30, 1998, and the related
consolidated statements of income for the three and nine
month periods ended March 31,September 30, 1998 and 1997 and
consolidated statements of cash flows for the threenine month
periods ended March 31,September 30, 1998 and 1997. 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 making inquiries of persons responsible
for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with
generally accepted auditing standards, 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
generally accepted accounting principles.
We have previously audited, in accordance with generally
accepted auditing standards, the consolidated balance sheet
and statement of capitalization of Idaho Power Company and
subsidiaries as of December 31, 1997, and the related
consolidated statements of income, retained earnings, and
cash flows for the year then ended (not presented herein);
and in our report dated January 30, 1998, 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, 1997 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
Portland, Oregon
May 8,Boise, Idaho
November 2, 1998
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This discussionIn Management's Discussion and consolidatedAnalysis we explain the general
financial statements reflect thecondition and results of operations of Idaho Power Company and its wholly owned or
controlled subsidiaries. This discussion uses the terms Idaho
Power and the Company interchangeably to refer tofor Idaho Power and
its diversified business subsidiaries. As you read the
Management's Discussion and Analysis, it may be helpful to refer
to our Consolidated Statements of Income which present the
results of our operations for the three-month and nine-month
periods ended September 30, 1998 and 1997. In our discussion we
explain the significant quarterly and year-to-date changes in the
specific line items in the Consolidated Statements of Income.
This discussion updates the discussion which was included in our
1997 Annual Report on Form 10-K for the year ended December 31,
1997, and should be read in conjunction with it.
FORWARD-LOOKING INFORMATION
Certain matters discussedthat we discuss in this report are "forward-looking"forward-
looking statements" intended to qualify for the safe harbor from
liability established by the Private Securities Litigation Reform
Act of 1995. Such statements address future plans, objectives,
expectations, and events or conditions concerning various matters
such as capital expenditures, earnings, litigation, rate and
other regulatory matters, liquidity and capital resources,
accounting matters and accounting matters.includes statements under the heading
"Other Matters" concerning the outcome of the Company's
Year 2000 efforts. Actual results in each case could differ materially
from those currentlythe results anticipated in such statements, by reason of factorsfor
reasons including without limitations, electric utility
restructuring, including ongoing state and federal legislative
and regulatory activities; future economic conditions; legislation; regulation;
competition; and other circumstances affecting anticipated rates,
revenues and costs. With respect to the Company's Year 2000
efforts results could differ due to unanticipated developments
while implementing the modifications necessary to mitigate Year
2000 compliance problems, including the ability to locate and
correct all relevant computer codes in computer and embedded
systems, the indirect impacts of third parties with whom the
Company does business and who do not mitigate their Year 2000
compliance problems, and similar uncertainties. Any forward-lookingforward-
looking statement speaks only as of the date on which such
statement is made, and the Company
undertakeswe undertake no obligation to update any
forward-looking statement.
RESULTS OF OPERATIONS
Earnings Per Share and Book Value
Earnings per share of common stock (basic and diluted) were $0.75was $0.59
for the quarter ended March 31,September 30, 1998, a decreasean increase of $0.02 (2.6$0.07
(13.5 percent) from the same quarter last year. Earnings per
share (basic and diluted) was $1.88 for the nine months ended
September 30, 1998, an increase of $0.07 (3.9 percent) over last
year.
At March 31,September 30, 1998, the book value per share of common stock
was $19.20.$19.41, compared to $18.40 at the same date in 1997.
General Business Revenue
GeneralOur general business revenue is dependent on many factors,
including the number of customers revenue per MWH,we serve, the rates we charge,
and weather conditions.
Inconditions (temperature and precipitation) in our
service territory.
Compared to 1997, the first quarternumber of 1998,general business customers we
served increased 3.0 percent compared tofor the first quarter of 1997,and 2.9 percent for
the nine months ended September 30, 1998. This increase was due
primarily to economic growth in the Company'sour service territory.
TheHotter than normal summer temperatures contributed to an increase
in our energy sales during the quarter. Cooling degree days, a
common measure used in the utility industry to analyze demand,
were 35.4 percent above the same period in 1997 and 63.4 percent
above normal. Compared to the same quarter last year, MWH's sold
per general business customer increased 4.8 percent. For the
year, warmer winter temperatures and increased rainfall during
the growing season more than offset the hotter summer
temperatures, resulting in a 1.7 percent decrease in sales per
general business customer.
Our revenue per MWH decreased 1.9increased 10.4 percent for the quarter ended
and 4.1 percent for the nine months ended September 30, 1998,
compared to 1997. Revenue per MWH changes as a result of the
annual rate adjustments discussed below in "Power Cost
Adjustment.". Heating
degree days, a common measure used in
The combination of the utility industry to
analyze temperature-related demand, were 11.5 percent less than
the first quarter of 1997, and 19.4 percent below normal. Thisfactors just discussed resulted in a 1.6 percent decrease in the average MWH used per
customer. These three factors resulted in a 0.7 percent decrease$24.0
million (19.1 percent) increase in general business revenue.revenue for
the quarter and a $19.1 million (5.3 percent) increase year-to-
date, compared to 1997.
