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, 2002

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from to

	Exact name of registrant as specified
	in its charter, state of	I.R.S. Employer
Commission File	incorporation, address of principal executive	Identification
Number	offices, and telephone number	Number
1-14465	IDACORP, Inc.	82-0505802
	1221 W. Idaho Street
	Boise, ID  83702-5627
	Telephone:  (208) 388-2200
	State of Incorporation:  Idaho

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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes  X  No ___

Number of shares of Common Stock outstanding as of September 30, 2002:  37,853,573

GLOSSARY
AFDC	-	Allowance for Funds used During Construction
APB	-	Accounting Principles Board
APC	-	Applied Power Company
BPA	-	Bonneville Power Administration
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
DIG	-	Derivatives Implementation Group
DSM	-	Demand-Side Management
EITF	-	Emerging Issues Task Force
EPA	-	Environmental Protection Agency
EPS	-	Earning per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FPA	-	Federal Power Act
Ida-West	-	Ida-West Energy
IE	-	IDACORP Energy
IFS	-	IDACORP Financial Services
IPC	-	Idaho Power Company
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	kilowatt
kWh	-	kilowatt-hour
LTICP	-	Long-Term Incentive and Compensation Plan
MD&A	-	Management's Discussion and Analysis
MMbtu	-	Million British Thermal Units
MW	-	Megawatt
MWh	-	Megawatt-hour
OPUC	-	Oregon Public Utility Commission
Overton	-	Overton Power District No. 5
PCA	-	Power Cost Adjustment
PG&E	-	Pacific Gas and Electric Company
PURPA	-	Public Utilities Regulatory Policy Act
REA	-	Rural Electrification Administration
RFP	-	Request for proposals
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
SCE	-	Southern California Edison
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company
Valmy	-	North Valmy Steam Electric Generating Plant
WSCC	-	Western Systems Coordinating Council

INDEX

Page
Part I.  Financial Information:
	Item 1.  Financial Statements (unaudited)
		Consolidated Statements of Income		4-5
		Consolidated Balance Sheets		6-7
		Consolidated Statements of Cash Flows		8
		Consolidated Statements of Comprehensive Income		9
		Notes to Consolidated Financial Statements		10-27
		Independent Accountants' Report		28
	Item 2.  Management's Discussion and Analysis of Financial
			Condition and Results of Operations	29-55
	Item 3.  Quantitative and Qualitative Disclosures about Market Risk			55
	Item 4.  Controls and Procedures			55
Part II.  Other Information:
	Item 1.  Legal Proceedings			56
	Item 6.  Exhibits and Reports on Form 8-K			56-57
Signatures				58
Certifications				59-60

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
(unaudited)

				Three months ended
				September 30,
				2002		2001
				(millions of dollars except for per share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	216	$	186
		Off-system sales			11		92
		Other revenues			10		9
			Total electric utility revenues		237		287
	Energy marketing commodities and services				19		105
	Other				3		3
		Total operating revenues			259		395
OPERATING EXPENSES:
	Electric utility:
		Purchased power			50		228
		Fuel expense			27		26
		Power cost adjustment			57		(58)
		Other operations and maintenance			52		51
		Depreciation			24		22
		Taxes other than income taxes			5		5
			Total electric utility expenses		215		274
	Energy marketing:
		Cost of energy commodities and services			12		36
		Selling, general and administrative			6		12
	Other				9		8
			Total operating expenses		242		330
OPERATING INCOME:
	Electric utility				22		13
	Energy marketing				1		57
	Other				(6)		(5)
		Total operating income			17		65
OTHER INCOME (EXPENSE)					(2)		5
INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				12		14
	Other interest				4		4
	Preferred dividends of Idaho Power Company				1		1
		Total interest expense and other			17		19
INCOME (LOSS) BEFORE INCOME TAXES					(2)		51
INCOME TAXES					(39)		17
NET INCOME				$	37	$	34
AVERAGE COMMON SHARES
	OUTSTANDING (000'S)				37,771		37,354
EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	0.98	$	0.91

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Income
(unaudited)

				Nine months ended
				September 30,
				2002		2001
				(millions of dollars except for per share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	590	$	475
		Off-system sales			42		206
		Other revenues			28		34
			Total electric utility revenues		660		715
	Energy marketing commodities and services				37		307
	Other				12		9
		Total operating revenues			709		1,031
OPERATING EXPENSES:
	Electric utility:
		Purchased power			112		523
		Fuel expense			76		74
		Power cost adjustment			133		(184)
		Other operations and maintenance			155		149
		Depreciation			70		64
		Taxes other than income taxes			15		16
			Total electric utility expenses		561		642
	Energy marketing
		Cost of energy commodities and services			37		105
		Selling, general and administrative			14		55
	Other				25		23
			Total operating expenses		637		825
OPERATING INCOME:
	Electric utility				99		73
	Energy marketing				(14)		147
	Other				(13)		(14)
		Total operating income			72		206
OTHER INCOME					6		12
INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				38		42
	Other interest				10		11
	Preferred dividends of Idaho Power Company				4		4
		Total interest expense and other			52		57
INCOME BEFORE INCOME TAXES					26		161
INCOME TAXES					(39)		56
NET INCOME				$	65	$	105
AVERAGE COMMON SHARES
	OUTSTANDING (000'S)				37,665		37,356
EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	1.72	$	2.80

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)
Assets

			September 30,		December 31,
			2002		2001
			(millions of dollars)
CURRENT ASSETS:
	Cash and cash equivalents		$	70	$	67
	Receivables:
		Customer		161		204
		Allowance for uncollectible accounts		(43)		(43)
		Employee notes		8		6
		Other		9		11
	Energy marketing assets			113		194
	Taxes receivable			-		51
	Accrued unbilled revenues			29		37
	Materials and supplies (at average cost)			25		26
	Fuel stock (at average cost)			11		9
	Prepayments			35		32
	Regulatory assets			15		56
		Total current assets		433		650
INVESTMENTS				204		159
PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,044		2,990
	Accumulated provision for depreciation			(1,279)		(1,220)
		Utility plant in service - net		1,765		1,770
	Construction work in progress			109		96
	Utility plant held for future use			2		2
	Other property, net of accumulated depreciation			23		18
		Property, plant and equipment - net		1,899		1,886
OTHER ASSETS:
	American Falls and Milner water rights			32		31
	Company-owned life insurance			35		40
	Energy marketing assets - long-term			163		204
	Regulatory assets			522		544
	Long-term receivables			74		74
	Other			49		51
		Total other assets		875		944
		TOTAL	$	3,411	$	3,639

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)
Liabilities and Shareholders' Equity

				September 30,		December 31,
				2002		2001
				(millions of dollars)
CURRENT LIABILITIES:
	Current maturities of long-term debt			$	116	$	36
	Notes payable				416		363
	Accounts payable				136		248
	Energy marketing liabilities				89		125
	Derivative liabilities				-		41
	Taxes accrued				28		-
	Interest accrued				20		15
	Deferred income taxes				5		21
	Other				25		55
		Total current liabilities			835		904
OTHER LIABILITIES:
	Deferred income taxes				628		590
	Energy marketing liabilities - long-term				101		135
	Regulatory liabilities				117		114
	Derivative liabilities - long-term				-		7
	Other				82		71
		Total other liabilities			928		917
LONG-TERM DEBT					702		843
COMMITMENTS AND CONTINGENT LIABILITIES
PREFERRED STOCK OF IDAHO POWER COMPANY					54		104
SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		37,991,981 and 37,628,919 shares issued, respectively)			466		454
	Retained earnings				436		424
	Accumulated other comprehensive income (loss)				(6)		(4)
	Treasury stock (138,408 and 66,188 shares at cost, respectively)				(4)		(3)
		Total shareholders' equity			892		871
			TOTAL	$	3,411	$	3,639

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows
(unaudited)

				Nine Months Ended
				September 30,
				2002		2001
				(millions of dollars)
OPERATING ACTIVITIES:
	Net income			$	65	$	105
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
		Allowance for uncollectible accounts			-		19
		Unrealized (gains) losses from energy marketing activities			37		(96)
		Depreciation and amortization			91		82
		Deferred taxes and investment tax credits			(92)		115
		Accrued PCA costs			128		(188)
		Change in:
			Receivables and prepayments		43		(86)
			Accrued unbilled revenues		9		12
			Materials and supplies and fuel stock		(1)		(1)
			Accounts payable		(148)		65
			Taxes receivable/accrued		79		(35)
			Other current assets and liabilities		27		(16)
		Other - net			5		(5)
			Net cash provided by (used in) operating activities		243		(29)
INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(89)		(138)
	Investments in affordable housing projects				(44)		-
	Proceeds from sales of assets				-		11
	Other - net				(3)		(4)
		Net cash used in investing activities			(136)		(131)
FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				-		120
	Retirement of:
		First mortgage bonds			(50)		(130)
		Other long-term debt			(12)		(14)
		Preferred stock of Idaho Power Company			(50)		-
	Dividends on common stock				(53)		(52)
	Increase in short-term borrowings				53		204
	Common stock issued				13		-
	Acquisition of treasury shares				(1)		(8)
	Other - net				(4)		(5)
		Net cash provided by (used in) financing activities			(104)		115
Net increase (decrease) in cash and cash equivalents					3		(45)
Cash and cash equivalents beginning of period					67		107
Cash and cash equivalents at end of period				$	70	$	62
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION:
	Cash paid (received) during the period for:
		Income taxes		$	(22)	$	(17)
		Interest (net of amount capitalized)		$	41	$	47
	Distribution of treasury stock to affiliates			$	-	$	8

The accompanying notes are an integral part of these statements

IDACORP, Inc.
Consolidated Statements of Comprehensive Income
(unaudited)

		Three Months Ended
			September 30,
			2002		2001
			(millions of dollars)
NET INCOME			$	37	$	34
OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($1) and ($1))			(1)		(1)
TOTAL COMPREHENSIVE INCOME			$	36	$	33

		Nine Months Ended
			September 30,
			2002		2001
			(millions of dollars)
NET INCOME			$	65	$	105
OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($2) and ($2))			(2)		(3)
TOTAL COMPREHENSIVE INCOME			$	63	$	102

The accompanying notes are an integral part of these statements

Notes to Consolidated Financial Statements
(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE).  IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon 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.

IDACORP, Inc.'s other subsidiaries include:

-Ida-West Energy (Ida-West) - independent power projects development and
   management;

-IdaTech - developer of integrated fuel cell systems;

-IDACORP Financial Services (IFS) - affordable housing and other real estate
   investments;

-Velocitus - commercial and residential Internet service provider;

-IDACOMM - provider of telecommunications services.

References in this report to "we" and "our" are to IDACORP, Inc. and its subsidiaries.

Financial Statements
In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly our consolidated financial position as of September 30, 2002, and our consolidated results of operations for the three and nine months ended September 30, 2002 and 2001 and consolidated cash flows for the nine months ended September 30, 2002 and 2001.  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 our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2001.  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 our accounts and the accounts of our wholly-owned or controlled subsidiaries.  All significant intercompany transactions and balances have been eliminated in consolidation.  Investments in business entities in which we do not have control, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.

Adopted Accounting Standards
On January 1, 2002, we adopted Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and Other Intangible Assets."  SFAS 142 requires that goodwill and certain intangible assets no longer be amortized, but instead be tested for impairment at least annually.

As required by the statement, we have completed transitional impairment tests on our January 1, 2002 goodwill balance of $13 million, which is related to the acquisitions of IdaTech and Velocitus.  There was no impairment of goodwill based on these tests.  We will be required to perform goodwill impairment tests at least annually, and more frequently if circumstances indicate a possible impairment.

The following table presents net income and earnings per share, adjusted to exclude goodwill amortization expense, for the three and nine months ended September 30:

	Three months ended				Nine months ended
	September 30,				September 30,
	2002		2001		2002		2001
	(millions of dollars except for per share amounts)
Reported net income	$	37	$	34	$	65	$	105
Add back goodwill amortization		-		-		-		1
Adjusted net income	$	37	$	34	$	65	$	106
Basic and diluted earnings per share:
Reported earnings per share	$	0.98	$	0.91	$	1.72	$	2.80
Add back goodwill amortization		-		0.01		-		0.05
Adjusted earnings per share	$	0.98	$	0.92	$	1.72	$	2.85

SFAS 142 also includes provisions related to reclassification of intangible assets and reassessment of useful lives of intangible assets.  We had no intangible assets affected by these provisions.

In January 2002, we adopted SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets."  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 Long-Lived Assets to be Disposed of."  The adoption of SFAS 144 did not have a significant effect on our financial statements.

