Idaho Power 10-Q 2 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2018	Jul. 27, 2018
Document Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Trading Symbol	IDA
Entity Registrant Name	IDACORP INC.
Entity Central Index Key	1,057,877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		50,392,903
Entity Tax Identification Number	820,505,802
Idaho Power Company
Document Information
Entity Registrant Name	Idaho Power Company
Entity Central Index Key	49,648
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,150,812
Entity Tax Identification Number	820,130,980

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income Statement - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues:
Electric utility revenues	$ 338,699	$ 331,768	$ 648,160	$ 633,732
Other operating revenues	1,253	1,238	1,898	1,818
Total operating revenues	339,952	333,006	650,058	635,550
Operating Expenses:
Purchased power	62,980	61,506	124,908	110,622
Fuel expense	21,515	20,416	49,250	56,668
Power cost adjustment	19,963	16,742	45,501	40,229
Other operations and maintenance	92,314	86,729	178,512	173,720
Energy efficiency programs	8,802	10,515	16,399	16,843
Depreciation	41,348	45,240	81,416	82,002
Taxes other than income taxes	9,118	8,843	18,395	17,521
Total electric utility expenses	256,040	249,991	514,381	497,605
Other	1,077	1,108	2,253	2,411
Total operating expenses	257,117	251,099	516,634	500,016
Operating Income	82,835	81,907	133,424	135,534
Other Income (Expense):
Allowance for equity funds used during construction	5,985	5,611	12,018	10,843
Earnings of equity-method investments	1,537	592	5,552	2,037
Other Income (Expense), Net	309	(426)	(150)	(841)
Interest Expense:
Interest on long-term debt	21,412	20,300	42,099	40,597
Other interest	2,162	2,756	5,121	5,471
Allowance for borrowed funds used during construction	(2,606)	(2,408)	(5,078)	(4,720)
Total interest expense, net	20,968	20,648	42,142	41,348
Income Before Income Taxes	69,698	67,036	108,702	106,225
Income Tax Expense	7,105	16,940	9,998	23,124
Net Income	62,593	50,096	98,704	83,101
Adjustment for loss attributable to noncontrolling interests	(305)	(265)	(274)	(168)
Net Income Attributable to IDACORP, Inc.	$ 62,288	$ 49,831	$ 98,430	$ 82,933
Weighted-average common shares outstanding - basic	50,435	50,363	50,430	50,361
Weighted-average common shares outstanding - diluted	50,481	50,407	50,472	50,402
Earnings Per Share of Common Stock:
Earnings attributable to IDACORP, Inc. - basic (in dollars per share)	$ 1.24	$ 0.99	$ 1.95	$ 1.65
Earnings attributable to IDACORP, Inc. - diluted (in dollars per share)	1.23	0.99	1.95	1.65
Dividends Declared Per Share of Common Stock	$ 0.59	$ 0.55	$ 1.18	$ 1.10
Idaho Power Company
Operating Revenues:
Electric utility revenues	$ 338,699	$ 331,768	$ 648,160	$ 633,732
Operating Expenses:
Purchased power	62,980	61,506	124,908	110,622
Fuel expense	21,515	20,416	49,250	56,668
Power cost adjustment	19,963	16,742	45,501	40,229
Other operations and maintenance	92,314	86,729	178,512	173,720
Energy efficiency programs	8,802	10,515	16,399	16,843
Depreciation	41,348	45,240	81,416	82,002
Taxes other than income taxes	9,118	8,843	18,395	17,521
Total electric utility expenses	256,040	249,991	514,381	497,605
Operating Income	82,659	81,777	133,779	136,127
Other Income (Expense):
Allowance for equity funds used during construction	5,985	5,611	12,018	10,843
Earnings of equity-method investments	683	(337)	4,825	917
Other Income (Expense), Net	(391)	(1,000)	(1,519)	(2,297)
Total other income	6,277	4,274	15,324	9,463
Interest Expense:
Interest on long-term debt	21,412	20,300	42,099	40,597
Other interest	2,148	2,740	5,093	5,438
Allowance for borrowed funds used during construction	(2,606)	(2,408)	(5,078)	(4,720)
Total interest expense, net	20,954	20,632	42,114	41,315
Income Before Income Taxes	67,982	65,419	106,989	104,275
Income Tax Expense	7,345	17,038	10,496	23,412
Net Income	$ 60,637	$ 48,381	$ 96,493	$ 80,863

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (250)	$ (302)	$ (500)	$ (604)
Net Income	62,593	50,096	98,704	83,101
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax	722	470	1,443	941
Total Comprehensive Income	63,315	50,566	100,147	84,042
Comprehensive (income) loss attributable to noncontrolling interests	(305)	(265)	(274)	(168)
Comprehensive Income Attributable to IDACORP, Inc.	63,010	50,301	99,873	83,874
Idaho Power Company
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	(250)	(302)	(500)	(604)
Net Income	60,637	48,381	96,493	80,863
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax	722	470	1,443	941
Total Comprehensive Income	$ 61,359	$ 48,851	$ 97,936	$ 81,804

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Unfunded pension liability adjustment, tax	$ 250	$ 302	$ 500	$ 604
Idaho Power Company
Unfunded pension liability adjustment, tax	$ 250	$ 302	$ 500	$ 604

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets Statement - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 183,141	$ 76,649
Receivables:
Customer	87,975	75,249
Other	5,284	30,438
Taxes receivable	2,929	8,147
Accrued unbilled revenues	79,818	75,120
Materials and supplies (at average cost)	60,229	55,745
Fuel stock (at average cost)	66,389	56,638
Prepayments	14,852	16,984
Current regulatory assets	37,977	48,613
Other	757	18
Total current assets	539,351	443,601
Investments	106,558	115,698
Property, Plant and Equipment:
Utility plant in service	6,005,176	5,906,162
Accumulated provision for depreciation	(2,162,143)	(2,098,274)
Utility plant in service - net	3,843,033	3,807,888
Construction work in progress	465,413	452,424
Utility plant held for future use	4,727	8,075
Other property, net of accumulated depreciation	17,908	15,488
Property, plant and equipment - net	4,331,081	4,283,875
Other Assets:
Company-owned life insurance	60,537	59,323
Regulatory assets	1,106,110	1,083,483
Other	62,480	59,425
Total other assets	1,229,127	1,202,231
Total	6,206,117	6,045,405
Current Liabilities:
Accounts payable	74,804	90,277
Taxes accrued	28,807	11,075
Interest accrued	23,153	22,379
Accrued compensation	40,004	47,018
Current regulatory liabilities	30,876	1,404
Advances from customers	28,408	18,414
Other	11,952	10,182
Total current liabilities	238,004	200,749
Other Liabilities:
Deferred income taxes	642,013	660,940
Regulatory liabilities	720,574	698,044
Pension and other postretirement benefits	429,513	438,869
Other	43,751	44,566
Total other liabilities	1,835,851	1,842,419
Long-Term Debt	1,834,055	1,746,123
Commitments and Contingencies
Equity:
Common stock	859,652	857,207
Retained earnings	1,465,009	1,426,528
Accumulated other comprehensive loss	(29,521)	(30,964)
Treasury stock	(1,936)	(1,386)
Total IDACORP, Inc. shareholders’ equity	2,293,204	2,251,385
Noncontrolling interests	5,003	4,729
Total equity	2,298,207	2,256,114
Total	6,206,117	6,045,405
Idaho Power Company
Current Assets:
Cash and cash equivalents	149,150	44,646
Receivables:
Customer	87,975	75,249
Other	5,143	30,274
Taxes receivable	0	26,492
Accrued unbilled revenues	79,818	75,120
Materials and supplies (at average cost)	60,229	55,745
Fuel stock (at average cost)	66,389	56,638
Prepayments	14,729	16,866
Current regulatory assets	37,977	48,613
Other	757	18
Total current assets	502,167	429,661
Investments	93,710	99,904
Property, Plant and Equipment:
Utility plant in service	6,005,176	5,906,162
Accumulated provision for depreciation	(2,162,143)	(2,098,274)
Utility plant in service - net	3,843,033	3,807,888
Construction work in progress	465,413	452,424
Utility plant held for future use	4,727	8,075
Property, plant and equipment - net	4,313,173	4,268,387
Other Assets:
Company-owned life insurance	60,537	59,323
Regulatory assets	1,106,110	1,083,483
Other	57,805	54,677
Total other assets	1,224,452	1,197,483
Total	6,133,502	5,995,435
Current Liabilities:
Accounts payable	74,694	89,978
Accounts payable to affiliates	44,202	57,562
Taxes accrued	21,884	10,904
Interest accrued	23,153	22,379
Accrued compensation	39,863	46,832
Current regulatory liabilities	30,876	1,404
Advances from customers	28,408	18,414
Other	11,365	9,556
Total current liabilities	274,445	257,029
Other Liabilities:
Deferred income taxes	708,205	725,942
Regulatory liabilities	720,574	698,044
Pension and other postretirement benefits	429,513	438,869
Other	42,947	43,652
Total other liabilities	1,901,239	1,906,507
Long-Term Debt	1,834,055	1,746,123
Commitments and Contingencies
Equity:
Common stock	97,877	97,877
Premium on capital stock	712,258	712,258
Capital stock expense	(2,097)	(2,097)
Retained earnings	1,345,246	1,308,702
Accumulated other comprehensive loss	(29,521)	(30,964)
Total equity	2,123,763	2,085,776
Total capitalization	3,957,818	3,831,899
Total	$ 6,133,502	$ 5,995,435

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Parenthetical) (Parentheticals) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Allowance for Doubtful Accounts Receivable, Current	$ 1,913	$ 2,013
Allowance for Doubtful Other Receivables, Current	$ 205	$ 180
Common Stock, No Par Value
Common Stock, Shares Authorized	120,000,000	120,000,000
Common Stock, Shares, Issued	50,420,000	50,420,000
Treasury Stock, Shares	27,000	28,000
Idaho Power Company
Allowance for Doubtful Accounts Receivable, Current	$ 1,913	$ 2,013
Allowance for Doubtful Other Receivables, Current	$ 205	$ 180
Common Stock, Par or Stated Value Per Share	$ 2.50	$ 2.50
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	39,151,000	39,151,000

