UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



X☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

	For the fiscal year ended December 31, ~~2018~~ 2019



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ................... to .................................................................




	Exact name of registrants as specified in			IRS Employer
Commission File Number	their charters, address of principal executive			~~IRS Employer~~
~~File Number~~	offices, zip code and telephone number	Identification Number
1-14465	IDACORP, Inc.			82-0505802
1-3198	Idaho Power Company			82-0130980
	1221 W. Idaho Street
	Boise,	ID	83702-5627
	(208)	388-2200

State of incorporation:			Idaho

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934



Title of each class	Trading Symbol(s)	Name of each exchange on
~~SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:~~		which registered
~~IDACORP, Inc.:~~ Common Stock, without par value	IDA	New York
		Stock Exchange

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934


~~SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:~~
Idaho Power Company:	Preferred Stock

Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.



IDACORP, Inc.	Yes	~~(X)~~☒	No	~~( )~~☐	Idaho Power Company	Yes	~~( )~~☐	No	~~(X)~~☒

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



IDACORP, Inc.	Yes	~~( )~~☐	No	~~(X)~~☒	Idaho Power Company	Yes	~~( )~~☐	No	~~(X)~~☒

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X) No ( )

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Indicate by check mark whether the registrants have submitted electronically Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).



IDACORP, Inc.	Yes	~~(X)~~☒	No	~~( )~~☐	Idaho Power Company	Yes	~~(X)~~☒	No	~~( )~~☐

~~Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter)~~

is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X)

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

IDACORP, Inc.:

Large accelerated filer X Accelerated filer __ Non-accelerated filer __

Smaller reporting company __☐

Emerging growth company __☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange

Act. __

Idaho Power Company:

Large accelerated filer __ Accelerated filer __ Non-accelerated filer X

Smaller reporting company __☐

Emerging growth company __☐

Act. __

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).



IDACORP, Inc.	Yes	~~( )~~☐	No	~~(X)~~☒	Idaho Power Company	Yes	~~( )~~☐	No	~~(X)~~☒

Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, ~~2018)~~2019):

IDACORP, Inc.: $ 4,611,144,658
Idaho Power Company: None



IDACORP, Inc.:	$	5,017,481,695	Idaho Power Company:	None



Number of shares of common stock outstanding as of February ~~15, 2019:~~14, 2020:
IDACORP, Inc.:	~~50,383,366~~50,409,901
Idaho Power Company:	39,150,812	, all held by IDACORP, Inc.



Documents Incorporated by Reference:

Part III, Items 10 - 14	Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders.

This combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representation as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.

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TABLE OF CONTENTS

		Page

Commonly Used Terms		4
Cautionary Note Regarding Forward-Looking Statements		5

Part I

Item 1	Business	7
	Information about our Executive Officers ~~of the Registrants~~	18
Item 1A	Risk Factors	1920
Item 1B	Unresolved Staff Comments	3032
Item 2	Properties	3032
Item 3	Legal Proceedings	3234
Item 4	Mine Safety Disclosures	3234

Part II

Item 5	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	3335
Item 6	Selected Financial Data	3437
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	3538
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	7473
Item 8	Financial Statements and Supplementary Data	7675
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~133~~132
Item 9A	Controls and Procedures	~~133~~132
Item 9B	Other Information	~~137~~136

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	~~137~~136
Item 11	Executive Compensation*	~~137~~136
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	~~137~~136
Item 13	Certain Relationships and Related Transactions, and Director Independence*	~~138~~137
Item 14	Principal Accountant Fees and Services*	~~138~~137

Part IV

Item 15	Exhibits and Financial Statement Schedules	~~139~~138
Item 16	Form 10-K Summary	~~150~~148

Signatures		~~150~~148

* Except as indicated in Items 10, 12, and 14, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s definitive proxy statement for the ~~2019~~2020 annual meeting of shareholders.

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COMMONLY USED TERMS

The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:

2019 Annual Report	-	IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2019	kWh	-	Kilowatt-hour
ADITC	-	Accumulated Deferred Investment Tax Credits	LTICP	-	IDACORP 2000 Long-Term Incentive and Compensation Plan
AFUDC	-	Allowance for Funds Used During Construction	MATS	-	Mercury and Air Toxics Standards
AOCI	-	Accumulated Other Comprehensive Income	MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
APCU	-	Annual Power Cost Update	MMBtu	-	Million British Thermal Units
ASU	-	Accounting Standards Update	MW	-	Megawatt
BCC	-	Bridger Coal Company, a joint venture of IERCo	MWh	-	Megawatt-hour
BLM	-	U.S. Bureau of Land Management	NAAQS	-	National Ambient Air Quality Standards
CAA	-	Clean Air Act	NEPA	-	National Environmental Policy Act
CO₂	-	Carbon Dioxide	NMFS	-	National Marine Fisheries Service
CWA	-	Clean Water Act	NOAA Fisheries	-	National Oceanic and Atmospheric Administration's National Marine Fisheries Service
EIS	-	Environmental Impact Statement	NO₂	-	Nitrogen Dioxide
EPA	-	U.S. Environmental Protection Agency	NO_x	-	Nitrogen Oxide
ESA	-	Endangered Species Act	O&M	-	Operations and Maintenance
FASB	-	Financial Accounting Standards Board	OATT	-	Open Access Transmission Tariff
FCA	-	Idaho Fixed Cost Adjustment	OPUC	-	Public Utility Commission of Oregon
FERC	-	Federal Energy Regulatory Commission	PCA	-	Idaho-jurisdiction Power Cost Adjustment
FPA	-	Federal Power Act	PCAM	-	Oregon Power Cost Adjustment Mechanism
GAAP	-	Generally Accepted Accounting Principles	PEIS	-	Programmatic Environmental Impact Statement
GHG	-	Greenhouse Gas	PURPA	-	Public Utility Regulatory Policies Act of 1978
HCC	-	Hells Canyon Complex	REC	-	Renewable Energy Certificate
IDACORP	-	IDACORP, Inc., an Idaho Corporation	RH BART	-	Regional haze - best available retrofit technology
Idaho Power	-	Idaho Power Company, an Idaho Corporation	RPS	-	Renewable Portfolio Standard
Idaho ROE	-	Idaho-jurisdiction return on year-end equity	SEC	-	U.S. Securities and Exchange Commission
Ida-West	-	Ida-West Energy Company, a subsidiary of IDACORP, Inc.	SCR	-	Selective catalytic reduction equipment
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company	SMSP	-	Security Plan for Senior Management Employees
IFS	-	IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.	SO₂	-	Sulfur Dioxide
IPUC	-	Idaho Public Utilities Commission	USFWS	-	U.S. Fish and Wildlife Service
IRP	-	Integrated Resource Plan	~~Valmy Plant~~Western EIM	-	~~North Valmy coal-fired power plant~~Energy imbalance market implemented in the western United States
IRS	-	U.S. Internal Revenue Service	~~Western EIM~~WDEQ	-	~~Energy imbalance market implemented in the western United States~~ Wyoming Department of Environmental Quality
kWJim Bridger plant	-	~~Kilowatt~~Jim Bridger generating plant	WPSC	-	Wyoming Public Service Commission
~~kWh~~kW	-	~~Kilowatt-hour~~Kilowatt	~~WDEQ~~	-	~~Wyoming Department of Environmental Quality~~

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power) may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, future events, or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "continues," "could," "estimates," "expects," "guidance," "intends," "potential," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, as well as in subsequent reports filed by IDACORP and Idaho Power with the U.S. Securities and Exchange Commission, and the following important factors:

the effect of decisions by the Idaho and Oregon public utilities commissions and the Federal Energy Regulatory Commission that impact Idaho Power's ability to recover costs and earn a return on investment;

changes to or the ~~expense and risks associated with capital expenditures for utility infrastructure, and the timing and availability~~elimination of Idaho Power's cost recovery ~~for such expenditures through customer rates, including the potential for the write-down or write-off of expenditures if not deemed prudent by regulators;~~mechanisms;

changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, or the addition of new customers, and their associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery through customer rates in the event of those changes;

the impacts of economic conditions, including inflation, interest rates, regulatory authorized returns on equity, supply costs, population growth or decline in Idaho Power's service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers, and the collection of receivables;

~~unseasonable~~abnormal or severe weather conditions, including conditions and events associated with climate change, wildfires, drought, and other natural phenomena and natural disasters, ~~including conditions and events associated with climate change,~~ which affect customer ~~demand, hydroelectric~~sales, hydropower generation levels, repair costs, service interruptions, liability for damage caused by utility property, and the availability and cost of fuel for generation plants or purchased power to serve customers;

advancement of self-generation, energy storage, and energy efficiency, alternative energy sources, and other technologies that may affect Idaho Power's sale or delivery of electric power or introduce operational or cyber-security vulnerability to the power grid;

acts or threats of terrorist incidents, other malicious acts, acts of war, cyber-attacks, the companies' failure to secure data or to comply with privacy laws or regulations, security breaches, or the disruption or damage to the companies' business, operations, or reputation resulting from such events and related litigation or penalties;

the expense and risks associated with capital expenditures for, and the permitting and construction of, utility infrastructure that Idaho Power may be unable or unwilling to complete or may not be deemed prudent by regulators;

unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new ~~cyber security risks;~~technology solutions;

variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydropower facilities;

the ability to acquire fuel, power, and transmission capacity under reasonable terms, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, climate change, or a credit downgrade;

disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission systems may constrain resources or cause Idaho Power to incur repair costs and purchase replacement power at increased costs;

accidents, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power assets, which can cause unplanned outages, reduce generating output, damage company assets, operations, or reputation, subject Idaho Power to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, and regulatory fines and penalties for which Idaho Power may have inadequate insurance coverage;

the increased purchased power costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;

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failure to comply with state and federal laws, regulations, and orders, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;

changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;

adoption of, changes in, and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and threatened and endangered species, and the ability to recover associated increased costs through rates;

~~variable hydrological conditions~~the inability to obtain or cost of obtaining and ~~over-appropriation of surface~~complying with required governmental permits and ~~groundwater in the Snake River Basin,~~approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydropower facilities;

failure to comply with mandatory reliability and security requirements, which may ~~impact~~ result in penalties, reputational harm, and operational changes;

the ~~amount~~cost and outcome of ~~power generated by Idaho Power's hydroelectric facilities;~~

litigation, dispute resolution, and regulatory proceedings, and the ability to ~~acquire fuel, power, and transmission capacity under reasonable terms, particularly in~~recover those costs or the ~~event~~costs of ~~unanticipated power demands, lack of physical availability, transportation constraints,~~resulting operational changes through insurance or ~~a credit downgrade;~~

~~accidents, fires (either affecting~~rates, or caused by Idaho Power facilities or infrastructure), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power assets, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, and regulatory fines and penalties for which the companies may have inadequate insurance coverage;from third parties;

the ~~increased purchased power~~impacts of economic conditions, including inflation, interest rates, supply costs, ~~and operational challenges associated with purchasing and integrating intermittent renewable energy sources into~~population growth or decline in Idaho Power's ~~resource portfolio;~~

~~Table~~service area, changes in customer demand for electricity, revenue from sales of ~~Contents~~

~~disruptions or outages~~excess power, credit quality of ~~Idaho Power's generation or transmission systems or~~counterparties and suppliers, and the collection of ~~any interconnected transmission systems may constrain resources or cause Idaho Power to incur repair costs and purchase replacement power at increased costs;~~receivables;

the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;

reductions in credit ratings, which could adversely impact access to debt and equity markets, increase borrowing costs, and require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements;

changes in the method for determining LIBOR and the potential replacement of LIBOR and the impact on interest rates for IDACORP's and Idaho Power's credit facilities;

the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended;

changes in actuarial assumptions, changes in interest rates, and the return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies' cash flows;

the assumptions underlying the coal mine reclamation obligations at Bridger Coal Company and related funding requirements;

the ability to continue to pay dividends based on financial performance and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations;

Idaho Power's concentration in one industry and one region and the lack of diversification, regional economic condition and regional legislation and regulation;

employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce and retirements, the cost and ability to attract and retain skilled workers and third-party vendors, and the ability to adjust the labor cost structure when necessary;

the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;

the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of resulting operational changes through insurance or rates, or from third parties;

the companies' failure to secure data or to comply with privacy laws or regulations, security breaches, or the disruption or damage to the companies' business, operations, or reputation resulting from cyber-attacks and related litigation or penalties, terrorist incidents or the threat of terrorist incidents, or other malicious acts, and acts of war;

~~unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new technology solutions;~~ and

adoption of or changes in accounting policies and principles, changes in accounting estimates, and new U.S. Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

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PART I

ITEM 1. BUSINESS

OVERVIEW

Background

IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho. Its principal operating subsidiary is Idaho Power Company (Idaho Power). IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions with access to books and records and imposes record retention and reporting requirements on IDACORP.

Idaho Power was incorporated under the laws of the state of Idaho in 1989 as the successor to a Maine corporation that was organized in 1915 and began operations in 1916. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the state regulatory commissions of Idaho and Oregon and by the 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. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations. As of December 31, ~~2018,~~2019, IDACORP had ~~1,981~~1,985 full-time employees, ~~1,972~~1,976 of whom were employed by Idaho Power, and 98 part-time employees, 76 of whom were employed by Idaho Power.

IDACORP’s other notable 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~~hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.

Available Information

IDACORP and Idaho Power make available free of charge on their websites their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC). IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com. The contents of these websites are not part of ~~this~~IDACORP's and Idaho Power's Annual Report on Form ~~10-K.~~10-K for the year ended December 31, 2019 (2019 Annual Report).

UTILITY OPERATIONS

Background

Idaho Power provided electric utility service to ~~more than~~ ~~558,000~~approximately 572,000 retail customers in southern Idaho and eastern Oregon as of December 31, ~~2018~~2019. Approximately ~~465,000~~477,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, health care, government, and ~~winter recreation.~~education. Idaho Power also provides irrigation customers with electric utility service to operate irrigation pumps during the agricultural growing season. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 72 cities in Idaho and 7 cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and 3 counties in Oregon. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of ~~1.2~~1.3 million.

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Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Wyoming Public Service Commission (WPSC) as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, ~~hydroelectric~~hydropower project relicensing, and system reliability, among other items.

Regulatory Accounting

Idaho Power ~~is subject to~~meets the requirements under accounting principles generally accepted in the United States of America (GAAP), to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation, with the impacts of rate regulation reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. These principles sometimes result 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 and recorded on the income statement when recovered or returned in rates or when otherwise directed to begin amortization by a regulator. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. Idaho Power records regulatory assets or liabilities if it expects the amounts will be reflected in future prices, based on regulatory orders or other available evidence.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective

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income tax rate is impacted as these differences arise and reverse. ~~Regulated enterprises are required to recognize those~~Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that the amounts will be recovered from or returned to customers in future rates.

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Business Strategy

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. IDACORP's board of directors regularly reviews IDACORP's long-term strategy, which as of the date of this report is focused on the following areas and initiatives:



~~Focus Areas~~Cornerstones		Initiatives
Grow ~~to Enhance~~ Financial Strength		- ~~Execute on Business Development Initiatives~~ ~~- Find~~Pursue New Investment and Revenue Opportunities - Promote and Engage in Beneficial Electrification - Maintain Shareholder Confidence - Continue Focus on Productive Regulatory Outcomes
Improve the Core Business		~~- Implement/Utilize Value-Added Analytics and Machine Learning~~ ~~- Upgrade Infrastructure for Growth, Technology Changes, Renewable Energy Integration, and Flexibility~~ - Evaluate and Control Expenditures and Continue Efficient Operations - ~~Use~~Evaluate and Deploy Transformative Technology ~~to Enhance the Grid, System Reliability, and Safety~~Solutions - ~~Implement Rate Structures that are Fair and Reasonable to All Customers~~Continue Progress on Key Transmission Projects - ~~Leverage Technology and Turn Disruptive Threats into Opportunities~~Continue Progress on Hydropower Relicensing Projects - Continue Development of Regional Markets
Enhance Idaho Power's Brand		- Enhance Idaho Power's Customers' Experience and Interactions - ~~Continue~~Communicate Progress Toward Environmental ~~Stewardship~~ and ~~Emission Reductions~~Community Goals - ~~Continue Constructive Regulatory Relationships and a Regulatory Compliance Mindset~~ ~~- Communicate~~Share Idaho Power's Story
~~Focus on Safety & Employee Engagement~~Keep Employees Safe and Engaged		- Continue Idaho Power's Strong Focus on Safety ~~and Reducing Injuries~~ - ~~Execute~~Facilitate Progress on Employee Engagement - Evolve Workforce Development Strategy and ~~Leadership Development Initiatives~~Programs

In executing the focus areas above, IDACORP seeks to balance the interests of shareholders, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working ~~to continue~~for strong, sustainable financial results and strong credit ratings by continuing to provide safe, fair-priced, reliable service to its customers from a diversified source of generation ~~resources, with a continued commitment to strong, sustainable financial results and strong credit ratings.~~resources.