In June 2001, the Derivative Implementation Group of the Financial Accounting Standards Board (FASB) issued Interpretation C-15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity," concluding that contracts subject to book-outs were not eligible for the normal purchase and sales exception in SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."  Therefore, certain contracts were recorded as derivatives in prior periods.  However, this Interpretation was revised in October 2001 and December 2001, and now allows these contracts to qualify for the exception.  This revision applies only to electric utilities, due to the unique nature of the industry.  IPC has completed an evaluation of the effect of this revised Interpretation on its treatment of booked-out contracts and has determined that contracts previously classified as derivatives are exempt.  This change does not have a material effect on our financial statements.

Reclassifications
Certain items previously reported for periods prior to September 30, 2002 have been reclassified to conform to the current period's presentation.  Net income and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which is effective for fiscal years beginning after June 15, 2002.  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  It requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred.  When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost.  Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset.  An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset.  We are currently assessing but have not yet determined the impact of SFAS 143 on our financial statements.

In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities."  The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan.  Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity.  This standard supersedes Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)."  SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.  We are currently assessing but have not yet determined the impact of SFAS 146 on our financial statements.

EITF Issue No. 02-3, "Issues Involved in Accounting for Contracts under EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities"" reached a consensus to rescind EITF 98-10, the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS 133.  The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002.  Energy trading contracts not within the scope of SFAS 133 purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting.  In addition, effective on January 1, 2003, all energy trading contracts we previously accounted for at fair value under EITF 98-10 must be adjusted to historical cost unless those contracts meet the definition of a derivative under SFAS 133.  We will be required to record this adjustment as a cumulative effect of adoption of a new accounting principle.  We are currently assessing but have not yet determined the impact of the rescission of EITF 98-10 on our financial statements.  The changes are anticipated to primarily affect the timing of the recognition of income or loss in earnings, and not change the underlying economics or cash flows of transactions entered into by IE.

EITF 02-3 also reached a consensus that gains and losses on derivative instruments within the scope of SFAS 133 should be shown net in the income statement if the derivative instruments are held for trading purposes.  In anticipation of this requirement, IDACORP has elected to change its presentation of energy trading activities from gross to net presentation, in accordance with the option allowed under EITF 98-10.  Prior periods have been reclassified to conform to current presentation.   Therefore Operating Revenues for the Energy Marketing segment include revenues from the sale of electricity and gas netted against the cost of purchased power and natural gas.  Additionally, all financial transactions are presented on a net basis as operating revenue and unrealized income is presented on a net basis as operating revenue.  Operating expenses include general and administrative expenses, bad debt reserves, transmission expenses and broker fees.  Our net financial position and results of operations were not affected by this change in presentation.

2.  INCOME TAXES:

Our effective tax rate for the nine months ended September 30, 2002 decreased from 34.9 percent in 2001 to a benefit of 147.3 percent in 2002.  Non-recurring items occurring in 2002 include a tax accounting method change and the settlement of a partnership audit, which resulted in a decrease to tax expense.  Reconciliations between the statutory income tax rate and the effective rates are as follows (in millions of dollars):

		Nine Months Ended September 30,
		2002			2001
		Amount		Rate		Amount			Rate
Computed income taxes based on statutory
	federal income tax rate	$	9	35.0 %		$	56	35.0%
Changes in taxes resulting from:
	Tax accounting method change and audit settlements		(34)	(128.7)			-	-
	Capitalized overhead costs		(3)	(10.0)			-	-
	Investment tax credits		(2)	(9.2)			(2)	(1.4)
	Repair allowance		(2)	(7.0)			(2)	(1.3)
	Pension expense		-	-			(1)	(0.9)
	State income taxes		3	10.5			9	5.4
	Depreciation		6	23.5			6	3.9
	Affordable housing tax credits		(16)	(61.2)			(10)	(6.2)
	Preferred dividends of IPC		1	4.8			1	0.9
	Other		(1)	(5.0)			(1)	(0.5)
Total provision (benefit) for federal and state income taxes		$	(39)	(147.3)%		$	56	34.9%

Tax Accounting Method Change
During the three months ended September 30, 2002, we filed our 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs.  The old method allocated such costs primarily to construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.

IPC adopted the method change during 2002 to take advantage of new tax rules enacted or promulgated during the first half of 2002. The key rule changes include: an announcement in January that this method change qualifies for the automatic change procedures; the signing in March of an economic stimulus bill that expanded the loss carryback period from two years to five years; and the announcement in March that the full effects of method changes could be absorbed in the year of change.  These new rules provided sufficient incentive to IPC to adopt the method change with our 2001 tax return, filed in September 2002.

The tax accounting method change has been recorded as a decrease to income tax expense for the three months ended September 30, 2002 of $31 million, attributable to 2001 and prior years, and is consistent with prior regulatory treatment.  The 2002 effects of the method change have been included as a $3 million decrease to income tax expense for the three months ended September 30, 2002.

Status of Audit Proceedings
During the three months ended September 30, 2002, IPC settled income tax deficiencies related to its partnership investment in the Bridger Coal Company, covering the years 1991 through 1998.  The settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.

Our federal income tax returns for years through 1997 have been examined by the Internal Revenue Service and substantially all issues have been settled.  Management believes that adequate provision for income taxes has been made for the open years 1998 and after and for any unsettled issues prior to 1998.

3.  PREFERRED STOCK OF IDAHO POWER COMPANY:

The number of shares of IPC preferred stock outstanding were as follows:

			September 30,	December 31,
			2002	2001
Cumulative, $100 par value:
	4% preferred stock (authorized 215,000 shares)		139,851	143,872
	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

IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.

4.  FINANCING:

The following table summarizes long-term debt at:

			September 30,		December 31,
			2002		2001
			(millions of dollars)
First mortgage bonds:
	6.85% Series due 2002		$	27	$	27
	6.40% Series due 2003			80		80
	8     % Series due 2004			50		50
	5.83% Series due 2005			60		60
	7.38% Series due 2007			80		80
	7.20% Series due 2009			80		80
	6.60% Series due 2011			120		120
	7.50% Series due 2023			80		80
	8.75% Series due 2027			-		50
		Total first mortgage bonds		577		627
Pollution control revenue bonds:
	8.30% Series 1984 due 2014			50		50
	6.05% Series 1996A due 2026			68		68
	Variable Rate Series 1996B due 2026			24		24
	Variable Rate Series 1996C due 2026			24		24
	Variable Rate Series 2000 due 2027			4		4
		Total pollution control revenue bonds		170		170
REA notes				1		1
American Falls bond guarantee				20		20
Milner Dam note guarantee				12		12
Unamortized premium/discount - net				(1)		(1)
Debt related to investments in affordable housing				39		50
	Total			818		879
Current maturities of long-term debt				(116)		(36)
		Total long-term debt	$	702	$	843

In March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

Credit facilities have been established at both IDACORP and IPC.  IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364-day credit facility that expires in March 2003.  Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating.  Commercial paper may be issued up to the amounts supported by the credit facilities.  At September 30, 2002, short-term borrowing on these facilities totaled $283 million.

IPC has regulatory authority to incur up to $350 million of short-term indebtedness.  IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which it pays a facility fee on the commitment quarterly in arrears, based on its corporate credit rating.  Commercial paper may be issued subject to the regulatory maximum, up to amounts supported by the credit facilities.  At September 30, 2002, IPC's short-term borrowing under this facility totaled $133 million.  IPC repaid $100 million of floating rate notes in September 2002, using short-term borrowings from IDACORP, which are payable on November 15, 2002.  IPC plans to replace this intercompany debt with external financing.

IDACORP currently has shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt securities, including medium-term notes, and preferred or common stock.  At September 30, 2002 none had been issued.

IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock.  At September 30, 2002 none had been issued.

5.  COMMITMENTS AND CONTINGENT LIABILITIES:

Commitments under contracts and purchase orders relating to IPC's and Ida-West's programs for construction and operation of facilities amounted to approximately $6 million and $30 million, respectively, at September 30, 2002.  The commitments are generally revocable by the companies subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges.

From time to time we are a party to various other legal claims, actions and complaints not discussed below.  We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them although we are unable to predict with certainty whether or not we will ultimately be successful.  However, based on our evaluation, we believe that the resolution of these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Other Legal Proceedings
Overton Power District No. 5:  IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract.  The contract provided for Overton to purchase 40 megawatts (MW) of electrical energy per hour from IE at $88.50 per megawatt hour (MWh), from July 1, 2001 through June 30, 2011.  In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.

IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract.  Overton filed an Answer and Counterclaim on April 23, 2002 claiming IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in the amount to be proved at trial.  Overton also asserts that the contract is unenforceable or subject to rescission.  IE believes Overton's assertions are without merit and has filed a motion for partial summary judgment.  Overton has filed a cross-motion for partial summary judgment alleging that its CEO lacked authority to execute the contract.  The motions have been heard, but not decided by the Court.  The parties continue with discovery in the lawsuit.  Trial is scheduled to commence on May 5, 2003.

IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit.  While the outcome of litigation is never certain, IE believes it should prevail on the merits.  At September 30, 2002, IE had a $74 million long-term asset related to the Overton claim.  IE will review the recoverability of the asset on an ongoing basis.

This has been previously reported in our Annual Report on Form 10-K for the year ending December 31, 2001 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002 and June 30, 2002.

Truckee-Donner Public Utility District:  IE has received notice from Truckee-Donner Public Utility District (Truckee), located in California, asserting that IE was in purported breach of, and that Truckee has the right to renegotiate certain terms of, the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities.  Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWh.

On May 30, 2002, IE filed a lawsuit against Truckee in the Idaho State District Court in and for the County of Ada.  IE seeks a declaration that it is not in breach of the contract, injunctive relief requiring Truckee to make payments pursuant to the terms of the contract and to raise its rates as stipulated in the contract.  The lawsuit has been removed to the United States District Court for the District of Idaho.  On August 15, 2002, Truckee answered the complaint, denying the material allegations, and asserted various counterclaims against IE, IPC and IDACORP, in which it contends that these entities were in breach of the contract, inter alia, incident to the sale of surplus energy for Truckee, and by failing to provide firm backing for the capacity and associated energy provided pursuant to the contract.  On September 23, 2002, IE, IPC and IDACORP filed a reply to the counterclaim, denying the material allegations of Truckee's counterclaim.  Trial of the lawsuit is scheduled to commence September 8, 2003.

On July 23, 2002, Truckee filed a complaint against IPC, IE and IDACORP with the FERC seeking relief under its long-term power contract for the purchase of wholesale electric power from IPC and IE.

The complaint requests that the FERC, among other matters, (1) reform or terminate the contract under Section 206 of the Federal Power Act, (2) order refunds, (3) assert exclusive jurisdiction over the rate issues and exercise primary jurisdiction to consider state-law claims arising out of the contract provisions and underlying facts and (4) assess the market power of IE and IPC within the Sierra Pacific and IPC control areas under the FERC's Supply Margin Assessment test and impose appropriate remedies if the test is not passed.

The companies intend to vigorously defend their position in these proceedings and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

This has been previously reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.

United Systems, Inc., f/k/a Commercial Building Services, Inc.:  On March 18, 2002, United Systems, Inc. (United Systems) filed a complaint against IDACORP Services Co., a subsidiary of IDACORP, dba IDACORP Solutions.  United Systems is a heating, ventilation, refrigeration and plumbing contracting company that entered into a contract with IDACORP Services in December 2000.

Under the terms of the contract, IDACORP Services authorized United Systems to do business as "IDACORP Solutions."  The contract was to be effective from January 2001 through December 2005.

In November 2001, IDACORP Services notified United Systems that IDACORP Services was terminating the contract for convenience.  The contract allowed for such termination but required the terminating party to compensate the other party for all costs incurred in preparation for, and in performance of the contract, and for reasonable net profit for the remaining term of the contract.  United Systems claims $7 million in net profits lost and costs incurred.

IDACORP Services asserts that termination related compensation owed to United Systems, if any, is substantially less than the amount claimed by United Systems.

On August 8, 2002, United Systems filed an amended complaint adding IDACORP, IE, and IPC as additional defendants claiming they should be held jointly and severally liable for any judgment entered against IDACORP Services.

This case is set for a jury trial the week of June 13, 2003.  The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Public Utility District No. 1 of Grays Harbor County, Washington:  On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC, and IE.

On March 9, 2001, Grays Harbor entered into a 20-MW purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per MWh.  In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE.