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities:
Net Income	$ 98,704	$ 83,101
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	83,306	83,912
Deferred income taxes and investment tax credits	(9,708)	6,828
Changes in regulatory assets and liabilities	45,691	37,736
Pension and postretirement benefit plan expense	14,038	14,513
Contributions to pension and postretirement benefit plans	(24,516)	(3,920)
Earnings of equity-method investments	(5,552)	(2,037)
Distributions from equity-method investments	11,300	8,100
Allowance for equity funds used during construction	(12,018)	(10,843)
Other non-cash adjustments to net income, net	5,185	3,741
Change in:
Accounts receivable	(5,937)	(5,406)
Accounts payable and other accrued liabilities	(13,010)	(30,677)
Taxes accrued/receivable	22,950	18,073
Other current assets	(16,152)	(16,951)
Other current liabilities	9,054	6,948
Other assets	(5,439)	(3,692)
Other liabilities	(1,472)	(430)
Net cash provided by operating activities	196,424	188,996
Investing Activities:
Additions to property, plant and equipment	(133,598)	(146,341)
Payments received from transmission project joint funding partners	20,323	5,787
Proceeds from the sale of emission allowances and renewable energy certificates	1,650	1,839
Purchase of equity securities	(228)	(3,165)
Proceeds from the sale of equity securities	2,450	2,428
Other	495	2,860
Net cash used in investing activities	(108,908)	(136,592)
Financing Activities:
Issuance of long-term debt	220,000	0
Retirement of long-term debt	(130,000)	(1,064)
Dividends on common stock	(59,941)	(55,763)
Net change in short-term borrowings	0	(21,250)
Acquisition of treasury stock	(3,551)	(3,174)
Make-whole premium on retirement of long-term debt	(4,607)	0
Other	(2,925)	(4)
Net cash provided by (used in) financing activities	18,976	(81,255)
Net increase (decrease) in cash and cash equivalents	106,492	(28,851)
Cash and cash equivalents at beginning of the period	76,649	61,480
Cash and cash equivalents at end of the period	183,141	32,629
Supplemental Disclosure of Cash Flow Information:
Income taxes	0	1,202
Interest (net of amount capitalized)	39,494	39,481
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	20,650	21,410
Idaho Power Company
Operating Activities:
Net Income	96,493	80,863
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	83,007	83,611
Deferred income taxes and investment tax credits	(9,505)	6,144
Changes in regulatory assets and liabilities	45,691	37,736
Pension and postretirement benefit plan expense	14,038	14,513
Contributions to pension and postretirement benefit plans	(24,516)	(3,920)
Earnings of equity-method investments	(4,825)	(917)
Distributions from equity-method investments	11,300	8,100
Allowance for equity funds used during construction	(12,018)	(10,843)
Other non-cash adjustments to net income, net	(220)	(47)
Change in:
Accounts receivable	(4,884)	(12,446)
Accounts payable and other accrued liabilities	(27,256)	(1,109)
Taxes accrued/receivable	37,472	13,679
Other current assets	(16,145)	(16,945)
Other current liabilities	9,099	6,974
Other assets	(5,439)	(3,693)
Other liabilities	(1,363)	(275)
Net cash provided by operating activities	190,929	201,425
Investing Activities:
Additions to property, plant and equipment	(133,584)	(146,328)
Payments received from transmission project joint funding partners	20,323	5,787
Proceeds from the sale of emission allowances and renewable energy certificates	1,650	1,839
Purchase of equity securities	(228)	(3,165)
Proceeds from the sale of equity securities	2,450	2,428
Other	440	2,860
Net cash used in investing activities	(108,949)	(136,579)
Financing Activities:
Issuance of long-term debt	220,000	0
Retirement of long-term debt	(130,000)	(1,064)
Dividends on common stock	(59,949)	(55,695)
Net change in short-term borrowings	0	(21,800)
Make-whole premium on retirement of long-term debt	(4,607)	0
Other	(2,920)	0
Net cash provided by (used in) financing activities	22,524	(78,559)
Net increase (decrease) in cash and cash equivalents	104,504	(13,713)
Cash and cash equivalents at beginning of the period	44,646	44,140
Cash and cash equivalents at end of the period	149,150	30,427
Supplemental Disclosure of Cash Flow Information:
Income taxes	0	22,861
Interest (net of amount capitalized)	39,467	39,447
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$ 20,650	$ 21,410

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Equity $ in Thousands	USD ($)
Balance at beginning of period at Dec. 31, 2016	$ 851,833
Common Stock
Other common stock changes	1,771
Balance at end of period at Jun. 30, 2017	853,604
Balance at beginning of period at Dec. 31, 2016	1,323,198
Retained Earnings
Net Income Attributable to IDACORP, Inc.	82,933
Common stock dividends	(55,594)
Balance at end of period at Jun. 30, 2017	1,350,537
AOCI - Beginning Balance at Dec. 31, 2016	(20,882)
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	941
AOCI - Ending Balance at Jun. 30, 2017	(19,941)
Balance at beginning of period at Dec. 31, 2016	(243)
Treasury Stock
Issued	2,060
Acquired	(3,174)
Balance at end of period at Jun. 30, 2017	(1,357)
Balance at beginning of period at Dec. 31, 2016	3,960
Noncontrolling Interests
Adjustment for loss attributable to noncontrolling interests	168
Balance at end of period at Jun. 30, 2017	4,128
Balance at end of period at Jun. 30, 2017	853,604
Retained Earnings
Net Income Attributable to IDACORP, Inc.	49,831
Balance at end of period at Jun. 30, 2017	1,350,537
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	470
AOCI - Ending Balance at Jun. 30, 2017	(19,941)
Balance at end of period at Jun. 30, 2017	(1,357)
Noncontrolling Interests
Adjustment for loss attributable to noncontrolling interests	265
Balance at end of period at Jun. 30, 2017	4,128
Treasury Stock
Total IDACORP, Inc. shareholders’ equity at end of period	2,182,843
Noncontrolling Interests
Total equity at end of period	2,186,971
Total IDACORP, Inc. shareholders’ equity at end of period	2,251,385
Total equity at end of period	2,256,114
Balance at beginning of period at Dec. 31, 2017	857,207
Common Stock
Other common stock changes	2,445
Balance at end of period at Jun. 30, 2018	859,652
Balance at beginning of period at Dec. 31, 2017	1,426,528
Retained Earnings
Net Income Attributable to IDACORP, Inc.	98,430
Common stock dividends	(59,949)
Balance at end of period at Jun. 30, 2018	1,465,009
AOCI - Beginning Balance at Dec. 31, 2017	(30,964)
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	1,443
AOCI - Ending Balance at Jun. 30, 2018	(29,521)
Balance at beginning of period at Dec. 31, 2017	(1,386)
Treasury Stock
Issued	3,007
Acquired	(3,557)
Balance at end of period at Jun. 30, 2018	(1,936)
Balance at beginning of period at Dec. 31, 2017	4,729
Noncontrolling Interests
Adjustment for loss attributable to noncontrolling interests	274
Balance at end of period at Jun. 30, 2018	5,003
Balance at end of period at Jun. 30, 2018	859,652
Retained Earnings
Net Income Attributable to IDACORP, Inc.	62,288
Balance at end of period at Jun. 30, 2018	1,465,009
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	722
AOCI - Ending Balance at Jun. 30, 2018	(29,521)
Balance at end of period at Jun. 30, 2018	(1,936)
Noncontrolling Interests
Adjustment for loss attributable to noncontrolling interests	305
Balance at end of period at Jun. 30, 2018	5,003
Treasury Stock
Total IDACORP, Inc. shareholders’ equity at end of period	2,293,204
Noncontrolling Interests
Total equity at end of period	$ 2,298,207

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Equity (Parenthetical) (Parentheticals) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Dividends Declared Per Share of Common Stock	$ 0.59	$ 0.55	$ 1.18	$ 1.10

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to Condensed Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations. Nature of Business IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power (Jim Bridger plant). IDACORP’s significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). Regulation of Utility Operations As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3 - "Regulatory Matters." Financial Statements In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of June 30, 2018 , consolidated results of operations for the three and six months ended June 30, 2018 and 2017 , and consolidated cash flows for the six months ended June 30, 2018 and 2017 . These adjustments are of a normal and recurring nature. 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 should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2017 . The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred. Management Estimates Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those estimates. New and Recently Adopted Accounting Pronouncements Recently Adopted Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) . ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. IDACORP and Idaho Power adopted ASU 2014-09 on January 1, 2018, using the modified-retrospective approach as provided for in the standard. The adoption did not change the timing or amounts of revenue currently recognized by the companies, so no cumulative-effect adjustment was required. The adoption did change presentation of revenues on the condensed consolidated statements of income and also added disclosures. To conform with current period presentation, electric utility revenues on IDACORP's and Idaho Power's condensed consolidated statements of income for the three and six months ended June 30, 2018 and 2017, which had previously been reported separately as "General business," "Off-system sales," and "Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of revenue and additional disclosures. In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which revises the accounting related to the classification and measurement of investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal years beginning after December 15, 2017, including interim periods. IDACORP and Idaho Power adopted ASU 2016-01 on January 1, 2018. The adoption did not have a material impact on the companies' financial statements as the companies previously elected the fair value option and reported available-for-sale securities at fair value. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments , to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The companies' classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will be classified as investing activities under the new guidance. The new guidance did not affect the companies' presentation of debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments. IDACORP and Idaho Power adopted ASU 2016-15 on January 1, 2018, using the retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $2.6 million of company-owned life insurance proceeds received for the six months ended June 30, 2017, to "Other" within "Investing Activities" from "Change in accounts receivable" within "Operating Activities" on the condensed consolidated statements of cash flows. In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits, and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power adopted ASU 2017-07 on January 1, 2018, and accordingly, have retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit costs. The adoption did not have a material impact on the companies' financial statements nor did it affect net income for the three and six months ended June 30, 2018 . For IDACORP, for the three and six months ended June 30, 2017 , $0.8 million and $1.5 million , respectively, were reclassified out of "Other operations and maintenance" and $2.0 million and $4.1 million , respectively, were reclassified out of "Other" operating expenses for a total of $2.8 million and $5.6 million , respectively, reclassified to "Other Income (Expense), Net" to conform to current period presentation. For Idaho Power, for the three and six months ended June 30, 2017 , $0.8 million and $1.5 million , respectively, were reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation. Recent Accounting Pronouncements Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on leasing transactions. The ASU significantly changes the accounting model used by lessees to account for leases, requiring that all material leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the balance sheet while other leases are classified as operating leases and are not recognized on the balance sheet. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. The standard must be adopted using a modified retrospective approach. IDACORP and Idaho Power are evaluating the impact of ASU 2016-02 on their financial statements. Specifically, the companies are considering whether the new guidance will affect their accounting for purchase power agreements, easements and rights-of-way, utility pole attachments, and other utility industry-related arrangements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption. Reclassifications In these condensed consolidated financial statements, certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with current period presentation. On IDACORP's and Idaho Power's December 31, 2017 condensed consolidated balance sheets, the "Long-term receivables" balances of $4.3 million and $0.5 million , respectively, which had previously been reported separately, were reclassified to "Other" within "Other Assets" and "Deferred Debits," respectively.

INCOME TAXES_

INCOME TAXES:	3 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount. Income Tax Expense The following table provides a summary of income tax expense for the six months ended June 30 (in thousands): IDACORP Idaho Power 2018 2017 2018 2017 Income tax at statutory rates (federal and state) $ 27,909 $ 41,468 $ 27,539 $ 40,772 First mortgage bond redemption costs (1,261 ) — (1,261 ) — Share-based compensation (1,053 ) (1,559 ) (1,040 ) (1,530 ) Other (1) (15,597 ) (16,785 ) (14,742 ) (15,830 ) Income tax expense $ 9,998 $ 23,124 $ 10,496 $ 23,412 Effective tax rate 9.2 % 21.8 % 9.8 % 22.5 % (1) "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. The decreases in income tax expense for the six months ended June 30, 2018 , as compared to the same period in 2017 , were primarily due to lower statutory tax rates and a flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the second quarter of 2018. The decrease in statutory rates was due to the 2017 Tax Cuts and Jobs Act, which reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent , and Idaho House Bill 463 which lowered the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent . The federal and Idaho state income tax rate changes were effective January 1, 2018. On a net basis, Idaho Power’s estimate of its annual 2018 regulatory flow-through tax adjustments is comparable to 2017 .

