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

 

Commission File Number		Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, and telephone number		I.R.S. Employer Identification Number
1-3198		Idaho Power Company		82-0130980
		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            No    X_

Number of shares of Common Stock outstanding as of September 30, 2002:	37,612,351 shares, all of which are held by IDACORP, Inc.

 

 

 

GLOSSARY
AFDC	-	Allowance for Funds used During Construction
APB	-	Accounting Principles Board
BPA	-	Bonneville Power Administration
CSPP	-	Cogeneration and Small Power Production
DIG	-	Derivatives Implementation Group
DSM	-	Demand-Side Management
EITF	-	Emerging Issues Task Force
EPA	-	Environmental Protection Agency
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FPA	-	Federal Power Act
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	kilowatt
kWh	-	kilowatt-hour
MD&A	-	Management's Discussion and Analysis
MW	-	Megawatt
MWh	-	Megawatt-hour
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utilities Regulatory Policy Act
REA	-	Rural Electrification Administration
RFP	-	Request for proposals
RTOs	-	Regional Transmission Organizations
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company
Valmy	-	North Valmy Steam Electric Generating Plant

 

 

 

 

 

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 Capitalization		8
		Consolidated Statements of Cash Flows		9
		Consolidated Statements of Comprehensive Income		10
		Notes to Consolidated Financial Statements		11-24
		Independent Accountants' Report		25
	Item 2.  Management's Discussion and Analysis of Financial
			Condition and Results of Operations	26-44
	Item 3.  Quantitative and Qualitative Disclosures about Market Risk			45
	Item 4.  Controls and Procedures			45
Part II.  Other Information:
	Item 1.  Legal Proceedings			46
	Item 6.  Exhibits and Reports on Form 8-K			46-50
Signatures				51
Certifications				52-53

 

 

 

 

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
Idaho Power Company
Consolidated Statements of Income
(unaudited)

 

 

				Three Months Ended
				September 30,
				2002			2001
				(thousands of dollars)
REVENUES:
	General business			$	216,452		$	185,830
	Off-system sales				10,859			91,654
	Other revenues				9,940			8,808
		Total revenues			237,251			286,292
EXPENSES:
	Operation:
		Purchased power			50,240			228,460
		Fuel expense			26,529			25,947
		Power cost adjustment			57,153			(57,770)
		Other			38,308			36,515
	Maintenance				14,339			13,829
	Depreciation				23,577			21,894
	Taxes other than income taxes				5,069			4,947
		Total expenses			215,215			273,822
INCOME FROM OPERATIONS					22,036			12,470
OTHER INCOME (EXPENSE):
	Allowance for equity funds used during construction				(4)			173
	Other - net				410			4,930
		Total other income			406			5,103
INTEREST CHARGES:
	Interest on long-term debt				12,330			13,770
	Other interest				2,318			2,450
	Allowance for borrowed funds used during construction				(432)			(879)
		Total interest charges			14,216			15,341
INCOME BEFORE INCOME TAXES					8,226			2,232
INCOME TAXES					(31,129)			958
NET INCOME					39,355			1,274
	Dividends on preferred stock				919			1,374
EARNINGS ON COMMON STOCK				$	38,436		$	(100)

 

The accompanying notes are an integral part of these statements.

 

 

 

 

 

Idaho Power Company
Consolidated Statements of Income
(unaudited)

 

				Nine Months Ended
				September 30,
				2002			2001
				(thousands of dollars)
REVENUES:
	General business			$	590,136		$	475,158
	Off-system sales				41,994			205,552
	Other revenues				28,775			33,828
		Total revenues			660,905			714,538
EXPENSES:
	Operation:
		Purchased power			111,614			523,165
		Fuel expense			76,165			73,545
		Power cost adjustment			133,378			(184,102)
		Other			111,991			108,055
	Maintenance				42,500			41,046
	Depreciation				69,932			64,293
	Taxes other than income taxes				15,415			15,591
		Total expenses			560,995			641,593
INCOME FROM OPERATIONS					99,910			72,945
OTHER INCOME:
	Allowance for equity funds used during construction				40			758
	Other - net				11,373			12,108
		Total other income			11,413			12,866
INTEREST CHARGES:
	Interest on long-term debt				37,884			41,943
	Other interest				7,293			7,270
	Allowance for borrowed funds used during construction				(1,753)			(3,295)
		Total interest charges			43,424			45,918
INCOME BEFORE INCOME TAXES					67,899			39,893
INCOME TAXES					(8,175)			15,549
INCOME FROM CONTINUING OPERATIONS					76,074			24,344
DISCONTINUED OPERATIONS:
	Income from operations of energy marketing transferred to
		parent (net of tax of $33,574)			-			49,943
NET INCOME					76,074			74,287
	Dividends on preferred stock				3,579			4,128
EARNINGS ON COMMON STOCK				$	72,495		$	70,159

 

The accompanying notes are an integral part of these statements.