In its lawsuit, Grays Harbor alleges that the assignment was void and unenforceable, and seeks restitution from IE and IDACORP.  Alternatively, Grays Harbor alleges that the contract should be rescinded or reformed as against IDACORP, IPC and IE, claiming that the contract was entered into pursuant to a mutual or unilateral mistake; that it is unconscionable; or that Grays Harbor entered into the contract under duress.  Grays Harbor seeks as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

IDACORP, IPC, and IE have removed this action from the state court to the United States District Court for the Western District of Washington at Tacoma.  The companies intend to vigorously defend this lawsuit and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

State of California Attorney General:  The California Attorney General (AG) filed the complaint in this case in the California Superior Court in San Francisco on May 30, 2002.  This is one of thirteen virtually identical cases brought by the AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair competition law - California Business and Professions Code Section 17200.  Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice . . . ."  The AG alleges that IPC engaged in unlawful conduct by violating the Federal Power Act (FPA) in two respects:  (1) by failing to file its rates with the FERC as required by the FPA; and (2) charging unjust and unreasonable rates in violation of the FPA.  The AG alleges that there were "thousands of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions."  Pursuant to Business and Professions Code Section 17206, the AG seeks civil penalties of up to $2,500 for each alleged violation.  IPC is vigorously defending the action.  On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002, the AG filed a motion to remand back to state court.  The court previously denied the AG's prior motions to remand back to state court in the companion cases.  IPC's Motion to Dismiss was heard by the court on July 31, 2002.  A decision is expected before the end of the year. IPC intends to vigorously defend its position in this proceeding and believes this matter will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II:  These cross-actions against IE and IPC emerge from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara Mathews in their personal capacities.  Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C., and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C., Duke Energy Oakland, L.L.C. (collectively, Duke).  While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC), colluded to influence the price of electricity in the California wholesale electricity market.  Plaintiffs asserted various claims that the defendants violated California Antitrust Law, (the Cartwright Act) Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business & Professions Code Section 17200, et seq.  Among the acts complained of are bid rigging, information exchanges, withholding of power, and various other wrongful acts.  These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants.  Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC.  Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC.  Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq.  As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the PMC as to any power Reliant purchased through the California markets.

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court.  IPC and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs.  As a result of the various motions, no trial date is set at this time.  The companies cannot predict the outcome of this proceeding, nor can they evaluate the merits of any of the claims at this time but they intend to vigorously defend these lawsuits.

California Energy Situation
As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation.  The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold.  Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff.  Under the participation agreement, if a participant in the CalPX exchange defaulted on a payment to the exchange, the other participants were required to pay their allocated share of the default amount to the exchange.  The allocated shares were based upon the level of trading activity, which included 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 the CalPX and the California Independent System Operator (Cal ISO) 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 Cal ISO were among the creditors of PG&E.  To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO, the 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 spot market 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's Chief Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the 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.

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, we believe our exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review.   The latter--more than 60--have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations.  The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation and although the California Parties (the California Attorney General, other state agencies and the California Investor Owned Utilities) have requested specific procedures to implement that requirement, the FERC has not yet acted on that request.

This case has been further complicated by an August 13, 2002 FERC staff (Staff) Report which included the recommendation to replace the published California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing Price (MMCP) to calculate refunds with other published indices for producing basin prices plus a transportation allowance. Staff's recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated published index prices.  Staff bases its speculation in large part on a statistical correlation analysis of Henry Hub and California prices.  If FERC accepts the Staff recommendation, the total amount of refunds could roughly double over earlier estimates. IE, in conjunction with others, submitted comments on the Staff recommendation - asserting that Staff's conclusions were incorrect in part on the basis of the fact that the Staff's correlation study ignored evidence of normal market forces and scarcity which created the pricing variations which Staff observed, rather than improper manipulation of reported prices.  Beyond soliciting comments on the Staff recommendation, the FERC has not decided whether or how to proceed with consideration of a change in the gas pricing methodology which it previously approved.

An Initial Decision and Recommendation from FERC Administrative Law Judge Birchman is anticipated during the Fall of 2002 and the FERC has indicated they would issue an order on those recommendations in early 2003.  Based upon that order and subject to possible modification based upon revision of the gas indices to be used, the Cal ISO would then be directed by the FERC to calculate revised refund amounts due from sellers of spot market power into the CalPX and Cal ISO during the refund period.

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 recommendations and findings to the FERC on September 24, 2001. The ALJ found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have submitted comments to the FERC respecting the ALJ's recommendations.  The City of Tacoma and the Port of Seattle have requested that the docket be reopened to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others.  IE has opposed that request, and both the ALJ's recommended findings and the issue of re-opening the record are pending at the FERC.

IPC transferred its non-utility wholesale electricity marketing operations to IE on June 11, 2001 effective June 1, 2001.  Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE.  At September 30, 2002, 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.  IE has accrued a reserve of $41 million against these receivables.

These reserves were calculated taking into account the uncertainty of collection, given the current California energy situation.  Based on the reserves recorded as of September 30, 2002, IE believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on its financial statements.

In a series of requests for information ending on May 8, 2002, the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001.  The request required IPC and IE to respond in the form of an affidavit to inquiries respecting various trading practices that the FERC identified in its fact-finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000.  IPC and IE filed the various responses sought by the FERC.  The May 2002 response indicated that although they did export energy from the CalPX outside of California during the period 2000-2001, they did not engage in any impermissible trading practice described in the Enron memoranda.  The energy was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction.  The companies denied engaging in the other ten practices identified by the FERC.  IPC and IE filed additional responses to the FERC on May 31 and June 5, 2002.  In the May 31 response, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price.  In the June 5 response, where the data request was directed to all sellers of natural gas in the Western Systems Coordinating Council and/or Texas during the years 2000-2001, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of natural gas together with a simultaneous purchase of the same product at the same price.

On October 2, 2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to IPC requesting, among other things, all records related to all natural gas and electricity trades by IPC involving "round trip trades", also known as "wash trades" or "sell/buyback trades" including, but not limited to those made outside the Western Systems Coordinating Council region.  The subpoena applies to both IE and IPC.  As discussed above, on May 22, 2002, both IE and IPC responded to a similar request from the FERC stating that they did not engage in "round trip" or "wash" trades.  By letter from the CFTC dated October 7, 2002, the Division of Enforcement agreed to hold in abeyance until a later date all items requested in the subpoena with the exception of one paragraph which related to three trades on a certain date with a specific party.  The companies have provided the requested information.

Nevada Power Company
In February and April of 2001 IE entered into several transactions under the Western Systems Power Pool (WSPP) Agreement whereby IE agreed to deliver to Nevada Power Company (NPC) 25 MW's during the third quarter of 2002.  NPC agreed to pay IE $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries.  Based upon the uncertain financial condition of NPC, IE asked for further assurances of NPC's ability to pay for the power if IE made the deliveries.  NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated the transactions effective July 8, 2002.

Pursuant to the WSPP Agreement IE notified NPC of the liquidated damages amount and NPC responded with a letter, which describes their view of rights under the WSPP Agreement and suggests a negotiated resolution.  IE will continue to pursue its rights under the WSPP Agreement.  At September 30, 2002, IE had a $5 million receivable related to the NPC claim.  IE will review the recoverability of the asset on an ongoing basis.

6.  REGULATORY ISSUES:

Wind Down of Power Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations.  The announcement stated that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce by approximately 50 percent.  IE planned to continue its natural gas marketing operations in Houston and was evaluating growth opportunities in the natural gas mid-stream markets through an office established in Denver.  On November 5, 2002, IDACORP announced that it was terminating further evaluation of growth opportunities in the mid-stream natural gas markets.  The announcement stated that IE would close its Denver office by year-end, affecting five employees, and because of its link to the natural gas platform, would shut down its natural gas trading operation in Houston by March 2003, affecting six employees.  The announcement concluded that IE's continued wind down of its electric trading operations would result in additional work-force reductions at IE's Boise operations through mid-2003.

With the announcement on November 5, 2002, to exit this business, IE will be recording a restructuring charge during the three months ended December 31, 2002 of between $8 and $13 million or $0.13 and $0.20 per share.  These charges relate to, among other matters, severance benefits, buyout of long-term lease agreements and expected impairment charges of fixed assets in the business.

Beginning August 1, 2002, IPC resumed the function of buying and selling wholesale electricity to support its utility operations.  IPC conducted electricity marketing until June 2001 when those operations were transferred to IE.

In connection with the wind down of power marketing at IE, certain matters were identified that require resolution with the FERC or the Idaho Public Utilities Commission (IPUC).

Matters that need to be resolved with the FERC include:

-a utility such as IPC is entitled to transmission priority for its retail customers, while transmission for trading transactions must be purchased under the utility's open access tariff on the same basis as third parties.  It appears that in some transactions this distinction was not observed;

-certain transactions between a utility and an affiliate are required to have prior FERC approval.  Such prior approval was not sought for some electricity transactions between IE and IPC, such as spinning reserves and load following services, which are common industry services; and

-although IPC informed the FERC before IE was split off from IPC that it intended to move the utility's power marketing business to IE, IPC's power marketing contracts were assigned without formally obtaining the requisite prior approval of the FERC.

IE and IPC voluntarily contacted the FERC in September 2002 to discuss these matters.  The FERC requested certain documents and other information most of which IE and IPC have supplied.  IE and IPC expect to make additional filings with the FERC in November 2002, which will include requests for approval of certain electricity transactions, the assignment of certain contracts between IPC and IE and termination of the Electricity Supply Management Services Agreement entered into between IPC and IE in June 2001.

Should the FERC conclude that its regulations or rate schedules were not complied with, it has significant discretion as to the appropriate remedies, if any.  The FERC's remedial authority includes the authority to require refunds, to order equitable relief, to suspend the authorization to sell wholesale power at market-based rates, and, in some instances, to impose monetary penalties.

In an IPUC proceeding that has been underway since May 2001, IPC and the IPUC staff have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates since February 2001.  Similar state regulatory issues relating to the period prior to February 2001 were resolved by the parties involved and approved by the IPUC by Order No. 28852 issued on August 28, 2002.  In that order, the IPUC approved IPC's ongoing hedging and risk management strategies.  This formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales.  In Order No. 29102, the IPUC directed IPC to present a resolution or a status report to the IPUC no later than December 20, 2002 on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues.

The companies do not believe that resolution of these transactions will have any adverse impact on retail customers or a material adverse effect on its ongoing operations.  However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on earnings and whether it will be material.

As previously disclosed, the FERC filing made on May 14, 2001, with respect to the pricing of real-time energy transactions between IPC and IE, is still under review by the FERC.  For the period June 2001 through March 2002, IE paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the period that was most favorable to IPC.  This amount was credited to ratepayers through the PCA.  An additional $1 million has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology.  However, until the FERC takes final action on this filing, rates for real-time transactions between IE and IPC are subject to adjustment.

Deferred Power Supply Costs
Idaho:  IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to Idaho retail customers.  These adjustments, which typically take effect 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 next year's PCA adjustment.

On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing.  The order granted recovery of $255 million of excess power supply costs, consisting of:

-$209 million of voluntary load reduction and power supply costs incurred between  March 1, 2001 and March 31, 2002.

-$28 million of excess power supply costs forecasted for the period April 2002-          March 2003.

-$18 million of unamortized costs previously approved for recovery beginning          October 1, 2001.  The amount authorized in October 2001 totaled $49 million.  This order spreads the remaining October rate increase, which would have ended in September 2002, through May 2003.

The order also:

-Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC sought to recover.

-Authorized recovery over a one-year period for all but $12 million of the $255 million of allowed deferred costs.  In June 2002, the IPUC issued Order No. 29065 deferring an additional $4 million applicable to certain industrial customers.  The $16 million will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.

-Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years.

-Discontinued the IPUC-required three-tiered rate structure for residential customers.

-Authorized a separate surcharge to collect approximately $3 million annually to fund future conservation programs.

The IPUC had previously issued an order disallowing the lost revenue portion of the irrigation load reduction program.  IPC believes that the IPUC's order is inconsistent with an earlier order that allowed recovery of such costs and IPC filed a Petition for Reconsideration on May 2, 2002.  On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration.  As a result of this order, approximately $12 million was expensed in September 2002.  IPC still believes it should be entitled to receive recovery of this amount and has asked the Idaho Supreme Court to review the IPUC's decision.

Oregon:  IPC filed an application with the Oregon Public Utility Commission (OPUC) to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction.  On June 18, 2001, the OPUC approved new rates that would recover less than $1 million over the next year.  Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon.  During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities.  IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs.  As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001.