REGULATORY MATTERS_

REGULATORY MATTERS:	6 Months Ended
	Jun. 30, 2018
Public Utilities, Rate Matters [Abstract]
Regulatory Matters	REGULATORY MATTERS Included below is a summary of Idaho Power's most recent general rate cases and base rate changes, as well as other recent or pending notable regulatory matters and proceedings. Idaho and Oregon General Rate Cases Idaho Power's current base rates are a result of orders from the Idaho Public Utilities Commission (IPUC) and Public Utility Commission of Oregon (OPUC). The commissions approve settlement stipulations that generally provide for cost recovery and an authorized rate of return on their respective Idaho-jurisdiction and Oregon-jurisdiction rate bases. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and Idaho Power filed a large single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates. Between general rate cases, Idaho Power relies upon customer growth, power cost adjustment mechanisms, tariff riders, and other mechanisms to reduce the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. For more information on the Idaho and Oregon general rate cases and base rate adjustments, refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2017. Idaho Settlement Stipulations In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table included under "Income Tax Reform - Regulatory Treatment" below. Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, during the second quarter of 2018 Idaho Power reversed the $0.5 million of additional accumulated deferred investment tax credits (ADITC) amortization recorded during the first quarter of 2018, based on Idaho Power's current estimate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) for the full-year 2018. During the second quarter of 2017, Idaho Power reversed $1.9 million of additional ADITC amortization recorded during the first quarter of 2017, as actual financial results exceeded Idaho Power's early estimates. Income Tax Reform - Regulatory Treatment In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to file a report with the IPUC, identifying and quantifying the financial impact of the income tax reform changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full year of 2017. In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers throu gh the Idaho-jurisdiction power cost adjustment (PCA) mech anism for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's open access transmission tariff (OATT). The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues. The May 2018 Idaho Tax Reform Settlement Stipulation also provides for the indefinite extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019. The table below summarizes and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho Tax Reform Settlement Stipulation that will be applicable commencing on January 1, 2020. October 2014 Idaho Earnings Support and Sharing Settlement Stipulation (Effective through December 31, 2019) May 2018 Idaho Tax Reform Settlement Stipulation (Effective beginning January 1, 2020, with no defined end date) If Idaho Power's actual annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million over the 2015 through 2019 period. If the $45 million of ADITC are completely amortized, the revenue sharing provisions below would no longer be applicable. If Idaho Power's actual annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished. If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 25 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho Power. In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their respective terms. Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future tax reform benefits. The settlement stipulation also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of Unit 1 at Idaho Power's jointly-owned North Valmy coal-fired plant and approved Idaho Power's request to recover annual incremental accelerated depreciation of $2.5 million relating to Unit 1, beginning June 1, 2018, and ending December 31, 2019. Hells Canyon Complex Relicensing Costs Settlement Stipulation In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the Hells Canyon Complex (HCC) were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and a third party intervenor, recognizing that a total of $216.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in the fourth quarter of 2017, which included $4.3 million for costs incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the $216.5 million of associated costs to be reasonably and prudently incurred. Idaho Power Cost Adjustment Mechanisms In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheet for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation. In June 2018, the IPUC issued an order approving a $22.6 million net decrease in PCA rates, effective for the 2018-2019 PCA collection period from June 1, 2018, to May 31, 2019. The net decrease in PCA rates is primarily due to better-than-expected actual water conditions for the 2017-2018 PCA year, which resulted in additional low-cost hydroelectric generation available to reduce net power supply costs. Previously in May 2017, the IPUC issued an order approving a $10.6 million net increase in PCA rates, effective for the 2017-2018 PCA collection period from June 1, 2017, to May 31, 2018. The net increase in PCA rates was primarily due to expected higher power supply costs resulting from new renewable energy power purchase agreements under PURPA and higher coal-fired generation costs, combined with the effect of lower-than-expected actual hydroelectric generation for the 2016-2017 PCA year. The net increase included an offsetting $13.0 million one-time refund of previously collected Idaho energy efficiency rider funds. Idaho Fixed Cost Adjustment Mechanism The Idaho jurisdiction fixed cost adjustment (FCA) mechanism is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and instead linking it to a set amount per customer. The FCA mechanism, applicable to residential and small commercial customers, is adjusted each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. In May 2018, the IPUC issued an order approving a decrease of $19.4 million in the FCA from $35.0 million to $15.6 million , with new rates effective for the period from June 1, 2018, to May 31, 2019. Previously in May 2017, the IPUC issued an order approving an increase of $6.9 million in the FCA from $28.1 million to $35.0 million , with rates effective for the period from June 1, 2017, to May 31, 2018. Western Energy Imbalance Market Costs Idaho Power's participation in the energy imbalance market implemented in the western United States (Western EIM) commenced on April 4, 2018. The Western EIM aims to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. In August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its participation in the Western EIM. In January 2017, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. Idaho Power deferred $1.0 million of incremental other operations and maintenance (O&M) costs incurred through April 1, 2018. In November 2017, Idaho Power filed an application with the IPUC requesting approval to establish an interim method of recovery for costs associated with participation in the Western EIM. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for a recovery mechanism administered through Idaho Power's PCA mechanism. The recovery mechanism provides for monthly incremental revenue, which includes a return on and return of Western EIM-related capital costs and recovery of ongoing Western EIM operating costs. As of April 1, 2018, Idaho Power ceased deferring incremental Western EIM participation O&M start-up costs, and began recognizing the monthly incremental revenue associated with Western EIM participation. During both the three and six months ended June 30, 2018, Idaho Power recorded $0.7 million of revenue relating to Western EIM participation and deferred the same amount to the PCA deferral account.

REVENUES_ (Notes)

REVENUES: (Notes)	6 Months Ended
	Jun. 30, 2018
Revenues [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUES On January 1, 2018, IDACORP and Idaho Power adopted ASU 2014-09 using the modified retrospective method. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, no cumulative-effect adjustment was recorded. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Electric utility operating revenues: Revenue from contracts with customers $ 331,298 $ 326,190 $ 620,871 $ 620,081 Alternative revenue programs and other revenues 7,401 5,578 27,289 13,651 Total electric utility operating revenues $ 338,699 $ 331,768 $ 648,160 $ 633,732 Revenues from Contracts with Customers Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Revenues from contracts with customers: Retail revenues: Residential (includes $5,508, $3,205, $19,052 and $8,331, respectively, related to the FCA (1) ) $ 109,155 $ 112,534 $ 255,838 $ 264,689 Commercial (includes $291, $276, $652 and $387, respectively, related to the FCA (1) ) 76,965 78,982 151,191 153,260 Industrial 48,868 49,766 94,660 95,224 Irrigation 65,065 56,068 65,471 56,993 Deferred revenue related to HCC relicensing AFUDC (2) (1,462 ) (2,349 ) (4,046 ) (4,933 ) Total retail revenues 298,591 295,001 563,114 565,233 Less: FCA mechanism revenues (1) (5,799 ) (3,481 ) (19,704 ) (8,718 ) Wholesale energy sales 10,214 6,003 24,283 13,967 Transmission services (wheeling) revenues 13,205 11,965 24,600 20,824 Energy efficiency program revenues 8,802 10,515 16,399 16,843 Other revenues from contracts with customers 6,285 6,187 12,179 11,932 Total revenues from contracts with customers $ 331,298 $ 326,190 $ 620,871 $ 620,081 (1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers. (2) As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for that energy or those services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year. Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates. Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $1.5 million and $1.8 million for the three and six months ended June 30, 2018 , respectively, and $2.2 million and $2.4 million for the three and six months ended June 30, 2017 , respectively. Residential Customers : Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. Commercial Customers : Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. Industrial Customers : Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. Irrigation Customers : Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers with increased precipitation generally resulting in decreased sales. Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales. Transmission Services (Wheeling) Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be part of a long-term capacity contract, short-term contract, or on demand when available. Transmission services revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission service revenues are affected by changes in Idaho Power’s OATT transmission rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region. Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At June 30, 2018 , Idaho Power's energy efficiency rider balances were a $2.6 million regulatory liability in the Idaho jurisdiction and a $6.5 million regulatory asset in the Oregon jurisdiction. Alternative Revenue Programs and Other Revenues While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, which may increase or decrease tariff-based rates billed to customers. The Idaho FCA mechanism, applicable to residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year. The FCA mechanism revenues include only the initial recognition of FCA revenues when the regulator-specified conditions for recognition have been met. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that had been initially recorded in prior periods when regulator-specified conditions were met. When those amounts are included in the price of utility service and billed to customers, such amounts are recorded as recovery of the associated regulatory asset or liability and not as revenues. The table below presents the FCA mechanism revenues and other revenues for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Alternative revenue programs and other revenues: FCA mechanism revenues $ 5,799 3,481 $ 19,704 $ 8,718 Derivative revenues 1,602 2,097 7,585 4,933 Total alternative revenue programs and other revenues $ 7,401 $ 5,578 $ 27,289 $ 13,651 IDACORP's Other Revenues IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydroelectric generation projects that satisfy the requirements of PURPA.

LONG-TERM DEBT_ (Notes)

LONG-TERM DEBT: (Notes)	6 Months Ended
	Jun. 30, 2017
LongTermDebtTextBlock [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT In March 2018, Idaho Power issued $220 million in principal amount of 4.20 percent first mortgage bonds, secured medium-term notes, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, $130 million in principal amount of 4.50 percent first mortgage bonds, medium-term notes, Series H due March 2020. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $4.6 million . Idaho Power used a portion of the net proceeds from the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption. As of June 30, 2018 , $280 million in principal amount of long-term debt securities remained available for issuance under a selling agency agreement executed on September 27, 2016, and pursuant to state regulatory authority.

COMMON STOCK_

COMMON STOCK:	3 Months Ended
	Jun. 30, 2018
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common Stock	COMMON STOCK IDACORP Common Stock During the six months ended June 30, 2018 , IDACORP granted 75,761 restricted stock unit awards to employees and 12,950 shares of common stock to directors but made no original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. As directed by IDACORP, plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan use market purchases of IDACORP common stock, as opposed to original issuance of common stock from IDACORP, to acquire shares of IDACORP common stock for the plans. However, IDACORP may determine at any time to use original issuances of common stock under those plans. Restrictions on Dividends Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At June 30, 2018 , the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 percent , respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.3 billion and $1.1 billion , respectively, at June 30, 2018 . There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At June 30, 2018 , IDACORP and Idaho Power were in compliance with those financial covenants. Idaho Power’s Revised Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At June 30, 2018 , Idaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP. Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report, Idaho Power has no preferred stock outstanding. In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings.