Rates and Revenues

Idaho Power generates revenue primarily through the sale of electricity to retail and wholesale customers and the provision of transmission service. The prices that the IPUC, the OPUC, and the FERC authorize Idaho Power to charge for electric power and services are critical factors in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

Retail Rates: Idaho Power's rates for retail electric services are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses including depreciation on capital investments, an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators. Idaho Power regularly evaluates the need to request changes to its retail electricity price structure to cover its operating costs and to earn a fair return on its investments. Idaho Power uses general rate cases, power cost adjustment mechanisms in Idaho and Oregon, a fixed cost adjustment (FCA) mechanism in Idaho, balancing accounts and tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order. Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties. The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment. The ability to

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request rate changes does not, however, ensure that Idaho Power will recover all of its costs or earn a specified rate of return, or that its costs will be recovered in advance of or at the same time as the costs are incurred.

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In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of amounts ~~recorded~~deferred or accrued under specific authorization from the IPUC or ~~OPUC but deferred for recovery or accrued for refund.~~OPUC. Deferred amounts are generally collected from and accrued amounts are generally refunded to retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. ~~Idaho Power collects most of its energy efficiency program costs through energy efficiency riders on customer bills.~~ The Idaho and Oregon power cost adjustment mechanisms are intended to address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers by allowing partial recovery or refund of the difference between net power supply costs included in base rates and actual net power supply costs incurred by Idaho Power. The FCA mechanism, applicable to Idaho 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~~over-collection to customers or to collect ~~undercollection~~under-collection 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~~may be capped at 3 percent of base revenue annually at the discretion of the IPUC, with any excess deferred for collection in a subsequent year. Idaho Power collects most of its energy efficiency program costs through energy efficiency riders on customer bills.

Wholesale Markets: Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 ~~hydroelectric~~hydropower generation facilities are operated to optimize the water that is available by choosing when to run ~~hydroelectric~~hydropower generation units and when to store water in reservoirs. Idaho Power at times operates these and its other generation facilities to take advantage of market opportunities. These decisions affect the timing and volumes of market purchases and market sales. Even in below-normal water years, there are opportunities to vary water usage to capture wholesale marketplace economic benefits, maximize generation unit efficiency and meet peak loads. Compliance factors such as allowable river stage elevation changes and flood control requirements also influence these generation dispatch decisions. Idaho Power's wholesale energy sales depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as market power prices at the time when those resources are available. A reduction in either factor leads to lower wholesale energy sales.

Idaho Power’s OATT rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1. The FERC oversees mandatory transmission and network reliability standards, as well as power and transmission markets, including protection against market manipulation. These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, which have responsibility for compliance and enforcement of transmission and reliability standards.

Retail Energy Sales:Weather, seasonal customer demand, energy efficiency, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned, and associated expenses are not incurred, evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak during the winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and mild temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could continue to alter demand for Idaho Power's electric energy. 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 operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.”

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The table that follows presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type.


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
Retail revenues (thousands of dollars):
Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA⁽¹⁾)	$	530,527		$	552,333		$	514,954
Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA⁽¹⁾)	310,299			319,195			302,650
Residential (includes $35,587, $34,625 and $17,320, respectively, related to the FCA⁽¹⁾)										$	526,966		$	530,527		$	552,333
Commercial(includes $1,336, $1,299, and $876, respectively, related to the FCA⁽¹⁾)										295,203			310,299			319,195
Industrial	190,130			195,124			182,590			181,372			190,130			195,124
Irrigation	158,001			150,030			156,505			135,850			158,001			150,030
Provision for sharing	(5,025		)	—			—			—			(5,025		)	—
Deferred revenue related to HCC relicensing AFUDC⁽²⁾	(8,780		)	(10,706		)	(10,706		)	(8,780		)	(8,780		)	(10,706		)
Total retail revenues	1,175,152			1,205,976			1,145,993			1,130,611			1,175,152			1,205,976
Wholesale energy sales	52,845			24,790			11,900			71,198			52,845			24,790
Transmission wheeling revenues	59,094			43,970			32,496
Transmission wheeling-related revenues										53,828			59,094			43,970
Energy efficiency program revenues	35,703			39,241			33,754			40,128			35,703			39,241
Other revenues	43,788			30,916			35,210			47,175			43,788			30,916
Total electric utility operating revenues	$	1,366,582		$	1,344,893		$	1,259,353		$	1,342,940		$	1,366,582		$	1,344,893
Energy sales (thousands of Megawatt-hour (MWh)):
Residential	5,135			5,355			5,004			5,273			5,135			5,355
Commercial	4,105			4,099			3,999			4,092			4,105			4,099
Industrial	3,371			3,346			3,243			3,412			3,371			3,346
Irrigation	1,976			1,771			1,950			1,760			1,976			1,771
Total retail energy sales	14,587			14,571			14,196			14,537			14,587			14,571
Wholesale energy sales	2,246			1,934			742			2,171			2,246			1,934
Bundled energy sales	617			202			444			680			617			202
Total energy	17,450			16,707			15,382			17,388			17,450			16,707


(1)	The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers as disclosed in Note 4 – “Revenues” to the consolidated financial statements included in this report.

(2)

~~As part of its January 30, 2009, general rate case order, the~~The IPUC ~~is allowing~~allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the Hells Canyon Complex (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” to the consolidated financial statements included in this report, Idaho Power was collecting $10.7 million annually.

Competition: Idaho Power's electric utility business has historically been recognized as a natural monopoly. Idaho Power competes with fuel distribution companies, including natural gas providers, in serving the energy needs of customers for space heating, water heating, and appliances.

Idaho Power also participates in the wholesale energy markets and in the electric transmission markets. Generally, these wholesale markets are regulated by the FERC, which requires electric utilities to transmit power to or for wholesale purchasers and sellers and make available, on a non-discriminatory basis, transmission capacity for the purpose of providing these services.

In return for agreeing to provide service to all customers within a defined service area, electric utilities are typically provided with an exclusive right to provide service in that service area. However, certain prescribed areas within Idaho Power's service area, such as municipalities or Native American Tribal reservations, may elect not to take service from Idaho Power and instead operate as a municipal electric utility or otherwise as a separate entity. In such cases, the entity would be required to purchase or otherwise obtain rights (such as by contract) to Idaho Power's distribution infrastructure within the municipal or other designated area. Idaho Power would have no responsibility for providing electric service to the municipal or separate entity, absent Idaho Power's voluntary execution of an agreement to provide that service.

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Power Supply

Overview: Idaho Power primarily relies on company-owned ~~hydroelectric,~~hydropower, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Market purchases and sales are used to supplement Idaho Power's generation and balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”

Weather, load demand, supply constraints, economic conditions, and availability of generation resources impact power supply costs. Idaho Power’s annual ~~hydroelectric~~hydropower generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable ~~hydroelectric~~hydropower generation conditions increase production at Idaho Power’s ~~hydroelectric~~hydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Economic conditions and governmental regulations can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the financial impacts to Idaho Power of volatile fuel and power costs.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. Idaho Power reached its highest all-time system peak demand of 3,422 megawatts (MW) on July 7, 2017. Idaho Power's highest all-time winter peak demand of 2,527 MW was last achieved on January 6, 2017. During these and other similarly heavy load periods, Idaho Power’s system is fully committed to serve load and meet required operating reserves. The table that follows shows Idaho Power’s total power supply for the last three years.


	Power Supply			Percent of Total Generation						Power Supply			Percent of Total Generation
	2018	2017	2016	2018		2017		2016		2019	2018	2017	2019		2018		2017
	(thousands of MWh)									(thousands of MWh)
Hydroelectric plants	8,682	8,900	6,408	65	%	65	%	53	%
Hydropower plants										8,294	8,682	8,900	62	%	65	%	65	%
Coal-fired plants	3,274	3,284	4,045	24	%	24	%	33	%	3,012	3,274	3,284	22	%	24	%	24	%
Natural gas-fired plants	1,408	1,504	1,722	11	%	11	%	14	%	2,114	1,408	1,504	16	%	11	%	11	%
Total system generation	13,364	13,688	12,175	100	%	100	%	100	%	13,420	13,364	13,688	100	%	100	%	100	%

Purchased power - cogeneration and small power production	3,045	2,800	2,314							2,983	3,045	2,800
Purchased power - other	2,386	1,442	2,023							2,217	2,386	1,442
Total purchased power	5,431	4,242	4,337							5,200	5,431	4,242
Total power supply	18,795	17,930	16,512							18,620	18,795	17,930

~~Hydroelectric~~Hydropower Generation: Idaho Power operates 17 ~~hydroelectric~~hydropower projects located on the Snake River and its tributaries. Together, these ~~hydroelectric~~hydropower facilities provide a total nameplate capacity of ~~1,775~~1,796 MW and annual generation of approximately 8.7 million MWh under median water conditions. The amount of water available for ~~hydroelectric power~~hydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s ~~hydroelectric~~hydropower facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summer time irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s ~~hydroelectric~~hydropower projects on the Snake River.

In 2019 and 2018, reservoir storage carryover from the previous year coupled with near-normal winter snowpack resulted in 8.3 million MWh and 8.7 million MWh of ~~hydroelectric generation.~~hydropower generation, respectively. In 2017, above normal winter and spring precipitation resulted in 8.9 million MWh of ~~hydroelectric~~hydropower generation. In 2016, low upstream reservoir carryover (primarily in the upper Snake River basin) resulted in reduced downstream flow releases. Additionally, although snowpack accumulation was near-normal on April 1, 2016, the snowpack melted earlier than usual. The combined effect was lower than median hydro production of 6.4 million MWh in 2016. During low water years, when stream flows into Idaho Power’s ~~hydroelectric~~hydropower projects are reduced, Idaho Power’s ~~hydroelectric~~hydropower generation is reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. For ~~2019,~~2020, Idaho Power estimates annual generation from its ~~hydroelectric~~hydropower facilities towill be between 6.5 million MWh and 8.5 million MWh.

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Idaho Power obtains licenses for its ~~hydroelectric~~hydropower projects from the FERC, similar to other utilities that operate nonfederal ~~hydroelectric~~hydropower projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental agencies. The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the HCC, its largest ~~hydroelectric~~ hydropower

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generation source. Idaho Power also has three Oregon licenses under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities. For further information on relicensing activities, see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of ~~Hydroelectric~~Hydropower Projects.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its ~~hydroelectric~~hydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed ~~hydroelectric~~hydropower projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include, among other items, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, and possible takeover of a project after expiration of its license upon payment of net investment and severance damages.

Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants:

Jim Bridger, located in Wyoming, in which Idaho Power has a one-third interest;

North Valmy, located in Nevada, in which Idaho Power has a 50 percent interest; and

Boardman, located in Oregon, in which Idaho Power has a 10 percent interest.

BCC supplies coal to the Jim Bridger power plant. IERCo, a wholly-owned subsidiary of Idaho Power, owns a one-third interest in BCC and PacifiCorp owns a two-third interest in BCC and is the operator of the Bridger Coal Mine. The mine operates under a long-term sales agreement that provides for delivery of coal through 2024 from surface and underground sources. Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at least the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2021 from the Black Butte mine located near the Jim Bridger plant. This contract supplements the BCC deliveries and provides another coal supply to fuel the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

NV Energy is the operator of the North Valmy power ~~plant (Valmy Plant).~~plant. Idaho Power expects to meet ~~2019~~2020 fuel requirements through existing inventory and coal contracts and expects to be able to meet future coal requirements through new or existing coal supply contracts. ~~In 2017 and 2018,~~ Idaho Power has an established a process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the North Valmy ~~Plant units~~plant. Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019, as planned, and plans to end its participation in unit 2 ~~in 2019 and 2025, respectively. In 2018, the Valmy Plant provided 5 percent of Idaho Power's total generation, compared with 2 percent of Idaho Power's total generation in both 2017 and 2016.~~by December 31, 2025.

Portland General Electric Company is the operator of the Boardman power plant. Idaho Power believes that it has sufficient inventory and coal contracts to supply the Boardman plant with fuel through 2019. The Boardman plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Idaho Power expects to meet future coal needs through similar contracts. In December 2010,2020. As approved by the Oregon Environmental Quality Commission, ~~approved a plan~~Idaho Power plans to cease coal-fired operations at the Boardman power plant no later than December 31, 2020. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the Boardman power plant.

Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined cycle power plant and the Danskin and Bennett Mountain natural gas-fired simple cycle combustion turbine power plants. All three plants are located in Idaho.

Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is transported through the Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. These transportation agreements vary in contract length but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. This firm storage contract expires in 2043. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.

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As of December 31, ~~2018,~~2019, Idaho Power had approximately ~~6.4~~12.6 million MMBtu of natural gas ~~was~~ financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through ~~January 2020.~~July 2021. Idaho Power plans to manage the procurement of additional natural gas for the peaking units on the daily spot market or from storage inventory as necessary to meet system requirements and fueling strategies.

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Purchased Power: As described below, Idaho Power purchases power in the wholesale market as well as ~~power~~ pursuant to long-term power purchase contracts and exchange agreements.

Wholesale Market Transactions: To supplement its self-generated power and long-term purchase arrangements, Idaho Power purchases power in the wholesale market based on economics, operating reserve margins, risk management policy requirements, and unit availability. Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets. During ~~2018~~2019 and ~~2017,~~2018, Idaho Power purchased ~~1.4~~1.6 million MWh and ~~0.9~~1.8 million MWh of power through wholesale market purchases at an average cost of ~~$31.55~~$21.95 per MWh and ~~$26.32~~$28.82 per MWh, respectively. During ~~2018~~both 2019 and ~~2017,~~2018, Idaho Power sold 2.2 ~~million MWh and 1.9~~ million MWh of power in wholesale market sales, with an average price of $32.80 per MWh and $23.53 per MWh, ~~and $12.82 per MWh,~~ respectively.

Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has the following notable long-term power purchase contracts and energy exchange agreements:

Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from the Elkhorn Valley wind project located in eastern Oregon. The contract term ends in 2027.

USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs Unit #1 geothermal power plant located near Vale, Oregon. The contract term ends in 2037.

Clatskanie People's Utility - for up to 18 MW of generation from the Arrowrock ~~hydroelectric~~hydropower project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The contract term ends in 2020. Idaho Power has the right to renew the agreement for an additional five-year term.

Raft River Energy I, LLC - for up to 13 MW (estimated average annual output) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term ends in 2033.

Jackpot Holdings LLC - a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility, with an expected in-service date in 2022. The agreement was approved by the IPUC in December 2019 and is, as of the date of this report, pending approval by the OPUC.

PURPA Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA qualifying facilities as mandated by federal law. As of December 31, ~~2018,~~2019, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of ~~1,119~~1,136 MW of nameplate generation capacity, with an additional 2911 MW nameplate capacity of projects projected to be on-line ~~in 2019.~~by 2022. The energy sales agreements for these qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA qualifying facilities during the last three years is included in the following table:


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018		2017
PURPA contracts expense (in thousands)	$	189,722	$	169,788	$	153,665	$	187,344	$	189,722	$	169,788
MWh purchased under PURPA contracts (in thousands)	3,045		2,800		2,314		2,983		3,045		2,800
Average cost per MWh from PURPA contracts	$	62.31	$	60.64	$	66.41	$	62.80	$	62.31	$	60.64

Pursuant to the requirements of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power’s purchase of power from qualifying facilities that meet the requirements of PURPA. A key component of the PURPA contracts is the energy price contained within the agreements. PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The IPUC and OPUC have established specific rules and regulations to calculate the avoided cost that Idaho Power is required to include in PURPA energy sales agreements under each state's jurisdiction. For PURPA energy sales agreements:

Idaho Power is required to purchase all of the output delivered from the contracted qualifying facilities, ~~located inside its service area,~~ subject to some exceptions such as adverse impacts on system reliability.

Idaho Power is required to purchase the output of projects located outside its service area if it has the ability to receive power at the qualifying facility’s requested point of delivery on Idaho Power's system.

The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho-jurisdiction power cost adjustment (PCA) mechanism, and the OPUC jurisdictional portion is recovered through base rates and an Oregon power cost ~~recovery~~adjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.

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OPUC jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years.

The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 kilowatts (kW) and all other types of projects that are smaller than 10 average MWs. For PURPA qualifying

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facilities that exceed these size limitations, Idaho Power is required to negotiate an applicable price ~~(premised~~using an avoided cost methodology based on ~~avoided costs) based upon~~ IPUC regulations.

The IPUC issued an order in August 2015 that revised the standard PURPA power purchase contract term for new contracts to a 2-year term from the previously required 20-year term for qualifying facilities that exceed the size limitations for published avoided costs.

The OPUC requires that Idaho Power pay the published avoided costs for solar PURPA qualifying facilities with a nameplate rating of 3 MW or less and all other types of projects with a nameplate rating of 10 MW or less. Idaho Power is required to negotiate an applicable price ~~(premised~~using an avoided cost methodology based on ~~avoided costs) for all other qualifying facilities based upon~~ OPUC regulations.