 

 

 

Idaho Power Company
Consolidated Balance Sheets
(unaudited)
Assets

					September 30,			December 31,
					2002			2001
					(thousands of dollars)
ELECTRIC PLANT:
	In service (at original cost)				$	3,043,566		$	2,989,630
	Accumulated provision for depreciation					(1,278,568)			(1,220,002)
		In service - Net				1,764,998			1,769,628
	Construction work in progress					98,264			86,010
	Held for future use					2,335			2,232
			Electric plant - Net			1,865,597			1,857,870
INVESTMENTS AND OTHER PROPERTY						37,390			37,432
CURRENT ASSETS:
	Cash and cash equivalents					15,206			43,040
	Receivables:
		Customer				70,653			58,702
		Allowance for uncollectible accounts				(1,517)			(1,500)
		Notes				4,988			3,488
		Employee notes				7,515			6,274
		Related parties				20,754			37,517
		Other				790			2,280
	Taxes receivable					-			8,244
	Accrued unbilled revenues					28,742			37,400
	Materials and supplies (at average cost)					22,842			23,280
	Fuel stock (at average cost)					10,647			8,726
	Prepayments					33,784			31,897
	Regulatory assets					14,853			55,107
			Total current assets			229,257			314,455
DEFERRED DEBITS:
	American Falls and Milner water rights					31,585			31,585
	Company-owned life insurance					35,440			39,602
	Regulatory assets					520,946			544,134
	Other					34,081			34,626
			Total deferred debits			622,052			649,947
	TOTAL				$	2,754,296		$	2,859,704

 

The accompanying notes are an integral part of these statements.

 

 

 

 

 

 

Idaho Power Company
Consolidated Balance Sheets
(unaudited)
Capitalization and Liabilities

					September 30,			December 31,
					2002			2001
						(thousands of dollars)
CAPITALIZATION:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 37,612,351 shares outstanding)		$	94,031		$	94,031
		Premium on capital stock				361,875			362,602
		Capital stock expense				(2,724)			(4,144)
		Retained earnings				336,128			316,856
		Accumulated other comprehensive income (loss)				(5,980)			(3,719)
			Total common stock equity			783,330			765,626
	Preferred stock					53,985			104,387
	Long-term debt					672,323			802,201
			Total capitalization			1,509,638			1,672,214
CURRENT LIABILITIES:
	Long-term debt due within one year					107,084			27,078
	Notes payable					133,300			282,000
	Accounts payable					37,534			68,806
	Notes and accounts payable to related parties					100,827			6,931
	Taxes accrued					41,881			-
	Derivative liabilities					-			40,528
	Interest accrued					19,570			13,115
	Deferred income taxes					14,853			14,578
	Other					22,337			16,118
			Total current liabilities			477,386			469,154
DEFERRED CREDITS:
	Deferred income taxes					591,140			541,482
	Derivative liabilities - long-term					-			7,253
	Regulatory liabilities					116,672			113,957
	Other					59,460			55,644
			Total deferred credits			767,272			718,336
COMMITMENTS AND CONTINGENT LIABILITIES
			TOTAL		$	2,754,296		$	2,859,704

 

The accompanying notes are an integral part of these statements.

 

 

 

 

 

 

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

 