EARNINGS PER SHARE_

EARNINGS PER SHARE:	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and six months ended June 30, 2018 and 2017 (in thousands, except for per share amounts). Three months ended Six months ended 2018 2017 2018 2017 Numerator: Net income attributable to IDACORP, Inc. $ 62,288 $ 49,831 $ 98,430 $ 82,933 Denominator: Weighted-average common shares outstanding - basic 50,435 50,363 50,430 50,361 Effect of dilutive securities 46 44 42 41 Weighted-average common shares outstanding - diluted 50,481 50,407 50,472 50,402 Basic earnings per share $ 1.24 $ 0.99 $ 1.95 $ 1.65 Diluted earnings per share $ 1.23 $ 0.99 $ 1.95 $ 1.65

COMMITMENTS_

COMMITMENTS:	6 Months Ended
	Jun. 30, 2018
Disclosure Text Block Supplement [Abstract]
Commitments	COMMITMENTS Purchase Obligations IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the six months ended June 30, 2018 , except that Idaho Power entered into agreements with solar and biomass PURPA-qualifying facilities, which increased contractual payment obligations by approximately $51 million over the 20-year terms of the contracts. Guarantees Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was $58.4 million at June 30, 2018 , representing IERCo's one-third share of BCC's total reclamation obligation of $175.2 million . BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At June 30, 2018 , the value of BCC's reclamation trust fund was $108.3 million . During the six months ended June 30, 2018 , the reclamation trust fund made distributions of $3.0 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal. IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of June 30, 2018 , management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

CONTINGENCIES_

CONTINGENCIES:	3 Months Ended
	Jun. 30, 2018
Loss Contingency [Abstract]
Contingencies	CONTINGENCIES IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power’s operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred. IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report, the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations.

BENEFIT PLANS_

BENEFIT PLANS:	6 Months Ended
	Jun. 30, 2018
Retirement Benefits, Description [Abstract]
Benefit Plans	BENEFIT PLANS Idaho Power has a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (collectively, SMSP). Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under the pension plan are based on years of service and the employee’s final average earnings. Idaho Power also maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying dependents. The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended June 30, 2018 and 2017 (in thousands). Pension Plan SMSP Postretirement Total 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 9,742 $ 8,245 $ (79 ) $ 190 $ 242 $ 197 $ 9,905 $ 8,632 Interest cost 9,683 9,716 1,061 1,079 656 702 11,400 11,497 Expected return on plan assets (13,056 ) (11,181 ) — — (605 ) (584 ) (13,661 ) (11,765 ) Amortization of prior service cost 2 7 25 32 12 17 39 56 Amortization of net loss 3,394 3,212 947 740 — — 4,341 3,952 Net periodic benefit cost 9,765 9,999 1,954 2,041 305 332 12,024 12,372 Regulatory deferral of net periodic benefit cost (1) (9,309 ) (9,488 ) — — — — (9,309 ) (9,488 ) Previously deferred pension costs recognized (1) 4,289 4,289 — — — — 4,289 4,289 Net periodic benefit cost recognized for financial reporting (1)(2) $ 4,745 $ 4,800 $ 1,954 $ 2,041 $ 305 $ 332 $ 7,004 $ 7,173 (1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. (2) Of total net periodic benefit cost recognized for financial reporting, $4.1 million and $4.4 million , respectively, was recognized in "Other operations and maintenance" and $2.9 million and $2.8 million , respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the three months ended June 30, 2018 and 2017. The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the six months ended June 30, 2018 and 2017 (in thousands). Pension Plan SMSP Postretirement Total 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 19,485 $ 16,871 $ (158 ) $ 380 $ 526 $ 486 $ 19,853 $ 17,737 Interest cost 19,365 19,479 2,124 2,157 1,322 1,392 22,811 23,028 Expected return on plan assets (26,111 ) (22,569 ) — — (1,234 ) (1,154 ) (27,345 ) (23,723 ) Amortization of prior service cost 3 14 49 64 24 24 76 102 Amortization of net loss 6,788 6,595 1,894 1,481 — — 8,682 8,076 Net periodic benefit cost 19,530 20,390 3,909 4,082 638 748 24,077 25,220 Regulatory deferral of net periodic benefit cost (1) (18,616 ) (19,284 ) — — — — (18,616 ) (19,284 ) Previously deferred pension costs recognized (1) 8,577 8,577 — — — — 8,577 8,577 Net periodic benefit cost recognized for financial reporting (1)(2) $ 9,491 $ 9,683 $ 3,909 $ 4,082 $ 638 $ 748 $ 14,038 $ 14,513 (1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. (2) Of total net periodic benefit cost recognized for financial reporting, $8.2 million and $8.9 million , respectively, was recognized in "Other operations and maintenance" and $5.8 million and $5.6 million , respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the six months ended June 30, 2018 and 2017. Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2018. However, during the six months ended June 30, 2018, Idaho Power made $20 million of discretionary contributions to its defined benefit pension plan, in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions. Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the Employee Savings Plan.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS:	6 Months Ended
	Jun. 30, 2018
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative Financial Instruments	DERIVATIVE FINANCIAL INSTRUMENTS Commodity Price Risk Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop. All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows. The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and six months ended June 30, 2018 and 2017 (in thousands). Gain/(Loss) on Derivatives Recognized in Income (1) Location of Realized Gain/(Loss) on Derivatives Recognized in Income Three months ended Six months ended 2018 2017 2018 2017 Financial swaps Operating revenues $ 27 $ (305 ) $ 266 $ 1,173 Financial swaps Purchased power 13 (287 ) (189 ) (735 ) Financial swaps Fuel expense (112 ) (4 ) (800 ) 666 Financial swaps Other operations and maintenance 31 (55 ) 38 (81 ) Forward contracts Operating revenues — — 2 — Forward contracts Purchased power (7 ) (8 ) (20 ) (10 ) Forward contracts Fuel expense 10 3 24 3 (1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities. Settlement gains and losses on electricity swap contracts are recorded on the income statement in revenues from contracts with customers or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense. See Note 12 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities. Derivative Instrument Summary The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at June 30, 2018 , and December 31, 2017 (in thousands). Asset Derivatives Liability Derivatives Balance Sheet Location Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities June 30, 2018 Current: Financial swaps Other current assets $ 1,545 $ (791 ) $ 754 $ 791 $ (791 ) $ — Financial swaps Other current liabilities 195 (195 ) — 1,051 (195 ) 856 Forward contracts Other current assets 3 — 3 — — — Long-term: Financial swaps Other assets 49 (1 ) 48 1 (1 ) — Financial swaps Other liabilities 15 (15 ) — 354 (15 ) 339 Total $ 1,807 $ (1,002 ) $ 805 $ 2,197 $ (1,002 ) $ 1,195 December 31, 2017 Current: Financial swaps Other current assets $ 18 $ — $ 18 $ — $ — $ — Financial swaps Other current liabilities 553 (553 ) — 1,971 (748 ) (1) 1,223 Forward contracts Other current liabilities — — — 2 — 2 Long-term: Financial swaps Other assets 4 — 4 — — — Total $ 575 $ (553 ) $ 22 $ 1,973 $ (748 ) $ 1,225 (1) Current liability derivative amount offset includes $0.2 million of collateral receivable for the period ended December 31, 2017 . The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at June 30, 2018 and 2017 (in thousands of units). June 30, Commodity Units 2018 2017 Electricity purchases MWh 323 194 Electricity sales MWh 58 38 Natural gas purchases MMBtu 12,371 10,297 Natural gas sales MMBtu 233 75 Diesel purchases Gallons 451 605 Credit Risk At June 30, 2018 , Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under Western Systems Power Pool agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency. Credit-Contingent Features Certain Idaho Power derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at June 30, 2018 was $2.2 million . Idaho Power posted $0.8 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2018 , Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $3.0 million to cover the open liability positions as well as completed transactions that have not yet been paid.

FAIR VALUE MEASUREMENTS_

FAIR VALUE MEASUREMENTS:	6 Months Ended
	Jun. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: • Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access. • Level 2: Financial assets and liabilities whose values are based on the following: a) quoted prices for similar assets or liabilities in active markets; b) quoted prices for identical or similar assets or liabilities in non-active markets; c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability. IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data. • Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs during the six months ended June 30, 2018 . The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2018 , and December 31, 2017 (in thousands). June 30, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Money market funds IDACORP (1) $ 30,611 $ — $ — $ 30,611 $ 28,038 $ — $ — $ 28,038 Idaho Power 80,593 — — 80,593 10,260 — — 10,260 Derivatives 802 3 — 805 22 — — 22 Equity securities 27,916 — — 27,916 30,266 — — 30,266 Liabilities: Derivatives 1,195 — — 1,195 1,223 2 — 1,225 (1) Holding company only. Does not include amounts held by Idaho Power. Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivatives are valued using New York Mercantile Exchange and Intercontinental Exchange pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Equity securities consist of employee-directed investments related to an executive deferred compensation plan and actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a Rabbi trust. The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of June 30, 2018 , and December 31, 2017 , using available market information and appropriate valuation methodologies (in thousands). June 30, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value IDACORP Assets: Notes receivable (1) $ 3,804 $ 3,804 $ 3,804 $ 3,804 Liabilities: Long-term debt (1) 1,834,055 1,946,794 1,746,123 1,915,459 Idaho Power Liabilities: Long-term debt (1) 1,834,055 1,946,794 1,746,123 1,915,459 (1) Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 12. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.

SEGMENT INFORMATION_

SEGMENT INFORMATION:	3 Months Ended
	Jun. 30, 2018
Segment Reporting, Measurement Disclosures [Abstract]
Segment Information	SEGMENT INFORMATION IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture. IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the "All Other" category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, and IDACORP’s holding company expenses. The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands). Utility Operations All Other Eliminations Consolidated Total Three months ended June 30, 2018: Revenues $ 338,699 $ 1,253 $ — $ 339,952 Net income attributable to IDACORP, Inc. 60,637 1,651 — 62,288 Total assets as of June 30, 2018 6,133,502 153,529 (80,914 ) 6,206,117 Three months ended June 30, 2017: Revenues $ 331,768 $ 1,238 $ — $ 333,006 Net income attributable to IDACORP, Inc. 48,381 1,450 — 49,831 Six months ended June 30, 2018: Revenues $ 648,160 $ 1,898 $ — $ 650,058 Net income attributable to IDACORP, Inc. 96,493 1,937 — 98,430 Six months ended June 30, 2017: Revenues $ 633,732 $ 1,818 $ — $ 635,550 Net income attributable to IDACORP, Inc. 80,863 2,070 — 82,933

CHANGES IN ACCUMULATED OTHER CO

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME:	3 Months Ended
	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Changes in Accumulated Other Comprehensive Income [Text Block]	CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and six months ended June 30, 2018 and 2017 (in thousands). Items in parentheses indicate charges to AOCI. Defined Benefit Pension Items Three months ended Six months ended 2018 2017 2018 2017 Balance at beginning of period $ (30,243 ) $ (20,411 ) $ (30,964 ) $ (20,882 ) Amounts reclassified out of AOCI 722 470 1,443 941 Balance at end of period $ (29,521 ) $ (19,941 ) $ (29,521 ) $ (19,941 ) The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and six months ended June 30, 2018 and 2017 (in thousands). Items in parentheses indicate increases to net income. Amount Reclassified from AOCI Details About AOCI Three months ended Six months ended 2018 2017 2018 2017 Amortization of defined benefit pension items (1) Prior service cost $ 25 $ 32 $ 49 $ 64 Net loss 947 740 1,894 1,481 Total before tax 972 772 1,943 1,545 Tax benefit (2) (250 ) (302 ) (500 ) (604 ) Net of tax 722 470 1,443 941 Total reclassification for the period $ 722 $ 470 $ 1,443 $ 941 (1) Amortization of these items is included in IDACORP's condensed consolidated income statements in other operating expenses and in Idaho Power's condensed consolidated statements of income in other expense, net. (2) The tax benefit is included in income tax expense in the condensed consolidated statements of income of both IDACORP and Idaho Power.