Participation in Western Energy Imbalance Market: In ~~2014, the California Independent System Operator and PacifiCorp implemented~~April 2018, Idaho Power began participating in an energy imbalance market in the western United States (Western EIM) under which the participating parties enabled their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. Idaho Power commenced participation in the Western EIM in April 2018. For information on regulatory proceedings related to costs associated with joining the Western EIM, see Part II, Item 7 – MD&A - "Regulatory Matters - Western Energy Imbalance Market Costs."

Transmission Services

Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located hundreds of miles away from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy. These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection, the transmission grid covering much of western North America. Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the Western Electricity Coordinating Council, the Northwest PowerPool, the Northern Tier Transmission Group, and the North American Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the Western Interconnection.

Transmission to serve Idaho Power's retail customers is subject to the jurisdiction of the IPUC and OPUC for retail rate making purposes. Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approved OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system. As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function.

Idaho Power is jointly working on the permitting of two significant transmission projects. The Boardman-to-Hemingway ~~line~~project is a proposed 300-mile, ~~500-kV~~high-voltage transmission ~~project~~line between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West ~~line~~project is a proposed 1,000-mile, ~~500-kV~~high-voltage transmission lines project between a station located near Douglas, Wyoming and the Hemingway station. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 – MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.

Resource Planning

Integrated Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP). Idaho Power filed its most recent IRP with the IPUC and OPUC in June ~~2017.~~2019, which was amended in January 2020. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and ~~demand-side~~transmission resource options, and identifies potential near-term and long-term actions. The four primary goals of the IRP are to:

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identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;

ensure the selected resource portfolio balances cost, risk, and environmental concerns;

give equal and balanced treatment to ~~both~~ supply-side, ~~resources~~demand-side, and ~~demand-side measures;~~transmission resources; and

involve the public in the planning process in a meaningful way.

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During the time between IRP filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect economic conditions, anticipated resource development, changes in technology, and regulatory requirements.

~~In 2018, Idaho Power began preparing its 2019 IRP.~~ The load forecast assumptions Idaho Power ~~expects to use~~used in its 2019 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads.


	5-Year Forecast		20-Year Forecast		5-Year Forecasted Annual Growth Rate		20-Year Forecasted Annual Growth Rate
	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)	Retail Sales (Billed MWh)	Annual Peak (Peak Demand)	Retail Sales (Billed MWh)	Annual Peak (Peak Demand)
2019 IRP (preliminary)	1.3%	1.4%	1.0%	1.2%
2019 IRP					1.3%	1.4%	1.0%	1.2%
2017 IRP	1.1%	1.6%	0.9%	1.4%	1.1%	1.6%	0.9%	1.4%
2015 IRP	1.1%	1.5%	1.1%	1.4%	1.5%	1.8%	1.2%	1.5%

As noted above, on January 31, 2020, Idaho ~~Power's 2017~~Power amended the originally filed 2019 IRP ~~identifies its~~with additional information and modeling results. The updated 2019 IRP identified a preferred resource portfolio and action ~~plan. The IRP~~plan, which includes the completion of the Boardman-to-Hemingway ~~500-kV~~ transmission line byin 2026, the end ofto Idaho Power's participation in coal-fired operations at the North Valmy ~~power~~ plant units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger plant by 2030, including the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the ~~early retirement~~addition of ~~Jim Bridger units 1 and 2~~a 120-MW solar resource in ~~2032 and 2028, respectively, with no other new resource needs prior to 2026.~~2022. However, as noted in the ~~2017~~2019 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of ~~third party~~third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These ~~and other~~ uncertainties, ~~could~~as well as others, will likely result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. As of the date of this report, proceedings relating to the amended 2019 IRP are pending at the IPUC and OPUC.

Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 2327 programs. These energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer at times of peak loads. The programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimize or delay the need for new generation and transmission infrastructure. Idaho Power’s programs include:

financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;

energy efficiency programs for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, air duct sealing, and energy efficient lighting;

incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes;

demand response programs to reduce peak summer demand through the voluntary cycling of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through actions taken by business owners and operators; and

~~membership~~participation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.

In ~~2018,~~2019, Idaho Power’s energy efficiency programs reduced energy usage by approximately 205,000 MWh compared with 173,000 ~~MWh.~~in 2018. For ~~2018,~~2019, Idaho Power had a demand response available capacity of approximately ~~382~~397 MW. In 2019, 2018, ~~2017,~~ and ~~2016,~~2017, Idaho Power expended approximately $49 million, $44 million, ~~$48 million,~~ and ~~$43~~$48 million, respectively, on both energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the power cost adjustment mechanisms. Energy efficiency program expenditures funded through the

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riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.

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Environmental, Social, and Governance Initiatives

IDACORP’s and Idaho Power’s boards of directors are responsible for the oversight of the companies’ environmental, social, and governance (ESG) initiatives and are regularly informed of the goals, measures, and results of ~~their~~the companies' ESG and sustainability programs. IDACORP and Idaho Power publicly ~~released their inaugural sustainability report in May 2012 and have issued~~release annual sustainability reports ~~annually thereafter. IDACORP’s and Idaho Power’s ESG initiatives include establishing responsible management goals to balance shareholder return~~ and the companies’ impact on the environment (such as the sustainability benefits from the Boardman to Hemingway transmission project, which includes integrating renewable energy generation and deferring the need for development of additional fossil-fueled resources), operational excellence in providing reliable, fair priced, and clean energy, continuing various environmental stewardship programs along the Snake River, engaging and empowering Idaho Power’s workforce (including succession planning at all levels, retirement planning education, and providing competitive pension benefits), promoting a culture of safety and inclusiveness for all employees, and building strong community partnerships for healthy economic development in Idaho Power’s service area, among other things. The most current sustainability report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power. The sustainability reports and related website content are not incorporated by reference into this 2019 Annual ~~Report~~Report. IDACORP’s and Idaho Power’s ESG initiatives include:

establishing responsible management goals to related to the companies’ impact on ~~Form 10-K.~~the environment, such as


◦	the "Clean Today, Cleaner Tomorrow.^®" goal to provide Idaho Power's customers with 100-percent clean energy by 2045,


◦	the sustainability benefits from the Boardman-to-Hemingway transmission project, which includes integrating renewable energy generation and deferring the need for development of additional fossil-fueled resources,


◦	continuing various environmental stewardship programs along the Snake River, including fish habitat preservation and restoration,


◦	wildfire mitigation planning and actions, and


◦	wildlife habitat, archaeological and cultural resource, and raptor protection stewardships.

operational excellence in providing reliable, fair priced, and clean energy,

engaging and empowering Idaho Power’s workforce (including succession planning at all levels, employee development, retirement planning education, and providing competitive pension benefits),

promoting a culture of safety and inclusiveness for all employees, and

building strong community partnerships for healthy economic development in Idaho Power’s service area.

Voluntary CO₂ Emissions Intensity Reduction Goal:Idaho Power is engaged in voluntary greenhouse gas (GHG) emissions intensity reduction efforts. In 2013, IDACORP's and Idaho Power's boards of directors extended a goal they originally established in 2009, seeking to reduce the company-owned resource portfolio average carbon dioxide (CO₂) emissions intensity to 15-20 percent below 2005 levels of 1,194 lbs CO₂/MWh for the 2010-2017 cumulative period. Idaho Power has achieved and furthered the reduction goal several times, which now extends through 2020. Through 2019, Idaho Power was beating its current C0₂emissions intensity goal, with an average reduction of 29 percent since 2010.

Idaho Power's estimated historic CO₂ emissions intensity from its generation facilities is as follows (in lbs CO₂/MWh):



	2019	2018	2017	2016	2015	2014	2013	2012	2011	2010
Cumulative Emissions Intensity 2010-2019	848	870	896	934	944	945	929	867	864	1,066
Annual Average Emissions Intensity	646	656	632	858	944	1,015	1,129	874	681	1,066

Reduction in Coal-Fired Generation: Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. Continued review of the economic appropriateness of further investments in coal-fired plants was included in an IPUC order in February 2014, in which the IPUC requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning and promptly apprise the IPUC of developments that could impact the company's continued reliance on the North Valmy ~~Plant~~plant as a coal-fired resource. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy ~~Plant~~plant in connection with Idaho Power's plan to end its participation in the operation of units 1 and 2. Idaho Power ended its participation in the operation of unit 1 ~~at the Valmy Plant by the~~in December 2019, as planned, and plans to end ~~of 2019 and~~its participation in unit 2 by December 31, 2025. The plan to end Idaho Power's participation in operations of units 1 and 2 at the North Valmy ~~Plant~~plant was based primarily on the economics of operating the plant. The settlement stipulations are described in Part II, Item 7 - MD&A - "Regulatory Matters” in this report. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of selective catalytic reduction equipment (SCR) installation, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The table above does not include costs associated with a SCR installation on units 1 and 2 at the Jim Bridger power plant.

~~Voluntary CO~~₂ ~~Emissions Intensity Reduction Goal~~:Idaho Power is engaged in voluntary greenhouse gas emissions (GHG) emissions intensity reduction efforts. In 2013, IDACORP's and Idaho Power's boards of directors extended a goal they originally established in 2009, seeking to reduce the company-owned resource portfolio average carbon dioxide (CO₂~~) emissions intensity to 15-20 percent below 2005 levels of 1,194 lbs CO~~₂~~/MWh for the 2010-2017 cumulative period. Idaho Power has achieved and furthered the reduction goal several times, which now extends through 2020.~~

~~Idaho Power's estimated historic CO~~₂ ~~emissions intensity from its generation facilities is as follows (in lbs CO~~₂~~/MWh):~~

2018 2017 2016 2015 2014 2013 2012 2011 2010
Cumulative Emissions Intensity 2010-2018 869 896 934 944 945 929 867 864 1,066
Annual Average Emissions Intensity 647 632 858 944 1,015 1,129 874 681 1,066

Environmental Regulation and Costs

Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with

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permits and licenses. In addition to generally applicable regulations, Idaho Power's three co-owned coal-fired power plants, three natural gas combustion turbine power plants, and 17 ~~hydroelectric~~hydropower generating plants are subject to a broad range of environmental

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requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Item 7 - MD&A - "Environmental Matters" in this report.

Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, particularly given the volume of existing and proposed regulations at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars):


	2019		2020-2021		2020		2021-2022
Capital expenditures:
License compliance and relicensing efforts at hydroelectric facilities	$	12	$	35
License compliance and relicensing efforts at hydropower facilities					$	30	$	46
Investments in equipment and facilities at thermal plants	4		22		8		15
Total capital expenditures	$	16	$	57	$	38	$	61
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	21	$	42
Operating costs for environmental facilities - hydropower					$	21	$	41
Operating costs for environmental facilities - thermal	12		23		11		22
Total operations and maintenance	$	33	$	65	$	32	$	63

Idaho Power anticipates that finalization, implementation, or modification of a number of federal and state rulemakings and other proceedings addressing, among other things, greenhouse gases and endangered species could result in substantial changes in operating and compliance costs, but Idaho Power is unable to estimate those changes in costs given the uncertainty associated with existing and potential future regulations. Idaho Power expects that it would seek to recover increases in costs through the ratemaking process. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and potential early plant retirements cannot be fully recovered in rates on a timely basis.

IDACORP FINANCIAL SERVICES, INC.

IFS invests in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk with most of IFS’s investments having been made through syndicated funds. ~~While IFS has not actively pursued new investment opportunities for some time, IFS does evaluate new investment opportunities.~~ At December 31, ~~2018,~~2019, the unamortized amount of IFS’s portfolio was approximately $3$4 million ($~~146~~126 million in gross tax credit investments, net of ~~$143~~$122 million of accumulated amortization). IFS generated tax credits of $2.9 million in 2019 and $2.6 million in ~~each year in~~both 2018 ~~2017,~~ and ~~2016.~~2017. In 2019, 2018, ~~2017,~~ and ~~2016,~~2017, IFS received distributions related to fully-amortized affordable housing investments that reduced IDACORP's income tax expense by $3.2 million, $0.3 million, ~~$1.1 million,~~ and ~~$1.7~~$1.1 million, respectively.

IDA-WEST ENERGY COMPANY

Ida-West operates and has a 50 percent ownership interest in nine ~~hydroelectric~~hydropower projects that have a total ~~generating~~nameplate capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho ~~hydroelectric~~hydropower projects at a cost of approximately $9 million in 2019 and $10 million in both 2018 and ~~2017 and $8 million in 2016.~~2017.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS ~~OF THE REGISTRANTS~~

The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), along with their business experience during at least the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed.

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RYAN N. ADELMAN, 45

Vice President of Transmission & Distribution, Engineering and Construction, October 2019 - present

Regional Manager for the Southeast Region of Idaho Power Company, January 2018 - October 2019

Transmission & Distribution Projects Senior Manager of Idaho Power Company, January 2015 - December 2017

DARREL T. ANDERSON, 6061

Chief Executive Officer of Idaho Power Company, January 2014 - present

President and Chief Executive Officer of IDACORP, Inc., May 2014 - present

President and Chief Executive Officer of Idaho Power Company, January 2014 - ~~present~~

~~President and Chief Financial Officer of Idaho Power Company, January 2012 - December 2013~~

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~~Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 2009 - April 2014~~September 2019

Member of the Boards of Directors of IDACORP, Inc. and Idaho Power Company since September 2013

BRIAN R. BUCKHAM, 4041

Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - present

Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - February 2017

In-house legal counsel of IDACORP, Inc. and Idaho Power Company, April 2010 - March 2016

~~JEFFREY S. GLENN, 51~~SARAH E. GRIFFIN, 50

Vice President of ~~Corporate Services and Chief Information Officer~~Human Resources of Idaho Power Company, ~~June 2018~~October 2019 - present

~~Vice President~~Director of ~~Information Technology and Chief Information Officer~~Human Resources of Idaho Power Company, ~~January 2016 - June 2018~~

~~Vice President of Technology Operations of Verizon Digital Media Services, Inc. (a digital media content delivery network company), January~~May 2014 - ~~January 2016~~

~~Vice President of Technology Operations of Edgecast Networks, Inc. (acquired by Verizon Digital Media Services, Inc. in 2014), January 2012 - January 2014~~October 2019

LISA A. GROW, 5354

President of Idaho Power Company, October 2019 - present

Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - ~~present~~October 2019

Senior Vice President of Operations of Idaho Power Company, January 2016 - March 2016

Senior Vice President - Power Supply of Idaho Power Company, October 2009 - December 2015

JAMES BO D. HANCHEY, 44

Vice President of Customer Operations and Chief Safety Officer of Idaho Power Company, October 2019 - present

Customer Service Senior Manager of Idaho Power Company, February 2018 - October 2019

Regional Manager of Southern Region of Idaho Power Company, May 2014 - February 2018

STEVEN R. KEEN, 5859

Senior Vice President - Chief Financial Officer, and Treasurer of IDACORP, Inc., May 2014 - present

Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 2014 - present

~~Senior Vice President - Finance and Treasurer of Idaho Power Company, January 2012 - December 2013~~

~~Vice President - Finance and Treasurer of IDACORP, Inc., June 2010 - April 2014~~

JEFFREY L. MALMEN, 5152

Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present

Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, October 2008 - March 2016

TESSIA PARK, 5758

Vice President of Power Supply of Idaho Power Company, January 2016 - present

Director of Load Serving Operations of Idaho Power Company, September 2012 - December 2015

KEN W. PETERSEN, 5556

Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - present

~~Corporate Controller~~

ADAM RICHINS, 41

Senior Vice President and Chief ~~Accounting~~Operating Officer ~~of IDACORP, Inc. and Idaho Power Company, May 2010 - December 2013~~

~~N. VERN PORTER, 59~~

~~Vice President of Transmission & Distribution Engineering and Construction and Chief Safety Officer, April 2016 - present~~

~~Vice President of Customer Operations~~ of Idaho Power Company, ~~January 2016~~October 2019 - ~~March 2016~~

~~Senior Vice President of Customer Operations of Idaho Power Company, April 2015 - December 2015~~

~~Vice President of Idaho Power Company, January 2014 - April 2015~~

~~Vice President of Delivery Engineering and Construction of Idaho Power Company, May 2012 - December 2013~~

~~ADAM RICHINS, 40~~present

Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - ~~present~~October 2019

General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017

~~In-house legal counsel of Idaho Power Company, November 2010 - January 2014~~

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ITEM 1A. RISK FACTORS

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IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below should not be considered a complete list of potential risks that the companies may encounter. These risk factors may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Matters Impacting Future Results" in this report, and information in other reports the companies file with the SEC, may be important to understanding any statement in this 2019 Annual Report or elsewhere and should be considered carefully when making any investment decisions relating to IDACORP or Idaho Power.

IDACORP's and Idaho Power's businesses regularly face risks, many of which may cause future results to be different than anticipated as of the date of this report. Below are certain important utility-specific regulatory, operational, legal and compliance, financial and investment, and general business risks. IDACORP's and Idaho Power's reactions to material future developments as well as the utility industry's reactions to those developments may also impact the Companies' future results.