					September 30,							December 31,
					2002					%		2001				%
					(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock				$	94,031						$	94,031
	Premium on capital stock					361,875							362,602
	Capital stock expense					(2,724)							(4,144)
	Retained earnings					336,128							316,856
	Accumulated other comprehensive income (loss)					(5,980)							(3,719)
		Total common stock equity				783,330			52				765,626				46
PREFERRED STOCK:
	4% preferred stock					13,985							14,387
	7.68% Series, serial preferred stock					15,000							15,000
	7.07% Series, serial preferred stock					25,000							25,000
	Auction rate preferred stock					-							50,000
		Total preferred stock				53,985			4				104,387				6
LONG-TERM DEBT:
	First mortgage bonds:
		6.85%  Series due 2002				27,000							27,000
		6.40%  Series due 2003				80,000							80,000
		8     %  Series due 2004				50,000							50,000
		5.83%  Series due 2005				60,000							60,000
		7.38%  Series due 2007				80,000							80,000
		7.20%  Series due 2009				80,000							80,000
		6.60%  Series due 2011				120,000							120,000
		7.50%  Series due 2023				80,000							80,000
		8.75%  Series due 2027				-							50,000
			Total first mortgage bonds			577,000							627,000
		Amount due within one year				(107,000)							(27,000)
			Net first mortgage bonds			470,000							600,000
	Pollution control revenue bonds:
		8.30% Series 1984 due 2014				49,800							49,800
		6.05% Series 1996A due 2026				68,100							68,100
		Variable Rate Series 1996B due 2026				24,200							24,200
		Variable Rate Series 1996C due 2026				24,000							24,000
		Variable Rate Series 2000 due 2007				4,360							4,360
			Total pollution control revenue bonds			170,460							170,460
	REA notes					1,204							1,263
		Amount due within one year				(84)							(78)
			Net REA notes			1,120							1,185
	American Falls bond guarantee					19,885							19,885
	Milner Dam note guarantee					11,700							11,700
	Unamortized premium/discount - Net					(842)							(1,029)
			Total long-term debt			672,323			44				802,201				48
TOTAL CAPITALIZATION					$	1,509,638			100			$	1,672,214				100

 

The accompanying notes are an integral part of these statements.

 

 

Idaho Power Company
Consolidated Statements of Cash Flows
(unaudited)

					Nine Months Ended
					September 30,
					2002				2001
					(thousands of dollars)
OPERATING ACTIVITIES:
	Net income				$	76,074				$	74,287
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
		Allowance for uncollectible accounts				17					20,174
		Unrealized gains from energy marketing activities				-					(101,461)
		Depreciation and amortization				79,560					73,740
		Deferred taxes and investment tax credits				(64,131)					99,391
		Accrued PCA costs				128,215					(188,202)
		Change in:
			Accounts receivable and prepayments			(12,138)					(13,047)
			Accrued unbilled revenue			8,658					12,398
			Materials and supplies and fuel stock			(1,483)					394
			Accounts payable			(37,560)					8,276
			Taxes receivable/accrued			50,127					(29,549)
			Other current assets and liabilities			12,673					167
		Other - net				5,973					(2,995)
	Net cash provided by (used in) operating activities					245,985					(46,427)
INVESTING ACTIVITIES:
	Additions to utility plant					(81,157)					(120,871)
	Note receivable payment from parent					15,315					-
	Other - net					(796)					(3,182)
		Net cash used in investing activities				(66,638)					(124,053)
FINANCING ACTIVITIES:
	Issuance of first mortgage bonds					-					120,000
	Retirement of first mortgage bonds					(50,000)					(130,000)
	Retirement of preferred stock					(50,402)					-
	Dividends on common stock					(52,545)					(52,343)
	Dividends on preferred stock					(3,579)					(4,128)
	Increase (decrease) in short-term borrowings					(48,517)					184,300
	Other - net					(2,138)					(3,925)
		Net cash provided by (used in) financing activities				(207,181)					113,904
Net increase (decrease) in cash and cash equivalents						(27,834)					(56,576)
Cash and cash equivalents at beginning of period						43,040					83,494
Cash and cash equivalents at end of period					$	15,206				$	26,918
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION:
	Cash paid (received) during the period for:
		Income taxes			$	11,512				$	(15,059)
		Interest (net of amount capitalized)				35,017					39,058
	Net assets transferred to parent for notes receivable					-					76,250

 

The accompanying notes are an integral part of these statements.

 

 

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				September 30,
				2002			2001
				(thousands of dollars)
NET INCOME				$	39,355			$	1,274
OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($659)
		and $(655))			(1,014)				(1,008)
TOTAL COMPREHENSIVE INCOME				$	38,341			$	266

 

 

 

				Nine Months Ended
				September 30,
				2002			2001
				(thousands of dollars)
NET INCOME				$	76,074		$	74,287
OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of
		($1,430) and ($1,580))			(2,261)			(2,615)
TOTAL COMPREHENSIVE INCOME				$	73,813		$	71,672

 

 

The accompanying notes are an integral part of these statements.

 

 

 

 

Notes to the Consolidated Financial Statements
(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
Idaho Power Company (IPC) is an electric utility 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 our Jim Bridger generating plant.

References in this report to "we," "us" and "our" are to IPC and its subsidiary.

The outstanding shares of our common stock were exchanged on a share-for-share basis into common stock of IDACORP, Inc. (IDACORP) on October 1, 1998 and are no longer actively traded.  Our preferred stock and debt securities were unaffected.