SUMMARY OF SIGNIFICANT ACCOUN24

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Organization, Consolidation, Presentation, and Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Revenue Recognition, Policy [Policy Text Block]	Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for that energy or those services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year. Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates. Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $1.5 million and $1.8 million for the three and six months ended June 30, 2018 , respectively, and $2.2 million and $2.4 million for the three and six months ended June 30, 2017 , respectively. Residential Customers : Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. Commercial Customers : Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. Industrial Customers : Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. Irrigation Customers : Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers with increased precipitation generally resulting in decreased sales. Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales. Transmission Services (Wheeling) Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be part of a long-term capacity contract, short-term contract, or on demand when available. Transmission services revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission service revenues are affected by changes in Idaho Power’s OATT transmission rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region. Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At June 30, 2018 , Idaho Power's energy efficiency rider balances were a $2.6 million regulatory liability in the Idaho jurisdiction and a $6.5 million regulatory asset in the Oregon jurisdiction. Alternative Revenue Programs and Other Revenues While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, which may increase or decrease tariff-based rates billed to customers. The Idaho FCA mechanism, applicable to residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year.
Nature of Business	IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power (Jim Bridger plant). IDACORP’s significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
Regulation of Utility Operations	As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3 - "Regulatory Matters."
Financial Statements	In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of June 30, 2018 , consolidated results of operations for the three and six months ended June 30, 2018 and 2017 , and consolidated cash flows for the six months ended June 30, 2018 and 2017 . These adjustments are of a normal and recurring nature. 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 should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2017 . The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.
Management Estimates	Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those estimates.
Reclassification	In these condensed consolidated financial statements, certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with current period presentation. On IDACORP's and Idaho Power's December 31, 2017 condensed consolidated balance sheets, the "Long-term receivables" balances of $4.3 million and $0.5 million , respectively, which had previously been reported separately, were reclassified to "Other" within "Other Assets" and "Deferred Debits," respectively.
Income Tax	In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.
Fair Value of Financial Instruments	IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: • Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access. • Level 2: Financial assets and liabilities whose values are based on the following: a) quoted prices for similar assets or liabilities in active markets; b) quoted prices for identical or similar assets or liabilities in non-active markets; c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability. IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data. • Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized.
New Accounting Pronouncements	New and Recently Adopted Accounting Pronouncements Recently Adopted Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) . ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. IDACORP and Idaho Power adopted ASU 2014-09 on January 1, 2018, using the modified-retrospective approach as provided for in the standard. The adoption did not change the timing or amounts of revenue currently recognized by the companies, so no cumulative-effect adjustment was required. The adoption did change presentation of revenues on the condensed consolidated statements of income and also added disclosures. To conform with current period presentation, electric utility revenues on IDACORP's and Idaho Power's condensed consolidated statements of income for the three and six months ended June 30, 2018 and 2017, which had previously been reported separately as "General business," "Off-system sales," and "Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of revenue and additional disclosures. In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which revises the accounting related to the classification and measurement of investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal years beginning after December 15, 2017, including interim periods. IDACORP and Idaho Power adopted ASU 2016-01 on January 1, 2018. The adoption did not have a material impact on the companies' financial statements as the companies previously elected the fair value option and reported available-for-sale securities at fair value. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments , to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The companies' classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will be classified as investing activities under the new guidance. The new guidance did not affect the companies' presentation of debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments. IDACORP and Idaho Power adopted ASU 2016-15 on January 1, 2018, using the retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $2.6 million of company-owned life insurance proceeds received for the six months ended June 30, 2017, to "Other" within "Investing Activities" from "Change in accounts receivable" within "Operating Activities" on the condensed consolidated statements of cash flows. In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits, and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power adopted ASU 2017-07 on January 1, 2018, and accordingly, have retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit costs. The adoption did not have a material impact on the companies' financial statements nor did it affect net income for the three and six months ended June 30, 2018 . For IDACORP, for the three and six months ended June 30, 2017 , $0.8 million and $1.5 million , respectively, were reclassified out of "Other operations and maintenance" and $2.0 million and $4.1 million , respectively, were reclassified out of "Other" operating expenses for a total of $2.8 million and $5.6 million , respectively, reclassified to "Other Income (Expense), Net" to conform to current period presentation. For Idaho Power, for the three and six months ended June 30, 2017 , $0.8 million and $1.5 million , respectively, were reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation. Recent Accounting Pronouncements Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on leasing transactions. The ASU significantly changes the accounting model used by lessees to account for leases, requiring that all material leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the balance sheet while other leases are classified as operating leases and are not recognized on the balance sheet. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. The standard must be adopted using a modified retrospective approach. IDACORP and Idaho Power are evaluating the impact of ASU 2016-02 on their financial statements. Specifically, the companies are considering whether the new guidance will affect their accounting for purchase power agreements, easements and rights-of-way, utility pole attachments, and other utility industry-related arrangements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption.
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop. All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.
Derivatives, Reporting of Derivative Activity	Settlement gains and losses on electricity swap contracts are recorded on the income statement in revenues from contracts with customers or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense.
Segment Reporting	IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture. IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the "All Other" category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, and IDACORP’s holding company expenses.

REVENUES_ (Policies)

REVENUES: (Policies)	6 Months Ended
	Jun. 30, 2018
Revenues [Abstract]
Revenue Recognition, Policy [Policy Text Block]	Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for that energy or those services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year. Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates. Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $1.5 million and $1.8 million for the three and six months ended June 30, 2018 , respectively, and $2.2 million and $2.4 million for the three and six months ended June 30, 2017 , respectively. Residential Customers : Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. Commercial Customers : Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. Industrial Customers : Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. Irrigation Customers : Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers with increased precipitation generally resulting in decreased sales. Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales. Transmission Services (Wheeling) Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be part of a long-term capacity contract, short-term contract, or on demand when available. Transmission services revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission service revenues are affected by changes in Idaho Power’s OATT transmission rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region. Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At June 30, 2018 , Idaho Power's energy efficiency rider balances were a $2.6 million regulatory liability in the Idaho jurisdiction and a $6.5 million regulatory asset in the Oregon jurisdiction. Alternative Revenue Programs and Other Revenues While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, which may increase or decrease tariff-based rates billed to customers. The Idaho FCA mechanism, applicable to residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year.

INCOME TAXES_ Level 3 (Tables)

INCOME TAXES: Level 3 (Tables)	3 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The following table provides a summary of income tax expense for the six months ended June 30 (in thousands): IDACORP Idaho Power 2018 2017 2018 2017 Income tax at statutory rates (federal and state) $ 27,909 $ 41,468 $ 27,539 $ 40,772 First mortgage bond redemption costs (1,261 ) — (1,261 ) — Share-based compensation (1,053 ) (1,559 ) (1,040 ) (1,530 ) Other (1) (15,597 ) (16,785 ) (14,742 ) (15,830 ) Income tax expense $ 9,998 $ 23,124 $ 10,496 $ 23,412 Effective tax rate 9.2 % 21.8 % 9.8 % 22.5 % (1) "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments.

REVENUES_ Electric utility oper

REVENUES: Electric utility operating revenues (Tables)	6 Months Ended
	Jun. 30, 2018
Electric utility operating revenues [Line Items]
Electric utility operating revenues [Table Text Block]	The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Electric utility operating revenues: Revenue from contracts with customers $ 331,298 $ 326,190 $ 620,871 $ 620,081 Alternative revenue programs and other revenues 7,401 5,578 27,289 13,651 Total electric utility operating revenues $ 338,699 $ 331,768 $ 648,160 $ 633,732

REVENUES_ (Tables)

REVENUES: (Tables)	6 Months Ended
	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]	Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Revenues from contracts with customers: Retail revenues: Residential (includes $5,508, $3,205, $19,052 and $8,331, respectively, related to the FCA (1) ) $ 109,155 $ 112,534 $ 255,838 $ 264,689 Commercial (includes $291, $276, $652 and $387, respectively, related to the FCA (1) ) 76,965 78,982 151,191 153,260 Industrial 48,868 49,766 94,660 95,224 Irrigation 65,065 56,068 65,471 56,993 Deferred revenue related to HCC relicensing AFUDC (2) (1,462 ) (2,349 ) (4,046 ) (4,933 ) Total retail revenues 298,591 295,001 563,114 565,233 Less: FCA mechanism revenues (1) (5,799 ) (3,481 ) (19,704 ) (8,718 ) Wholesale energy sales 10,214 6,003 24,283 13,967 Transmission services (wheeling) revenues 13,205 11,965 24,600 20,824 Energy efficiency program revenues 8,802 10,515 16,399 16,843 Other revenues from contracts with customers 6,285 6,187 12,179 11,932 Total revenues from contracts with customers $ 331,298 $ 326,190 $ 620,871 $ 620,081 (1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers. (2) As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

REVENUES_ Alternative revenue p

REVENUES: Alternative revenue program and other revenues (Tables)	6 Months Ended
	Jun. 30, 2018
Regulated Operations [Abstract]
Alternative revenue programs and other revenues [Table Text Block]	The table below presents the FCA mechanism revenues and other revenues for the three and six months ended June 30 , 2018 and 2017 (in thousands): Three months ended Six months ended 2018 2017 2018 2017 Alternative revenue programs and other revenues: FCA mechanism revenues $ 5,799 3,481 $ 19,704 $ 8,718 Derivative revenues 1,602 2,097 7,585 4,933 Total alternative revenue programs and other revenues $ 7,401 $ 5,578 $ 27,289 $ 13,651

EARNINGS PER SHARE_ Level 3 (Ta

EARNINGS PER SHARE: Level 3 (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share, Basic and Diluted [Abstract]
Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Table Text Block]	The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and six months ended June 30, 2018 and 2017 (in thousands, except for per share amounts). Three months ended Six months ended 2018 2017 2018 2017 Numerator: Net income attributable to IDACORP, Inc. $ 62,288 $ 49,831 $ 98,430 $ 82,933 Denominator: Weighted-average common shares outstanding - basic 50,435 50,363 50,430 50,361 Effect of dilutive securities 46 44 42 41 Weighted-average common shares outstanding - diluted 50,481 50,407 50,472 50,402 Basic earnings per share $ 1.24 $ 0.99 $ 1.95 $ 1.65 Diluted earnings per share $ 1.23 $ 0.99 $ 1.95 $ 1.65

BENEFIT PLANS_ Level 3 (Tables)