Off System Sales
Off-system sales are comprised of trading in the wholesale
electricity markets, long-term sales contracts, and opportunity
sales made when we have surplus energy available. The increaseincreases
in off-system revenue isare due primarily to a 158.483.9 percent increaseand 110.8
percent increases in MWH sold in the third quarter and year-to-
date, and to increased prices. The sales volume and price
increases were primarily from increased trading in the wholesale
electricity markets. We discuss our energy trading activity in
more detail below in "Other Matters."
Expenses
Purchased power expenses increased $74.6$163.2 million (381.6(184.7 percent),
for the quarter and $276.9 million (190.9 percent) year-to-date.
These increases are due to a 323.3primarily to129.8 percent increaseand 146.4
percent increases in MWHs purchased for the third quarter and
year-to-date, and to increased prices. These purchases were
primarily from
increased trading in the wholesale electricity markets.
Fuel expenses increased $6.2$2.3 million (43.1(10.1 percent), for the
quarter and $12.0 million (25.1 percent) year-to-date, due
primarily to a 50.222.2 percent increaseand 24.2 percent increases in MWHs
generated by Company'sour coal-fired power plants.plants for the quarter and year-
to-date. Generation by these plants was increased to meet retail
loads and take advantage of off systemoff-system sales opportunities.
The PCA (power cost adjustment) component of expenses increased
$1.7 million.$5.6 million for the quarter and $18.9 million year-to-date. The
PCA mechanism reducesincreases expenses when actual power supply costs are below
the costs forecasted in the annual PCA filing and decreases
expenses when actual power supply costs are above forecast and increases them when power supply costs are
belowthe forecast.
In the firstthird quarter of 1998, actual power supply costs were
slightly above what had been forecast; in 1997 actual power
supply costs were above the forecast to a greater degree. Year-to-
date, power supply costs have been significantly below forecast
while in 19971998, while they were somewhat above forecast. Theforecast in 1997. Our
1998 forecast anticipated near-normal streamflow conditions.
Actual conditions have been better than forecasted. We discuss
the PCA is discussedand streamflow conditions in more detail below in "Power Cost Adjustment."Other
Matters."
Other operation expenses increased $3.0$4.4 million (4.4 percent)
year-to-date. These increases were due to increases
in electricity wheeling charges, relatedprimarily to increased
MWH sales,administrative and increased payroll-related expenses.labor expenses and a $1.2 million increase in
transmission charges from other utilities.
Maintenance expenses decreased $1.3$1.2 million (10.4 percent) for
the quarter and $4.6 million (12.7 percent) year-to-date. These
decreases are due primarily to decreased boiler maintenance expenses at the Jim
Bridger plant.plant and reduced maintenance on overhead lines. During
the first quarterhalf of 1997 extensive maintenance was performed at the
Bridger plant and on the plant while the Company maximized the use of its
hydro generation facilities.transmission lines.
Other
Other income decreased $2.4increased $1.6 million (74.1 percent) for the three
month period ended September 30 compared to the prior year. This
increase is due primarily to $2.3 million of carrying charges on
1994-7 demand-side management (DSM) charges, offset by a $1.0$0.9
million increase in expenses related to Company initiatives and
$0.7 million of losses on gas trading activities. In addition,We began
trading natural gas in 1997 the Company recorded a $0.6 million gain on the salethird quarter of an investment.1997. Since then,
trading volumes and related administrative costs have increased
significantly. We discuss our energy trading activities in more
detail below in "Other Matters."
Income taxes decreasedincreased $1.7 million (15.7 percent) for the
quarter, due primarily to the decrease inincreased net income before taxes.
Year-to-date income taxes and a decrease in the effective tax rate.
The effective tax rate has decreased $1.5 million primarily as a result offrom
increased affordable housing tax credits and from affordable housing andadjustments
associated with the impactsettlement of expectedprior year tax settlements for the years 1993-1995.returns, offset
by increased net income.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
For the threenine months ended March 31,September 30, 1998, the Companywe generated $48.5$134.8
million in net cash from operations. After deducting for both
common and preferred dividends, net cash generation from
operations provided approximately $29.6$78.2 million for the Company'sour
construction program and other capital requirements.
Cash Expenditures
Idaho Power estimatesWe estimate that itsour cash construction program for 1998 will
require approximately $100.0 million. This estimate is subject
to revision in light of changing economic, regulatory,
environmental, and conservation factors. During the first threenine
months of 1998, the Company expendedwe spent approximately $21.3$60.1 million for
construction. Idaho Power'sOur primary financial commitments and obligations
are related to contracts and purchase orders associated with
its ongoing construction program.programs. To the extent required, the Company expectswe expect
to finance these commitments and obligations by using both
internally generated funds and externally financed capital. At
March 31,September 30, 1998, the Company'sour short-term borrowings totaled $48.8$22.4
million.