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 subsidiary.  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
In January 2002, we adopted Statement of Financial Accounting Standard (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 for 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.  We have completed an evaluation of the effect of this revised Interpretation on the treatment of booked out contracts and have determined that contracts previously classified as derivatives are exempt.  This change does not have a material effect on our financial statements.

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.

2.   INCOME TAXES:

Our effective tax rate for the nine months ended September 30, 2002 decreased from 39.8 percent in 2001 to a benefit of 12.0 percent in 2002.  Non-recurring items occurring in 2002 include a tax accounting method change and the settlement of a partnership audit, both of which resulted in a decrease to tax expense.  Reconciliations between the statutory income tax rate and the effective rates are as follows (in thousands of dollars):

		Nine Months Ended September 30,
		2002						2001
		Amount			Rate			Amount				Rate
Computed income taxes based on statutory
	federal income tax rate	$	23,765			35.0 %		$	43,193				35.0%
Changes in taxes resulting from:
	Tax accounting method change and audit settlement		(33,662)			(49.6)			-				-
	Capitalized overhead costs		(2,625)			(3.9)			-				-
	Investment tax credits		(2,399)			(3.5)			(2,329)				(1.9)
	Repair allowance		(1,838)			(2.7)			(2,100)				(1.7)
	Pension expense		(26)			0.0			(1,368)				(1.1)
	State income taxes		4,650			6.8			6,604				5.4
	Depreciation		6,159			9.1			6,325				5.1
	Other		(2,199)			(3.2)			(1,202)				(1.0)
Total provision (benefit) for federal and state income taxes		$	(8,175)			(12.0)%		$	49,123				39.8%

 

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 our 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.

We 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 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, we settled income tax deficiencies related to our 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 us 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:

The number of shares of 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

 

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

4.  FINANCING:

We have regulatory authority to incur up to $350 million of short-term indebtedness.  We also have a $200 million 364-day revolving credit facility that expires in March 2003, under which we pay a facility fee on the commitment quarterly in arrears, based on our 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, our short-term borrowing under this facility totaled $133 million.  We repaid $100 million of floating rate notes in September 2002 using short-term borrowings from IDACORP which are payable on November 15, 2002.  We plan to replace this intercompany debt with external financing.

We currently have 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 of First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

5.  COMMITMENTS AND CONTINGENT LIABILITIES:

Commitments under contracts and purchase orders relating to our program for construction and operation of facilities amounted to approximately $6 million at September 30, 2002.  The commitments are generally revocable by us 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
Truckee-Donner Public Utility District:  IDACORP Energy (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 megawatts (MW) light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per megawatt hour (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 with 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 System) 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 contact, 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 IPC, IDACORP and IE.

On March 9, 2001, Grays Harbor entered into a 20MW 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 IPC, IDACORP 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. We intend to vigorously defend our 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.

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
On July 25, 2001, the FERC issued an order establishing a 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.

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 22, 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 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 United States 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.

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.

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 Utility 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 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 filing made with the FERC 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 Power Cost Adjustment (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:  Our PCA mechanism 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 we 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 we will earn a six percent carrying charge on the balance.

-Denied our 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.  We believe that the IPUC's order is inconsistent with an earlier order that allowed recovery of such costs and we 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.  We still believe we should be entitled to receive recovery of this amount and have asked the Idaho Supreme Court to review the IPUC's decision.

Oregon:  We filed an application with the Oregon Public Utility Commission (OPUC) to begin recovering extraordinary 2001 power supply costs in our 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 our 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.  We 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 us to increase our rate of recovery to six percent effective November 28, 2001.

Deferred power supply costs consist of the following (in thousands of dollars):

				September 30,			December 31,
				2002			2001
Oregon deferral				$	14,284		$	14,866
Idaho PCA current deferral:
	Deferral for 2001-2002 rate year				-			78,395
	Deferral for 2002-2003 rate year				3,003			-
	Irrigation load reduction program				-			69,586
	Astaris load reduction agreement				18,449			62,247
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year			11,876			-
	Industrial customer deferral for recovery in the
		2003-2004 rate year			3,690			-
Idaho PCA true-up:
	Remaining true-up authorized October 2001				-			36,500
	Remaining true-up authorized May 2001				-			42,895
	Remaining true-up authorized May 2002				124,972			-
		Total deferral		$	176,274		$	304,489

 

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load reduction rates contained in our Voluntary Load Reduction (VLR) Agreement with FMC/Astaris.  This VLR Agreement amended the Electric Service Agreement (ESA) that governed the delivery of electric service to FMC/Astaris' Pocatello plant, which ceased operations late in 2001.  On June 6, 2002, we, along with 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 we would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing 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 us in the Fourth Judicial District for the State of Idaho.