BENEFIT PLANS: Level 3 (Tables)	6 Months Ended
	Jun. 30, 2018
Defined Benefit Plan [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended June 30, 2018 and 2017 (in thousands). Pension Plan SMSP Postretirement Total 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 9,742 $ 8,245 $ (79 ) $ 190 $ 242 $ 197 $ 9,905 $ 8,632 Interest cost 9,683 9,716 1,061 1,079 656 702 11,400 11,497 Expected return on plan assets (13,056 ) (11,181 ) — — (605 ) (584 ) (13,661 ) (11,765 ) Amortization of prior service cost 2 7 25 32 12 17 39 56 Amortization of net loss 3,394 3,212 947 740 — — 4,341 3,952 Net periodic benefit cost 9,765 9,999 1,954 2,041 305 332 12,024 12,372 Regulatory deferral of net periodic benefit cost (1) (9,309 ) (9,488 ) — — — — (9,309 ) (9,488 ) Previously deferred pension costs recognized (1) 4,289 4,289 — — — — 4,289 4,289 Net periodic benefit cost recognized for financial reporting (1)(2) $ 4,745 $ 4,800 $ 1,954 $ 2,041 $ 305 $ 332 $ 7,004 $ 7,173 (1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. (2) Of total net periodic benefit cost recognized for financial reporting, $4.1 million and $4.4 million , respectively, was recognized in "Other operations and maintenance" and $2.9 million and $2.8 million , respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the three months ended June 30, 2018 and 2017. The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the six months ended June 30, 2018 and 2017 (in thousands). Pension Plan SMSP Postretirement Total 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 19,485 $ 16,871 $ (158 ) $ 380 $ 526 $ 486 $ 19,853 $ 17,737 Interest cost 19,365 19,479 2,124 2,157 1,322 1,392 22,811 23,028 Expected return on plan assets (26,111 ) (22,569 ) — — (1,234 ) (1,154 ) (27,345 ) (23,723 ) Amortization of prior service cost 3 14 49 64 24 24 76 102 Amortization of net loss 6,788 6,595 1,894 1,481 — — 8,682 8,076 Net periodic benefit cost 19,530 20,390 3,909 4,082 638 748 24,077 25,220 Regulatory deferral of net periodic benefit cost (1) (18,616 ) (19,284 ) — — — — (18,616 ) (19,284 ) Previously deferred pension costs recognized (1) 8,577 8,577 — — — — 8,577 8,577 Net periodic benefit cost recognized for financial reporting (1)(2) $ 9,491 $ 9,683 $ 3,909 $ 4,082 $ 638 $ 748 $ 14,038 $ 14,513 (1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. (2) Of total net periodic benefit cost recognized for financial reporting, $8.2 million and $8.9 million , respectively, was recognized in "Other operations and maintenance" and $5.8 million and $5.6 million , respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the six months ended June 30, 2018 and 2017.

DERIVATIVE FINANCIAL INSTRUME32

DERIVATIVE FINANCIAL INSTRUMENTS: Level 3 (Tables)	3 Months Ended
	Jun. 30, 2018
Summary of Derivative Instruments [Abstract]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and six months ended June 30, 2018 and 2017 (in thousands). Gain/(Loss) on Derivatives Recognized in Income (1) Location of Realized Gain/(Loss) on Derivatives Recognized in Income Three months ended Six months ended 2018 2017 2018 2017 Financial swaps Operating revenues $ 27 $ (305 ) $ 266 $ 1,173 Financial swaps Purchased power 13 (287 ) (189 ) (735 ) Financial swaps Fuel expense (112 ) (4 ) (800 ) 666 Financial swaps Other operations and maintenance 31 (55 ) 38 (81 ) Forward contracts Operating revenues — — 2 — Forward contracts Purchased power (7 ) (8 ) (20 ) (10 ) Forward contracts Fuel expense 10 3 24 3 (1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at June 30, 2018 , and December 31, 2017 (in thousands). Asset Derivatives Liability Derivatives Balance Sheet Location Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities June 30, 2018 Current: Financial swaps Other current assets $ 1,545 $ (791 ) $ 754 $ 791 $ (791 ) $ — Financial swaps Other current liabilities 195 (195 ) — 1,051 (195 ) 856 Forward contracts Other current assets 3 — 3 — — — Long-term: Financial swaps Other assets 49 (1 ) 48 1 (1 ) — Financial swaps Other liabilities 15 (15 ) — 354 (15 ) 339 Total $ 1,807 $ (1,002 ) $ 805 $ 2,197 $ (1,002 ) $ 1,195 December 31, 2017 Current: Financial swaps Other current assets $ 18 $ — $ 18 $ — $ — $ — Financial swaps Other current liabilities 553 (553 ) — 1,971 (748 ) (1) 1,223 Forward contracts Other current liabilities — — — 2 — 2 Long-term: Financial swaps Other assets 4 — 4 — — — Total $ 575 $ (553 ) $ 22 $ 1,973 $ (748 ) $ 1,225 (1) Current liability derivative amount offset includes $0.2 million of collateral receivable for the period ended December 31, 2017 .
Schedule of Derivative Instruments	The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at June 30, 2018 and 2017 (in thousands of units). June 30, Commodity Units 2018 2017 Electricity purchases MWh 323 194 Electricity sales MWh 58 38 Natural gas purchases MMBtu 12,371 10,297 Natural gas sales MMBtu 233 75 Diesel purchases Gallons 451 605

FAIR VALUE MEASUREMENTS_ Level

FAIR VALUE MEASUREMENTS: Level 3 (Tables)	3 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2018 , and December 31, 2017 (in thousands). June 30, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Money market funds IDACORP (1) $ 30,611 $ — $ — $ 30,611 $ 28,038 $ — $ — $ 28,038 Idaho Power 80,593 — — 80,593 10,260 — — 10,260 Derivatives 802 3 — 805 22 — — 22 Equity securities 27,916 — — 27,916 30,266 — — 30,266 Liabilities: Derivatives 1,195 — — 1,195 1,223 2 — 1,225
Fair Value, by Balance Sheet Grouping [Table Text Block]	The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of June 30, 2018 , and December 31, 2017 , using available market information and appropriate valuation methodologies (in thousands). June 30, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value IDACORP Assets: Notes receivable (1) $ 3,804 $ 3,804 $ 3,804 $ 3,804 Liabilities: Long-term debt (1) 1,834,055 1,946,794 1,746,123 1,915,459 Idaho Power Liabilities: Long-term debt (1) 1,834,055 1,946,794 1,746,123 1,915,459 (1) Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 12.

SEGMENT INFORMATION_ Level 3 (T

SEGMENT INFORMATION: Level 3 (Tables)	3 Months Ended
	Jun. 30, 2018
Segment Information [Abstract]
Schedule of Segment Reporting Information, by Segment	The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands). Utility Operations All Other Eliminations Consolidated Total Three months ended June 30, 2018: Revenues $ 338,699 $ 1,253 $ — $ 339,952 Net income attributable to IDACORP, Inc. 60,637 1,651 — 62,288 Total assets as of June 30, 2018 6,133,502 153,529 (80,914 ) 6,206,117 Three months ended June 30, 2017: Revenues $ 331,768 $ 1,238 $ — $ 333,006 Net income attributable to IDACORP, Inc. 48,381 1,450 — 49,831 Six months ended June 30, 2018: Revenues $ 648,160 $ 1,898 $ — $ 650,058 Net income attributable to IDACORP, Inc. 96,493 1,937 — 98,430 Six months ended June 30, 2017: Revenues $ 633,732 $ 1,818 $ — $ 635,550 Net income attributable to IDACORP, Inc. 80,863 2,070 — 82,933

CHANGES IN ACCUMULATED OTHER 35

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: Level 3 (Tables)	3 Months Ended
	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and six months ended June 30, 2018 and 2017 (in thousands). Items in parentheses indicate charges to AOCI. Defined Benefit Pension Items Three months ended Six months ended 2018 2017 2018 2017 Balance at beginning of period $ (30,243 ) $ (20,411 ) $ (30,964 ) $ (20,882 ) Amounts reclassified out of AOCI 722 470 1,443 941 Balance at end of period $ (29,521 ) $ (19,941 ) $ (29,521 ) $ (19,941 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and six months ended June 30, 2018 and 2017 (in thousands). Items in parentheses indicate increases to net income. Amount Reclassified from AOCI Details About AOCI Three months ended Six months ended 2018 2017 2018 2017 Amortization of defined benefit pension items (1) Prior service cost $ 25 $ 32 $ 49 $ 64 Net loss 947 740 1,894 1,481 Total before tax 972 772 1,943 1,545 Tax benefit (2) (250 ) (302 ) (500 ) (604 ) Net of tax 722 470 1,443 941 Total reclassification for the period $ 722 $ 470 $ 1,443 $ 941 (1) Amortization of these items is included in IDACORP's condensed consolidated income statements in other operating expenses and in Idaho Power's condensed consolidated statements of income in other expense, net. (2) The tax benefit is included in income tax expense in the condensed consolidated statements of income of both IDACORP and Idaho Power.

SUMMARY OF SIGNIFICANT ACCOUN36

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Accounting Adoption Pronouncement (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Payments for (Proceeds from) Other Investing Activities			$ (495)	$ (2,860)
Other	$ 62,480		62,480		$ 59,425
Other Income (Expense), Net	309	$ (426)	(150)	(841)
Idaho Power Company
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Payments for (Proceeds from) Other Investing Activities			(440)	(2,860)
Other	57,805		57,805		54,677
Other Income (Expense), Net	$ (391)	(1,000)	$ (1,519)	(2,297)
Changes in accounts receivable
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Payments for (Proceeds from) Other Investing Activities				2,600
Other operations and maintenance [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Income (Expense), Net		(800)		(1,500)
Other operations and maintenance [Member] | Idaho Power Company
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Income (Expense), Net		(800)		(1,500)
Other Operating Income (Expense) [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Income (Expense), Net		(2,000)		(4,100)
Operating Income (Loss) [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Income (Expense), Net		$ (2,800)		$ (5,600)
Long-term receivables [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other					4,300
Long-term receivables [Member] | Idaho Power Company
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other					$ 500

INCOME TAXES_ Level 4 (Details)

INCOME TAXES: Level 4 (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Income Tax Expense [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				21.00%		35.00%
Income tax at statutory rates (federal and state)				$ 27,909	$ 41,468
First mortgage bond redemption costs				1,261	0
Share-based compensation				(1,053)	(1,559)
Other	[1]			(15,597)	(16,785)
Income Tax Expense		$ 7,105	$ 16,940	$ 9,998	$ 23,124
Effective tax rate				9.20%	21.80%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent				6.925%		7.40%
Idaho Power Company
Income Tax Expense [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				21.00%		35.00%
Income tax at statutory rates (federal and state)				$ 27,539	$ 40,772
First mortgage bond redemption costs				1,261	0
Share-based compensation				(1,040)	(1,530)
Other	[1]			(14,742)	(15,830)
Income Tax Expense		$ 7,345	$ 17,038	$ 10,496	$ 23,412
Effective tax rate				9.80%	22.50%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent				6.925%		7.40%
[1]	"Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments.