Utility-Specific Regulatory Risks

Utility-specific regulatory risk includes the risks that federal, state, or local regulators may impose additional requirements and costs on Idaho Power and the utility industry, or require Idaho Power as a utility to make adverse changes to its business models, strategies, and practices.

State or federal regulators may not approve customer rates that provide timely or sufficient recovery of Idaho Power's costs or allow Idaho Power to earn a reasonable rate of return, which could cause IDACORP's and Idaho Power's financial condition and results of operations to be adversely affected.

The prices that the IPUC and OPUC authorize Idaho Power to charge customers for its retail services, and the tariff rate that the FERC permits Idaho Power to charge for its transmission services, are generally the most significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, liquidity, and financial condition. Idaho Power's ability to recover its costs and earn a reasonable rate of return can be affected by many regulatory factors, including the timing difference between when Idaho Power incurs costs and when Idaho Power recovers those costs in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs included in rates and the amount of actual costs incurred. Idaho Power is often required to incur costs before the IPUC, OPUC, or FERC approves the recovery of those costs, such as construction costs for new facilities, changes in the long-term cost-effectiveness or ~~power lines,~~changes to the operating conditions of Idaho Power's assets that could result in early retirements of utility facilities, the costs of compliance with legislative and regulatory requirements, increased funding levels of a defined benefit pension plan, and the costs of damage from fires, weather-related events, and natural disasters. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basis that they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. Ratemaking has generally been premised on estimates of historic costs based on a test year, so if a given year’s actual costs are higher than historic costs, rates may not be sufficient to cover actual costs. While rate regulation is also premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard. Decisions are subject to judicial appeal, which could lead to further uncertainty in regulatory proceedings.

Economic, political, legislative, public policy, or regulatory pressures may lead stakeholders to seek rate reductions or refunds, limits on rate increases, or lower allowed rates of return on investments for Idaho Power. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates. The IPUC and OPUC may adopt different methods of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. Compliance with state and federal regulatory standards may also limit Idaho Power's ability to operate profitably. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings or significant regulatory lag may cause Idaho Power to record an impairment of its assets or otherwise adversely affect cash flows and earnings and result in lower credit ratings, reduced access to capital and higher financing costs, and reductions or delays in planned capital expenditures.

For additional information relating to Idaho Power's state and federal regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," ~~Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, and~~ Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and

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Results of Operations - Regulatory Matters," and Note 3 - "Regulatory Matters" to the consolidated financial statements of Part II - Item 8 in this report.

Idaho Power's cost recovery mechanisms may not function as intended and are subject to change or elimination, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustment mechanism in Idaho. The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differences between these two amounts is deferred for future recovery from, or refund to, customers through rates. Volatility in power supply costs continues to be significant, in large part due to fluctuations in ~~hydroelectric~~hydropower generation conditions and high costs for the purchase of renewable energy under mandatory long-term contracts. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. The fixed cost adjustment mechanism is a decoupling mechanism designed to remove a portion of Idaho Power's disincentive to invest in and support

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energy efficiency activities. This mechanism allows Idaho Power to charge Idaho residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case. The power cost and fixed cost adjustment mechanisms are generally subject to change at the discretion of applicable state regulators, who could decide to modify or eliminate either mechanism in a manner that adversely impacts IDACORP's and Idaho Power's financial condition, cash flows, and results of operations.

Operational Risks

Operational risk relates to risks arising from the systems, assets, processes, people, and external factors that affect the operation of IDACORP's or Idaho Power's businesses.

IDACORP's and Idaho Power's business, financial condition, and results of operations may be negatively affected by changes in customer growth or customer usage.Changes in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, expansion or loss of service area, changes in customer needs and expectations, adoption rates of energy efficiency measures, customer-generated power such as from solar panels and gas-fired generators, demand-side management requirements, regulation or deregulation, and adverse economic conditions. An economic downturn or recession could also negatively impact customer use and reduce revenues and cash flows, thus adversely affecting results of operations. Many electric utilities, including Idaho Power, have experienced a decline in usage per customer, in part attributable to energy efficiency activities. State or federal regulations may be enacted to encourage or require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, legislation to deregulate electric service, and customers seeking alternative sources of energy and electric service. If customers choose to generate their own energy, discontinue a portion or all service from Idaho Power, or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of its services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho residential customers has declined from ~~1,063~~1,039 kWh in ~~2009~~2010 to ~~945~~936 kWh in ~~2018.~~2019. Rate mechanisms, such as the Idaho fixed cost adjustment, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's volume-based energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in IDACORP and Idaho Power modifying or eliminating large generation or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

Conversely, if Idaho Power were to experience an unanticipated increase in the demand for energy through, for example, the rapid addition of new industrial and commercial customers or population growth in the service area, Idaho Power may be required to rely on higher-cost purchased power to meet peak system demand and may need to accelerate investment in additional generation or transmission resources. If the incremental costs associated with the unanticipated changes in loads

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exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

Changes in weather conditions, severe weather, and the impacts of climate change can adversely affect IDACORP's and Idaho Power's operating results and cause them to fluctuate ~~seasonally and can be adversely affected by changes in weather conditions, severe weather, and climate change.~~seasonally. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.

Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, droughts, heat waves, fires, floods, snow loading, and other extreme weather events, and impact Idaho Power’s ability to generate or import power on transmission lines from other geographic areas. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and

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extended or mass outages, increasing costs and other operating and maintenance expenses, including emergency response planning and preparedness expenses, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to higher temperatures are likely to decrease power generation from ~~hydroelectric~~hydropower plants.

Idaho Power's customers' energy needs vary with weather and to the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require Idaho Power to invest in generating assets and transmission and distribution infrastructure, while decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions creating high energy demand may raise wholesale electricity prices for power that Idaho Power purchases to serve customers, increasing the cost of energy Idaho Power provides to its customers, and at the same time can increase the revenues Idaho Power receives for wholesale market sales of excess generation during regional extreme weather events. Variations in ~~hydroelectric~~hydropower generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus ~~hydroelectric power~~hydropower in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs.

The costs of ~~repair~~repairing and replacing infrastructure or liability for personal injury, loss of life, orand property damage from utility equipment that fails as a result of significant weather and weather-related events, including fires, may not be covered in full by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators. In addition, state and federal legislation and regulations have been proposed in recent ~~years~~years; including in the State of Oregon, to limit the severity and impact of climate change, such as imposing mandatory reductions in greenhouse gas emissions, which could increase Idaho Power’s power supply and compliance costs. If financial markets increasingly view climate change or greenhouse gas emissions as a financial or investment risk for electric utilities, it could negatively affect IDACORP's and Idaho Power's ability to access debt and equity capital markets on favorable terms. For additional information relating to legislation, regulations, and legal proceedings related to environmental matters, see Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report.

New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could cause decreased customer energy demand and decreased revenues. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, power storage, and energy efficiency. In particular, in recent years the net cost of solar generation has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar generation. There is potential that customer-owned power generation systems, particularly if coupled with power storage devices, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way

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Idaho Power manages its distribution systems, and reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. Advances in technology that reduce the costs of alternative methods of producing electric energy could result in loss of revenue and customers, and may require Idaho Power to make significant expenditure reductions to remain competitive. These changes in technology could also alter the channels through which customers buy or utilize energy, which could reduce Idaho Power's revenues or impact Idaho Power's expenses. A reduction in load, however, would not necessarily reduce Idaho Power's need for ongoing investments in its infrastructure to reliably serve its customers. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency would result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.

Acts or threats of terrorism, cyber attacks, data or physical security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid could require significant expenditures, or result in claims against the companies, and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. Federal regulators have stated that a number of organizations continue to seek opportunities to exploit potential vulnerabilities in the U.S. energy infrastructure and that those attacks have become increasingly frequent and sophisticated. Some of Idaho Power's facilities are deemed "critical infrastructure," in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk electric power system, national economic security, and public health and safety. The possibility that infrastructure facilities, such as generation facilities and electric transmission or distribution facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack, including by nation states or nation state-sponsored groups (whether originating internally or externally), may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Idaho Power's electric transmission systems are part of an interconnected regional grid, and therefore, it faces the risk of causing or being subject to a blackout due to grid disturbances or disruptions on a neighboring interconnected system. Cyber threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power, such as process breakdowns, human error, security architecture or design vulnerabilities, or by third parties, such as computer hackings, cyber attacks, computer viruses, or other destructive or disruptive software, denial of service attacks, social engineering or other malicious activities, or any combination of the foregoing, could result in a degradation or disruption in the energy grid and the services of the companies. Physical or cyber attacks against key suppliers or service providers could have a similar effect on IDACORP and Idaho Power.

Political, economic, social, or financial market instability or damage to or interference with Idaho Power’s operating assets, customers, or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair, or other costs, any of which may materially adversely affect Idaho Power in ways that cannot be predicted as of the date of this report. The breach of certain information technology systems could adversely affect IDACORP's and Idaho Power's ability to correctly record, process and report customer, business, and financial information. Any of these risks could materially affect the companies’ consolidated financial results.

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These events, and governmental actions in response, could result in a material decrease in revenues and increase costs to protect, repair, and insure Idaho Power's assets and operate its business.

Idaho Power's operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. No security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, human error, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. Any security breaches, such as misappropriation, misuse, leakage, falsification or accidental release or loss of information maintained in IDACORP's and Idaho Power's information technology systems, including customer data, could result in violations of privacy and other laws, financial loss to Idaho Power or to its customers, customer dissatisfaction or diminished customer confidence, damage to Idaho Power’s reputation, and significant litigation and penalty exposure, all of which could materially affect Idaho Power's financial condition and results of operations.

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~~Capital~~

Changes in capital expenditures for infrastructure and the risks associated with permitting and construction of ~~that~~utility infrastructure ~~and the timing and availability of cost recovery for the expenditures,~~ can significantly affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s business is capital intensive and requires significant investments in energy generation, transmission, and distribution infrastructure. A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, long-term anticipated increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure. For instance, Idaho Power is in the permitting process for two ~~500-kV~~high-voltage transmission line projects, which are intended to help meet future customer energy demands. Construction projects are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:

the ability to timely obtain labor or materials at reasonable costs;

defaults by suppliers and contractors;

equipment, engineering, and design failures;

unexpected environmental and geological problems;

the effects of adverse weather conditions;

availability of financing;

load forecasts;

the ability to obtain and comply with permits and land use rights, and environmental constraints; and

delays and costs associated with disputes and litigation with third parties.

The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable or unwilling to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

Factors contributing to lower hydropower generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power derives a significant portion of its power supply from its hydropower facilities. During 2018 and 2019, 65 percent and 62 percent, respectively, of Idaho Power's electric power from Idaho Power-owned generation was from hydropower facilities. Due to Idaho Power’s heavy reliance on hydropower generation, factors such as precipitation and snowpack, the timing of run-off, and the availability of water in the Snake River basin can significantly affect its operations. The combination of a long-term trend of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights reduce Snake River flows available for hydropower generation. When hydropower generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and market power purchases; therefore, costs increase and opportunities for wholesale energy sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydropower generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity.

Idaho Power’s use of coal and natural gas to fuel power generation facilities exposes it to commodity availability and price risk, which can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. As part of its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, regulations related to greenhouse gas emissions, and changes in technology. Natural gas

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transportation to Idaho Power's three natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience regulatory, financial, or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power's failure to provide service due to such disruptions may also result in fines, penalties, or cost disallowances through the regulatory process. Idaho Power may not be able to fully or timely recover these increased costs through rates, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes or attrition, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, wildfires, acts of terrorism or sabotage (both cyber and asset-based), the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties (including tort liability), and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area during high-load periods. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third-parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third-party contractors to perform work on its generation, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, reputational harm, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.

Accidents, terrorist acts, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, uncontrolled release of water from hydropower dams, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could also expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire and increasing the magnitude of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and commonly hot, dry summer conditions, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs in the event there are fires that are deemed to be separate occurrences covered by self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected.

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Purchases of power from renewable energy projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. An abundance of intermittent, non-dispatchable generation from renewable energy projects interconnected with Idaho Power's system has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. As of December 31, 2019, Idaho Power had federally-mandated contracts to purchase energy from 127 on-line projects with third parties. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydropower and fossil fuel-fired generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in additional generation. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and revenue and shifts in customer costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. If Idaho Power is unable to timely recover those costs through its power cost adjustment mechanisms or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.

Legal and Compliance Risks

Legal and compliance risk relates to risks arising from government and regulatory action and from legal proceedings and compliance with applicable laws, rules, orders, regulations, policies, and procedures, including those related to financial reporting, environmental, health, and safety, and potential changes in legal requirements.

Changes in legislation, regulation, and government policy may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. Changes in, and uncertainty with respect to, federal, state, and local legislation, regulation, and government policy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals and recently enacted legislation that could have a material impact on IDACORP and Idaho Power include, but are not limited to, tax reform, utility regulation, infrastructure renewal programs, environmental regulation, and modifications to accounting and public company reporting requirements. Further, the proposals and new legislation could have an impact on the rate of growth of Idaho Power’s customers and their willingness to expand operations and increase electric service requirements. Laws, regulations, and policies relating to environmental compliance could change and require IDACORP and Idaho Power and their customers to modify their business strategy or affect their returns on

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investment by restricting activities and projects or subjecting them to increased compliance costs. Although the United States has not adopted any international or federal greenhouse gas emissions reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. The state of Oregon, for instance, has been pursuing cap-and-trade legislation for greenhouse gas emissions. Idaho Power could also become subject to climate change lawsuits and an adverse outcome could require substantial expenditures and could possibly require payment of damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition, or cash flows if such costs are not recovered through regulated rates. IDACORP and Idaho Power are monitoring the implementation by federal, state, and local governmental authorities of various executive orders and are unable to predict whether and to what extent such actions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.

Changes in income tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for income taxes. Amounts of income tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. These judgments may include estimates for potential outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal, or through litigation. In recent years, state regulatory mechanisms with income tax-related provisions (such as Idaho Power's May 2018 ~~regulatory~~Idaho tax reform settlement stipulation with the IPUC), has significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of potential future income tax proceedings, or the state public utility commissions' treatment of those outcomes, could differ materially from the amounts

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IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances, the treatment from a ratemaking perspective of any net income tax expense or benefit could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. In addition, Idaho Power uses the regulatory flow-through income tax accounting method as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in income tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than most other companies.

IDACORP's and Idaho Power’s businesses are subject to an extensive set of environmental laws, rules, and regulations, which could impact their operations and costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. IDACORP's and Idaho Power's operations are subject to a number of federal, state, and local environmental statutes, rules, and regulations relating to air and water quality, natural resources, renewable energy, and health and safety. Many of these laws and regulations are described in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. These laws and regulations generally require IDACORP and Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, and other approvals, including through substantial investment in pollution controls, and may be enforced by both public officials and private individuals. Some of these regulations are pending, changing, or subject to interpretation, and failure to comply may result in penalties, mandatory operational changes, and other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties and complying with new operating requirements. Idaho Power devotes significant resources to environmental monitoring, pollution control equipment, and mitigation projects to comply with existing and anticipated environmental regulations. However, it is possible that federal, state and local authorities could attempt to enforce more stringent standards, stricter regulation, and more expansive application of environmental regulations.

Environmental regulations have created the need for Idaho Power to install new pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its owned and co-owned power generation facilities, often at a substantial cost. Compliance with environmental regulations can significantly increase capital spending, operating costs, and plant outages, and can negatively affect the affordability of Idaho Power's services for customers. Idaho Power cannot predict with certainty the amount and timing of all future expenditures necessary to comply with these environmental laws and regulations, although Idaho Power expects the expenditures will be substantial. In some cases, the costs to obtain permits and ensure facilities are in compliance may be prohibitively expensive. If the costs of compliance with new regulations renders the generating facilities uneconomical to maintain or operate, Idaho Power would need to identify alternative resources for power, potentially in the form of new generation and transmission facilities, market power purchases, demand-side management programs, or a combination of these and other methods. Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its existing infrastructure or construction of new infrastructure.

~~The current presidential administration has issued a number~~In response to state and federal regulatory requirements, judicial decisions and international accords, emissions of ~~executive orders related~~greenhouse gases including, most significantly CO₂ could be restricted in the future. If new emissions reduction rules were to ~~environmental matters designed to ease environmental regulation~~become effective, they could result in significant additional compliance costs that ~~the federal agencies~~would affect Idaho Power's future financial position, results of operations, and cash flows if such costs are ~~still implementing. However, the outcome of the Environmental Protection Agency's and other federal agencies' review of regulations covered by the executive orders is difficult to predict.~~not timely recovered through regulated rates. Moreover, the executive orders and any resulting federal regulations could be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federalpossibility exists that stricter laws, regulations, or ~~bolster~~enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

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environmental compliance and enforcement efforts at the local level. Accordingly, Idaho Power may not realize any benefit from changes to federal environmental regulations, if any, resulting from the executive orders and, as of the date of this report, cannot predict whether and to what extent the orders and resulting changes to regulations could affect its operations and environmental-related expenditures.