IPC's deferred power supply costs consist of the following (in millions of dollars):

			September 30,		December 31,
			2002		2001
Oregon deferral			$	14	$	15
Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78
	Deferral for 2002-2003 rate year			3		-
	Irrigation load reduction program			-		70
	Astaris load reduction agreement			18		62
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		12		-
	Industrial customer deferral for recovery in the
		2003-2004 rate year		4		-
Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		37
	Remaining true-up authorized May 2001			-		43
	Remaining true-up authorized May 2002			125		-
	Total deferral		$	176	$	305

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in the Voluntary Load Reduction (VLR) Agreement between IPC and FMC/Astaris.  This VLR Agreement amended the Electric Service Agreement (ESA) that governs the delivery of electric service to FMC/Astaris' Pocatello plant, which ceased operations late in 2001.  On June 6, 2002, IPC and FMC/Astaris signed and filed a proposed Stipulation and Settlement Agreement (Agreement) with the IPUC and on June 10, 2002, the IPUC approved the Agreement in Order No. 29050 which included the following provisions:

-The VLR payments that IPC would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million.  Approximately 90 percent of this reduction will flow through the PCA mechanism as a reduction in costs to Idaho retail customers.

-FMC/Astaris agreed to dismiss, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.

-FMC/Astaris will pay IPC approximately $31 million through March 2003 to settle the ESA.

Garnet Power Purchase Agreement
IPC and Garnet Energy LLC (Garnet), a subsidiary of Ida-West, had entered into a power purchase agreement (PPA) for IPC to purchase energy produced by Garnet's to-be-built natural gas generation facility.  A hearing before the IPUC was scheduled for July 23, 2002 on IPC's application for an order approving the PPA and an accounting order authorizing the inclusion of power supply expenses associated with the purchase of capacity and energy from Garnet in the PCA.

Prior to the hearing date, Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility.  Garnet further advised IPC that there may be alternative financing arrangements that could allow Garnet to obtain financing within the constraints of the PPA.  However, pursuing alternative financing arrangements would require additional time. As a result IPC sought a continuance in the hearing scheduled for July 23, 2002.  Ida-West has capitalized approximately $11 million related to the Garnet facility as of September 30, 2002.

On July 24, 2002, the IPUC issued its ruling effectively closing the proceeding involving IPC's petition to enter into a PPA with Garnet.  IPC was directed to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how IPC proposes to meet future power requirements if the Garnet facility is not built.  On October 30, 2002, IPC submitted its compliance report to the IPUC, which included (1) Ida-West's notification that due to the dramatic changes in the electricity industry, financing the project on acceptable terms under the PPA was impracticable, (2) Ida-West's offering of three alternatives to allow the project to go forward and (3) IPC's revised plan for meeting future load requirements absent the PPA associated with the Garnet project including wholesale power purchases, energy exchanges, obtaining certain transmission rights or constructing or acquiring generation resources located in IPC's service territory.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, IPC filed an application requesting the IPUC to issue an accounting order authorizing IPC to defer its extraordinary costs associated with increased security measures subsequent to the events of September 11, 2001.  The additional or extraordinary security measures are needed to help ensure the safety of IPC employees and to protect IPC facilities.  In March 2002 the IPUC issued Order No. 28975 directing the following related to these costs:

-Costs in excess of $11,000 per month are to be deferred in a regulatory asset account.

-Such costs incurred in 2001 are to be amortized over a five-year period beginning in January 2003.  Costs deferred in each subsequent year are to be amortized beginning in January of the next calendar year.

-Deferred costs are to receive the appropriate carrying charge.

-Costs are to be allocated among IPC's various jurisdictions and affiliates.

-The IPUC deferred making a final decision regarding final allocation of deferred security expenses to other affiliates and sharing with shareholders until such time as the IPUC conducted a prudence review of the expenses.

At September 30, 2002, IPC had deferred $1 million of extraordinary security costs.

IDACORP Energy and Idaho Power Company Agreement
IPC entered into an Electricity Supply Management Services Agreement (Agreement) with IE in June 2001.  The IPUC is currently assessing issues associated with this Agreement.  While some of the issues likely became moot with the decision to wind down IE's trading operation, the IPUC staff has indicated its desire to continue to review whether adequate compensation has been provided to IPC customers as a result of transactions between IE and IPC after February 2001.  Similar issues arising prior to February 2001 were resolved by IPUC Order No. 28852.  IPUC Order No. 29102 requires that the remaining IPC/IE compensation and transfer pricing issues be brought to resolution or that a status report be filed by December 20, 2002.

A preliminary review of uncompensated amounts for transactions between IE and IPC occurring after February 2001 showed that the amount IE would pay to IPC could be approximately $6 million.

7.  DERIVATIVE FINANCIAL INSTRUMENTS:

Energy Trading Contracts
The following table details the gross margin for the energy marketing operations for the three and nine months ended September 30 (in millions of dollars):

			Three months ended				Nine months ended
			September 30,				September 30,
			2002		2001		2002		2001
Gross Margin:
	Realized or otherwise settled		$	(14)	$	74	$	37	$	106
	Unrealized (loss) gain			21		(5)		(37)		96
		Total	$	7	$	69	$	-	$	202

8.  INDUSTRY SEGMENT INFORMATION:

We have identified two reportable operating segments, Utility Operations and Energy Marketing.

The following table summarizes the segment information for our utility 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
		(millions of dollars)
Three months ended September 30, 2002
	Revenues	$	237	$	19		$	3	$		-	$		259
	Net income (loss)		38		1			(2)			-			37
Total assets at September 30, 2002		$	2,754	$	505		$	241	$		(90)	$		3,411
Three months ended September 30, 2001
	Revenues	$	287	$	105		$	3	$		-	$		395
	Net income (loss)		-		35			(1)			-			34
Total assets at December 31, 2001		$	2,860	$	718		$	202	$		(141)	$		3,639
Nine months ended September 30, 2002
	Revenues	$	660	$	37		$	12	$		-	$		709
	Net income (loss)		72		(7)			-			-			65
Nine months ended September 30, 2001
	Revenues	$	715	$	307		$	9	$		-	$		1,031
	Net income (loss)		20		89			(4)			-			105

Certain intersegment revenues from Utility Operations to Energy Marketing are not eliminated because they are included in the regulatory cost mechanism for IPC.

INDEPENDENT ACCOUNTANTS' REPORT

IDACORP, Inc.
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries as of September 30, 2002, and the related consolidated statements of income and comprehensive income for the three and nine month periods ended September 30, 2002 and 2001 and consolidated statements of cash flows for the nine month periods ended September 30, 2002 and 2001.  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 of IDACORP, Inc. and subsidiaries as of December 31, 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated January 31, 2002, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

DELOITTE & TOUCHE LLP
Boise, Idaho
November 7, 2002

Item 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions, except per share amounts.  Megawatt hours (MWh) in thousands.)

INTRODUCTION:

In Management's Discussion and Analysis (MD&A) we explain the general financial condition and results of operations for IDACORP, Inc. (IDACORP) and subsidiaries.  IDACORP is a holding company formed in 1998 as the parent of Idaho Power Company (IPC), IDACORP Energy (IE), and several other entities.

IPC is an electric utility with a service territory covering over 20,000 square miles in southern Idaho and eastern Oregon.  IPC is the parent of Idaho Energy Resources, Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant.

IDACORP announced on June 21, 2002 that IE will wind down its power marketing operations.  The announcement stated that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce by 46 percent or approximately 50 employees.

IPC added 3,146 general business customers during the three months ended September 30, 2002 and 9,352 additional customers for the nine months ended September 30, 2002.  As of September 30, 2002, IPC had 411,091 general business customers.

IDACORP's other significant operating subsidiaries are:

-Ida-West Energy (Ida-West) - independent power projects development and management;

-IdaTech - developer of integrated fuel cell systems;

-IDACORP Financial Services (IFS) - affordable housing and other real estate investments;

-Velocitus - commercial and residential Internet service provider;

-IDACOMM - provider of telecommunications services.

References in this report to "we" and "our" are to IDACORP, Inc. and its subsidiaries.

This MD&A should be read in conjunction with the accompanying consolidated financial statements.  This discussion updates our MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2001, and 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 us or on our behalf 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:

-changes in governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utility Commission (IPUC) and the Oregon Public Utility Commission (OPUC), 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, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;

-litigation resulting from the energy situation in the western United States;

-economic and geographic factors including political and economic risks;

-changes in and compliance with environmental and safety laws and policies;

-weather variations affecting customer energy usage;

-operating performance of plants and other facilities;

-environmental conditions and requirements;

-system conditions and operating costs;

-population growth rates and demographic patterns;

-competition for retail and wholesale customers;

-pricing and transportation of commodities;

-market demand and prices for energy, including structural market changes;

-capacity and fuel;

-changes in tax rates or policies, or interest rates or in rates of inflation;

-changes in actuarial assumptions;

-exposure to market and credit risk in our energy trading and marketing operations;

-changes in project costs;

-unanticipated changes in operating expenses and capital expenditures;

-capital market conditions;

-rating actions by Moody's, Standard & Poor's (S&P) and Fitch IBCA (Fitch);

-competition for new energy development opportunities;

-the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;

-natural disasters, act of war or terrorism;

-legal and administrative proceedings (whether civil or criminal) and settlements that influence our business and profitability; and

-new accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.

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, followed by a more detailed discussion of our electric utility and energy marketing activities for the three and nine months ended September 30:

			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2002		2001		Change		2002		2001		Change
Earnings per share of
	common stock
	Electric utility		$	1.02	$	-	$	1.02	$	1.93	$	0.52	$	1.41
	Energy marketing			0.02		0.93		(0.91)		(0.19)		2.38		(2.57)
	Other			(0.06)		(0.02)		(0.04)		(0.02)		(0.10)		0.08
		Total	$	0.98	$	0.91	$	0.07	$	1.72	$	2.80	$	(1.08)

Earnings per share from our utility operations increased $1.02 and $1.41 for the three and nine months ended September 30, 2002.  Major changes occurring at the utility caused the following increases to our EPS:

-Net power supply costs absorbed by the utility decreased $14 million and $37 million for the three and nine months ended September 30, 2002 increasing EPS $0.22 and $0.59, respectively.

-A change to the utility's tax accounting method for capitalized overhead costs in addition to settled income tax deficiencies related to its partnership investment in Bridger Coal Company created a tax benefit of $37 million or a $0.96 increase to our EPS during the three months ended September 30, 2002.

-Lost revenue of $12 million was expensed during the three months ended September 30, 2002, after the utility was denied its request to recover lost revenue from the 2001 irrigation load reduction program.  This amount compares to $10 million in disallowed Power Cost Adjustment (PCA) costs expensed during the three months ended September 30, 2001.

EPS from energy marketing activities decreased $0.91 and $2.57 for the three and nine months ended September 30, 2002.  Last year's results were driven by high prices, extreme volatility and wide regional price spreads.  The decline in regional price spreads and volatility, combined with the decreasing number of creditworthy counterparties, has limited our ability to match the results of the prior year.  In addition, the decision to wind down power marketing and trading at IE has also reduced the EPS from this segment.

EPS from our other business decreased $0.04 for the three months ended September 30, 2002 due to a $0.01 increase at IFS offset by declines at Ida-West of $0.01 and IdaTech/IDACOMM of $0.02.  For the nine months ended September 30, 2002, EPS at our other businesses increased $0.08 due to a $0.05 increase at IFS and $0.03 increase at IdaTech/IDACOMM offset by a $0.06 decrease at Ida-West.  The remaining changes represent an adjustment to consolidated income tax expense to reflect an expected full year effective tax of less than zero.

On July 12, 2002 IPC customers set a record for power use of 2,963 megawatts (MW).  The previous record, 2,919 MW, was set on July 12, 2000.

Utility Operations
This section discusses IPC's utility operations, which are subject to regulation by the state regulatory commissions of Idaho and Oregon, and the FERC.

General Business Revenue:  The following table presents IPC's general business revenue and MWh sales for the three and nine months ended September 30:

		Three Months Ended September 30,						Nine Months Ended September 30,
		Revenue				MWh		Revenue				MWh
		2002		2001		2002	2001	2002		2001		2002	2001
Residential		$	68	$	61	966	956	$	223	$	181	3,209	3,139
Commercial			50		45	878	883		146		117	2,592	2,526
Industrial			46		41	848	939		133		109	2,412	3,001
Irrigation			52		39	1,047	769		88		68	1,717	1,342
	Total	$	216	$	186	3,739	3,547	$	590	$	475	9,930	10,008

IPC's general business revenue is dependent on many factors, including the number of customers served, the rates charged and economic and weather conditions.  The 2002 change in revenues is due primarily to the following:

-Rate increases due to the annual PCA resulted in increased revenues of approximately $15 million and $89 million for the three and nine months ended September 30, 2002.  The PCA is discussed in more detail below in "Regulatory Issues."