Financing Program
The CompanyWe currently hashave a $200,000,000$200 million shelf registration statement
that can be used for both First Mortgage Bonds (including Medium
Term Notes) and Preferred Stock of which $143$83 million remains
available at March 31,September 30, 1998. Idaho Power'sIn September, 1998 we issued
$60 million principal amount of Secured Medium Term Notes, 5.83%
series, due September 9, 2005. The proceeds from this issuance
were used to redeem $30 million of First Mortgage Bonds which
matured in September 1998, and to reduce the balance of
commercial paper issued in connection with ongoing business.
Our objective is to maintain capitalization ratios of
approximately 45 percent common equity, 5 to 10 percent preferred
stock, and the balance in long-term debt. For the twelve-month
period ended March 31, the Company'sSeptember 30, our consolidated pre-tax interest
coverage was 3.243.30 times.
OTHER MATTERS
Holding Company
On October 1, 1998, Idaho Power Company officially adopted a
holding company structure with the completion of a statutory
share exchange under which the outstanding common stock of Idaho
Power was exchanged on a share-for-share basis for the common
stock of IDACORP, Inc. (IDACORP) , and Idaho Power became a
subsidiary of IDACORP. We had previously received approval to
form the holding company from our shareholders, the state
regulatory commissions in Idaho, Oregon, Nevada and Wyoming and
the FERC.
Following the share exchange, Idaho Power transferred ownership
of three subsidiaries, Ida-West Energy Company (Ida-West),
IDACORP Energy Solutions Co. (IES), and IDACORP Retail
Enterprises Co. (IREC) to IDACORP.
Shareholders of Idaho Power Company common stock will retain
their current certificates and any new common stock issued on
or after October 1, 1998 will be issued as IDACORP stock.
Common shares will trade on the New York and Pacific Stock
Exchanges under the existing symbol "IDA".
Idaho Power Chairman and Chief Executive Officer (CEO) Joseph
W. Marshall will serve as Chairman and CEO of IDACORP. Jan
B. Packwood, Idaho Power President and Chief Operating
Officer and J. LaMont Keen, Vice President, Chief Financial
Officer and Treasurer will assume similar positions in
IDACORP.
Ida-West holds investments in 13 operating hydroelectric plants
with a total generating capacity of 72 MW. IES, currently a
shell, will conduct non-regulated marketing functions under the
new holding company. IREC owns a 25% interest in Allied Utility
Network, a Georgia-based limited liability company which develops
and assists with the marketing of non-utility goods and services
to retail customers.
Our purpose in forming the holding company is to create a
structure under which Idaho Power will continue as a regulated
entity while allowing our unregulated operations to compete for
business in the non-regulated environment. We anticipate that we
will be transferring other Idaho Power subsidiaries and other non-
utility operations to IDACORP in the near future. The formation
of the holding company is discussed in more detail in the notes
to the consolidated financial statements.
Power Cost Adjustment
The Company hasWe have a PCApower cost adjustment (PCA) mechanism that provides for
annual adjustments to the rates chargedwe charge to our Idaho retail
customers. These adjustments, which take effect annually on May
16, are based on forecasts of net power supply costs. The
difference between the actual costs incurred and the forecasted
costs areis deferred, with interest, and trued-up in the next annual
rate adjustment.
On April 15,The May 16, 1998 the Company filed its annual PCA request with
the IPUC. The filing requests a $37.1adjustment increased rates $34.0 million increase over
the 1997 rates and $17.3 million over base rates. The increase
is largely due primarily to the forecasted return to more normal
streamflow conditions from the near-record conditions experienced
in 1997, and rising costs associated with mandatory purchases
from CSPP projects. If this requestprojects The IPUC has requested that the treatment of
mandatory purchases from certain CSPP projects be reviewed to
determine if there is approved, revenue from Idaho retail customers will be $20.4
million greater than what would be recovered ifa way to avoid a large true-up which was a
major factor in the Company was
charging the base rates during this rate period.1998 increase.
Regulatory Settlement
Under the terms of an IPUC Settlement in effect though 1999, when
the Company's actual earnings in theour Idaho jurisdiction exceedsexceed an 11.75 percent return
on year-end common equity, the Company
willwe refund 50 percent of the excess to
Idaho'sour Idaho retail ratepayers. InFor 1997, the Companywe set aside an estimated $8.7$7.6 million
of revenue for the benefit of its Idahothese customers. Subsequently, this amount was revised to $7.6The IPUC has
ordered that approximately $5.0 million based on
actual data. In the April 15, 1998 PCA filing, the Company
requested that this revised amount be applied against the
balance of demand-side conservation expenditures in order to
defer any rate increase associated with conservation recovery
until May 16, 1999, the same time as the next PCA adjustment to
rates. In October 1998 we filed an application requesting
reimbursement for $2.4 in payments made in 1997 and 1998 to the
Northwest Energy Efficiency Alliance. In this filing we asked
that the reimbursement come out of the remaining revenue sharing
funds.
Demand-Side Management Expenses
We are seeking changes to the regulatory treatment of previously
deferred demand-side management (DSM) expenses in both Idaho and
Oregon.