In addition, some environmental regulations are currently subject to litigation and not yet final. As a result of this uncertainty, approaches to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot foresee the potential impacts these regulations would have on Idaho Power's operations or financial condition. Idaho Power is not guaranteed timely or full recovery through customer rates or insurance of costs associated with environmental regulations, environmental compliance, plant closures, or clean-up of contamination. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, or subjected to additional costs.

~~Factors contributing to lower hydroelectric generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results~~ For further discussion of ~~operations~~.environmental matters that may affect Idaho Power, ~~derives a significant portion~~see "Environmental Matters" in "Item 7. Management's Discussion and Analysis of ~~its power supply from its hydroelectric facilities. During 2017~~Financial Condition and ~~2018, 65 percent~~Results of Idaho Power's electric power generation was from hydroelectric facilities. Due to Idaho Power’s heavy reliance on hydroelectric generation, factors such as precipitation and snowpack, the timing of run-off, and the availability of waterOperations" in the Snake River basin can significantly affect its operations. The combination of a long-term trend of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights reduce Snake River flows available for hydroelectric generation. When hydroelectric generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and market power purchases; therefore, costs increase and opportunities for wholesale energy sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydroelectric generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity.this report.

Obligations imposed in connection with ~~hydroelectric~~hydropower license renewals may require large capital expenditures, increase operating costs, reduce ~~hydroelectric~~hydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its

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largest ~~hydroelectric~~hydropower generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s ~~hydroelectric~~hydropower projects, which may be reflected in ~~hydroelectric~~hydropower licenses, including for the Hells Canyon Complex. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to ~~hydroelectric~~hydropower facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of ~~hydroelectric~~hydropower generation available to meet Idaho Power’s generation requirements. One significant issue identified in connection with the Hells Canyon Complex relicensing effort involves water temperature gradients in the Snake River below the Hells Canyon dam. Certain parties in the relicensing proceedings have advocated for the installation of a water temperature management apparatus which, if required to be installed, would involve substantial costs to construct, operate, and maintain. Idaho Power may be unable to recover in full or in a timely manner the costs of such an apparatus through rates, particularly given the magnitude of any potential impact on customer rates. Another significant issue related to the relicensing effort involves a dispute between the states of Idaho and Oregon regarding whether to reintroduce or establish spawning populations of fish species into Idaho waters. In December 2018, the states of Idaho and Oregon, along with Idaho Power, reached a proposed settlement on this matter, requiring Idaho Power to reintroduce certain fish species and fund-related research. Idaho Power cannot predict ~~the outcome of these proceedings,~~ the requirements that might be imposed during the relicensing process, the financial impact of those requirements, whether a new multi-year license will ultimately be issued, and whether the IPUC or OPUC will allow recovery through rates of the substantial costs incurred in connection with the licensing process and subsequent compliance. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce ~~hydroelectric~~hydropower generation, which could negatively affect results of operations and financial condition.

Idaho ~~Power’s use of coal~~Power could be subject to penalties, reputational harm, and ~~natural gas to fuel power generation facilities exposes~~operational changes if it ~~to commodity availability~~violates mandatory reliability and ~~price risk,~~security requirements, which ~~can~~could adversely ~~affect~~impact IDACORP's and Idaho Power's results of operations and financial ~~condition~~.condition. As ~~part~~an owner and operator of ~~its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term~~

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contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, and changes in technology. Natural gas transportation to Idaho Power's three natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thusbulk power transmission system, Idaho Power is ~~exposed~~subject to ~~risk of disruption of coal production in, or transportation from,~~mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that ~~region.~~need to be performed to ensure the bulk power system operates reliably and are guided by reliability, security, and market interface principles. Compliance with reliability standards subjects Idaho Power ~~may~~to higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations from, time to time enter into new, or renegotiate, these long-term contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterpartiesand regularly self-reports reliability standard compliance issues to, the ~~natural gas~~FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC regulations may be substantial, and in some circumstances monetary penalties may exceed $1.3 million per day per violation. As a utility with a large customer base, Idaho Power is subject to adverse publicity focused on the reliability of its services and the speed with which it is able to respond to electric outages caused by storm damage or ~~coal supply agreements will fulfill their obligations~~other unanticipated events. Adverse publicity could harm the reputations of IDACORP and Idaho Power; may make state legislatures, utility commissions, and other regulatory authorities less likely to ~~supply natural gas or coal,~~view the companies in a favorable light; and they may experience financial or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to ~~seek alternative,~~be subject to less favorable legislative and ~~potentially more costly, sources~~regulatory outcomes or increased regulatory oversight. The imposition of ~~fuel or rely~~any of the foregoing on ~~other generation sources or wholesale market power purchases.~~ Idaho Power ~~may not be able~~for its actual or alleged failure to ~~fully or timely recover these increased costs through rates, which may adversely affect IDACORP's~~comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition.

IDACORP and Idaho ~~Power's~~Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have reputational impact and a short- or long-term negative effect on their financial condition and results of operations. Similarly, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.

~~If the assumptions underlying coal mine reclamation at Bridger Coal Company~~Financial and ~~related forecast trust fund growth are materially inaccurate,~~Investment Risks

Financial and investment risks relate to IDACORP's and Idaho ~~Power’s costs could be greater than anticipated or be incurred sooner than anticipated~~. ~~Bridger Coal Company, a subsidiary of Idaho Power, uses both surface and underground methods~~Power's ability to mine coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closuremeet financial obligations and ~~standards for mining of coal. Bridger Coal Company’s estimate of reclamation liability~~mitigate exposure to market risks, including liquidity risks and bonding obligations is reviewed periodically by Idaho Power’s management committee, audit committee of the board of directors, external and internal auditors, and by government regulators. Idaho Power funds a trust to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected.

~~Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry~~. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes or attrition, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, wildfires, acts of terrorism or sabotage, the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties, and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, the transmission system in Idaho Power's service area is constrained, limiting the ability to ~~transmit electric energy within the service area~~raise capital and ~~access electric energy from outside the service area during high-load periods. Idaho Power's transmission facilities are also interconnected with those~~cost of third parties, and thus operation of Idaho Power's and third parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third party contractors to perform work on its generation, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.

Accidents, terrorist acts, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, uncontrolled release of water from hydroelectric dams, and other unplanned eventsfunding, risks related to ~~Idaho Power's infrastructure would increase repair costs~~credit ratings, credit risk, liquidity, interest rates, and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could also expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, and property damage, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire and increasing the magnitude of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, andcommodity prices.

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commonly hot, dry summer conditions, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs in the event there are fires that are deemed to be separate occurrences covered by self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected.

Volatility or disruptions in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing and ability to execute on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The credit facilities represent commitments by the participating banks to make loans and issue letters of credit. However, the ability and obligation of the participating banks to make those loans and issue letters of credit is subject to specified conditions and volatility or disruptions in the financial markets could affect the companies' ability to obtain debt financing or draw upon or renew existing credit ~~facilities.~~facilities on favorable terms. Idaho Power's ability to issue long-term debt is also subject to a number of conditions included in an indenture, and Idaho Power's ability to issue long-term debt and commercial paper is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all.

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Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper or short-term or long-term debt at reasonable interest rates and terms or at all. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on IDACORP's and Idaho Power's operating results. Changes in interest rates may also impact the fair value of the debt securities in Idaho Power's pension funds, as well as Idaho Power's ability to earn a return on short-term investments of excess cash. Also, while the credit facilities represent a contractual obligation to make loans, one or more of the participating banks may default on their obligations to make loans under, or may withdraw from, the credit facilities.

Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities include financial covenants that limit the amount of debt that can be outstanding as a percentage of total capital, and Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. The companies must also make specified representations in connection with request for loans and it is possible that they may be unable to do so at the time of such request, which would limit or eliminate the obligation of the banks to provide loans. Failure to maintain these representations and covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could limit their ability to pursue certain projects and adversely impact IDACORP's and Idaho Power's financial condition, results of operations, and liquidity.

A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and rate mechanisms, the effectiveness of management, resource risks and power supply costs, and other factors. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. In addition, IDACORP's or Idaho Power's credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access short- and long-term capital under reasonable terms or at all, reduce the pool of potential lenders, increase borrowing costs under existing credit facilities, limit access to the commercial paper market, require the companies to pay a higher interest rate on their debt, limit the ability of IDACORP to declare and make dividends, and require the companies to post additional performance assurance collateral with transaction counterparties. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, IDACORP's and Idaho Power's ability to pursue improvements or acquisitions (including generating capacity and transmission assets, which may be necessary for future growth), financial condition and results of operations could be adversely affected.

Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. The interest rates for any borrowings under IDACORP and Idaho Power’s credit facilities, as amended in November 2019, are based on either (1) a floating rate

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that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero ~~percent.~~percent, provided that, an alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available, or if lenders have increased costs due to changes in LIBOR, IDACORP and Idaho Power may suffer from potential increases in interest rates on any borrowings. Further, IDACORP and Idaho Power may need to renegotiate their credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.

Idaho Power’s risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to buy and sell power, natural gas, and transmission service, enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financial hedge transactions to mitigate in part exposure to variable commodity prices. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments used for hedging might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative

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instruments, and any such failure to mitigate exposure could result in financial losses. Certain of Idaho Power's purchase or sale, hedging, and derivative agreements may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. Idaho Power has additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts and by vendors for infrastructure development projects. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor or supplier would need to replace the security with an acceptable substitute, which may be impracticable and may expose Idaho Power to losses resulting from a vendor or supplier default. If the security were not replaced, the party could be in default under the contract and Idaho Power's remedies for default may be inadequate to fully compensate Idaho Power for its losses. Forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions that Idaho Power may not be able to collect in customer rates. The FERC may take action to limit volatility in the energy market by imposing price limits or other market restrictions to control market-based rate sales, which could adversely affect the companies' financial results. As a result, risk management actions, or the failure or inability to manage commodity availability and price and counterparty risk, may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations. Further, the bankruptcy or insolvency of a counterparty to commodity or other transactions could impair Idaho Power’s ability to collect amounts receivable from those counterparties, potentially including the ability to collect or retain collateral posted by a counterparty. ~~In January 2019, Pacific Gas & Electric Company and PG&E Corporation, its parent entity (collectively, PG&E), filed voluntary bankruptcy petitions under Chapter 11 of the U.S. Bankruptcy Code.~~ Idaho Power ~~does not have any direct power, gas, or derivative transactions with PG&E. However, both Idaho Power and PG&E are participants~~is a participant in the energy markets, including the Western EIM, and ~~engage~~engages in direct and indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that ~~PG&E~~counterparties may owe each other ~~participants~~ in the Western ~~EIM. Also, PG&E purchases~~EIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the ~~output of power from small hydroelectric facilities located in California, in which Ida-West is a 50% co-owner. If PG&E is unable~~Western EIM to ~~perform~~make payments when due on its obligations under its arrangements with Ida-West’s joint venture, IDACORP does not believe the impact would be material to its financial condition nor results of operations. However, a bankruptcy filing of the magnitude of PG&E’s filing in 2019 could have a ripple effect on various Idaho Power counterparties in the power, gas, and derivative markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of Idaho Power’s counterparties to perform on their obligations.

Idaho Power could be subject to penalties and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability, security, and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC regulations may be substantial, and in some circumstances monetary penalties may exceed $1 million per day per violation. The imposition of penalties on Idaho Power for its actual or alleged failure to comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition.

Federally mandated purchases of power from renewable energy projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's

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~~and IDACORP's results of operations and financial condition.~~ An abundance of intermittent, non-dispatchable generation from renewable energy projects interconnected with Idaho Power's system has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in additional generation. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and shifts in customer costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. If Idaho Power is unable to timely recover those costs through its power cost adjustment mechanisms or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.

The performance of pension and postretirement benefit plan investments, increasing health care costs, and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. Idaho Power's self-insured costs of health care benefits for eligible employees and retirees have increased in recent years and Idaho Power believes these costs will continue to rise. As benefit costs continue to rise, there is no assurance that the ~~state public utility commissions~~IPUC and OPUC will continue to allow recovery.

The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.

If the assumptions underlying coal mine reclamation at Bridger Coal Company and related forecast trust fund growth are materially inaccurate, Idaho Power’s costs could be greater than anticipated or be incurred sooner than anticipated. Bridger Coal Company, a subsidiary of Idaho Power, uses both surface and underground methods to mine coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closure obligations and standards for mining of coal. Bridger Coal Company’s estimate of reclamation liability and bonding obligations is reviewed periodically by Idaho Power’s management committee, audit committee of the board of directors, external and internal auditors, and by government regulators. Idaho

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Power funds a trust to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected.

As a holding company, IDACORP does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other means. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiary's actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, tax obligations, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which may reduce or cease payment of dividends at any time. See Note 7 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.

General Risks

General risks include other risks specific to IDACORP and Idaho Power that are not categorized above.

IDACORP's and Idaho Power's activities are concentrated in one industry and in one region, which exposes it to risks from lack of diversification, regional economic conditions, and regional legislation and regulation. IDACORP and Idaho Power do not have diversified operations or sources of revenue. Idaho Power comprises the bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and Idaho Power's future performance, revenues, and collectability of revenues, as well as expenses, will be affected by regional economic conditions, regulatory and legislative activity, weather conditions, and other events and conditions in its service area and in the electric power industry.

The impacts of a retiring workforce with specialized utility-specific functions and the inability to hire qualified third-party vendors could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and

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design personnel, and generation plant operators, require extensive, specialized training. Idaho Power has experienced in recent years an above-average number of employee retirements and expects the increased level of retirement of its skilled workforce and persons in key positions will continue in ~~2019~~2020 and in the near-term. At December 31, ~~2018,~~2019, approximately 22 percent of Idaho Power's employees were eligible for regular or early retirement under Idaho Power's defined benefit pension plan. This will require Idaho Power to attract, train, and retain new employees to help prevent a loss of institutional knowledge and avoid a skills gap. Idaho Power does not have employment contracts with its officers or key employees and cannot guarantee that any member of its management or any key employee at the IDACORP parent or any subsidiary level will continue to serve in any capacity for any particular period of time. The loss of skills and institutional knowledge of experienced employees and the failure to hire and the costs associated with attracting, training, and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

~~IDACORP and~~ Idaho Power ~~are subject~~also hires third-party vendors to ~~costs~~assist in performing a variety of ordinary business functions, such as power plant maintenance, data warehousing and management, software development and licensing, electric transmission and distribution operations, billing and metering processes, and vegetation management, among other ~~effects of legal and regulatory proceedings, disputes, and claims~~. ~~From time to time in the normal course of business, IDACORP and~~things. In recent years, Idaho Power ~~are subject to various lawsuits, regulatory proceedings, disputes,~~has experienced increased competition and ~~claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number~~rising prices for many forms of ~~uncertainties, and management is often unable to predict~~third-party vendor services. While Idaho Power does not rely entirely on third-party vendors for many of these business functions, the ~~outcome~~unavailability of such ~~matters; resulting liabilities~~vendors could ~~exceed amounts currently reserved or insured against with respect to such matter. The legal costs~~adversely affect the quality and ~~final resolution~~cost of ~~matters in which IDACORP or~~ Idaho ~~Power are involved could have reputational~~Power's electric service and negatively impact ~~and a short- or long-term negative effect on their financial condition and~~its results of operations. Similarly, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.operation.

Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board (FASB) and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of

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operations nor the timing of such changes. Idaho Power meets ~~conditions~~the requirements under GAAP to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants. In addition to these physical assets, Idaho Power has rights-of-way and water rights that enable it to use its facilities. Idaho Power’s system is comprised of 17 ~~hydroelectric~~hydropower generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. As of December 31, ~~2018,~~2019, the system also includes approximately ~~4,816~~4,830 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 21 transmission substations, 9 switching stations, 3231 mixed-use transmission and distribution substations, ~~183~~185 energized distribution substations (excluding mobile substations and dispatch centers), and approximately ~~27,569~~27,968 pole-miles of distribution lines.

Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for all of its ~~hydroelectric~~hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s ~~hydroelectric~~hydropower projects is discussed in Part II - Item 7 - MD&A – "Regulatory Matters – Relicensing of ~~Hydroelectric~~Hydropower Projects” in this report.

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Idaho Power's ~~hydroelectric~~hydropower projects and other owned and co-owned generating facilities and their nameplate capacities, as of the date of this report, are included in the table below.