-Customer growth in IPC's service territory increased approximately two percent, resulting in a $3 million and $6 million increase in revenues for the three and nine months ended September 30, 2002.

-In 2001 many irrigation customers participated in a program to decrease their usage.  This program was not in effect during 2002, resulting in increased sales to irrigation customers of $13 million and $20 million for the three and nine months ended September 30, 2002.

-FMC/Astaris, previously IPC's largest volume customer, closed its Pocatello manufacturing plant late in 2001.  However, based on a take or pay contract with FMC/Astaris which requires payment for power regardless of delivery, IPC will continue to receive payments from FMC/Astaris through March 2003.  Because of this revenues from FMC/Astaris changed minimally, despite the significant decrease in MWhs sold.

Off-system sales:  Off-system sales consist primarily of sales of surplus system energy when available, and long-term sales contracts.  Revenues decreased for the three and nine months ended September 30, 2002 due to decreased availability of surplus system energy and lower wholesale electricity prices. The following table presents IPC's off-system sales for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2002		2001		2002		2001
Off-system sales	$	11	$	92	$	42	$	206
MWhs		388		744		1,641		1,774
Revenue per MWh	$	28.02	$	123.25	$	25.60	$	115.90

Purchased power:  The decrease in purchased power expense is due primarily to reduced wholesale electricity prices.  Additionally, improved hydroelectric generation decreased our dependence on purchased power.  Load reduction program costs also included in purchased power have decreased due to expiration of the irrigation load reduction program and changes to the FMC/Astaris Voluntary Load Reduction Agreement.  The following table presents IPC's purchased power expenses for the three and nine months ended September 30:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2002		2001		2002		2001
Purchased Power:
	Purchases	$	35	$	148	$	71	$	405
	Program costs		15		80		41		118
MWhs			1,132		1,352		2,435		2,795
Cost per MWh		$	30.72	$	109.72	$	29.27	$	145.05

Fuel expense:  Fuel expense increased slightly for the three and nine months ended September 30, 2002 as decreased generation was offset by increased coal prices.  The following table presents IPC's fuel expense for the three and nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2002		2001		2002		2001
Fuel expense	$	27	$	26	$	76	$	74
Thermal MWhs generated		1,900		1,993		5,312		5,640

PCA:  The PCA expense component is related to IPC's PCA regulatory mechanism.  In 2001, actual power supply costs were significantly greater than forecasted, resulting in a large PCA credit, which is now being recovered in rates (as revenues) and the deferred balance is being amortized as PCA expense.  FMC/Astaris and irrigation load reduction program cost deferrals also affect the PCA.  The PCA is discussed in more detail below in "Regulatory Issues."

The following table presents the components of PCA expense for the three and nine months ended September 30:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2002		2001		2002		2001
Current year power supply costs accrual (deferral)		$	(3)	$	(32)	$	1	$	(142)
Astaris and irrigation program costs (deferral)			(12)		(72)		(31)		(105)
Amortization of prior year authorized balances			60		36		150		53
Write-off of disallowed costs			12		10		13		10
	Total power cost adjustment	$	57	$	(58)	$	133	$	(184)

Energy Marketing
The following table presents our energy marketing operations (including intersegment transactions) for the three and nine months ended September 30:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2002		2001		2002		2001
Operating revenues:
	Electricity		$	20	$	103	$	33	$	300
	Gas			(1)		2		4		7
		Total	$	19	$	105	$	37	$	307
Settled volumes:
	Electricity (MWh's)			7,807		11,356		34,327		24,553
	Gas (mmbtu's in thousands)			7,941		31,381		31,822		80,108
Operating expenses:
	Electricity		$	17	$	47	$	46	$	156
	Gas			1		1		5		4
		Total	$	18	$	48	$	51	$	160

Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues Involved in Accounting for Contracts under EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities"" reached a consensus to rescind EITF 98-10, the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS 133.  The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002.  Energy trading contracts not within the scope of SFAS 133 purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting.  In addition, effective on January 1, 2003, all energy trading contracts we previously accounted for at fair value under EITF 98-10 must be adjusted to historical cost unless those contracts meet the definition of a derivative under SFAS 133.  We will be required to record this adjustment as a cumulative effect of adoption of a new accounting principle.  We are currently assessing but have not yet determined the impact of the rescission of EITF 98-10 on our financial statements.  The changes are anticipated to primarily affect the timing of the recognition of income or loss in earnings, and not change the underlying economics or cash flows of transactions entered into by IE.

EITF 02-3 also reached a consensus that gains and losses on derivative instruments within the scope of SFAS 133 should be shown net in the income statement if the derivative instruments are held for trading purposes.  In anticipation of this requirement, IDACORP has elected to change its presentation of energy trading activities from gross to net presentation, in accordance with the option allowed under EITF 98-10.  Prior periods have been reclassified to conform to current presentation.   Therefore Operating Revenues for the Energy Marketing segment include revenues from the sale of electricity and gas netted against the cost of purchased power and natural gas.  Additionally, all financial transactions are presented on a net basis as operating revenue and unrealized income is presented on a net basis as operating revenue.  Operating expenses include general and administrative expenses, bad debt reserves, transmission expenses and broker fees.  Our net financial position and results of operations were not affected by this change in presentation.

The decrease in operating revenues, operating expenses and earnings are due to the dramatic decline in regional price per MWh, pricing spreads and volatility.  The decisions to terminate the Electricity Supply Management Services Agreement with IPC and to wind down power marketing and trading at IE have also caused a reduction in these items.  Additionally, unrealized revenues have declined as a result of a reduction in the valuation of certain forward positions due to the continued deterioration of credit quality in the industry and the significant reduction of new deals being added to the energy marketing portfolio as a result of the power wind down.  Despite this decrease in revenue, settled physical power sales have increased 40 percent over the first nine months of 2001.  This increase is driven primarily by the settling of transactions already on the books prior to the decision to wind down this segment of the business.  Settled physical power sales have decreased 31 percent for the three months ended September 30, 2002 primarily due to the discontinuation of pursuing the power marketing business.  Our average price per settled MWh sold decreased from $157 in the first nine months of 2001 to $34 in the first nine months of 2002 and from $154 in the three months ended September 30, 2001 to $43 in the three months ended September 30, 2002.  Basis spreads between regions and price volatility continue to be much lower than last year.

We measure our sensitivity to commodity price risk using a value-at-risk (VaR) measure.  This methodology computes VaR based upon forward market prices and forward price volatility and correlation as of September 30, 2002.  Our average VaR for the quarter was $0.7 million, peaking at $1.9 million.  As of September 30, 2002 it was $0.6 million.  Our VaR measure is calculated by application of a variance/covariance methodology - assuming a 95 percent confidence level and a one-day holding period.  Daily backtesting ensures that VaR measures produced by the model are in line with actual historical results.

The VaR is understood to be 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, at September 30, 2002, there is a five percent chance that the daily loss could exceed $0.6 million.

Contracts Accounted for at Fair Value:  When determining the fair value of our marketing and trading contracts, we use actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities.  To determine fair value of contracts with terms that are not consistent with actively quoted prices, we use (when available) prices provided by other external sources.  When prices from external sources are not available, we determine prices by using internal pricing models that incorporate available current and historical pricing information.  Finally, we adjust the fair market value of our contracts for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level.

The following table details the gross margin for the energy marketing operations for the three and nine months ended September 30:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2002		2001		2002		2001
Gross Margin:
	Realized or otherwise settled		$	(14)	$	74	$	37	$	106
	Unrealized (loss) gain			21		(5)		(37)		96
		Total	$	7	$	69	$	-	$	202

At September 30, 2002, 54 percent of the credit exposure related to our unrealized position is with investment grade counterparties.  Additionally, more than 50 percent of this credit exposure is with one investment grade counterparty.  Less than one percent is with non-investment grade counterparties.  The remaining 45 percent of credit exposure is with non-rated counterparties.  The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives.

The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2001 and September 30, 2002 is explained as follows:

Net fair value of contracts outstanding as of 12/31/2001		$	138
Contracts realized or otherwise settled during the period			(37)
Net fair value of new contracts when entered into during the period			2
Changes in net fair value attributable to market prices and other market changes			(17)
	Net fair value of contracts outstanding as of 9/30/2002	$	86

The net fair value of new contracts when entered into during the period reflect the change in value of deals on the day the deals were transacted.  This value is reflective of the market price change during the course of one day and the corresponding change in value of a deal from the time it was transacted until the close of business on the transaction date.

Changes in net fair value attributable to market prices and other market changes include:

-Changes in value due to changes in actively quoted prices;

-Changes in value due to changes in prices provided by other external sources;

-Changes in value due to changes in prices derived by models or other methods;

-Changes in value due to the decisions to terminate the Electricity Supply Management Services Agreement with IPC and discontinuation of the power marketing and trading business;

-Changes in implied volatility and price correlations;

-Changes in liquidity at various delivery points that are driven by changes in market conditions;

-Changes in discounts related to counterparty creditworthiness.

Net fair value at September 30, 2002 disaggregated by source of fair value and maturity of contracts:

			Maturity						Maturity
			less than		Maturity		Maturity		in excess of
Source of Fair Value			1 year		1-3 years		4-5 years		5 years		Total
Prices actively quoted			$	21	$	30	$	4	$	-	$	55
Prices provided by other
	external sources			3		19		(3)		14		33
Prices based on models
	and other valuation
	methods			-		(2)		1		(1)		(2)
		Total	$	24	$	47	$	2	$	13	$	86

Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg.  The time horizon is October 2002 through September 2007.  Products include physical, financial, swap, interest rate, index and basis for both natural gas and heavy load power.

Prices provided by other external sources are quoted periodically by brokers and trading exchanges such as TFS, APB, Prebon, Intercontinental, and Bloomberg.  The time horizon is October 2002 through December 2010.  Products include physical, financial, swap, index and basis for both natural gas and heavy and light load power.

Prices derived from models and other valuation methods incorporate available current and historical pricing information and assumptions.  The time horizon is October 2002 through December 2007.  Products include transmission, options and ancillary services related to heavy and light load power.

INCOME TAXES:

Tax Accounting Method Change
During the three months ended September 30, 2002 we filed our 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs.  The old method allocated such costs primarily to construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.

IPC adopted the method change during 2002 to take advantage of new tax rules enacted or promulgated during the first half of 2002. The key rule changes include: an announcement in January that this method change qualifies for the automatic change procedures; the signing in March of an economic stimulus bill that expanded the loss carryback period from two years to five years; and the announcement in March that the full effects of method changes could be absorbed in the year of change.  These new rules provided sufficient incentive to IPC to adopt the method change with our 2001 tax return, filed in September 2002.

The tax accounting method change has been recorded as a decrease to income tax expense for the three months ended September 30, 2002 of $31 million, attributable to 2001 and prior years, and is consistent with prior regulatory treatment.  The 2002 effects of the method change have been included as a $3 million decrease to income tax expense for the three months ended September 30, 2002.

Status of Audit Proceedings
During the three months ended September 30, 2002 IPC settled income tax deficiencies related to its partnership investment in the Bridger Coal Company, covering the years 1991 through 1998.  The settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.

Our federal income tax returns for years through 1997 have been examined by the Internal Revenue Service and substantially all issues have been settled.  Management believes that adequate provision for income taxes has been made for the open years 1998 and after and for any unsettled issues prior to 1998.

LIQUIDITY AND CAPITAL RESOURCES:

Cash Flow
Our net cash provided by operations totaled $243 million for the nine months ended September 30, 2002.  Significant factors affecting cash flows in 2002 include:

-a $54 million income tax refund related to net operating loss carrybacks associated with 2001 power supply costs received during the six months ended June 30, 2002 and a $14 million income tax refund related to a change to IPC's tax accounting method for capitalized overhead costs received in September 2002, offset by tax payments of $46 million;

-the recovery through the PCA of power supply costs incurred in 2001 and 2002.

We anticipate that our cash flows from operations will continue to be positively affected as we recover the remaining balance of the 2002 PCA.  We discuss the PCA in the section "Regulatory Issues" below.

Contractual Cash Obligations
Total contractual cash obligations of $944 million at September 30, 2002 declined compared with December 31, 2001 mainly due to the early redemption of $50 million of First Mortgage Bonds.  Other changes since December 31, 2001 are consistent with normal business operations.

Working Capital
The significant changes in working capital that are not attributed to normal business activity and timing are discussed below.

Due to the wind down of the power marketing and trading business, customer receivables have decreased $53 million, accounts payable have decreased $75 million and other liabilities have decreased $36 million.

Energy marketing assets and liabilities represent the fair value of energy marketing contracts.  The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds.  The decreases in energy marketing assets and liabilities from December 31, 2001 to September 30, 2002 is primarily a reflection of lower market prices at September 30, 2002 and the wind down of the power marketing business.