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

 

Garnet Power Purchase Agreement
We had entered into a power purchase agreement (PPA) with Garnet Energy LLC (Garnet), a subsidiary of Ida-West Energy (Ida-West), a subsidiary of IDACORP, 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 our 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 us 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 that there might 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 we 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 our petition to enter into a PPA with Garnet.  We were directed to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how we propose to meet future power requirements if the Garnet facility is not built.   On October 30, 2002, we submitted our 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) our 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 our service territory.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, we filed an application requesting the IPUC to issue an accounting order authorizing the deferral of 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 our employees and to protect our 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 our 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 its prudence review of the expenses.

 

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

IDACORP Energy and Idaho Power Company Agreement
We 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 our customers as a result of transactions with IE 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 that IE would pay to IPC could be approximately $6 million.

7.  RELATED PARTY TRANSACTIONS:

In exchange for the transfer of Energy Marketing to IE in June 2001, we received a partnership interest in IE, which was transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million of which $58 million had been repaid at September 30, 2002.

In September 2002, we repaid $100 million of floating rate notes using short-term borrowings in the same amount from IDACORP which are payable on November 15, 2002.

For the nine months ended September 30, 2002 and 2001, we have paid IE approximately $2 million and $1 million, respectively under the Electricity Supply Management Services Agreement.

The following table presents sales to and purchases from IE for the three and nine months ended September 30 (in thousands of dollars):

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2002			2001			2002			2001
Sales to IE		$	2,208		$	6,937		$	21,891		$	12,845
Purchases			4,002			19,413			13,282			26,674

 

 

 

 

 

INDEPENDENT ACCOUNTANTS' REPORT

Idaho Power Company
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet and statement of capitalization of Idaho Power Company and its subsidiary 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 and statement of capitalization of Idaho Power Company and its subsidiary as of December 31, 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated 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 and statement of capitalization as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.



DELOITTE & TOUCHE LLP

Boise, Idaho
November 7, 2002

 

 

 

 

 

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

(Dollars in thousands unless otherwise indicated.  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 Idaho Power Company (IPC) and its subsidiary.

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.

We 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, we had 411,091 general business customers.

References in this report to "we", "us" and "our" are to IPC and its subsidiary.

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;

-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, acts 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:

Net income increased $38 million and $2 million for the three and nine months ended September 30, 2002.  The following are major changes affecting net income:

-Net power supply costs decreased $8 million and $22 million, after tax, for the three and nine months ended September 30, 2002.

-A change to our tax accounting method for capitalized overhead costs in addition to settled income tax deficiencies related to our partnership investment in Bridger Coal Company created a tax benefit of $37 million.

-Income from discontinued operations related to energy marketing totaled $50 million after tax for the nine months ended September 30, 2001.

-Lost revenue of $12 million was expensed during the three months ended September 30, 2002, after we were denied our 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.

 

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

General Business Revenue
The following table presents 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			$	68,098		$	60,593		966		956		$	223,200		$	180,739		3,209		3,139
Commercial				50,030			45,339		878		883			146,479			117,046		2,592		2,526
Industrial				45,888			40,921		848		939			132,537			109,491		2,412		3,001
Irrigation				52,436			38,977		1,047		769			87,920			67,882		1,717		1,342
	Total		$	216,452		$	185,830		3,739		3,547		$	590,136		$	475,158		9,930		10,008

 

General business revenue is dependent on many factors, including the number of customers served, the rates charged and economic and weather conditions.  The change in revenues in 2002 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 our 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 our 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, we 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 primarily to decreased availability of surplus system energy and lower wholesale electricity prices. The following table presents 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		$	10,859		$	91,654		$	41,994		$	205,552
MWhs			388			744			1,641			1,773
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 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		$	34,771		$	148,304		$	71,283		$	405,428
	Program costs			15,469			80,156			40,331			117,737
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 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		$	26,529		$	25,947		$	76,165		$	73,545
Thermal MWhs generated			1,900			1,993			5,312			5,640

 

PCA
The PCA expense component is related to the 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)			$	(3,273)		$	(32,005)		$	1,296		$	(142,761)
Astaris and irrigation program costs (deferral)				(12,334)			(71,781)			(31,353)			(104,844)
Amortization of prior year authorized balances				60,640			35,661			149,855			53,149
Write-off of disallowed costs				12,120			10,355			13,580			10,354
	Total power cost adjustment		$	57,153		$	(57,770)		$	133,378		$	(184,102)

 

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 our 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.