Project	Nameplate Capacity (kW)⁽¹⁾	License Expiration			Nameplate Capacity (kW)⁽¹⁾	License Expiration
Hydroelectric Projects:
Hydropower Projects:
Properties Subject to Federal Licenses:
Lower Salmon	60,000	2034			60,000	2034
Bliss	75,000	2034			75,000	2034
Upper Salmon	34,500	2034			34,500	2034
Shoshone Falls	11,500	2034			11,500	2040
CJ Strike	82,800	2034			82,800	2034
Upper Malad - Lower Malad	21,770	2035			21,770	2035
Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex)	1,235,600	2005	⁽²⁾		1,256,500	2005	⁽²⁾
Swan Falls	27,170	2042			27,170	2042
American Falls	92,340	2025			92,340	2025
Cascade	12,420	2031			12,420	2031
Milner	59,448	2038			59,448	2038
Twin Falls	52,897	2040			52,897	2040
Other Hydroelectric:
Other Hydropower:
Clear Lakes - Thousand Springs	9,300				9,300
Total Hydroelectric	1,774,745
Total Hydropower					1,795,645
Steam and Other Generating Plants:
Jim Bridger (coal-fired)⁽³⁾	770,501				770,501
North Valmy (coal-fired)⁽³⁾	283,500
North Valmy Unit 2 (coal-fired)⁽³⁾⁽⁴⁾					145,000
Boardman (coal-fired)⁽⁴⁾⁽⁵⁾	64,200				64,200
Danskin (gas-fired)	270,900				270,900
Langley Gulch (gas-fired)	318,452				318,452
Bennett Mountain (gas-fired)	172,800				172,800
Salmon (diesel-internal combustion)	5,000				5,000
Total Steam and Other	1,885,353				1,746,853
Total Generation	3,660,098				3,542,498
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.								(2) Licensed on an annual basis while the application for a new multi-year license is pending.	(3) Idaho Power’s ownership interests are one-third for Jim Bridger, 50 percent for North Valmy, and 10 percent for Boardman. Amounts shown represent Idaho Power’s share.
(4) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.
(4) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end in 2025 at unit 2.				(4) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end in 2025 at unit 2.
(5) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.				(5) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.

IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus is comprised of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,113,631 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon.

Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act (FPA) and reservoirs and other easements. Substantially all of Idaho Power’s property is subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. Idaho Power’s property is subject to minor defects common to properties of such size and character that it believes do not materially impair the value to, or the use by, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition.

Through Idaho Energy Resources Co., Idaho Power owns a one-third interest in Bridger Coal Company (BCC) and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West holds ~~50-percent~~50-

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percent interests in nine ~~hydroelectric~~hydropower plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California.

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ITEM 3. LEGAL PROCEEDINGS

Refer to Note 11 – “Contingencies” to the consolidated financial statements included in this report.

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE) under the trading symbol "IDA". On February ~~15, 2019,~~14, 2020, there were ~~9,006~~8,583 holders of record of IDACORP common stock. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.

For information regarding IDACORP's dividend policy, see Part II - Item 7 - MD&A - "Liquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends see, Note 7 - "Common Stock" to the consolidated financial statements included in this report.

During the quarter ended December 31, 2019, IDACORP ~~did not repurchase any shares~~effected the following repurchases of ~~its~~ common ~~stock during the fourth quarter~~stock:



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1, 2019 - October 31, 2019	—	$	—	—	—
November 1, 2019 - November 30, 2019	128	103.94		—	—
December 1, 2019 - December 31, 2019	244	106.80		—	—
Total	372	$	105.82	—	—
⁽¹⁾ These shares were withheld for taxes upon vesting of restricted stock.

Table of ~~2018.~~Contents

Performance Graph

The graph below shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the Edison Electric Institute (EEI) Electric Utilities Index. The data assumes that $100 was invested on December 31, ~~2013,~~2014, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI


	2013		2014		2015		2016		2017		2018		2014		2015		2016		2017		2018		2019
IDACORP	$	100.00	$	131.78	$	139.49	$	169.92	$	197.83	$	206.86	$	100.00	$	105.85	$	128.94	$	150.12	$	156.97	$	184.73
S&P 500	100.00		113.68		115.25		129.02		157.17		150.27		100.00		101.37		113.49		138.25		132.18		173.79
EEI Electric Utilities Index	100.00		128.91		123.88		145.48		162.53		168.49		100.00		96.10		112.86		126.08		130.71		164.42

The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and shall not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.

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ITEM 6. SELECTED FINANCIAL DATA

																																IDACORP, Inc.	SUMMARY OF OPERATIONS	(thousands of dollars, except per share amounts and statistics)
	2018			2017			2016			2015			2014				2019			2018			2017			2016			2015
Operating revenues	$	1,370,752		$	1,349,486		$	1,262,020		$	1,270,289		$	1,282,524			$	1,346,383		$	1,370,752		$	1,349,486		$	1,262,020		$	1,270,289
Operating income⁽¹⁾	296,922			315,545			283,582			297,048			267,194				298,326			296,922			315,545			283,582			297,048
Net income attributable to IDACORP, Inc.	226,801			212,419			198,288			194,679			193,480				232,854			226,801			212,419			198,288			194,679
Diluted earnings per share	4.49			4.21			3.94			3.87			3.85				4.61			4.49			4.21			3.94			3.87
Dividends declared per share	2.40			2.24			2.08			1.92			1.76				2.56			2.40			2.24			2.08			1.92

Financial Condition:
Total assets⁽²⁾	$	6,382,754		$	6,045,405		$	6,289,897		$	6,023,314		$	5,701,037			$	6,641,201		$	6,382,754		$	6,045,405		$	6,289,897		$	6,023,314
Long-term debt (including current portion)⁽²⁾	$	1,834,788		$	1,746,123		$	1,745,678		$	1,726,474		$	1,599,686			$	1,836,659		$	1,834,788		$	1,746,123		$	1,745,678		$	1,726,474

Financial Statistics:
Times interest charges earned:
Before tax⁽³⁾⁽¹⁾	3.55			3.82			3.54			3.61			3.38				3.65			3.55			3.82			3.54			3.61
After tax⁽⁴⁾⁽²⁾	3.36			3.30			3.15			3.12			3.19				3.40			3.36			3.30			3.15			3.12
Book value per share⁽⁵⁾⁽³⁾	$	47.04		$	44.68		$	42.74		$	40.88		$	38.85			$	48.90		$	47.04		$	44.68		$	42.74		$	40.88
Market-to-book ratio⁽⁶⁾⁽⁴⁾	198		%	204		%	188		%	166		%	170		%		218		%	198		%	204		%	188		%	166		%
Payout ratio⁽⁷⁾⁽⁵⁾	53		%	53		%	53		%	50		%	46		%		56		%	53		%	53		%	53		%	50		%
Return on year-end common equity⁽⁸⁾⁽⁶⁾	9.6		%	9.4		%	9.2		%	9.5		%	9.9		%		9.4		%	9.6		%	9.4		%	9.2		%	9.5		%

(1) Operating income in 2018-2014 reflects IDACORP's 2018 adoption of Accounting Standards Update (ASU) 2017-07. IDACORP retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit cost. The non-service cost components of net periodic benefit cost were reclassified from "Other operations and maintenance" and "Other" operating expenses to "Other Expense, Net" on the consolidated statements of income to conform to current period presentation.
(2) Amounts in 2014 were adjusted to reflect IDACORP's 2015 adoption of ASU 2015-03, which required debt issuance costs be reported as reductions of long-term debt rather than as long-term assets on the consolidated balance sheets.
The financial statistics listed above are calculated in the following manner:
(3) The sum of "Interest on long-term debt," "Other interest" expense, and "Income before income taxes" divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(4) The sum of "Interest on long-term debt," "Other interest" expense, and "Net income attributable to IDACORP, Inc." divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(5) "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year divided by shares outstanding at the end of the year.
(6) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (5) above.
(7) Dividends paid per common share divided by diluted earnings per share.
(8) "Net income attributable to IDACORP, Inc." on the consolidated income statements divided by "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year.
(1) The sum of "Interest on long-term debt," "Other interest" expense, and "Income before income taxes" divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.																(1) The sum of "Interest on long-term debt," "Other interest" expense, and "Income before income taxes" divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(2) The sum of "Interest on long-term debt," "Other interest" expense, and "Net income attributable to IDACORP, Inc." divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.																(2) The sum of "Interest on long-term debt," "Other interest" expense, and "Net income attributable to IDACORP, Inc." divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(3) "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year divided by shares outstanding at the end of the year.																(3) "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year divided by shares outstanding at the end of the year.
(4) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (4) above.																(4) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (4) above.
(5) Dividends paid per common share divided by diluted earnings per share.																(5) Dividends paid per common share divided by diluted earnings per share.
(6) "Net income attributable to IDACORP, Inc." on the consolidated income statements divided by "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year.																(6) "Net income attributable to IDACORP, Inc." on the consolidated income statements divided by "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2018 compared with 2017 can be found in their Annual Report on Form 10-K for the year ended December 31, 2018 (2018 Annual Report). See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2018 Annual Report for further information on the companies' prior period results of operations. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

INTRODUCTION

IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity.

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. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; and Ida-West Energy Company, an operator of small ~~hydroelectric~~hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

EXECUTIVE OVERVIEW

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements and recognitions during ~~2018~~2019 include:

IDACORP achieved net income growth for ~~an eleventh~~a twelfth consecutive year;

IDACORP provided a 1413 percent cumulative annual total shareholder return over the past three years, including share price appreciation and dividends ~~paid, ranking~~paid;

Idaho Power's customer count grew 2.5 percent in 2019;

Idaho Power achieved its lowest ever recorded employee safety incident rate, which was significantly below the national average and the average of peer utilities of similar size;

Idaho Power reached its highest ever recorded residential customer satisfaction score, the highest of any investor-owned utility in the ~~63rd percentile among peer companies~~nation, as rated by an independent third party;

Idaho Power continued its strong performance in ~~the Edison Electric Institute (EEI) Electric Utilities Index;~~

IDACORP received its second EEI Electric Utilities Index award in the past three years, for the best total shareholder return performance among small cap utilities (market capitalization of less than $5 billion) over the past five years, measured as of September 30, 2018;system reliability, slightly behind 2018's record reliability score;

IDACORP increased its quarterly common stock dividend from ~~$0.59~~$0.63 per share to ~~$0.63~~$0.67 per share, as a part of a ~~110~~123 percent increase in quarterly dividends approved over the last ~~seven years under~~eight years;

IDACORP adopted a new dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, an increase from the ~~company's objective to pay dividends at the upper end~~previous policy adopted in 2011 that targeted a dividend payout ratio of ~~the range of~~between 50 percent to 60 percent of sustainable earnings;

Idaho Power reached an agreement with NV Energy, approved by the IPUC and OPUC, that facilitates the planned end of Idaho Power's ~~customer count grew 2.3 percent~~participation in ~~2018;~~

coal-fired operations at units 1 and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and 2025, respectively. As planned, Idaho Power ~~ranked second~~ended its participation in ~~J.D. Power's Electric Utility Residential Customer Satisfaction Study in its West Region Midsize segment for the second year in a row;~~

~~Idaho Power reached milestones on key transmission projects as the U.S. Forest Service issued a record of decision on the siting~~unit 1 of the Boardman-to-Hemingway 500-kV project and the U.S. Bureau of Land Management (BLM) issued a record of decision for the remaining transmission line segments of the Gateway West 500-kV transmission project;North Valmy plant in December 2019;


•	Idaho Power ~~achieved~~announced its "Clean Today, Cleaner Tomorrow.^®" goal to provide its customers with 100-percent clean energy by 2045; and


•	Idaho Power beat its carbon dioxide (CO₂) emissions intensity goal, with an average reduction ~~goal; and~~of 29 percent since 2010.

Idaho Power reached several constructive regulatory settlements that were approved by the IPUC and OPUC related to recent income tax reform, the indefinite extension, with modifications, of the current earnings support and revenue sharing mechanism, the prudence of certain Hells Canyon Complex (HCC) relicensing costs, and the treatment of costs incurred to join the energy imbalance market implemented in the western United States (Western EIM).

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Summary of ~~2018~~2019 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2019, 2018, ~~2017,~~ and ~~2016~~2017 (in thousands, except earnings per share amounts):


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018		2017
Idaho Power net income	$	222,334	$	206,347	$	189,242	$	224,437	$	222,334	$	206,347
Net income attributable to IDACORP, Inc.	$	226,801	$	212,419	$	198,288	$	232,854	$	226,801	$	212,419
Average outstanding shares – diluted (000’s)	50,510		50,424		50,373		50,537		50,510		50,424
IDACORP, Inc. earnings per diluted share	$	4.49	$	4.21	$	3.94	$	4.61	$	4.49	$	4.21

The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, ~~2018,~~2019, from the year ended December 31, ~~2017~~2018 (items are in millions and are before tax unless otherwise noted):


Net income attributable to IDACORP, Inc. - December 31, 2017			$	212.4
Net income attributable to IDACORP, Inc. - December 31, 2018								$	226.8
Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanisms	10.3					18.8
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms	(9.4	)				(21.4	)
Idaho fixed cost adjustment (FCA) revenues	17.7					1.0
Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms	(26.9	)				(2.8	)
Transmission wheeling and other revenues	16.1
Non-cash amortization of regulatory deferrals (related to tax reform)	(4.0	)
Other operations and maintenance (O&M) expenses (excluding non-cash amortization of regulatory deferrals)	(13.8	)
Transmission wheeling-related revenues						(5.3	)
Other operations and maintenance (O&M) expenses						8.7
Other changes in operating revenues and expenses, net	(3.6	)				(1.7	)
Decrease in Idaho Power operating income prior to sharing mechanism	(13.6	)
Decrease in revenues as a result of sharing mechanism	(5.0	)
Decrease in Idaho Power operating income	(18.6	)
Earnings of unconsolidated equity-method investments	1.4
Prior year provision for sharing with customers						5.0
Increase in Idaho Power operating income						2.3
Non-operating income and expenses, net	0.3					9.9
Decrease in income tax expense from remeasurement of deferred taxes and make-whole premium for early bond redemption	9.0
Income tax expense (excluding remeasurement of deferred taxes and make-whole premium for early bond redemption)	23.9
Income tax expense						(10.1	)
Total increase in Idaho Power net income			16.0					2.1
Other IDACORP changes (net of tax)			(1.6		)			4.0
Net income attributable to IDACORP, Inc. - December 31, 2018			$	226.8
Net income attributable to IDACORP, Inc. - December 31, 2019								$	232.9

IDACORP's net income increased ~~$14.4~~$6.1 million for ~~2018~~2019 compared with ~~2017,~~2018, primarily due to higher net income at Idaho ~~Power. Customer~~Power and IFS.

Idaho Power's customer growth of 2.5 percent added ~~$10.3~~$18.8 million to Idaho Power's operating income compared with ~~2017. Sales~~2018. Lower sales volumes on a per-customer basis decreased operating income by ~~$9.4~~$21.4 million in ~~2018~~2019 compared with ~~2017. A decrease in sales volumes~~2018, primarily due to ~~residential customers was partially offset by an increase in usage per~~lower irrigation ~~customer. Milder~~sales. Greater precipitation and more moderate spring and summer temperatures in ~~2018 compared with 2017 caused residential customers to use 6 percent less electricity per customer, mostly for cooling and heating purposes, while decreased precipitation~~Idaho Power's service area led agricultural irrigation customers to use 912 percent ~~more electricity~~less energy per customer to operate irrigation ~~pumps. However, due mostly to the lower usage by Idaho residential customers, the FCA mechanism added $17.7 million to operating income~~pumps during ~~2018~~2019 compared with ~~2017.~~2018. To a lesser extent, sales volumes on a per-customer basis in 2019 were negatively affected by lower per-customer commercial and industrial sales.

The net decrease in retail revenues per MWh reduced operating income by ~~$26.9~~$2.8 million in ~~2018~~2019 compared with ~~2017. The~~2018. As provided by the settlement ~~stipulations~~stipulation approved by the IPUC ~~and OPUC during the second quarter of~~in 2018 ~~relating~~related to ~~recent~~ income tax reform, reduced revenues by approximately $22 million in 2018. The timing of the revenue reductions may not align with decreases in income tax expense in any given period due to the method and timing of customer rate reductions provided for in the settlement

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stipulations, the nature and timing of income tax accruals, discrete items, and other items discussed in more detail in the "Income Tax Reform" section below. Also, a change in customer sales mix reduced the retail revenues per MWh ~~as volumes sold to residential customers made up a smaller portion of the customer sales mix.~~

~~During 2018, Idaho Power benefited from a $16.1 million increase~~ in ~~transmission wheeling and other revenues, compared with 2017. This change was largely due to a 37 percent increase in the Open Access Transmission Tariff (OATT) rate in October 2017, partially offset~~2019 were reduced by ~~a 10 percent decrease in the OATT rate in October 2018 and, to a lesser extent, an increase in wheeling volumes.~~

~~Other O&M expenses included $4.0~~$7.4 million of non-cash accruals for future amortization ~~expense of~~related to regulatory deferrals that would otherwise be a future liability of Idaho customers, compared with a $1.5 million revenue reduction in 2018. In 2018, a corresponding $4.0 million of non-cash accruals were recorded as ~~provided~~other O&M expense for the amortization of specified deferrals. The decrease in retail revenues per MWh from these non-cash accruals was partially offset by changes in the customer sales mix, as volumes sold to residential customers in 2019 made up a greater portion of the customer sales mix compared with 2018. Residential customers generally pay a higher per-MWh rate than other customers.

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During 2019, transmission wheeling-related revenues decreased $5.3 million compared with 2018. Idaho Power's open access transmission tariff (OATT) rates decreased 10 percent in October 2018 and 13 percent in October 2019. To a lesser extent, lower volumes also reduced transmission wheeling-related revenues.