The changes in regulatory assets - current and derivative liabilities - current are due to adoption of Financial Accounting Standards Board (FASB) Derivative Implementation Group Interpretation C-15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity."

The increase in taxes payable is primarily due to estimated taxes payable offset by the receipt of $54 million related to net operating loss carrybacks associated with 2001 power supply costs and a remaining $23 million in tax benefits to be received due to IPC's tax accounting method change for capitalized overhead costs.

Cash Expenditures
We forecast that internal cash generation after dividends will provide approximately 100 percent of total capital requirements in 2002 and 97.5 percent during the two-year period 2003-2004.  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.

In 2002, we have targeted a reduction in our capital-spending program of between 10 percent and 20 percent of our overall $200 million capital budget.  Emphasis will be in the areas of nonessential expenditures that will not negatively impact our customers or reliability of our systems.  Through September 2002, we are 17 percent below our budgeted levels.

Financing Program
Credit facilities have been established at both IDACORP and IPC. IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364-day credit facility that expires in March 2003.  Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating.  Commercial paper may be issued up to the amounts supported by the credit facilities.  At September 30, 2002, short-term borrowing on these facilities totaled $283 million.

IPC has regulatory authority to incur up to $350 million of short-term indebtedness.  IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which it pays a facility fee on the commitment quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued subject to the regulatory maximum, up to the amount supported by the credit facilities.  At September 30, 2002, IPC's short term borrowing under this facility totaled $133 million.  IPC repaid $100 million of floating rate notes in September 2002 using short-term borrowings from IDACORP which are payable on November 15, 2002.  IPC plans to replace this intercompany debt with external financing.

IDACORP currently has shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt securities, including medium-term notes, and preferred or common stock.  At September 30, 2002 none had been issued.

IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock.  At September 30, 2002 none had been issued.

In March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed using short-term borrowings.

IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.

IDACORP has been considering the issuance of common stock or equity linked securities.  We are currently reviewing this in light of the decision to wind down our wholesale power marketing function.  We are reviewing options to balance our capital structure while minimizing the need for new equity.  Accordingly, we do not anticipate issuing new common stock or equity linked securities during the balance of 2002 except for common stock issued for our Dividend Reinvestment Plan and our Employee Savings Plan.

Credit Rating
On September 10, 2002, Moody's changed its rating outlook for IPC to negative from stable.  Moody's stated that the negative rating outlook reflects uncertainties relating to potential effects from the FERC-related matters associated with the wind down of the power marketing business at IE.

Access to capital markets at a reasonable cost is determined in large part by credit quality.  The following outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities:

	Standard and Poor's		Moody's		Fitch IBCA
	IPC	IDACORP	IPC	IDACORP	IPC	IDACORP
Corporate Credit Rating	A-	A-	A3	Baa 1	None	None
Senior Secured Debt	A	None	A2	None	A	None
Senior Unsecured Debt	BBB+	BBB+	A3	Baa 1	A-	BBB+
Preferred Stock	BBB	BBB-	Baa 2	Baa 3	BBB+	None
Trust Preferred Stock	None	BBB-	None	Baa 2	None	BBB
Commercial Paper	A-2	A-2	P-1	P-2	F-1	F-2
Rating Outlook	Positive	Positive	Negative	Negative	Stable	Stable

These security ratings reflect the views of the rating agencies.  An explanation of the significance of these ratings may be obtained from each rating agency.  Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness.  Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.  Each rating should be evaluated independently of any other rating.

Some collateral agreements in place between IE and its counterparties include provisions requiring additional margining in the event of a credit rating downgrade.  In general, credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IDACORP.  A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact on the liquidity of IDACORP.  IDACORP believes its existing credit facilities are adequate to fund these potential liquidity requirements.

REGULATORY ISSUES:

Wind Down of Power Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations.  The announcement stated that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce by approximately 50 percent.  IE planned to continue its natural gas marketing operations in Houston and was evaluating growth opportunities in the natural gas mid-stream markets through an office established in Denver.  On November 5, 2002, IDACORP announced that it was terminating further evaluation of growth opportunities in the mid-stream natural gas markets.  The announcement stated that IE would close its Denver office by year-end, affecting five employees, and because of its link to the natural gas platform, would shut down its natural gas trading operation in Houston by March 2003, affecting six employees.  The announcement concluded that IE's continued wind down of its electric trading operations would result in additional work-force reductions at IE's Boise operations through mid-2003.

With the announcement on November 5, 2002, to exit this business, IE will be recording a restructuring charge during the three months ended December 31, 2002 of between $8 and $13 million or $0.13 and $0.20 per share.  These charges relate to, among other matters, severance benefits, buyout of long-term lease agreements and expected impairment charges of fixed assets in the business.

Beginning August 1, 2002, IPC resumed the function of buying and selling wholesale electricity to support its utility operations.  IPC conducted electricity marketing until June 2001 when those operations were transferred to IE.

In connection with the wind down of power marketing at IE, certain matters were identified that require resolution with the FERC or the IPUC.

Matters that need to be resolved with the FERC include:

-a utility such as IPC is entitled to transmission priority for its retail customers, while transmission for trading transactions must be purchased under the utility's open access tariff on the same basis as third parties.  It appears that in some transactions this distinction was not observed;

-certain transactions between a utility and an affiliate are required to have prior FERC approval.  Such prior approval was not sought for some electricity transactions between IE and IPC, such as spinning reserves and load following services, which are common industry services; and

-although IPC informed the FERC before IE was split off from IPC that it intended to move the utility's power marketing business to IE, IPC's power marketing contracts were assigned without formally obtaining the requisite prior approval of the FERC.

IE and IPC voluntarily contacted the FERC in September 2002 to discuss these matters.  The FERC requested certain documents and other information most of which IE and IPC have supplied.  IE and IPC expect to make additional filings with the FERC in November 2002, which will include requests for approval of certain electricity transactions, the assignment of certain contracts between IPC and IE and termination of the Electricity Supply Management Services Agreement entered into between IPC and IE in June 2001.

Should the FERC conclude that its regulations or rate schedules were not complied with, it has significant discretion as to the appropriate remedies, if any.  The FERC's remedial authority includes the authority to require refunds, to order equitable relief, to suspend the authorization to sell wholesale power at market-based rates, and, in some instances, to impose monetary penalties.

In an IPUC proceeding that has been underway since May 2001, IPC and the IPUC staff have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates since February 2001.  Similar state regulatory issues relating to the period prior to February 2001 were resolved by the parties involved and approved by the IPUC by Order No. 28852 issued on August 28, 2002.  In that order, the IPUC approved IPC's ongoing hedging and risk management strategies.  This formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales.  In Order No. 29102, the IPUC directed IPC to present a resolution or a status report to the IPUC no later than December 20, 2002 on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues.

The companies do not believe that resolution of these transactions will have any adverse impact on retail customers or a material adverse effect on its ongoing operations.  However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on earnings and whether it will be material.

As previously disclosed, the FERC filing made on May 14, 2001, with respect to the pricing of real-time energy transactions between IPC and IE, is still under review by the FERC.  For the period June 2001 through March 2002, IE paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the period that was most favorable to IPC.  This amount was credited to ratepayers through the PCA.  An additional $1 million has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology.  However, until the FERC takes final action on this filing, rates for real-time transactions between IE and IPC are subject to adjustment.

Deferred Power Supply Costs
Idaho:  IPC has a PCA mechanism that provides for annual adjustments to the rates charged to Idaho retail customers.  These adjustments, which typically take effect 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 next year's PCA adjustment.

On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing.  The order granted recovery of $255 million of excess power supply costs, consisting of:

-$209 million of voluntary load reduction and power supply costs incurred between  March 1, 2001 and March 31, 2002.

-$28 million of excess power supply costs forecasted for the period April 2002-March 2003.

-$18 million of unamortized costs previously approved for recovery beginning          October 1, 2001.  The amount authorized in October 2001 totaled $49 million.  This order spreads the remaining October rate increase, which would have ended in September 2002, through May 2003.

The order also:

-Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC sought to recover.

-Authorized recovery over a one-year period for all but $12 million of the $255 million of allowed deferred costs.  In June 2002, the IPUC issued Order No. 29065 deferring an additional $4 million applicable to certain industrial customers.  The $16 million will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.

-Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years

-Discontinued the IPUC-required three-tiered rate structure for residential customers.

-Authorized a separate surcharge to collect approximately $3 million annually to fund future conservation programs.

The IPUC had previously issued an order disallowing the lost revenue portion of the irrigation load reduction program.  IPC believes that the IPUC's order is inconsistent with an earlier order that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002.  On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration.  As a result of this order, approximately $12 million was expensed in September 2002.  IPC still believes it should be entitled to receive recovery of this amount and has asked the Idaho Supreme Court to review the IPUC's decision.

Oregon:  IPC filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction.  On June 18, 2001, the OPUC approved new rates that would recover less than $1 million over the next year.  Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon.  During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities.  IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs.  As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001.

IPC's deferred power supply costs consist of the following:

			September 30,		December 31,
			2002		2001
Oregon deferral			$	14	$	15
Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78
	Deferral for 2002-2003 rate year			3		-
	Irrigation load reduction program			-		70
	Astaris load reduction agreement			18		62
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		12		-
	Industrial customer deferral for recovery in the
		2003-2004 rate year		4		-
Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		37
	Remaining true-up authorized May 2001			-		43
	Remaining true-up authorized May 2002			125		-
	Total deferral		$	176	$	305

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in the Voluntary Load Reduction (VLR) Agreement between IPC and FMC/Astaris.  This VLR Agreement amended the Electric Service Agreement (ESA) that governs the delivery of electric service to FMC/Astaris' Pocatello plant, which ceased operations late in 2001.  On June 6, 2002, IPC and FMC/Astaris signed and filed a proposed Stipulation and Settlement Agreement (Agreement) with the IPUC and on June 10, 2002, the IPUC approved the Agreement in Order No. 29050 which included the following provisions:

-The VLR payments that IPC would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million.  Approximately 90 percent of this reduction will flow through the PCA mechanism as a reduction in costs to Idaho retail customers.

-FMC/Astaris agreed to dismiss, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.

-FMC/Astaris will pay IPC approximately $31 million through March 2003 to settle the ESA.

Garnet Power Purchase Agreement
IPC and Garnet Energy LLC (Garnet) a subsidiary of Ida-West, had entered into a power purchase agreement (PPA) for IPC to purchase energy produced by Garnet's to-be-built natural gas generation facility.  A hearing before the IPUC was scheduled for July 23, 2002 on IPC's application for an order approving the PPA and an accounting order authorizing the inclusion of power supply expenses associated with the purchase of capacity and energy from Garnet in the PCA.

Prior to the hearing date, Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility.  Garnet further advised IPC that there may be alternative financing arrangements that could allow Garnet to obtain financing within the constraints of the PPA.  However, pursuing alternative financing arrangements would require additional time.  As a result, IPC sought a continuance in the hearing scheduled for July 23, 2002.  Ida-West has capitalized approximately $11 million related to the Garnet facility as of September 30, 2002.

On July 24, 2002, the IPUC issued its ruling effectively closing the proceeding involving IPC's petition to enter into a PPA with Garnet.  IPC was directed to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how IPC proposes to meet future power requirements if the Garnet facility is not built.   On October 30, 2002, IPC submitted its compliance report to the IPUC, which included (1) Ida-West's notification that due to the dramatic changes in the electricity industry, financing the project on acceptable terms under the PPA was impracticable, (2) Ida-West's offering of three alternatives to allow the project to go forward and (3) IPC's revised plan for meeting future load requirements absent the PPA associated with the Garnet project including wholesale power purchases, energy exchanges, obtaining certain transmission rights or constructing or acquiring generation resources located in IPC's service territory.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, IPC filed an application requesting the IPUC to issue an accounting order authorizing IPC to defer its extraordinary costs associated with increased security measures subsequent to the events of September 11, 2001.  The additional or extraordinary security measures are needed to help ensure the safety of IPC employees and to protect IPC facilities.  In March 2002 the IPUC issued Order No. 28975 directing the following related to these costs:

-Costs in excess of $11,000 per month are to be deferred in a regulatory asset account.

-Such costs incurred in 2001 are to be amortized over a five-year period beginning in January 2003.  Costs deferred in each subsequent year are to be amortized beginning in January of the next calendar year.

-Deferred costs are to receive the appropriate carrying charge.

-Costs are to be allocated among IPC's various jurisdictions and affiliates.