REGULATORY MATTERS_ Level 4 (De

REGULATORY MATTERS: Level 4 (Details) - USD ($) $ in Thousands

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

May 31, 2020

May 31, 2019

May 31, 2018

May 31, 2017

Jun. 01, 2018

Apr. 30, 2018

Apr. 01, 2018

Jun. 01, 2017

Jun. 01, 2016

Oct. 31, 2014

Regulatory Matters

Revenue from contracts with customers

$ 331,298

$ 326,190

$ 620,871

$ 620,081

IDAHO | Idaho Power Company

Regulatory Matters

Pre-tax charge for relicensing costs write-down

$ 5,000

Idaho Settlement Stipulation - Investment Tax Credits and Sharing Mechanism

Regulatory Matters

Additional ADITC amortization

500

1,900

Power cost adjustment mechanism

Regulatory Matters

Amount of approved rate change

$ 10,600

Regulatory liabilities

$ 13,000

Idaho fixed cost adjustment mechanism

Regulatory Matters

Amount of approved rate change

$ (19,400)

$ 6,900

Annual fixed cost adjustment mechanism deferral

$ 15,600

$ 35,000

$ 28,100

October 2014 Idaho Settlement Stipulation | IDAHO

Regulatory Matters

Minimum authorized return on equity

9.50%

Maximum additional ADITC amortization in one year

$ 25,000

Maximum additional ADITC amortization

$ 45,000

Target authorized return on equity

10.00%

Maximum authorized return on equity

10.50%

Percentage to be shared with customers

75.00%

Percentage to be allocated to Idaho Power

25.00%

Percent to be shared with customers as a rate reduction

50.00%

Percent to be shared with customers as pension asset amortization

25.00%

May 2018 Tax Reform Settlement Stipulation | IDAHO

Regulatory Matters

Minimum authorized return on equity

9.40%

Maximum additional ADITC amortization in one year

$ 25,000

Maximum additional ADITC amortization

$ 45,000

Target authorized return on equity

10.00%

Maximum authorized return on equity

10.50%

Percentage to be shared with customers

80.00%

Percentage to be allocated to Idaho Power

20.00%

Percent to be shared with customers as a rate reduction

55.00%

Percent to be shared with customers as pension asset amortization

25.00%

Change in Idaho ROE from rate case | October 2014 Idaho Settlement Stipulation | IDAHO

Regulatory Matters

Percentage to be shared with customers

75.00%

Minimum percentage of target ROE

95.00%

Percent to be shared with customers as a rate reduction

50.00%

Percent to be shared with customers as pension asset amortization

25.00%

Maximum percentage of target ROE

105.00%

Change in Idaho ROE from rate case | May 2018 Tax Reform Settlement Stipulation | IDAHO

Regulatory Matters

Percentage to be shared with customers

80.00%

Minimum percentage of target ROE

95.00%

Percent to be shared with customers as a rate reduction

55.00%

Percent to be shared with customers as pension asset amortization

25.00%

Maximum percentage of target ROE

105.00%

Pre-2016 relicensing costs | IDAHO | Idaho Power Company

Regulatory Matters

Pre-tax charge for relicensing costs write-down

4,300

Post-2016 relicensing costs | IDAHO | Idaho Power Company

Regulatory Matters

Pre-tax charge for relicensing costs write-down

$ 700

Subsequent event | Power cost adjustment mechanism

Regulatory Matters

Amount of approved rate change

$ (22,600)

Subsequent event | May 2018 Tax Reform Settlement Stipulation | IDAHO

Regulatory Matters

Amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals

7,400

Subsequent event | Annual recurring rate (reduction) increase | May 2018 Tax Reform Settlement Stipulation | IDAHO

Regulatory Matters

Amount of approved rate change

(18,700)

Subsequent event | Annual recurring rate (reduction) increase | May 2018 Tax Reform Settlement Stipulation | OREGON

Regulatory Matters

Amount of approved rate change

(1,500)

Subsequent event | Annual recurring rate (reduction) increase | Valmy Plant | OREGON

Regulatory Matters

Amount of approved rate change

2,500

Subsequent event | One-time benefit | May 2018 Tax Reform Settlement Stipulation | IDAHO

Regulatory Matters

Amount of approved rate change

$ (2,700)

$ (7,800)

Retail revenues

Regulatory Matters

Revenue from contracts with customers

298,591

$ 295,001

$ 563,114

$ 565,233

Western EIM | IDAHO

Regulatory Matters

Revenue

$ 700

Western EIM | Deferred Western EIM O&M costs | IDAHO

Regulatory Matters

Regulatory assets

$ 1,000

REVENUES_ Electric utility op39

REVENUES: Electric utility operating revenues (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Jan. 01, 2018
Cumulative Effect of New Accounting Principle in Period of Adoption					$ 0
Revenue from contracts with customers	$ 331,298,000	$ 326,190,000	$ 620,871,000	$ 620,081,000
Alternative revenue programs and other revenues	7,401,000	5,578,000	27,289,000	13,651,000
Electric utility revenues	$ 338,699,000	$ 331,768,000	$ 648,160,000	$ 633,732,000

REVENUES_ (Details)

REVENUES: (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	May 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		$ 331,298	$ 326,190	$ 620,871	$ 620,081
Alternative revenue programs and other revenues		7,401	5,578	27,289	13,651
Contract with Customer, Asset, Credit Loss Expense		1,500	2,200	1,800	2,400
Derivative revenues
Disaggregation of Revenue [Line Items]
Alternative revenue programs and other revenues		1,602	2,097	7,585	4,933
Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		298,591	295,001	563,114	565,233
Idaho fixed cost adjustment mechanism
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	[1]	(5,799)	(3,481)	(19,704)	(8,718)
Alternative revenue programs and other revenues		5,799	3,481	19,704	8,718
Wholesale energy sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		10,214	6,003	24,283	13,967
Transmission Service Agreement
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		13,205	11,965	24,600	20,824
Energy efficiency program revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		8,802	10,515	16,399	16,843
Other revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		6,285	6,187	12,179	11,932
Residential Retail Revenue | Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	[1]	109,155	112,534	255,838	264,689
Residential Retail Revenue | Idaho fixed cost adjustment mechanism
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		5,508	3,205	19,052	8,331
Commercial Retail Revenue | Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	[1]	76,965	78,982	151,191	153,260
Commercial Retail Revenue | Idaho fixed cost adjustment mechanism
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		291	276	652	387
Industrial Retail Revenue | Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		48,868	49,766	94,660	95,224
Irrigation Retail Revenue | Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		65,065	56,068	65,471	56,993
Deferred revenue-AFUDC | Retail revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	[2]	(1,462)	$ (2,349)	(4,046)	$ (4,933)
IPUC authorized AFUDC Collection HCC Relicensing - Gross | Idaho Power Company | Hells Canyon Complex
Disaggregation of Revenue [Line Items]
Regulatory liabilities		(8,800)		(8,800)		$ (10,700)
Energy efficiency regulatory liability
Disaggregation of Revenue [Line Items]
Regulatory liabilities		(2,600)		(2,600)
Energy efficiency regulatory asset
Disaggregation of Revenue [Line Items]
Regulatory assets		$ 6,500		$ 6,500
[1]	The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.
[2]	As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually.

LONG-TERM DEBT_ (Details)

LONG-TERM DEBT: (Details) - USD ($) $ in Millions	Apr. 17, 2018	Jun. 30, 2018	Mar. 16, 2018
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount		$ 280
First Mortgage Bonds 4.20% Series K due 2048 [Member] | Idaho Power Company
Debt Instrument [Line Items]
Secured Long-term Debt, Noncurrent			$ 220
Debt Instrument, Interest Rate, Stated Percentage			4.20%
First mortgage bonds 4.50 Series due 2020 [Member] | Idaho Power Company
Debt Instrument [Line Items]
Secured Long-term Debt, Noncurrent	$ 130
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Gain (Loss) on Extinguishment of Debt	$ (4.6)

COMMON STOCK_ Level 4 (Details)

COMMON STOCK: Level 4 (Details) $ in Billions	6 Months Ended
	Jun. 30, 2018USD ($)shares
Shareholders' equity
Restricted Stock Unit Awards to Employees	75,761
Restricted stock awards to directors	12,950
IDACORP
Shareholders' equity
Stock Issued During Period, Shares, New Issues	0
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.44
Dividend Distribution Restriction Amount | $	$ 1.3
Idaho Power Company
Shareholders' equity
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.46
Dividend Distribution Restriction Amount | $	$ 1.1
Dividend Distribution Restriction Threshold	0.35
Ratio of total Capital to total capital and long-term debt	0.54
Preferred Stock, Shares Outstanding	0

EARNINGS PER SHARE_ Level 4 (De

EARNINGS PER SHARE: Level 4 (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Numerator:
Net Income Attributable to IDACORP, Inc.	$ 62,288	$ 49,831	$ 98,430	$ 82,933
Denominator:
Weighted-average common shares outstanding - basic	50,435	50,363	50,430	50,361
Effect of dilutive securities	46	44	42	41
Weighted-average common shares outstanding - diluted	50,481	50,407	50,472	50,402
Earnings attributable to IDACORP, Inc. - basic (in dollars per share)	$ 1.24	$ 0.99	$ 1.95	$ 1.65
Earnings attributable to IDACORP, Inc. - diluted (in dollars per share)	$ 1.23	$ 0.99	$ 1.95	$ 1.65

COMMITMENTS_ Level 4 (Details)

COMMITMENTS: Level 4 (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
Idaho Power Company
Guarantor Obligations
IERCo ownership interest in BCC	33.00%
IERCo guarantee of BCC reclamation obligation	$ 58.4
Long-term Purchase Commitment
Increase of Long-term Purchase Obligations, Amount	$ 51.3
Life of Contract	20 years
Bridger Coal Company
Guarantor Obligations
IERCo guarantee of BCC reclamation obligation	$ 175.2
Guarantor Obligations Total Reclamation Trust Fund	108.3
Distribution from Reclamation Trust Fund	$ 3