Other O&M expenses were $8.7 million lower in 2019 compared with 2018, as Idaho Power's continued focus on managing other O&M expenses resulted in lower expenses across a number of areas. Lower bad debt expense reduced other O&M expenses by $1.1 million, due primarily to enhanced collection efforts and a strong economy. Also, other O&M expenses in 2018 included $4.0 million of non-cash amortization expense of regulatory deferrals pursuant to the settlement stipulation approved by the IPUC in 2018 related to income tax reform. ~~Excluding~~

Based on its 2019 Idaho ROE, Idaho Power recorded no additional ADITC amortization or provision against current revenues for sharing of earnings with customers in 2019 under the ~~non-cash amortization of~~Idaho regulatory ~~deferrals, other O&M expenses were $13.8 million higher~~settlement stipulation approved in 2018 compared with 2017. In 2018, compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses.

October 2014. In 2018, Idaho Power recorded a $5.0 million ~~as a~~ provision against ~~current~~ revenues for sharing of earnings with customers.

Non-operating income and expenses, net, increased $9.9 million in 2019 compared with 2018. As disclosed in Note 12 - "Benefit Plans" to ~~be refunded to customers through~~the consolidated financial statements included in this report, a ~~future rate reduction, through~~ temporary deviation from an Idaho Power substantive postretirement plan resulted in a $4.2 million charge in 2018 that did not recur in 2019. Allowance for equity funds used during construction increased $2.8 million in 2019 as the ~~Idaho-jurisdiction power cost adjustment (PCA) mechanism pursuant to a settlement stipulation~~average construction work in progress balance was higher throughout 2019 compared with 2018. Also, investment income from the ~~IPUC as described in "Regulation of Rates and Cost Recovery" below.~~

Rabbi trust associated with Idaho Power's nonqualified defined benefit pension plans increased $2.2 million based on stronger asset returns in 2019 compared with 2018.

During 2018, Idaho Power recorded tax benefits for a $5.7 million remeasurement of deferred taxes resulting from ~~the federal and Idaho~~ income tax ~~rate change (discussed~~reform and $1.3 million for tax-deductible bond redemption costs incurred in ~~further detail below) on the adjustment of temporary differences as a result of IDACORP’s 2017 consolidated~~2018. There was no such remeasurement or bond redemption in 2019. These items, combined with higher pre-tax net income in 2019, resulted in higher income tax ~~return filings and the $1.3 million flow-through benefit~~expense in 2019 compared with 2018. Amortization of avintage investment tax ~~deductible make-whole premium~~credits that ~~Idaho Power paid~~became available in ~~connection with the early redemption of long-term debt in April 2018 decreased Idaho Power's~~2019 lowered income tax expense by ~~$7.0~~$3.4 million, most of which is not expected to recur.

At IFS, a $3.0 million increase in ~~2018. Idaho Power recorded $2.0 million of income tax expense in 2017 for the initial remeasurement of deferred taxes resulting~~distributions from the ~~federal and Idaho~~sale of low-income housing properties led to higher IFS net income ~~tax rate change. Excluding these items, Idaho Power income tax expense was $23.9 million lower during 2018~~in 2019 compared with ~~2017, due mostly to the lower federal and state statutory income tax rates resulting from income tax reform.~~2018.

~~2018~~2020 Initiatives and Strategy

IDACORP’s strategy is focused on four areas: growing ~~to enhance~~ financial strength, improving Idaho Power's core business, enhancing Idaho Power’s brand, and ~~focusing on safety~~keeping employees safe and ~~employee engagement.~~engaged. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic ~~focus areas,~~cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working ~~to continue~~for strong, sustainable financial results by continuing to provide safe, fair-priced, reliable service to its customers from a diversified ~~source of~~ generation ~~resources, with a continued commitment to strong, sustainable financial results.~~resources. For more information on the business strategy of the companies, see Part I, Item 1 – “Business - Business Strategy” in this report.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by a number of factors, and the impact of those factors is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:

~~Regulation of Rates and Cost Recovery:~~ The price that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has regulatory settlement stipulations in Idaho that include provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent (9.4 percent after 2019) return on year-end equity in the Idaho jurisdiction (Idaho ROE). The settlement stipulations also provide for the potential sharing between Idaho Power and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. The settlement stipulations provide for modifications of certain terms and the indefinite extension of the mechanism beyond the original termination date of December 31, 2019. The specific terms of these settlement stipulations are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. During

•

Regulation of Rates and Cost Recovery: The prices that Idaho Power is authorized to charge for its electric and transmission services are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and prudently managing expenses and investments. Idaho Power has regulatory settlement stipulations in Idaho that include provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent (9.4 percent after 2019) return on year-end equity in the Idaho jurisdiction (Idaho ROE). The settlement stipulations also provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. The settlement stipulations provide for modifications of certain terms and the indefinite extension of the mechanism beyond the original termination date of December 31, 2019. The specific terms of these settlement stipulations are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. During 2020, Idaho Power will

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~~2019, Idaho Power will~~ continue to assess the need to file a general rate case to reset base rates, but does not anticipate filing a rate case in the next twelve months.

~~Income Tax Reform:~~ In December 2017, the Tax Cuts and Jobs Act was signed into law, which lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations (Tax Cuts and Jobs Act). The majority of the changes, including the rate reduction, became effective on January 1, 2018. 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 May 2018, the IPUC ~~issued an order approving~~ a settlement stipulation related to these changes in income taxes (May 2018 Idaho Tax Reform Settlement Stipulation). Beginning June 1, 2018, the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million for the amortization of 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 through the PCA mech~~anism during the period from June 2018 through May 2019, for the income tax reform benefits accrued from January 2018 to May 2018 and for amounts included in Idaho Power's transmission revenues. The May 2018 Idaho Tax Reform Settlement Stipulation was designed to return to Idaho customers their share of the estimated annual pro forma tax expense reductions resulting from income tax reform, based on the full-year 2017 as required by the IPUC. Idaho Power's financial results from 2018 forward will be affected by any differences between annual income tax expense and the pro forma 2017 income tax expense used in the settlement until incorporated into a future rate proceeding or rate case. Refer to "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings.

~~Economic Conditions and Loads:~~ Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands.

•

Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure and purchase power. In recent years, Idaho Power has seen growth in the number of customers in its service area. In 2019, Idaho Power's customer count grew by 2.5 percent. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Employment in Idaho Power's service area grew by approximately 3.2 percent based on Idaho Department of Labor preliminary December 2019 data. Idaho Power continues to support State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area.

In June 2019, Idaho Power has seen growth in the number of customers in its service area. In 2018, Idaho Power's customer count grew by 2.3 percent, and employment in Idaho Power's service area grew by approximately 2.2 percent based on Idaho Department of Labor preliminary December 2018 data. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power has in recent years supported State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area.

~~In August 2018, Idaho Power began preparing~~released its 2019 Integrated Resource Plan (IRP), Idaho Power's long-term forecast of loads and ~~resources.~~resources, which was amended in January 2020. For more information on the 2019 IRP, including the ~~preliminary~~ load forecast assumptions Idaho Power ~~expects to use~~used in its 2019 IRP, refer to "Resource Planning" in Item 1 - "Business" in this Form 10-K.

•

Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year, when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to Idaho residential and small commercial customers is mitigated through the FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements in this report.

~~Weather Conditions:~~ Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year, when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to Idaho residential and small commercial customers is mitigated through the FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements in this report.

Further, as Idaho Power's ~~hydroelectric~~hydropower facilities comprise ~~approximately~~over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When ~~hydroelectric~~hydropower generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable ~~hydroelectric~~hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest ~~hydroelectric~~hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy ~~sales of its excess power.~~sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms.

•

Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.

•

Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies heavily on natural gas and coal to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs.

~~Rate Base Growth and Infrastructure Investment:~~ As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho


•	Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies,

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Power has been pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the HCC, its largest hydroelectric generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.

~~Mitigation of Impact of Fuel and Purchased Power Expense:~~ In addition to hydroelectric generation, Idaho Power relies heavily on natural gas and coal to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power.

~~Regulatory and Environmental Compliance Costs:~~ ~~Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies,~~ including the FERC, the North American Electric Reliability Corporation, and Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Recently, energy industry regulators have issued substantial penalties for utilities alleged to have violated reliability and critical infrastructure protection requirements. Moreover, environmental laws and regulations, in particular, may increase the cost of operating generation plants, including Idaho Power's coal-fired plants, ~~and~~increase the cost of constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade, and due to economic factors in part associated with the costs of compliance with environmental regulation, has accelerated the retirement dates of ~~certain of~~ its jointly-owned coal-fired ~~power~~generating plants.

•

Water Management and Relicensing of the Hells Canyon Hydropower Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydropower generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.

~~Water Management and Relicensing of the Hells Canyon Hydroelectric Project:~~ Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydroelectric projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydroelectric generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.

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RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for ~~2018~~2019 are compared with ~~2017 and the results for 2017 are compared with 2016.~~2018.

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last ~~three~~two years.


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018
Retail energy sales	14,587		14,571		14,196		14,537		14,587
Wholesale energy sales	2,246		1,934		742		2,171		2,246
Bundled energy sales	617		202		444		680		617
Total energy sales	17,450		16,707		15,382		17,388		17,450
Hydroelectric generation	8,682		8,900		6,408
Hydropower generation							8,294		8,682
Coal generation	3,274		3,284		4,045		3,012		3,274
Natural gas and other generation	1,408		1,504		1,722		2,114		1,408
Total system generation	13,364		13,688		12,175		13,420		13,364
Purchased power	5,431		4,242		4,337		5,200		5,431
Line losses	(1,345	)	(1,223	)	(1,130	)	(1,232	)	(1,345	)
Total energy supply	17,450		16,707		15,382		17,388		17,450

For purposes of illustration, Boise, Idaho, weather-related information for the last ~~three~~two years is presented in the table that follows.


	Year Ended December 31,				Year Ended December 31,
	2018	2017	2016	Normal⁽²⁾	2019	2018	Normal⁽²⁾
Heating degree-days⁽¹⁾	4,984	5,655	4,807	5,514	5,314	4,984	5,514
Cooling degree-days⁽¹⁾	1,116	1,341	1,001	942	1,020	1,116	942
Precipitation (inches)	10.6	15.4	8.7	11.3	14.5	10.6	11.3

(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree above 65 degrees is counted as one cooling degree-day, and each degree below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers.

(2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.

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Sales Volume and Generation: In ~~2018,~~2019, retail sales volumes ~~were relatively flat~~decreased less than 1 percent compared with ~~those of~~ the prior year. Greater precipitation and more moderate spring and summer temperatures in Idaho Power's service area led agricultural irrigation customers to use 12 percent less energy per customer to operate irrigation pumps during 2019. Customer growth ~~increased~~partially offset the decrease in sales volumes per customer during ~~2018~~2019 compared with ~~2017,~~2018, with the number of Idaho Power's customers growing by ~~2.3~~2.5 percent. During 2018, usage per irrigation customer was approximately 9 percent higher compared with 2017. Precipitation in the Idaho Power service area during 2018 was significantly less than in 2017, which increased usage by irrigation customers in 2018. Usage per residential customer was approximately 6 percent lower in 2018 compared with 2017. The decrease in residential usage was primarily due to milder weather during 2018 compared with 2017, which decreased the use of electricity for heating and cooling purposes. Cooling degree-days in Boise, Idaho were 17 percent lower during 2018 compared with 2017, but 18 percent above normal. Heating degree-days in Boise, Idaho were 12 percent lower during 2018 compared with 2017, and 10 percent below normal. Also, bundled energy sales (electric power combined with renewable energy certificates) volumes increased during 2018 compared with 2017. The solar generation projects under PURPA contracts that were initiated in 2017 generated an increased number of renewable energy credits to sell bundled with electricity.

Total system generation ~~decreased 2 percent during 2018 compared~~in 2019 was consistent with ~~2017. Hydroelectric generation decreased 2 percent during 2018 compared with 2017, but comprised 65 percent~~that of ~~Idaho Power's total system generation during both 2018 and 2017. In 2018, purchased power increased 28 percent compared with 2017 due to an~~the prior year. An increase in ~~power purchased from~~natural gas generation ~~projects under mandatory PURPA contracts~~more than offset decreases in hydropower and ~~an increase in other purchased power resulting from favorable wholesale gas and electricity market conditions and, to a lesser extent, transactions in the Western EIM, which commenced in~~coal generation.

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~~April 2018. The availability of hydroelectric generation and an increase in purchased power during 2018 reduced thermal generation compared with 2017.~~

Wholesale energy sales volumes ~~increased 312~~decreased 75 thousand MWh, or 163 percent, during ~~2018~~2019 compared with ~~2017,~~2018, due primarily to ~~an increase~~a decrease in purchased power, both in market purchases and in purchases under PURPA contracts, resulting in ~~increased~~decreased energy available for wholesale energy sales. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power in the wholesale energy markets.

The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms."

Operating Revenues

Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of customers for the last ~~three~~two years.


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018
Retail revenues:
Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA⁽¹⁾)	$	530,527		$	552,333		$	514,954
Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA⁽¹⁾)	310,299			319,195			302,650
Residential (includes $35,587 and $34,625, respectively, related to the FCA⁽¹⁾)										$	526,966		$	530,527
Commercial (includes $1,336 and $1,299, respectively, related to the FCA⁽¹⁾)										295,203			310,299
Industrial	190,130			195,124			182,590			181,372			190,130
Irrigation	158,001			150,030			156,505			135,850			158,001
Provision for sharing	(5,025		)	—			—			—			(5,025		)
Deferred revenue related to HCC relicensing AFUDC⁽²⁾	(8,780		)	(10,706		)	(10,706		)	(8,780		)	(8,780		)
Total retail revenues	$	1,175,152		$	1,205,976		$	1,145,993		$	1,130,611		$	1,175,152
Volume of Sales (MWh)
Residential	5,135			5,355			5,004			5,273			5,135
Commercial	4,105			4,099			3,999			4,092			4,105
Industrial	3,371			3,346			3,243			3,412			3,371
Irrigation	1,976			1,771			1,950			1,760			1,976
Total retail MWh sales	14,587			14,571			14,196			14,537			14,587
Number of retail customers at year-end
Residential	464,670			453,605			444,431			477,404			464,670
Commercial	71,680			70,411			69,344			72,855			71,680
Industrial	120			119			121			131			120
Irrigation	21,175			20,932			20,638			21,387			21,175
Total customers	557,645			545,067			534,534			571,777			557,645

(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~~The IPUC ~~is allowing~~allows 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 approximately $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 "Regulatory Matters" in this MD&A, Idaho Power was collecting $10.7 million annually.~~

Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last ~~three~~two years. The primary influences on customer demand for electricity are weather, economic

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conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates

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based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.

Retail Revenues ~~- 2018 Compared with 2017~~: Retail revenues decreased ~~$30.8~~$44.5 million in ~~2018~~2019 compared with ~~2017.~~2018. The primary factors affecting retail revenues during the period were the following:

•

Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanism, decreased retail revenues by $3.8 million in 2019 compared with 2018. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to income tax reform described further in "Regulatory Matters" in this MD&A reduced revenues in 2019 more significantly than in 2018. Customer rates also include the return to customers of amounts related to the PCA mechanism, which decreased revenues by $42.8 million in 2019 compared with 2018. The return to customers of amounts related to the PCA mechanism in rates does not have a significant effect on operating income as a corresponding amount is recorded as a reduction of expense in the same period it is returned through rates.


•	Customers: Customer growth of 2.5 percent increased retail revenues by $27.0 million in 2019 compared with 2018.

•

Usage: Lower usage (on a per customer basis), primarily by irrigation customers, decreased retail revenues by $30.9 million during 2019 compared with 2018. Greater precipitation and more moderate spring and summer temperatures in Idaho Power's service area led agricultural irrigation customers to use 12 percent less energy per customer to operate irrigation pumps during 2019. To a lesser extent, sales volumes on a per-customer basis were negatively affected by lower per-customer commercial and industrial sales.

•

Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue 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 through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small general service customers during 2019 increased the amount of FCA revenue accrued by $1.0 million compared with 2018.

•

Sharing: In 2019, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers as Idaho ROE was above 10.0 percent. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

~~Rates~~: Rate changes decreased retail revenues by $39.0 million in 2018 compared with 2017. As a direct result of settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to income tax reform described further in "Regulatory Matters" in this MD&A, Idaho Power's revenues decreased approximately $22 million in 2018 compared with 2017. The timing of the revenue reductions may not align with decreases in income tax expense in any given period due to the method and timing of customer rate reductions provided for in the settlement stipulations, the nature and timing of income tax accruals, discrete items, and other items discussed in this MD&A. The rates include collection of amounts related to the PCA mechanism, which decreased revenues by $15.4 million in 2018 compared with 2017. The collection of amounts related to the PCA mechanism in rates has no effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates.