-The IPUC deferred making a final decision regarding final allocation of deferred security expenses to other affiliates and sharing with shareholders until such time as the IPUC conducted a prudence review of the expenses.

At September 30, 2002, IPC had deferred $1 million of extraordinary security costs.

IDACORP Energy and Idaho Power Company Agreement
IPC entered into an Electricity Supply Management Services Agreement (Agreement) with IE in June 2001.  The IPUC is currently assessing issues associated with this Agreement.  While some of the issues likely became moot with the decision to wind down IE's trading operation, the IPUC staff has indicated its desire to continue to review whether adequate compensation has been provided to IPC customers as a result of transactions between IE and IPC after February 2001.  Similar issues arising prior to February 2001 were resolved by IPUC Order No. 28852.  IPUC Order No. 29102 requires that the remaining IPC/IE compensation and transfer pricing issues be brought to resolution or that a status report be filed by December 20, 2002.

A preliminary review of uncompensated amounts for transactions between IE and IPC occurring after February 2001 showed that the amount IE would pay to IPC could be approximately $6 million.

Integrated Resource Plan
Every two years, IPC is required to file with the IPUC and OPUC an Integrated Resource Plan (IRP), a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand.  The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within our utility service territory by mid-2005.  The new resources to be in place at that time were the previously identified 250-MW power purchase from the Garnet facility, an additional 100 MW generation resource to be determined and a 100 MW transmission upgrade to increase import capability.  These resources would all be necessary to satisfy energy demand during IPC's peak periods.  Prior to 2005, IPC will continue to use purchases from the Northwest energy markets as necessary to meet short-term energy needs.

As discussed earlier in "Garnet Power Purchase Agreement," IPC filed a compliance report with the IPUC on October 30, 2002 regarding the feasibility of financing the Garnet project under the existing PPA and current market conditions, as well as IPC's set of resource alternatives to the Garnet PPA.

The IPUC Staff and several other interested parties filed comments responding to IPC's proposed 2002 IRP.  The comments urge the IPUC not to acknowledge the IRP until (1) the Garnet issue is resolved, and (2) IPC provides additional detail on potential conservation measures that could be implemented.  IPC filed reply comments on October 30, 2002 addressing those issues.  The Garnet report was included in our reply comments by reference.  The IPUC will now consider the reply comments and the Garnet report as it deliberates on whether to acknowledge IPC's 2002 IRP as modified.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size and complexity of the project. Currently, the licenses for five hydro projects have expired.  These projects continue to operate under annual licenses.  Three more hydro project licenses will expire by 2010.

IPC is actively pursuing the relicensing of these projects, a process that may continue for the next 10 to 15 years. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric projects. The licenses for the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon) and the Swan Falls Project expire in 2005 and 2010, respectively. IPC is currently engaged in procedures necessary to file timely license applications for these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, IPC anticipates that it will relicense each of the eight projects.

Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls, and Shoshone Falls Projects.  New FERC licenses are anticipated at year-end.  While the actual costs of protection, mitigation and enhancement (PM&E) measures and other costs associated with the relicensing of the projects will not be known until the new license is issued by the FERC, costs associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million over the first five years of the licenses and $28 million over the following 25 years.

A draft EIS has been issued for the CJ Strike project and a new FERC license is expected in early 2003.  While the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC, costs associated with the license (assuming a 30-year license) are expected to total approximately $9 million over the first five years of the license and $38 million over the following 25 years.

The Upper and Lower Malad project license expires in July 2004 and the new license application was filed in July 2002.  The application is proceeding through the normal FERC licensing process.  The application includes proposed PM&E measures estimated to total (assuming a 30-year license) approximately $1 million over the first five years of the license and $3 million over the following 25 years.  However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by FERC.

The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of IPC's hydro generation capacity and 41 percent of its total generating capacity.  IPC developed its draft license application with the assistance of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests.  The draft license application was issued in September 2002 and the final application will be filed July 2003.  The draft application includes proposed PM&E measures estimated to total approximately (assuming a 30-year license) $78 million over the first five years of the license and $100 million over the following 25 years.  However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.

At September 30, 2002, $47 million of pre-relicensing costs were included in Construction Work in Progress and $6 million of pre-relicensing costs were included in Electric Plant in Service.  These balances will continue to grow as IPC actively pursues relicensing.  Pre-relicensing costs as well as costs related to the new licenses, as referenced above, will be submitted to regulators for recovery through the rate-making process.

Regional Transmission Organizations
In September 2002, the FERC issued an order granting in part RTO West's Stage 2 request for a declaratory order, approving with modification, the majority of the proposed plan for development of a regional transmission organization by ten utilities in the Northwest and Canada and the Bonneville Power Administration.  IPC is one of the filing utilities.  With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but can also provide a basic framework for standard market design for the West".  Further development of the RTO West proposal by the filing utilities will take place over the next several months.

Standard Market Design
In July 2002 the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design for regulated utilities.  If implemented as proposed, the NOPR will substantially change how wholesale markets operate throughout the United States.  The proposed rulemaking expands the FERC's intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets.  The proposed rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff.  The proposed rule also contemplates the implementation of a bid based system for buying and selling energy in wholesale markets to manage congestion.  The market will be administered by Regional Transmission Organizations (RTOs), or Independent Transmission Providers.  RTOs will also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements.  Finally, the proposed rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power.  Comments to the proposed rules are due during the last months of 2002 and the first part of 2003.  The FERC currently anticipates that the final rules will be in place in mid-2003 and the contemplated market changes will take place in 2003 and 2004.

OTHER LEGAL PROCEEDINGS:

Overton Power District No. 5
IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract.  The contract provided for Overton to purchase 40 MW of electrical energy per hour from IE at $88.50 per MWh, from July 1, 2001 through June 30, 2011.  In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.

IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract.  Overton filed an Answer and Counterclaim on April 23, 2002 claiming IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in the amount to be proved at trial.  Overton also asserts that the contract is unenforceable or subject to rescission.  IE believes Overton's assertions are without merit and has filed a motion for partial summary judgment.  Overton has filed a cross-motion for partial summary judgment alleging that its CEO lacked authority to execute the contract.  The motions have been heard, but not decided by the Court.  The parties continue with discovery in the lawsuit.  Trial is scheduled to commence on May 5, 2003.

IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit.  While the outcome of litigation is never certain, IE believes it should prevail on the merits.  At September 30, 2002, IE had a $74 million long-term asset related to the Overton claim.  IE will review the recoverability of the asset on an ongoing basis.

Truckee-Donner Public Utility District
IE has received notice from Truckee-Donner Public Utility District (Truckee), located in California, asserting that IE was in purported breach of, and that Truckee has the right to renegotiate certain terms of, the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities.  Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWh.

On May 30, 2002, IE filed a lawsuit against Truckee in the Idaho State District Court in and for the County of Ada.  IE seeks a declaration that it is not in breach of the contract, injunctive relief requiring Truckee to make payments pursuant to the terms of the contract and to raise its rates as stipulated in the contract.  The lawsuit has been removed to the United States District Court for the District of Idaho.  On August 15, 2002, Truckee answered the complaint, denying the material allegations, and asserted various counterclaims against IE, IPC and IDACORP, Inc., in which it contends that these entities were in breach of the contract, inter alia, incident to the sale of surplus energy for Truckee, and by failing to provide firm backing for the capacity and associated energy provided pursuant to the contract.  On September 23, 2002, IE, IPC and IDACORP, filed a reply to the counterclaim, denying the material allegations of Truckee's counterclaim.  Trial of the lawsuit is scheduled to commence September 8, 2003.

On July 23, 2002, Truckee filed a complaint against IPC, IE and IDACORP with the FERC seeking relief under its long-term power contract for the purchase of wholesale electric power from IPC and IE.

The complaint requests that the FERC, among other matters, (1) reform or terminate the contract under Section 206 of the Federal Power Act, (2) order refunds, (3) assert exclusive jurisdiction over the rate issues and exercise primary jurisdiction to consider state-law claims arising out of the contract provisions and underlying facts and (4) assess the market power of IE and IPC within the Sierra Pacific and IPC control areas under the FERC's Supply Margin Assessment test and impose appropriate remedies if the test is not passed.

The companies intend to vigorously defend their position in these proceedings and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

United Systems, Inc., f/k/a Commercial Building Services, Inc.
On March 18, 2002, United Systems, Inc. (United Systems) filed a complaint against IDACORP Services Co., a subsidiary of IDACORP, dba IDACORP Solutions.  United Systems is a heating, ventilation, refrigeration and plumbing contracting company that entered into a contract with IDACORP Services in December 2000.

Under the terms of the contract, IDACORP Services authorized United Systems to do business as "IDACORP Solutions."  The contract was to be effective from January 2001 through December 2005.

In November 2001, IDACORP Services notified United Systems that IDACORP Services was terminating the contract for convenience.  The contract allowed for such termination but required the terminating party to compensate the other party for all costs incurred in preparation for, and in performance of the contract, and for reasonable net profit for the remaining term of the contract.  United Systems claims $7 million in net profits lost and costs incurred.

IDACORP Services asserts that termination related compensation owed to United Systems, if any, is substantially less than the amount claimed by United Systems.

On August 8, 2002, United Systems filed an amended complaint adding IDACORP, IE, and IPC as additional defendants claiming they should be held jointly and severally liable for any judgment entered against IDACORP Services.

This case is set for a jury trial the week of June 13, 2003.  The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Public Utility District No. 1 of Grays Harbor County, Washington.
On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC, and IE.

On March 9, 2001, Grays Harbor entered into a 20-MW purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per MWh.  In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE.

In its lawsuit, Grays Harbor alleges that the assignment was void and unenforceable, and seeks restitution from IE and IDACORP.  Alternatively, Grays Harbor alleges that the contract should be rescinded or reformed as against IDACORP, IPC and IE, claiming that the contract was entered into pursuant to a mutual or unilateral mistake; that it is unconscionable; or that Grays Harbor entered into the contract under duress.  Grays Harbor seeks as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

IDACORP, IPC, and IE have removed this action from the state court to the United States District Court for the Western District of Washington at Tacoma.  The companies intend to vigorously defend this lawsuit and believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

State of California Attorney General
The California Attorney General (AG) filed the complaint in this case in the California Superior Court in San Francisco on May 30, 2002.  This is one of thirteen virtually identical cases brought by the AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair competition law - California Business and Professions Code Section 17200.  Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice . . . ."  The AG alleges that IPC engaged in unlawful conduct by violating the Federal Power Act (FPA) in two respects:  (1) by failing to file its rates with the FERC as required by the FPA; and (2) charging unjust and unreasonable rates in violation of the FPA.  The AG alleges that there were "thousands of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions."  Pursuant to Business and Professions Code Section 17206, the AG seeks civil penalties of up to $2,500 for each alleged violation.  IPC is vigorously defending the action.  On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002, the AG filed a motion to remand back to state court.  The court previously denied the AG's prior motions to remand back to state court in the companion cases.  The court heard IPC's Motion to Dismiss on July 31, 2002.  A decision is expected before the end of the year.  IPC intends to vigorously defend its position in this proceeding and believes this matter will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II
These cross-actions against IE and IPC emerge from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara Mathews in their personal capacities.  Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C., and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C., Duke Energy Oakland, L.L.C. (collectively, Duke).  While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC), colluded to influence the price of electricity in the California wholesale electricity market.  Plaintiffs asserted various claims that the defendants violated California Antitrust Law, (the Cartwright Act) Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business & Professions Code Section 17200, et seq.  Among the acts complained of are bid rigging, information exchanges, withholding of power, and various other wrongful acts.  These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants.  Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC.  Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC.  Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq.  As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the PMC as to any power Reliant purchased through the California markets.

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court.  IPC and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs.  As a result of the various motions, no trial date is set at this time.  The companies cannot predict the outcome of this proceeding, nor can they evaluate the merits of any of the claims at this time but they intend to vigorously defend these lawsuits.

California Energy Situation
As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation.  The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold.  Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff.  Under the participation agreement, if a participant in the CalPX exchange defaulted on a payment to the exchange, the other participants were required to pay their allocated share of the default amount to the exchange.  The allocated shares were based upon the level of trading activity, which included 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 CalPX and the California Independent System Operator (Cal ISO) 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 Cal ISO were among the creditors of PG&E.  To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO, the 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 spot market 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's Chief Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the 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.

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, we believe our exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review.   The latter--more than 60--have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations.  The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation and although the California Parties (the California Attorney General, other state agencies and the California Investor Owned Utilities) have requested specific procedures to implement that requirement, the FERC has not yet acted on that request.