In Idaho, we requested that the IPUC authorize recovery of post-
1993 DSM expenses and acceleration of the recovery of DSM
expenditures authorized in the last general rate case. We
requested a five-year amortization instead of the 24-year period
previously adopted. In its Order No. 27660 issued on July 31,
1998, the IPUC set a new amortization period of 12 years. The
IPUC order reflects an increase in annual revenue requirements of
$3.1 million for 12 years.
As noted above, we are funding the annual revenue requirement
with revenue sharing amounts until May 16, 1999. A group of our
industrial customers have filed a notice of appeal with the IPUC
indicating that the companies are appealing the IPUC order to the
Idaho Supreme Court.
In Oregon, the OPUC authorized the amortization of the Oregon-
allocated share of the DSM expenditures over five years. The
OPUC allowed a rate surcharge for extraordinary purchases to be
replaced by an identical charge to recover the amortization of
the DSM expenditures. We anticipate that the charge will recover
approximately $540,000 per year.
Energy Trading
We intend to be a competitive energy provider, including both
electricity and natural gas. In 1997, we opened gas trading
offices in Houston, Texas, to serve the southern and eastern
United States and in Boise, Idaho to serve the Northwest and
Canadian markets. We also actively participate in the western
wholesale electricity markets, the results of which are currently
recorded asincluded
in off-system revenue and purchased power expense. (see "Off-
system sales" and "Expenses"). Results of our gas trading
activity are included in other income (see "Other").
Inherent in the energy trading business are risks related to
market movements and the creditworthiness of counterparties.
When buying and selling energy, the high volatility of energy
prices can have a regulatory asset.
Precipitationsignificant impact on profitability if not
managed. Also, counterparty creditworthiness is key to ensuring
that transactions entered into withstand dramatic market
fluctuations.
To mitigate these risks while implementing our business strategy,
the Board of Directors gave approval for executive management to
form a Risk Management Committee, comprised of company officers,
to oversee a risk management program. The program is intended to
minimize fluctuations in earnings while managing the volatility
of energy prices. Embedded within the Risk Management policy and
Streamflows
Idaho Power monitorsprocedures is a credit policy requiring a credit evaluation of
all counterparties before doing business with them. The
objective of our risk management program is to mitigate commodity
price risk, credit risk, and other risks related to the energy
trading business.
Streamflow Conditions
We monitor the effect of precipitation and streamflow conditions on Brownlee
Reservoir, the water source for theour three Hells Canyon
hydroelectric projects. In a typical year, these three projects
combine to produce about half of the Company'sour generated electricity.
Inflows into Brownlee result from a combination of precipitation,
storage, and ground water conditions. Independent forecasters
have projected that inflowDuring the April-July 1998
runoff period, inflows into Brownlee Reservoir during the
April-July runoff period will be 5.2 MAF, slightly more thanwas 8.8 million acre-feet
(MAF), compared to the 70-year median of 4.9 MAF and just more than half of 1997's 9.8
MAF.
Holding CompanyYear 2000 Costs
Many existing computer systems use only two digits to identify a
year in the date field. These programs were designed and
developed without considering the impact of the upcoming change
in the century. Unless proper modifications are made, the
program logic in many of these systems will start to produce
erroneous results because, among other things, the systems will
read the date "01/01/00" as being January 1 of the year 1900 or
another incorrect date. In addition, the second half of 1997,systems may fail to
detect that the year 2000 is a leap year. Similar problems could
arise prior to the year 2000 as dates in the next millennium are
entered into systems which are not Year 2000 compliant.
We recognize the Year 2000 problem as a serious threat to the
Company filed applicationsand our customers. Our Year 2000 effort has been
underway for over two years and is being addressed at the highest
levels within the Company. The Vice President of Corporate
Services is responsible for coordinating the corporate effort.
Each vice president is responsible for addressing the problem
within their respective business units and each has assigned a
Year 2000 Project Leader to execute the project plan. In
addition, we have appointed a full-time Year 2000 Project Manager
to direct the project. Additional staff has been committed to
complete the conversion and implementation needed to bring non-
compliant items into compliance. This staff consists of a mix of
end users, Information Services staff and contract programmers.
Currently, there are over 20 full-time employees devoted to the
project with state regulatory commissionsdozens of others involved to varying degrees. We
have retained third parties to conduct technical and legal audits
of our plan to verify its adequacy. Our Year 2000 efforts
include our subsidiaries.
We have targeted July 1999 as the date by which we expect to be
ready for the Year 2000. This means that all critical systems
are expected to be capable of handling the century rollover and
that we will be able to continue servicing our customers without
interruption. It also means that all of the less critical
systems are expected to have been identified and that contingency
and/or repair plans are expected to be in Idaho, Oregon, Nevada and Wyoming
andplace for dealing with
the FERC seeking approval to formchange of century.
We are following a holding company to
be called IDACORP, Inc.detailed project plan. The purposemethodology is
modeled after those used by some of the holding companytop companies in the
world and has been adapted to meet our unique requirements. This
process includes all the phases and steps commonly found in such
plans, including the (i) identification and analysis of critical
systems, key manufacturers, service providers, embedded systems,
generation plants, (part of which is owned by the Company but is
operated by another electric utility), (ii) remediation and
testing, (iii) education and awareness and (iv) contingency
planning.