We 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 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 we settled income tax deficiencies related to our 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 us 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 $246 million for the nine months ended September 30, 2002.  Significant factors affecting cash flows in 2002 include:

-a $28 million income tax refund related to net operating loss carrybacks associated with 2001 power supply costs received in April 2002, offset by tax payments of $40 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 $905 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.

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 $28 million related to net operating loss carrybacks associated with 2001 power supply costs and a remaining $37 million in tax benefits to be received due to our tax accounting method change for capitalized overhead costs.

Cash Expenditures
We forecast that internal cash generation after dividends will be sufficient to meet our total capital requirements for 2002-2004.  We expect to finance our utility construction programs and other capital requirements with both internally generated funds and, to the extent necessary, externally financed capital.

Financing Program
We have regulatory authority to incur up to $350 million of short-term indebtedness.  We have a $200 million 364-day revolving credit facility that expires in March 2003, under which we pay a facility fee on the commitment quarterly in arrears, based on our 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, short term borrowing under this facility totaled $133 million.  We repaid $100 million of floating rate notes in September 2002 using short-term borrowings from IDACORP, Inc. (IDACORP) which are payable on November 15, 2002.  We plan to replace this intercompany debt with external financing.

We currently have 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 early using short-term borrowings.

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

Credit Rating
On September 10, 2002, Moody's changed its rating outlook 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 table outlines the current S&P, Moody's and Fitch ratings of our securities:

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

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.

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 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 filing made with the FERC 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:  Our PCA mechanism 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 we 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 will earn a six percent carrying charge on the balance.

-Denied our 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.  We believe that the IPUC's order is inconsistent with an earlier order that allowed recovery of such costs and we 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.  We still believe we should be entitled to receive recovery of this amount and have asked the Idaho Supreme Court to review the IPUC's decision.

Oregon:  We filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in our 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 our 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.  We 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 us to increase our rate of recovery to six percent effective November 28, 2001.

Deferred power supply costs consist of the following:

				September 30,			December 31,
				2002			2001
Oregon deferral				$	14,284		$	14,866
Idaho PCA current deferral:
	Deferral for 2001-2002 rate year				-			78,395
	Deferral for 2002-2003 rate year				3,003			-
	Irrigation load reduction program				-			69,586
	Astaris load reduction agreement				18,449			62,247
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year			11,876			-
	Industrial customer deferral for recovery in the
		2003-2004 rate year			3,690			-
Idaho PCA true-up:
	Remaining true-up authorized October 2001				-			36,500
	Remaining true-up authorized May 2001				-			42,895
	Remaining true-up authorized May 2002				124,972			-
	Total deferral			$	176,274		$	304,489

 

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in our Voluntary Load Reduction (VLR) Agreement with FMC/Astaris.  This VLR Agreement amended the Electric Service Agreement (ESA) that governed the delivery of electric service to FMC/Astaris' Pocatello plant, which ceased operations late in 2001.  On June 6, 2002, we along with 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 we would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing 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 us in the Fourth Judicial District for the State of Idaho.

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

 

Garnet Power Purchase Agreement
We had entered into a power purchase agreement (PPA) with Garnet Energy LLC (Garnet), a subsidiary of Ida-West Energy (Ida-West), a subsidiary of IDACORP, 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 our 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 us 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 that there might 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 we 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 our petition to enter into a PPA with Garnet.  We were directed to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how we propose to meet future power requirements if the Garnet facility is not built.  On October 30, 2002, we submitted our 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) our 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 our service territory.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, we filed an application requesting the IPUC to issue an accounting order authorizing the deferral of 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 our employees and to protect our 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 our 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 its prudence review of the expenses.

 

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

IDACORP Energy and Idaho Power Company Agreement
We 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 our customers as a result of transactions with IE 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 that IE would pay to IPC could be approximately $6 million.

Integrated Resource Plan
Every two years, we are required to file with the IPUC and OPUC an Integrated Resource Plan (IRP), a comprehensive look at our 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 our peak periods.  Prior to 2005, we 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," we 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 our set of resource alternatives to the Garnet PPA.

The IPUC Staff and several other interested parties filed comments responding to our proposed 2002 IRP.  The comments urge the IPUC not to acknowledge the IRP until (1) the Garnet issue is resolved, and (2) we provide additional detail on potential conservation measures that could be implemented.  We 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 our 2002 IRP as modified.