This case has been further complicated by an August 13, 2002 FERC staff (Staff) Report which included the recommendation to replace the published California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing Price (MMCP) to calculate refunds with other published indices for producing basin prices plus a transportation allowance. Staff's recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated published index prices.  Staff bases its speculation in large part on a statistical correlation analysis of Henry Hub and California prices.  If FERC accepts the Staff recommendation, the total amount of refunds could roughly double over earlier estimates. IE, in conjunction with others, submitted comments on the Staff recommendation - asserting that Staff's conclusions were incorrect in part on the basis of the fact that the Staff's correlation study ignored evidence of normal market forces and scarcity which created the pricing variations which Staff observed, rather than improper manipulation of reported prices.  Beyond soliciting comments on the Staff recommendation, the FERC has not decided whether or how to proceed with consideration of a change in the gas pricing methodology which it previously approved.

An Initial Decision and Recommendation from FERC Administrative Law Judge Birchman is anticipated during the Fall of 2002 and the FERC has indicated they would issue an order on those recommendations in early 2003.  Based upon that order and subject to possible modification based upon revision of the gas indices to be used, the Cal ISO would then be directed by the FERC to calculate revised refund amounts due from sellers of spot market power into the CalPX and Cal ISO during the refund period.

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 recommendations and findings to the FERC on September 24, 2001. The ALJ found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have submitted comments to the FERC respecting the ALJ's recommendations.  The City of Tacoma and the Port of Seattle have requested that the docket be reopened to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others.  IE has opposed that request, and both the ALJ's recommended findings and the issue of re-opening the record are pending at the FERC.

IPC transferred its non-utility wholesale electricity marketing operations to IE on June 11, 2001 effective June 1, 2001.  Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE.  At September 30, 2002, 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.  IE has accrued a reserve of $41 million against these receivables.

These reserves were calculated taking into account the uncertainty of collection, given the current California energy situation.  Based on the reserves recorded as of September 30, 2002, IE believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on its financial statements.

In a series of requests for information ending on May 8, 2002 the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001.  The request required IPC and IE to respond in the form of an affidavit to inquiries respecting various trading practices that the FERC identified in its fact-finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000.  IPC and IE filed the various responses sought by the FERC.  The May 2002 response indicated that although they did export energy from the CalPX outside of California during the period 2000-2001, they did not engage in any impermissible trading practice described in the Enron memoranda.  The energy was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction.  The companies denied engaging in the other ten practices identified by the FERC.  IPC and IE filed additional responses with the FERC on May 31 and June 5, 2002.  In the May 31 response, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price.  In the June 5 response, where the data request was directed to all sellers of natural gas in the Western Systems Coordinating Council and/or Texas during the years 2000-2001, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of natural gas together with a simultaneous purchase of the same product at the same price.

On October 2, 2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to IPC requesting, among other things, all records related to all natural gas and electricity trades by IPC involving "round trip trades", also known as "wash trades" or "sell/buyback trades" including, but not limited to those made outside the Western Systems Coordinating Council region.  The subpoena applies to both IE and IPC.  As discussed above, on May 22, 2002, both IE and IPC responded to a similar request from the FERC stating that they did not engage in "round trip" or "wash" trades.  By letter from the CFTC dated October 7, 2002, the Division of Enforcement agreed to hold in abeyance until a later date all items requested in the subpoena with the exception of one paragraph which related to three trades on a certain date with a specific party.  The companies have provided the requested information.

Nevada Power Company
In February and April of 2001 IE entered into several transactions under the Western Systems Power Pool (WSPP) Agreement whereby IE agreed to deliver to Nevada Power Company (NPC) 25 MW's during the third quarter of 2002.  NPC agreed to pay IE $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries.  Based upon the uncertain financial condition of NPC, IE asked for further assurances of NPC's ability to pay for the power if IE made the deliveries.  NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated the transactions effective July 8, 2002.

Pursuant to the WSPP Agreement IE notified NPC of the liquidated damages amount and NPC responded with a letter which describes their view of rights under the WSPP Agreement and suggests a negotiated resolution.  IE will continue to pursue its rights under the WSPP Agreement.  At September 30, 2002, IE had a $5 million receivable related to the NPC claim.  IE will review the recoverability of the asset on an ongoing basis.

OTHER MATTERS:

General Rate Case
It is likely IPC will file a general rate case in the fall of 2003.  Since 1994, IPC's customer numbers have grown by nearly 25 percent; in the neighborhood of 80,000 customers.  IPC has been experiencing a period of steady, and often robust, economic expansion in its service area.  Investment in generation, transmission and distribution infrastructure has been ongoing during that time.

Power Supply
We monitor the effect of streamflow conditions on Brownlee Reservoir, the water source for our three Hells Canyon hydroelectric facilities and IPC's key water storage facility.  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.

The National Weather Service River Forecast Center has reported that the April-July 2002 inflow into Brownlee Reservoir was 3.24 million acre-feet (maf).  Average inflow into the reservoir based upon National Weather Service River Forecast Center records is 6.3 maf.  Inflow into Brownlee Reservoir impacts IPC's ability to produce low-cost hydropower.

IPC's 2002 hydro generation is improved over 2001, but is still well below normal.  Generation increased nine percent for the three months ended and 11 percent for the nine months ended September 30, 2002.

Reservoir storage and soil moisture throughout the Snake River Basin, above the Hells Canyon Complex, are generally in a depleted condition due to two years of below normal precipitation.  This has also resulted in below normal inflow to the Hells Canyon Complex.  Long-term forecasts issued in mid-October by the National Weather Service predict normal to below normal precipitation through January.  Given the existing soil moisture and reservoir storage conditions, and the current precipitation forecast, it is anticipated that inflows to the Hells Canyon Complex will remain below normal in 2003.

New Accounting Pronouncements
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which is effective for fiscal years beginning after June 15, 2002.  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  It requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred.  When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost.  Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset.  An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset.  We are currently assessing but have not yet determined the impact of SFAS 143 on our financial statements.

In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities."  The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan.  Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity.  This standard supersedes Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)."  SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.  We are currently assessing but have not yet determined the impact of SFAS 146 on our financial statements.

Critical Accounting Policies
We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America, and these statements necessarily include some amounts that are based on informed judgments and estimates of management.  Our significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements.  Our critical accounting policies are subject to judgments and uncertainties that affect the application of such policies.  Our financial position and results of operations may be materially different when reported under different conditions or when using different assumptions in the application of such policies.  In the event estimates or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.  Those policies that management considers critical are described below:

Accounting for the Effects of Regulation:  As a regulated utility, IPC follows SFAS 71, "Accounting for the Effects of Certain Types of Regulation."  SFAS 71 requires IPC to reflect the impact of regulatory decisions in its consolidated financial statements and requires that certain costs be deferred on the balance sheet until matching revenues can be recognized.  Similarly, certain items may be deferred as regulatory liabilities and amortized to the income statement as rates to customers are reduced.  If all or part of our operations ceases to meet the criteria for application of SFAS 71, we could have to write off the related regulatory assets and regulatory liabilities and include such amounts in the statement of income as an extraordinary item.  Consequently, the discontinuance of SFAS 71 could have a material effect on our results of operations.  At September 30, 2002, IPC's regulatory assets and regulatory liabilities totaled $536 million and $48 million, respectively.  While we expect to fully recover this amount, such recovery is subject to final review by the regulatory entities.

Accounting for Energy Marketing Activities:  The value of IE's energy trading contracts are reported on our consolidated financial statements using mark-to-market accounting under EITF 98-10 and SFAS 133, "Accounting for Derivatives and Hedging Activities."

Mark-to-market accounting required us to consider several factors, including current relevant market prices, market depth and liquidity, potential model error, and expected credit losses at the counterparty level.  Due to the volatility of energy markets and certain model assumptions, changes in market conditions could substantially change the amounts of gains or losses ultimately realized in settlement of the contracts.

In October 2002, EITF 98-10 was rescinded.  We discuss the rescission in more detail in Note 1 to the Consolidated Financial Statements.

Accounting for Pensions:  We have defined benefit pension plans that cover substantially all employees, and we have certain other postretirement and post-employment benefits.  Changes in interest rates, changes in market values of stocks, and changes in the assumptions used by our actuaries could significantly affect the amounts reported for pension expense, assets and liabilities included in our financial statements.  Such actuarial assumptions, which are determined by management, include the discount rate, expected return on plan assets, and health care cost trend rates.

Based on current projections, we expect our 2003 pension costs to increase between $5 million and $9 million over 2002 amounts.  We do not anticipate making any pension contribution or recording a minimum pension liability related to our qualified pension in 2002.

Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our market risks related to commodity prices is included in Item 2 "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Energy Marketing".

Our market risks related to interest rates and foreign currency have not changed materially from those reported in our Annual Report on Form 10-K for the year ended December 31, 2001.

Item 4.  CONTROLS AND PROCEDURES

a.             Evaluation of disclosure controls and procedures:  Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 (c) and 15d-14 (c)) as of a date within 90 days of the filing of this report, have concluded that our disclosure controls and procedures are effective.

b.             Changes in internal controls:  There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation referenced in paragraph (a) above.

PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

Reference is made in the Note to Consolidated Financial Statements entitled "Commitments and Contingent Liabilities - Other Legal Proceedings".

Item 6.  Exhibits and Reports on Form 8-K

  (a)               Exhibits:

Exhibit	File Number	As Exhibit
*2	333-48031	2	Agreement and Plan of Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998.
*3(a)	33-56071	3(d)	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998.
*3(b)	333-64737	3.1	Articles of Incorporation of IDACORP, Inc.
*3(b)(i)	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(b)(ii)	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(c)	1-14465 Form 10-Q for 6/30/99	3(h)	Amended Bylaws of IDACORP, Inc. as of July 8, 1999.
*4(a)	1-14465 Form 8-K dated September 15, 1998	4	Rights Agreement, dated as of September 10, 1998, between IDACORP, Inc. and Wells Fargo Bank Minnesota, N.A. as Successor Rights Agent.
*4(b)	1-14465 Form 8-K dated February 28, 2001	4.1	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.
*4(c)	1-14465 Form 8-K dated February 28, 2001	4.2	First Supplemental Indenture dated as of February 1, 2001, to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.
*10(a) 1	1-3198 Form 10-K for 1996	10(n)(iv)	The Revised Security Plan for Senior Management Employees - a non-qualified, deferred compensation plan effective August 1, 1996.
*10(b) 1	1-14465 Form 10-K for 2001	10(n)(ii)	The Executive Annual Incentive Plan for senior management employees of IPC effective January 1, 2001.
*10(c) 1	1-3198 Form 10-K for 1994	10(n)(iii)	The 1994 Restricted Stock Plan for officers and key executives of IDACORP, Inc. and IPC effective July 1, 1994.

______________
[1] Compensatory Plan

*10(d) 1	1-14465 Form 10-K for 1998	10(h)(iv)	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 8, 1999.
*10(e) 1	1-14465 Form 10-Q for 3/31/02	10(e)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.
*10(f)	1-3198 Form 10-K for 1997	10(y)	Executive Employment Agreement dated November 20, 1996 between IPC and Richard Riazzi.
*10(g)	1-3198 Form 10-Q for 6/30/99	10(g)	Executive Employment Agreement dated April 12, 1999 between IPC and Marlene Williams.
*10(h)	1-14465 Form 10-Q for 9/30/99	10(h)	Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Richard Riazzi, Darrel T. Anderson, Bryan Kearney, Cliff N. Olson, Robert W. Stahman and Marlene K. Williams.
*10(i)1	1-14465 Form 10-Q for 3/31/02	10(i)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.
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.
*21	1-14465 Form 10-Q for 6/30/02		Subsidiaries of IDACORP, Inc.
99(a)			Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99(b)			Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

[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, 2002.

Items Reported	Date of Report
Item 9 - Regulation FD Disclosure	August 9, 2002
Item 5 - Other Events and Regulation FD Disclosure	August 29, 2002
Item 5 - Other Events and Regulation FD Disclosure and	September 9, 2002
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, 2002	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer
Date	November 8, 2002	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial
				Officer and Treasurer
				(Principal Financial Officer)
				(Principal Accounting Officer)

CERTIFICATIONS

I, Jan B. Packwood, President and Chief Executive Officer, certify that:

1. I have reviewed this quarterly report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 (c) and 15d-14 (c)) for the registrant and we have:

a)      designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)      evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)      presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)      all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)      any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date	November 8, 2002	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer

I, Darrel T. Anderson, Vice President, Chief Financial Officer and Treasurer, certify that:

I have reviewed this quarterly report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 (c) and 15d-14 (c)) for the registrant and we have:

a)      designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)      evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)      presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)      all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)      any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date	November 8, 2002	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial
				Officer and Treasurer