With respect to position Idaho Power to respondthat key component of the methodology related to
the changing business
environmentidentification of critical systems, we have identified those
critical systems which must be Year 2000 compliant in order to
continue operations. Many are already compliant or are in the
electric utility industry. Upon consummationprocess of vendor upgrades to become compliant. The largest of
these critical systems and their status regarding compliance are
set forth below:
System Description Status
Business The business systems include the transaction Idaho Power, alongPeopleSoft
Systems financial and administrative and PassPort
functions common to most companies. are both
Business systems include accounts compliant
payable, general ledger, accounts vendor
receivable, labor entry, inventory, packages.
purchasing, cash management, Testing is
budgeting, asset management, underway to
payroll, and financial reporting. verify
compliance.
Customer This system is used to bill In-house
Information customers, log calls from customers system is
System and create service or work requests currently
and track them through completion, being
among other things. At this time, repaired
the Company uses an in-house with Ida-West, will become
wholly owned subsidiariestesting
developed, mainframe-based Customer planned to
Information System to accomplish start in
these tasks. November 1998.
Energy The most critical function the The packages
Management Company offers is the delivery of IDACORP. Orders approvingcomprising
System electricity from the formationsource to the the EMS are
consumer. This must be done with largely compliant
minimal interruption in the midst of the holding company have been received from Idaho,
Oregon, Wyoming and the FERC. Nevada has also approved the
transaction and will be issuing its order shortly.fully
high demand, weather anomalies and compliant with a
equipment failures. To accomplish release scheduled
this, the Company relies on a server- for Fall of 1998
based energy management system and with operating
provided by Landis & Gyr. This system and database
system monitors and directs the upgrades already
delivery of electricity throughout available. Testing
the Company's service area. currently underway.
Metering The matter
was submittedCompany relies on several In-house code is
Systems processes for metering electricity currently being
usage, including some hand-held repaired. Vendor
devices with embedded chips. It is packages are
critical for metering systems to being upgraded.
operate without interruption so as Test plans have
not to jeopardize the Company's been developed
revenue stream. and approved byare underway.
Embedded There is a category of systems on Test bench
Systems which the shareholders at the 1998
Annual Meeting. Upon receipt of all regulatory approvals itCompany is expected the holding company will be effective sometime in the
second half of 1998.
Year 2000 Costs
The Year 2000 issue is the result of potential problems with
computer systems or any equipment withhighly reliant has been
called embedded systems. These are established.
typically computer chips that use
dates whereTesting is
provide for automated operations about 20%
within some device other than a complete.
computer such as a relay or a
security system. The Company is
highly reliant on these systems
throughout its generation and
delivery systems to monitor and
allow manual or automatic
adjustments to the year has been stored as just two characters (e.g.
97 for 1997). These systems may incorrectly evaluate dates
beyond the year 1999, potentially causing system failure and
disruption of operationsdesired devices.
Those devices with chips which could materiallyare
not Year 2000 compliant which affect
the Company's ability to conduct business. These systems must be
identified and either modified or replaced with systems that
correctly recognize dates beyond 1999.application of the device we
replaced.
Other The Company also relies on a number In various
Systems of other important systems to stages of
support engineering, human repair and
resources, safety and regulatory testing.
compliance, etc.
Regarding third parties, the plan methodology has developedrequired us to
identify those third parties with which we have a material
relationship. We have identified as material (1) our ownership
interest in thermal generating facilities which are operated and
implementedmaintained by third party electric utilities; (2) our fuel
suppliers for those thermal generating facilities; and (3) our
telecommunication providers. In addition, we have identified
ninety-three (93) key manufacturers which provide materials and
supplies to us. With respect to the thermal plants, fuel
suppliers and telecommunication providers, the plan methodology
includes a process wherein some members of the Year 2000 Compliance
Planteam
meet periodically with the third parties to assess the status of
their efforts. This is an ongoing process and will continue
until such time as the third party has completed compliance
testing and certified to us that addresses traditional hardwarethey are compliant. Regarding
the 93 key manufacturers we have contacted all via mail and
software systems,
embedded systems,requested they complete a survey indicating the extent and service providers.status
of their Year 2000 efforts. The plan also includes
identification of and coordinationsurvey is followed up with
all external interfacing
systems. The Company expects its critical systemscontact by telephone to be
compliant by mid-1999.
Idaho Power isfurther document their Year 2000 status.
Finally, we are connected to an electric grid that connects
utilities throughout the western portion of North America. This
interconnection is essential to the reliability and operational
integrity of each connected utility. This also means that
failure of one electric utility in the interconnected grid could
cause the failure of others. In the context of the Year 2000
problem, this interconnectivity compounds the challenge faced by
the electric utility industry. Our Company could do a very
thorough and effective job of becoming Year 2000 compliant and
yet encounter difficulties supplying services and energy because
another utility in the interconnected grid failed to achieve Year
2000 compliance. In this regard, the Company iswe are working closely with
other electric industry organizations concerned with the reliability
issues and technical collaboration.