Relicensing of Hydroelectric Projects
We, like other utilities that operate nonfederal hydroelectric projects, obtain licenses for our 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.

We are actively pursuing the relicensing of these projects, a process that may continue for the next 10 to 15 years. We have 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. We are 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, we anticipate that we 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 environmental 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 approximately (assuming a 30-year license) $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 the FERC.

The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of our hydro generation capacity and 41 percent of our total generating capacity.  We developed our 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 in 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 we actively pursue 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. We are 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:

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.

United Systems, Inc., f/k/a Commercial Building Services, Inc.
On March 18, 2002, United Systems, Inc. (United System) 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 contact, 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 IPC, IDACORP 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 IPC, IDACORP 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.  We intend to vigorously defend our 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.

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
On July 25, 2001, the FERC issued an order establishing a 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.

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 22, 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 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 United States 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.

OTHER MATTERS:

General Rate Case
It is likely we will file a general rate case in the fall of 2003.  Since 1994, our customer numbers have grown by nearly 25 percent; in the neighborhood of 80,000 customers.  We have been experiencing a period of steady, and often robust, economic expansion in our 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 our 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 our ability to produce low-cost hydropower.

Our 2002 hydro generation has 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 Statement of Financial Accounting Standards (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, we follow SFAS 71, "Accounting for the Effects of Certain Types of Regulation."  SFAS 71 requires us to reflect the impact of regulatory decisions in our 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 ceased 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, our 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 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 and interest rates 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 15d14 (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 the 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)	33-00440	4(a)(xiii)	Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 30, 1989.
*3(a)(i)	33-65720	4(a)(ii)	Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of IPC, as filed with the Secretary of State of Idaho on November 5, 1991.
*3(a)(ii)	33-65720	4(a)(iii)	Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of IPC, as filed with the Secretary of State of Idaho on June 30, 1993.
*3(a)(iii)	1-3198 Form 10-Q for 6/30/00	3(a)(iii)	Articles of Amendment to Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 15, 2000.
*3(b)	1-3198 Form 10-Q for 9/30/99	3(c)	By-laws of IPC amended on September 9, 1999, and presently in effect.
*3(c)	33-56071	3(d)	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998.
*4(a)(i)	2-3413	B-2	Mortgage and Deed of Trust, dated as of October 1, 1937, between IPC and Bankers Trust Company (now Deutsche Bank Trust Company Americas) and R. G. Page, as Trustees.
*4(a)(ii)			IPC Supplemental Indentures to Mortgage and Deed of Trust:
			Number	Dated
	1-MD	B-2-a	First	July 1, 1939
	2-5395	7-a-3	Second	November 15, 1943
	2-7237	7-a-4	Third	February 1, 1947
	2-7502	7-a-5	Fourth	May 1, 1948
	2-8398	7-a-6	Fifth	November 1, 1949
	2-8973	7-a-7	Sixth	October 1, 1951
	2-12941	2-C-8	Seventh	January 1, 1957
	2-13688	4-J	Eighth	July 15, 1957
	2-13689	4-K	Ninth	November 15, 1957
	2-14245	4-L	Tenth	April 1, 1958
	2-14366	2-L	Eleventh	October 15, 1958
	2-14935	4-N	Twelfth	May 15, 1959
	2-18976	4-O	Thirteenth	November 15, 1960
	2-18977	4-Q	Fourteenth	November 1, 1961
			Number	Dated
	2-22988	4-B-16	Fifteenth	September 15, 1964
	2-24578	4-B-17	Sixteenth	April 1, 1966
	2-25479	4-B-18	Seventeenth	October 1, 1966
	2-45260	2(c)	Eighteenth	September 1, 1972
	2-49854	2(c)	Nineteenth	January 15, 1974
	2-51722	2(c)(i)	Twentieth	August 1, 1974
	2-51722	2(c)(ii)	Twenty-first	October 15, 1974
	2-57374	2(c)	Twenty-second	November 15, 1976
	2-62035	2(c)	Twenty-third	August 15, 1978
	33-34222	4(d)(iii)	Twenty-fourth	September 1, 1979
	33-34222	4(d)(iv)	Twenty-fifth	November 1, 1981
	33-34222	4(d)(v)	Twenty-sixth	May 1, 1982
	33-34222	4(d)(vi)	Twenty-seventh	May 1, 1986