BENEFIT PLANS_ Level 4 (Details

BENEFIT PLANS: Level 4 (Details) - USD ($)	3 Months Ended				6 Months Ended
	Jun. 30, 2018		Jun. 30, 2017		Jun. 30, 2018		Jun. 30, 2017
Pension Plan
Defined Benefit Plan Disclosure
Service cost	$ 9,742,000		$ 8,245,000		$ 19,485,000		$ 16,871,000
Interest cost	9,683,000		9,716,000		19,365,000		19,479,000
Expected return on plan assets	(13,056,000)		(11,181,000)		(26,111,000)		(22,569,000)
Amortization of prior service cost	2,000		7,000		3,000		14,000
Amortization of net loss	3,394,000		3,212,000		6,788,000		6,595,000
Net periodic benefit cost	9,765,000		9,999,000		19,530,000		20,390,000
Regulatory deferral of net periodic benefit cost	(9,309,000)	[1]	(9,488,000)	[1]	(18,616,000)	[2]	(19,284,000)	[2]
IPUC Authorized recovered pension cost	4,289,000	[1]	4,289,000	[1]	8,577,000	[2]	8,577,000	[2]
Net periodic benefit cost recognized for financial reporting	4,745,000	[1],[3]	4,800,000	[1],[3]	9,491,000	[2],[4]	9,683,000	[2],[4]
Contribution Requirement					0
Defined Benefit Plan, Contributions by Employer					20,000,000
Senior Management Security Plan
Defined Benefit Plan Disclosure
Service cost	(79,000)		190,000		(158,000)		380,000
Interest cost	1,061,000		1,079,000		2,124,000		2,157,000
Expected return on plan assets	0		0		0		0
Amortization of prior service cost	25,000		32,000		49,000		64,000
Amortization of net loss	947,000		740,000		1,894,000		1,481,000
Net periodic benefit cost	1,954,000		2,041,000		3,909,000		4,082,000
Net periodic benefit cost recognized for financial reporting	1,954,000	[3]	2,041,000	[3]	3,909,000	[4]	4,082,000	[4]
Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Service cost	242,000		197,000		526,000		486,000
Interest cost	656,000		702,000		1,322,000		1,392,000
Expected return on plan assets	(605,000)		(584,000)		(1,234,000)		(1,154,000)
Amortization of prior service cost	12,000		17,000		24,000		24,000
Amortization of net loss	0		0		0		0
Net periodic benefit cost	305,000		332,000		638,000		748,000
Net periodic benefit cost recognized for financial reporting	305,000		332,000		638,000		748,000
Retirement Plan Total
Defined Benefit Plan Disclosure
Service cost	9,905,000		8,632,000		19,853,000		17,737,000
Interest cost	11,400,000		11,497,000		22,811,000		23,028,000
Expected return on plan assets	(13,661,000)		(11,765,000)		(27,345,000)		(23,723,000)
Amortization of prior service cost	39,000		56,000		76,000		102,000
Amortization of net loss	4,341,000		3,952,000		8,682,000		8,076,000
Net periodic benefit cost	12,024,000		12,372,000		24,077,000		25,220,000
Regulatory deferral of net periodic benefit cost	(9,309,000)	[1]	(9,488,000)	[1]	(18,616,000)	[2]	(19,284,000)	[2]
IPUC Authorized recovered pension cost	4,289,000	[1]	4,289,000	[1]	8,577,000	[2]	8,577,000	[2]
Net periodic benefit cost recognized for financial reporting	7,004,000	[1],[3]	7,173,000	[1],[3]	14,038,000	[2],[4]	14,513,000	[2],[4]
Net Periodic Benefit cost recognize in Other operations and maintenance	4,100,000		4,400,000		8,200,000		8,900,000
Net Periodic Benefit cost recognized in other expense, net	$ 2,900,000		$ 2,800,000		$ 5,800,000		$ 5,600,000
[1]	Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.
[2]	(1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.
[3]	(2) Of total net periodic benefit cost recognized for financial reporting, $4.1 million and $4.4 million, respectively, was recognized in "Other operations and maintenance" and $2.9 million and $2.8 million, respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the three months ended June 30, 2018 and 2017.
[4]	(2) Of total net periodic benefit cost recognized for financial reporting, $8.2 million and $8.9 million, respectively, was recognized in "Other operations and maintenance" and $5.8 million and $5.6 million, respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the six months ended June 30, 2018 and 2017.

Derivative Instruments Fair Val

Derivative Instruments Fair Value and Offsets Table (Details) - USD ($) $ in Thousands	Jun. 30, 2018		Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset			$ 200
Derivative Asset, Fair Value, Gross Asset	$ 1,807		575
Derivative Asset, Fair Value, Gross Liability	(1,002)		(553)
Derivative Asset, Fair Value, Amount Offset Against Collateral	805		22
Derivative Liability, Fair Value, Gross Liability	2,197		1,973
Derivative Liability, Fair Value, Gross Asset	(1,002)		(748)
Derivative Liability, Fair Value, Amount Offset Against Collateral	1,195		1,225
Financial Swaps | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,545		18
Derivative Asset, Fair Value, Gross Liability	(791)		0
Derivative Asset, Fair Value, Amount Offset Against Collateral	754		18
Derivative Liability, Fair Value, Gross Liability	791		0
Derivative Liability, Fair Value, Gross Asset	(791)		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Financial Swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	195		553
Derivative Asset, Fair Value, Gross Liability	(195)		(553)
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Gross Liability	1,051		1,971
Derivative Liability, Fair Value, Gross Asset	(195)	[1]	(748)
Derivative Liability, Fair Value, Amount Offset Against Collateral	856		1,223
Financial Swaps | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	49		4
Derivative Asset, Fair Value, Gross Liability	(1)		0
Derivative Asset, Fair Value, Amount Offset Against Collateral	48		4
Derivative Liability, Fair Value, Gross Liability	1		0
Derivative Liability, Fair Value, Gross Asset	(1)		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Financial Swaps | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15
Derivative Asset, Fair Value, Gross Liability	(15)
Derivative Asset, Fair Value, Amount Offset Against Collateral	0
Derivative Liability, Fair Value, Gross Liability	354
Derivative Liability, Fair Value, Gross Asset	(15)
Derivative Liability, Fair Value, Amount Offset Against Collateral	339
Forward contracts | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	3
Derivative Liability, Fair Value, Gross Liability	0
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 0
Forward contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Derivative Asset, Fair Value, Gross Liability			0
Derivative Asset, Fair Value, Amount Offset Against Collateral			0
Derivative Liability, Fair Value, Gross Liability			2
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Amount Offset Against Collateral			$ 2
[1]	Current liability derivative amount offset includes $0.2 million of collateral receivable for the period ended December 31, 2017.

Derivative Instruments Gains (L

Derivative Instruments Gains (Loss) on Derivatives Recognized in Income (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Financial Swaps | Operating revenues
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]		$ (305)
Derivative, Gain on Derivative	[1]	$ 27		$ 266	$ 1,173
Financial Swaps | Purchased power
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]		(287)	(189)	(735)
Derivative, Gain on Derivative	[1]	13
Financial Swaps | Fuel expense
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]	(112)	(4)	(800)
Derivative, Gain on Derivative	[1]				666
Financial Swaps | Other operations and maintenance
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]		(55)		(81)
Derivative, Gain on Derivative	[1]	31		38
Forward contracts | Operating revenues
Derivative Instruments, Gain (Loss)
Derivative, Gain on Derivative	[1]	0	0	2	0
Forward contracts | Purchased power
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]	(7)	(8)	(20)	(10)
Forward contracts | Fuel expense
Derivative Instruments, Gain (Loss)
Derivative, Gain on Derivative	[1]	$ 10	$ 3	$ 24	$ 3
[1]	Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Derivative Commodities and Disc

Derivative Commodities and Disclosures (Details) MWh in Thousands, MMBTU in Thousands, Gallon in Thousands, $ in Millions	Jun. 30, 2018USD ($)MMBTUGallonMWh	Jun. 30, 2017MMBTUGallonMWh
Derivative
Derivatives in a net liability position	$ 2.2
Collateral Already Posted, Aggregate Fair Value	0.8
Additional Collateral, Aggregate Fair Value	$ 3
Electricity (MWh) | Long
Derivative
Derivative, Nonmonetary Notional Amount | MWh	323	194
Electricity (MWh) | Short
Derivative
Derivative, Nonmonetary Notional Amount | MWh	58	38
Natural Gas (MMBTU) | Long
Derivative
Derivative, Nonmonetary Notional Amount | MMBTU	12,371	10,297
Natural Gas (MMBTU) | Short
Derivative
Derivative, Nonmonetary Notional Amount | MMBTU	233	75
Diesel Fuel (Gallons) | Long
Derivative
Derivative, Nonmonetary Notional Amount | Gallon	451	605

FAIR VALUE MEASUREMENTS_ Leve49

FAIR VALUE MEASUREMENTS: Level 4 (Details) - USD ($)		Jun. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount		$ 0	$ 0
Derivative Assets		805,000	22,000
Equity Securities, FV-NI		27,916,000	30,266,000
Money market funds	[1]	30,611,000	28,038,000
Derivative Liabilities		1,195,000	1,225,000
Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds		80,593,000	10,260,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		802,000	22,000
Equity Securities, FV-NI		27,916,000	30,266,000
Money market funds	[1]	30,611,000	28,038,000
Derivative Liabilities		1,195,000	1,223,000
Fair Value, Inputs, Level 1 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds		80,593,000	10,260,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		3,000	0
Equity Securities, FV-NI		0	0
Money market funds	[1]	0	0
Derivative Liabilities		0	2,000
Fair Value, Inputs, Level 2 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds		0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		0	0
Equity Securities, FV-NI		0	0
Money market funds	[1]	0	0
Derivative Liabilities		0	0
Fair Value, Inputs, Level 3 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds		$ 0	$ 0
[1]	Holding company only. Does not include amounts held by Idaho Power.

FAIR VALUE MEASUREMENTS_ Fair V

FAIR VALUE MEASUREMENTS: Fair Value, by Balance Sheet Grouping (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Receivable	[1]	$ 3,804	$ 3,804
Long-term debt	[1]	1,834,055	1,746,123
Carrying Amount | Idaho Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	[1]	1,834,055	1,746,123
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Receivable	[1]	3,804	3,804
Long-term debt	[1]	1,946,794	1,915,459
Estimated Fair Value | Idaho Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	[1]	$ 1,946,794	$ 1,915,459
[1]	Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 12.

SEGMENT INFORMATION_ Level 4 (D

SEGMENT INFORMATION: Level 4 (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information
Electric utility revenues	$ 338,699	$ 331,768	$ 648,160	$ 633,732
Total operating revenues	339,952	333,006	650,058	635,550
Net Income Attributable to IDACORP, Inc.	62,593	50,096	98,704	83,101
Net Income Attributable to IDACORP, Inc.	62,288	49,831	98,430	82,933
Total assets	6,206,117		6,206,117		$ 6,045,405
Idaho Power Company
Segment Reporting Information
Electric utility revenues				633,732
Net Income Attributable to IDACORP, Inc.	60,637	48,381	96,493	80,863
Total assets	$ 6,133,502		6,133,502
IERCo's ownership percentage in Bridger Coal Company	33.00%
All Other
Segment Reporting Information
Total operating revenues	$ 1,253	1,238	1,898	1,818
Net Income Attributable to IDACORP, Inc.	1,651	1,450	1,937	2,070
Total assets	153,529		153,529
Eliminations
Segment Reporting Information
Total operating revenues	0	0	0	0
Net Income Attributable to IDACORP, Inc.	0	$ 0	0	$ 0
Total assets	$ (80,914)		$ (80,914)

CHANGES IN ACCUMULATED OTHER 52

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: Level 4 (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Reclassification out of Accumulated Other Comprehensive Income
Amortization of prior service cost	[1]	$ 25	$ 32	$ 49	$ 64
Amortization of net loss	[1]	947	740	1,894	1,481
Total reclassification, before tax - pension and postretirement benefits		972	772	1,943	1,545
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	[2]	(250)	(302)	(500)	(604)
Total reclassification, net of tax - pension and postretirement benfits		722	470	1,443	941
Reclassifications		722	470	1,443	941
Increase (Decrease) in Accumulated Other Comprehensive Income [Roll Forward]
AOCI - Beginning Balance				(30,964)	(20,882)
Reclassifications		722	470	1,443	941
AOCI - Ending Balance		(29,521)	(19,941)	(29,521)	(19,941)
Accumulated Defined Benefit Pension Items
Reclassification out of Accumulated Other Comprehensive Income
Reclassifications		722	470	1,443	941
Increase (Decrease) in Accumulated Other Comprehensive Income [Roll Forward]
AOCI - Beginning Balance		(30,243)	(20,411)	(30,964)	(20,882)
Reclassifications		722	470	1,443	941
AOCI - Ending Balance		$ (29,521)	$ (19,941)	$ (29,521)	$ (19,941)
[1]	Amortization of these items is included in IDACORP's condensed consolidated income statements in other operating expenses and in Idaho Power's condensed consolidated statements of income in other expense, net.
[2]	The tax benefit is included in income tax expense in the condensed consolidated statements of income of both IDACORP and Idaho Power.