The Company estimates thatOur estimate of the cost of its operating expenses relatedYear 2000 plan remains at
approximately $5.3 million. This includes costs incurred to this
issue will total approximately $4.8 million between 1998date
(approximately $700,000) and 2000
and will be expensed as incurred. The Company doesestimated costs through the year
2000. This level of expenditure is not expect
these expendituresexpected to have aany
material effect on our operations or our financial position.
Funds to cover Year 2000 costs in 1999 have been budgeted by
business unit and within the Information Services Department with
approximately 10 percent of the Information Services budget used
for remediation. No information services department projects
have been deferred due to the Company's year 2000 efforts.
The Year 2000 issue poses risks to our internal operations due to
the potential inability to carry on our business activities and
from external sources due to the potential impact on the ability
of our customers to continue their business activities. The
major applications which pose the greatest risks internally are
those systems, embedded or otherwise, which impact the
generation, transmission and distribution of energy and the
metering and billing systems. The potential risks related to
these systems are electric service interruptions to customers and
associated reduction in loads and revenue and interrupted data
gathering and billing and the resultant delay in receipt of
revenues. All of this would negatively impact our relationship
with our customers which may enhance the likelihood of losing
customers in a restructured industry. Externally, those
customers which inadequately prepare for the Year 2000 issue may
be unable to continue their business activities. This would
affect us in a number of ways. Our loads and revenue would be
reduced because of the lost load from discontinued business
activities, and customers which lose jobs because of discontinued
business activities may face difficulties in paying their power
bills. The impact of this on us is dependent upon the number and
the size of those businesses which are forced to discontinue
business activities because of the Year 2000 issue.
As part of its Year 2000 plan, we are in the process of
developing a contingency plan and expect to complete this process
on or before July 1999.
New Accounting Pronouncements
In June 1998 the FASB issued SFAS No. 133 Accounting for
Derivative Instruments and Hedging Transactions. This statement
establishes accounting and reporting standards for derivative
financial condition or results of operations.instruments and other similar financial instruments and
for hedging activities. It is effective for fiscal years
beginning after June 15, 1999. We are reviewing this statement
to determine its effects on our accounting and reporting
requirements.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
On November 30, 1995, a complaint entitled Idaho Power Company
vs. Cogeneration, Inc.,Case No. 98467, was filed by the Company
in the District Court of the Fourth Judicial District of the
State of Idaho. The proceeding involves an effort by the Company
to terminate a Firm Energy Sales Agreement (FESA) for a small
hydroelectric generating plant.
As required by PURPA and the orders of the Idaho Public Utilities
Commission (IPUC), on January 7, 1992, the Company entered into a
35-year FESA with Cogeneration, Inc., to purchase the output of a
43-megawatt hydroelectric generating project known as the Auger
Falls Project. The FESA for the Auger Falls Project was approved
by the IPUC on January 27, 1992. The FESA required that on or
before January 1, 1994, Cogeneration, Inc., post cash or cash
equivalent security in the amount of approximately $1.9 million
to assure performance of the FESA. Cogeneration, Inc., failed to
provide the security amount. Consistent with the FESA, the
Company filed a petition for declaratory order with the IPUC
requesting that the FESA be terminated as a result of
Cogeneration, Inc.'s breach. Cogeneration, Inc., cross
petitioned claiming that its failure to perform was excused by
the occurrence of an event of force majeure. On April 17, 1995,
the IPUC issued its order finding that Cogeneration, Inc.'s
failure to post the cash security on January 1, 1994, was a
default under the FESA and further finding that the posting of
the liquid security was required by the public interest. Based
upon those findings, the IPUC ordered Cogeneration, Inc., to post
the cash security prior to May 1, 1995. Cogeneration, Inc.,
failed to comply with the Commission's order and has never posted
the $1.9 million amount required by the FESA.
After the IPUC's order became final and non-appealable, the
Company filed a complaint for declaratory relief in the District
Court of the Fourth Judicial District. The Complaint sought a
determination by the district court that Cogeneration, Inc.'s
failure to provide the cash security and its violation of the
IPUC's orders requiring that it expeditiously provide the cash
security constituted material breaches of the FESA. The Company
asked the district court to find that as a matter of law Idaho
Power was entitled to either terminate or rescind the FESA.
In response to the Company's complaint, Cogeneration, Inc., filed
counterclaims alleging that the Company, by seeking to terminate
the FESA, had breached the FESA and was attempting to monopolize
the electric generation market and drive Cogeneration, Inc., out
of business. Cogeneration, Inc., alleged damages for breach in
excess of $50 million and requested that any damages be trebled
under the anti-trust laws.
On November 30, 1995, the district judge, by memorandum decision
found that Cogeneration, Inc., had materially breached the FESA
and the Company was entitled to either rescind or terminate the
FESA.