	33-00440	4(c)(iv)	Twenty-eighth	June 30, 1989
	33-34222	4(d)(vii)	Twenty-ninth	January 1, 1990
	33-65720	4(d)(iii)	Thirtieth	January 1, 1991
	33-65720	4(d)(iv)	Thirty-first	August 15, 1991
	33-65720	4(d)(v)	Thirty-second	March 15, 1992
	33-65720	4(d)(vi)	Thirty-third	April 1, 1993
	1-3198 Form 8-K Dated 12/17/93	4	Thirty-fourth	December 1, 1993
	1-3198 Form 8-K Dated 11/21/00	4	Thirty-fifth	November 1, 2000
	1-3198 Form 8-K Dated 9/27/01	4(a)	Thirty-sixth	October 1, 2001
*4(b)	1-3198 Form 10-Q for 6/30/02	4(b)	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Bank One Trust Company N.A. as trustee
*4(c)	1-3198 Form 10-Q for 6/30/02	4(c)	First Supplemental Indenture dated as of September 1, 2001 to Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Bank One Trust Company N.A. as trustee.
*4(d)	1-3198 Form 10-Q for 6/30/00	4(b)	Instruments relating to IPC American Falls bond guarantee. (see Exhibit 10(c)).
*4(e)	33-65720	4(f)	Agreement of IPC to furnish certain debt instruments.
*4(f)	33-00440	2(a)(iii)	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation.
*10(a)	2-49854	5(b)	Agreements, dated September 22, 1969, between IPC and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project.
*10(a)(i)	2-51762	5(c)	Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(a).
*10(b)	2-49854	5(c)	Agreement, dated as of October 11, 1973, between IPC and Pacific Power & Light Company.
*10(c)	1-3198 Form 10-Q for 6/30/00	10(c)	Guaranty Agreement, dated April1, 2000, between IPC and Bank One Trust Company N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refunding Bonds of the American Falls Reservoir District, Idaho.
*10(d)	2-62034	5(r)	Guaranty Agreement, dated as of August 30, 1974, between IPC and Pacific Power & Light Company.
*10(e)	2-56513	5(i)	Letter Agreement, dated January 23, 1976, between IPC and Portland General Electric Company.
*10(e)(i)	2-62034	5(s)	Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and IPC.
*10(e)(ii)	2-62034	5(t)	Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e).
*10(e)(iii)	2-62034	5(u)	Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e).
*10(e)(iv)	2-62034	5(v)	Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(e).
*10(e)(v)	2-62034	5(w)	Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e).
*10(e)(vi)	2-68574	5(x)	Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e).
*10(f)	2-68574	5(z)	Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir.
*10(g)	2-64910	5(y)	Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and IPC.
*10(h)(i) 1	1-3198 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(h)(ii) 1	1-3198 Form 10-K for 2001	10(n)(ii)	The Executive Annual Incentive Plan for senior management employees of IPC effective January 1, 2001.
*10(h)(iii) 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.
*10(h)(iv) 1	1-3198 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, as amended.
*10(h) (v) 1	1-3198 Form 10-Q for 3/31/02	10(h)(v)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.
*10(h)(vi)	1-3198 Form 10-K for 1997	10(y)	Executive Employment Agreement dated November 20, 1996 between IPC and Richard Riazzi.
*10(h)(vii)	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)(viii)	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(h)(ix) 1	1-3198 Form 10-Q for 3/31/02	10(h)(ix)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.
*10(i)	33-65720	10(h)	Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights.
*10(i)(i)	33-65720	10(h)(i)	Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i).
*10(i)(ii)	33-65720	10(h)(ii)	Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i).
*10(j)	33-65720	10(m)	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC and the Twin Falls Canal Company and the Northside Canal Company Limited.
*10(j)(i)	33-65720	10(m)(i)	Guaranty Agreement, dated February 10, 1992, between IPC and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc.
12			Statement Re:  Computation of Ratio of Earnings to Fixed Charges.
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	1-3198 Form 10-K for 2001	21	Subsidiary of IPC.
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 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.

 

				IDAHO POWER COMPANY
				(Registrant)
Date	November 8, 2002	By:	/s/	J LaMont Keen
				J. LaMont Keen
				President and Chief
				Operating 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, Chief Executive Officer, certify that:

1.       I have reviewed this quarterly report on Form 10-Q of Idaho Power Company;

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			/s/Jan B. Packwood
			Name:	Jan B. Packwood
			Title:	Chief Executive Officer

 

 

 

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

1.       I have reviewed this quarterly report on Form 10-Q of Idaho Power Company;

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:

1. 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;
   
   
2. 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
   
   
3. 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):

1. 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
   
   
2. 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			/s/Darrel T. Anderson
			Name:	Darrel T. Anderson
			Title:	Vice President, Chief Financial
				Officer and Treasurer