On February 16, 1996, Cogeneration, Inc., dismissed its anti-
trust claims against the Company with prejudice, and on February
23, 1996, the Idaho Supreme Court granted Cogeneration, Inc.'s
request for an expedited appeal of the district court's decision
establishing an accelerated briefing schedule and scheduling oral
argument for May 10, 1996.
On August 12, 1996, the Idaho Supreme Court determined that the
District Court's decision that Cogeneration, Inc., had breached
the FESA was premature.
On February 10, 1997, Cogeneration, Inc. filed an amended
Complaint restating its previous claims, requesting a jury trial
rather than the court trial it had previously requested and
raising several new allegations and claims.
Following a court trial, on June 24, 1998 the District Court
issued a memorandum decision finding that Cogeneration, Inc. had
materially breached the FESA and as a result Idaho Power had
properly terminated the FESA.
On July 27, 1998, Cogeneration, Inc., filed a Notice of Appeal
with the Idaho Supreme Court.
This matter has been previously reported in Form 10-K dated March
12, 1998 and other reports filed with the Commission.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Exhibit File Number As Exhibit
2*2 1-3198 4(f) Agreement and planPlan of exchange,Exchange,
Form 10-K dated as of February 2, 1998.
for 1997
*3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation
of the Company as filed with the
Secretary of State of Idaho on
June 30, 1989.
*3(a)(ii)(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), as filed with
the Secretary of State of Idaho on
November 5, 1991.
*3(a)(iii)(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), as filed with the
Secretary of State of Idaho on June
30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation adopted
by Shareholders on May 1, 1991.
*3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on
June 30, 1989, and presently in
effect.
*3(d) 33-56071 3(d) Articles of share exchange as filed
with the Secretary of State of
Idaho on September 29, 1998.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated
as of October 1, 1937, between the
Company and Bankers Trust Company
and R. G. Page, as Trustees.
*4(a)(ii) 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 16, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
*4(b) Instruments relating to American
Falls bond guarantee. (see Exhibits
10(f) and 10(f)(i)Exhibit
10(c)).
*4(c) 33-65720 4(f) Agreement 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) 33-65720 4(e) Rights Agreement dated January 11,
1990, between the Company and First
Chicago Trust Company of New York,
as Rights Agent (The Bank of New
York, successor Rights Agent).
*4(e)(i) 1-3198 Form 4(e)(i) Amendment, dated as of January 30,
Form 10-K for 1997 1998, related to agreement filed
for 1997 as exhibitExhibit 4(e).
*4(f) 1-3198 Form 4(f) Agreement and Plan of Exchange
10-K for 1997 dated as of February 2, 1998
between Idaho Power Company, and
Idaho Power Holding Company.
*10(a) 2-51762 5(a) Agreement, dated April 20, 1973,
between the Company and FMC
Corporation.
*10(a)(i) 2-57374 5(b) Letter Agreement, dated October 22,
1975, relating to agreement filed as
Exhibit 10(a).
*10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated December 22,
1976, relating to agreement filed as
Exhibit 10(a).
*10(a)(iii 33-65720 10(a) Letter Agreement, dated December 11,
1981, relating to agreement filed as
Exhibit 10(a).
*10(b) 2-49584 5(b) Agreements, dated September 22,
1969, between the Company and
Pacific Power & Light Company
relating to the operation,
construction and ownership of the
Jim Bridger Project.
*10(b)*10(a)(i) 2-51762 5(c) Amendment, dated February 1, 1974,
relating to operation agreement
filed as Exhibit 10(b)10(a).
*10(c)*10(b) 2-49584 5(c) Agreement, dated as of October 11,
1973, between the Company and
Pacific Power & Light Company.
*10(d) 2-49584 5(d) Agreement, dated as of October 24,
1973, between the Company and Utah
Power & Light Company.
*10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25, 1978,
relating to agreement filed as
Exhibit 10(d).
*10(e) 33-65720 10(b) Coal Purchase Contract, dated as of
June 19, 1986, among the Company,
Sierra Pacific Power Company and
Black Butte Coal Company.
*10(f) 2-57374 5(k) Contract, dated March 31, 1976,
between the United States of America
and American Falls Reservoir
District, and related Exhibits.
*10(f)*10(c)(i) 33-65720 10(c) Guaranty Agreement, dated March 1,
1990, between the Company and West
One Bank, as Trustee, relating to
$21,425,000 American Falls
Replacement Dam Bonds of the
American Falls Reservoir District,
Idaho.
*10(g) 2-57374 5(m) Agreement, effective April 15, 1975,
between the Company and The
Washington Water Power Company.
*10(h) 2-62034 5(p) Bridger Coal Company Agreement,
dated February 1, 1974, between
Pacific Minerals, Inc., and Idaho
Energy Resources Co.
*10(i) 2-62034 5(q) Coal Sales Agreement, dated February
1, 1974, between Bridger Coal
Company and Pacific Power & Light
Company and the Company.
*10(i)(i) 33-65720 10(d) Second Restated and Amended Coal
Sales Agreement, dated March 7,
1988, among Bridger Coal Company and
PacifiCorp (dba Pacific Power &
Light Company) and the Company.
*10(i)(ii) 1-3198 10(i)(ii) Third Restated and Amended Coal
Form 10-Q Sales Agreement, dated January 1,
for 3/31/96 1996, among Bridger Coal Company and
PacifiCorp (dba Pacific Power &
Light Company) and the Company.
*10(j)*10(d) 2-62034 5(r) Guaranty Agreement, dated as of
August 30, 1974, with Pacific Power
& Light Company.
*10(k)*10(e) 2-56513 5(i) Letter Agreement, dated January 23,
1976, between the Company and
Portland General Electric Company.
*10(k)*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 the
Company.
*10(k)*10(e)(ii) 2-62034 5(t) Amendment, dated September 30,
1977, relating to agreement filed
as Exhibit 10(k)10(e).
*10(k)*10e)(iii) 2-62034 5(u) Amendment, dated October 31, 1977,
relating to agreement filed as
Exhibit 10(k)10(e).
*10(k)*10(e)(iv) 2-62034 5(v) Amendment, dated January 23, 1978,
relating to agreement filed as
Exhibit 10(k)10(e).
*10(k)*10(e)(v) 2-62034 5(w) Amendment, dated February 15, 1978,
relating to agreement filed as
Exhibit 10(k)10(e).
*10(k)*10(e)(vi) 2-68574 5(x) Amendment, dated September 1, 1979,
relating to agreement filed as
Exhibit 10(k)10(e).
*10(l)*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(m)*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
the Company.
*10(n)*10(h)(i)1 1-3198 10(n)(i) The Revised Security Plans for
Form 10-K Senior Management Employees and for
for 1994 Directors-aDirectors - a non-qualified,
deferred compensation plan
effective November 30, 1994.
*10(n)*10(h)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Plan
Form 10-K for senior management employees
for 1994 effective January 1, 1995.
*10(n)*10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for
Form 10-K officers and key executives
for 1994 effective July 1, 1994.
*10(n)*10(h)(iv)1 1-3198 10(n)(iv) The Revised Security Plans for
Form 10-K Senior Management Employees and for
for 1996 Directors-aDirectors - a non-qualified,
deferred compensation plan
effective August 1, 1996.
*10(o) 33-65720 10(f) Residential Purchase and Sale
Agreement, dated August 22, 1981,
among the United Stated of American
Department of Energy acting by and
through the Bonneville Power
Administration, and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated
August 25, 1981, including
amendments, among the United States
of America Department of Energy
acting by and through the Bonneville
Power Administration, and the
Company.
*10(q)*10(i) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of Idaho
and the Company relating to the
Company's Swan Falls and Snake
River water rights.
*10(q)*10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and the
Company relating to the agreement
filed as Exhibit 10(q)10(i).
*10(q)*10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated
October 25, 1984, between the State
of Idaho and the Company relating
to the agreement filed as Exhibit
10(q)10(i).
*10(r) 33-65720 10(i) Agreement for Supply of Power and
Energy, dated February 10, 1988,
between the Utah Associated
Municipal Power Systems and the
Company.
*10(s) 33-65720 10(j) Agreement Respecting Transmission
Facilities and Services, dated
March 21, 1988 among PC/UP&L Merging
Corp. and the Company including a
Settlement Agreement between
PacifiCorp and the Company.
*10(s)(i) 33-65720 10(j)(i) Restated Transmission Services
Agreement, dated February 6, 1992,
between Idaho Power Company and
PacifiCorp.
*10(t) 33-65720 10(k) Agreement for Supply of Power and
Energy, dated February 23, 1989,
between Sierra Pacific Power Company
and the Company.
*10(u) 33-65720 10(l) Transmission Services Agreement,
dated May 18, 1989, between the
Company and the Bonneville Power
Administration.
*10(v)*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 the Company and the Twin
Falls Canal Company and the
Northside Canal Company Limited.
*10(v)*10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February
10, 1992, between the Company and
New York Life Insurance Company, as
Note Purchaser, relating to
$11,700,000 Guaranteed Notes due
2017 of Milner Dam Inc.
*10(w) 33-65720 10(n) Agreement for the Purchase and Sale
of Power and Energy, dated October
16, 1990, between the Company and
The Montana Power Company.
*10(x) 1-3198 10(x) Agreement for design of substation
Form 10-Q dated October 4, 1995, between the
for 9/30/95 Company and Micron Technology, Inc.
12 Statement Re: Computation of Ratio
of Earnings to Fixed Charges.
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges.
12(b) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements.
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and
Preferred Dividend Requirements.
15 Letter re: unaudited interim
financial information.
27 Financial Data Schedule
(b) Reports on Form 8-K. No reports on Form 8-K were
filed forduring the three monthsmonth period ended March 31,September
30, 1998.
*Previously Filed and Incorporated Herein by Reference
_______________________________
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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 May 13,November 6, 1998 By: /s/ J LaMont Keen
J LaMont Keen
Vice President, Chief
Financial Officer and Treasurer
Treasurer (Principal Financial
Officer and Principal
Accounting Officer)
_______________________________
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