~~Customers: Customer growth of 2.3 percent increased retail revenues by $13.5 million in 2018 compared with 2017.~~

~~Usage~~: Lower usage (on a per customer basis), primarily by residential customers, decreased retail revenues by $18.0 million during 2018 compared with 2017. Decreased usage was primarily the result of more mild temperatures in Idaho Power's service area during 2018 compared with 2017, which led to decreased usage by residential customers for heating and cooling. For 2018, a 6 percent decrease in usage per residential customer compared with 2017 was partially offset by a 9 percent increase in usage per irrigation customer. Precipitation in Idaho Power's service area during 2018 was significantly less than 2017, which led to increased usage by irrigation customers.

~~Idaho FCA Revenue~~: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue 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 through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small general service customers during 2018 increased the amount of FCA revenue accrued by $17.7 million compared with 2017.

~~Sharing~~: During 2018, Idaho Power recorded $5.0 million as a provision against current revenues to be refunded to customers through a future rate reduction. If approved, the rate reduction would be included in PCA rates beginning in June 2019. Idaho Power did not record any provision for sharing in 2017. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

~~Retail Revenues - 2017 Compared with 2016: Retail revenues increased $60.0 million in 2017 compared with 2016. The factors affecting retail revenues during the period are discussed below:~~

~~Rates~~: Rate changes, including the revenue accruals provided for in the Valmy settlement stipulation, increased retail revenues by $39.8 million for 2017 compared with 2016. In the second quarter of 2017, the IPUC and OPUC each approved settlement stipulations related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025, which increased retail revenues collections and retail revenues accruals for 2017 compared with 2016. Colder winter temperatures in early 2017 and warmer summer temperatures during the third quarter of 2017 resulted in residential sales making up a larger portion of the sales mix and led to a greater proportion of residential sales in higher rate categories in Idaho Power's tiered rate structure in 2017 compared with 2016.

~~Customers: Customer growth of 2.0 percent increased retail revenues by $12.1 million in 2017 compared with 2016.~~

~~Usage~~: Higher usage (on a per customer basis), primarily by residential, industrial, and commercial customers increased retail revenues by $20.1 million in 2017 compared with 2016. Increased usage was primarily the result of warmer summer temperatures and colder winter temperatures in Idaho Power's service area, which increased usage by residential customers for cooling and heating. Cooling degree days and heating degree days were significantly higher in 2017 compared with 2016. These increases in usage were partially offset by an 11 percent decrease in usage per irrigation customer due to increased precipitation in Idaho Power's service area during 2017 compared with 2016,

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particularly in the first six months of 2017. Greater customer participation in energy efficiency programs, resulting in decreased usage, partially offset the increase in total usage during 2017 compared with 2016.

~~Idaho FCA Revenue~~: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue 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 through volume-based rates during the year. Higher usage (on a per customer basis) by residential and small general service customers during 2017 decreased the amount of FCA revenue accrued by $12.1 million compared with 2016. Idaho Power accrued $18.2 million of FCA revenue in 2017 compared with $30.3 million of FCA revenue in 2016.

Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the Western EIM, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last ~~three~~two years (in thousands, except for MWh amounts).


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018
Wholesale energy revenues	$	52,845	$	24,790	$	11,900	$	71,198	$	52,845
Wholesale MWh sold	2,246		1,934		742		2,171		2,246
Wholesale energy revenues per MWh	$	23.53	$	12.82	$	16.04	$	32.80	$	23.53

~~Wholesale Energy Sales - 2018 Compared with 2017~~: In ~~2018,~~2019, wholesale energy revenue increased by ~~$28.1~~$18.4 million, or ~~113~~35 percent, compared with ~~2017.~~2018. Wholesale energy sales volumes ~~increased 16~~decreased 3 percent in ~~2018~~2019 compared with ~~2017, and~~2018, but the average price of wholesale energy sales was 8439 percent higher for ~~2018~~2019 compared with ~~2017.~~2018. During the fourth quarter of 2018, a natural gas pipeline ruptured in British Columbia, Canada, disrupting natural gas flows to the Pacific Northwest and Western Canada, driving up energy and natural gas prices in

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the ~~region, including~~region. During the first half of 2019, the pipeline was operating at reduced capacity, which contributed to continued elevated energy prices during that period.

Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling decreased $5.3 million in ~~Idaho Power's service area. An increase in purchased power, both in market purchases and in purchases under PURPA contracts, resulted in additional energy available for wholesale energy sales in 2018~~2019 compared with 2017. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power in the wholesale energy markets. The increase in wholesale energy sales volumes and sales prices during 2018 compared with 2017 was also due to transactions in the Western EIM, which commenced in April 2018. ~~Under the Western EIM, participating parties enable their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads.~~

~~Wholesale Energy Sales - 2017 Compared with 2016~~: For 2017, wholesale energy sales revenue increased by $12.9 million, or 108 percent compared with 2016 as generation from Idaho Power's hydroelectric plants increased due to significantly greater precipitation in 2017 compared with 2016. The increase in hydroelectric generation resulted in more energy available for wholesale energy sales in 2017 compared with 2016. The average price of wholesale energy sales was 20 percent lower for 2017 compared with 2016, as an increase in output from hydroelectric resources in the northwest United States region due to increased precipitation during the period, as well as additional output from new wind and solar projects throughout the region, increased surplus power available for sale and decreased wholesale power market prices.

~~Transmission Wheeling Revenues:~~ ~~Revenue from transmission wheeling increased $15.1 million, or 34 percent, in 2018 compared with 2017, largely due to~~ Idaho Power's OATT ~~rate that increased~~rates decreased 10 percent in October ~~2017~~2018 and to13 percent October 2019. To a lesser extent, ~~an increase in wheeling volumes. In October 2017, Idaho Power's OATT rate increased from $25.52 per kW-year to $34.90 per kW-year. In October 2018, the rate decreased to $31.25 per kW-year.~~lower volumes also reduced transmission wheeling-related revenues. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate. Revenue from transmission wheeling increased $11.5 million, or 35 percent, in 2017 compared with 2016, largely due to an increase in wheeling volumes, an increase in Idaho Power's OATT rate, and a new long-term wheeling agreement that became effective in July 2016.

Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. The cumulative variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. 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 December 31, ~~2018,~~2019, Idaho Power's energy efficiency rider balances were a ~~$5.3~~$0.3 million regulatory ~~liability~~asset in the Idaho jurisdiction and a ~~$1.4~~$1.2 million regulatory asset in the Oregon jurisdiction.

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Operating Expenses

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last ~~three~~two years (in thousands, except for MWh amounts).


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018
Expense
PURPA contracts	$	189,722	$	169,788	$	153,665	$	187,344	$	189,722
Other purchased power (including wheeling)	104,092		79,162		92,099		97,922		104,092
Total purchased power expense	$	293,814	$	248,950	$	245,764	$	285,266	$	293,814
MWh purchased
PURPA contracts	3,045		2,800		2,314		2,983		3,045
Other purchased power	2,386		1,442		2,023		2,217		2,386
Total MWh purchased	5,431		4,242		4,337		5,200		5,431
Cost per MWh from PURPA contracts	$	62.31	$	60.64	$	66.41	$	62.80	$	62.31
Cost per MWh from other sources	$	43.63	$	54.90	$	45.53	$	44.17	$	43.63
Weighted average - all sources	$	54.10	$	58.69	$	56.67	$	54.86	$	54.10

Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost ~~hydroelectric~~hydropower and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. The other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

~~Purchased Power - 2018 Compared with 2017~~: Purchased power expense ~~increased $44.9~~decreased $8.5 million, or 183 percent, in ~~2018~~2019 compared with ~~2017,~~2018, primarily due to a 657 percent ~~increase~~decrease in the volume of other non-PURPA power ~~purchases and a 9 percent increase in the volume of power purchases from generation projects under PURPA contracts.~~purchases. Other non-PURPA purchased power volumes ~~increased during 2018 compared with 2017 due~~decreased as Idaho Power used its own generation to ~~wholesale gas and electricity market conditions and due to transactions in the Western EIM, which commenced in April 2018.~~meet customer demand. These volume ~~increases~~decreases were partially offset by ~~decreases~~increases in cost per MWh of power purchased from ~~sources other than PURPA contracts.~~all sources.

~~Purchased Power - 2017 Compared with 2016~~: Purchased power expense increased $3.2 million, or 1 percent, in 2017 compared with 2016, primarily due to an increase in generation provided by PURPA solar contracts. The increase in PURPA volumes was partially offset by decreases in costs per MWh. Other purchased power expense decreased $12.9 million, or 14 percent, as abundant hydroelectric generation in 2017 compared with 2016 reduced the need for market purchases to meet load requirements.

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Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last ~~three~~two years (in thousands, except per MWh amounts).


	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2019		2018
Expense
Coal	$	115,524	$	107,894	$	137,689	$	105,257	$	115,524
Natural gas⁽¹⁾	17,674		37,935		41,802		51,615		17,674
Total fuel expense	$	133,198	$	145,829	$	179,491	$	156,872	$	133,198
MWh generated
Coal	3,274		3,284		4,045		3,012		3,274
Natural gas⁽¹⁾	1,408		1,504		1,722		2,114		1,408
Total MWh generated	4,682		4,788		5,767		5,126		4,682
Cost per MWh - Coal	$	35.29	$	32.85	$	34.04	$	34.95	$	35.29
Cost per MWh - Natural gas	$	12.55	$	25.22	$	24.28	$	24.42	$	12.55
Weighted average, all sources	$	28.45	$	30.46	$	31.12	$	30.60	$	28.45

(1) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirds of the coal used by the Jim Bridger plant. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

~~Fuel Expense - 2018 Compared with 2017~~: Fuel expense ~~decreased $12.6~~increased $23.7 million, or 18 percent, in 2019 compared with 2018, due to a 9 percent increase in thermal generation volume and higher average costs per MWh for natural gas. Higher gas generation was mostly due to economic-based decisions to use the Danskin and Bennett Mountain gas-fired power plants as baseload resources and to increase generation at the Langley Gulch plant in 2019 compared with 2018. In 2019, gains on financial gas hedges included in fuel expense were $8.7 million lower than in 2018, ~~compared with 2017.~~increasing average costs per MWh for natural gas. In October 2018, a natural gas pipeline ruptured in British Columbia, Canada, which disrupted natural gas distribution to the Pacific Northwest region and Western Canada and drove up energy prices in the region. In accordance with its ongoing risk management policies, Idaho Power held ~~a number of~~ financial gas hedges at the time of the rupture. Fuel expense in the fourth quarter of 2018 included $23.3 million in gains on financial gas hedges, which reduced natural gas fuel expense. Idaho Power was able to meet natural gas needs by purchasing physical gas from sources unaffected by the rupture. Most of these realized hedging gains ~~will be a~~ benefit to customers through the power cost adjustment mechanisms described below.

~~Fuel Expense - 2017 Compared with 2016~~: Fuel expense decreased $33.7 million, or 19 percent, in 2017 compared with 2016, due primarily to increased output from Idaho Power's hydroelectric plants, which reduced utilization of gas and coal generation. Generation from the hydroelectric plants increased 39 percent during 2017 compared with 2016.

Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's ~~hydroelectric~~hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

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The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last ~~three~~two years (in thousands).


	Year Ended December 31,							Year Ended December 31,
	2018		2017		2016			2019			2018
Power supply cost accrual (deferral)	$	41,535	$	14,658	$	(43,841	)
Power supply cost accrual								$	49,234		$	41,535
Amortization of prior year authorized balances	571		37,366		38,511			(47,187		)	571
Total power cost adjustment expense	$	42,106	$	52,024	$	(5,330	)	$	2,047		$	42,106

The power supply accruals represent the portion of the power supply cost fluctuations accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, which was the case for ~~2018~~2019 and ~~2017,~~2018, most of the difference is accrued. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, ~~which was the case for 2016,~~ most of the difference is deferred. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism).

Idaho Power ~~Cost Adjustment Mechanisms -~~accrued $7.7 million more in power supply costs in 2019 compared with 2018 ~~Compared with 2017: Actual~~as actual net power supply costs ~~decreased in 2018~~were lower relative to forecasted costs, resulting in a change of $26.9 million—from accruals of $14.7 million to accruals of $41.5 million. The increase in accruals is due in part to lower natural gas fuel costs and purchased power, as explained above, combined with more surplus sales than forecasted.costs. In addition, Idaho Power recorded ~~$0.6~~$47.2 million of amortization of the prior-year authorized balances in ~~2018~~,2019, compared with ~~$37.4~~$0.6 million of amortization in ~~2017.~~2018.

~~Power Cost Adjustment Mechanisms - 2017 Compared with 2016~~: Actual net power supply costs decreased in 2017 relative to forecasted costs, resulting in a change of $58.5 million—from deferrals of $43.8 million to accruals of $14.7 million. The change from deferrals in 2016 to accruals in 2017 is due in part to the lower fuel costs and purchased power, combined with more surplus sales than forecasted. The $37.4 million of amortization of prior year authorized balances in 2017 offsets the collection from customers of prior years' deferrals.

Other Operations and Maintenance Expenses: ~~The changes~~Other O&M expenses decreased $8.7 million, or 2 percent, in 2019 compared with 2018, as Idaho Power's continued focus on managing other O&M expenses ~~for the periods presented are discussed below.~~

~~O&M - 2018 Compared with 2017: Other~~resulted in lower expenses across a number of areas. Lower bad debt expense reduced other O&M expenses ~~increased $17.8~~by $1.1 million, ~~or 5 percent, in 2018 compared with 2017. As provided by the settlement stipulation approved by the IPUC related~~due primarily to ~~recent income tax reform,~~enhanced collection efforts and a strong economy. Also, other O&M expenses in 2018 ~~also~~ included $4.0 million of non-cash amortization expense of regulatory deferrals ~~that would otherwise be a future liability of Idaho customers. In~~pursuant to the settlement stipulation approved by the IPUC in 2018 compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses.

~~O&M - 2017 Compared with 2016: Other O&M expense decreased by $2.2 million in 2017 compared with 2016, primarily due to a $2.4 million decrease~~ related to previously expensed energy efficiency rider-funded costs deemed to be prudently incurred and a $2.7 million decrease in thermal O&M expenses due to lower generation at thermal plants. These decreases in O&M were partially offset by a $2.5 million increase in O&M related to a settlement stipulation in Idaho that established the reasonableness of the HCC relicensing costs incurred through December 2015 as further discussed in "Regulatory Matters" in this MD&A.income tax reform.

Income Taxes

IDACORP's and Idaho Power's ~~2018 income tax expense decreased $31.3 million and $33.0 million, respectively, when~~

compared with 2017. The decrease was primarily due to: (1) the Tax Cut and Jobs Act’s reduction of the federal corporate tax rate from 35 percent to 21 percent that became effective January 1, 2018, (2) the remeasurement of deferred income tax balances related to IDACORP’s 2017 consolidated income tax return filings, and (3) a flow-through income tax benefit at Idaho Power related to the tax deduction for a bond make-whole premium that was paid in 2018.

~~IDACORP's and Idaho Power's 2017~~2019 income tax expense increased ~~$12.2~~$7.1 million and ~~$14.1~~$10.1 million, respectively, when

compared with ~~2016. The increase was primarily due to higher pre-tax earnings at~~2018. During 2018 Idaho Power recorded tax benefits for a $5.7 million remeasurement of deferred taxes resulting from income tax reform and $1.3 million for tax-deductible bond redemption costs incurred in ~~2017, and the $5.6 million~~

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~~flow-through~~2018. There was no such remeasurement or bond redemption in 2019. Also, 2018 included a benefit ~~of a~~from plant-related income tax ~~deductible make-whole premium that~~return adjustments, which reduced Idaho Power ~~paid in connection with the early redemption of long-term debt in 2016. There were no early redemptions of long-term debt in 2017. These increases in~~ income tax expense

~~were partially offset by~~ in 2018. These items, combined with greater 2019 net ~~flow-through~~income, resulted in higher income tax ~~items~~expense in 2019 compared with 2018. Amortization of vintage investment tax credits that became available in 2019 lowered tax expense by $3.4 million, most of which is not expected to recur. Also, at ~~Idaho Power.~~IFS, a $3.0 million increase in distributions from the sale of low-income housing properties reduced income tax expense at IDACORP in 2019 compared with 2018.

For additional information relating to IDACORP's and Idaho Power's income taxes ~~the effects of the Tax Cuts and Jobs Act,~~ and the availability of tax credit carryforwards, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power continues to pursue significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing ~~hydroelectric~~hydropower and thermal generation facilities also require continuing upgrades and component replacement. On an accrual basis, Idaho Power's ~~cash~~additions to electric plant, excluding AFUDC, were $295 million in 2019 and $274 million in 2018. Cash construction expenditures, ~~for property, plant,~~excluding AFUDC and ~~equipment,~~ excluding ~~AFUDC,~~net costs of removing assets from service, were $268 million in ~~2018, $277 million in 2017,~~each of 2019 and ~~$287 million in 2016.~~2018. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of ~~approximately $1.5~~more than $1.6 billion expected over the period from ~~2019~~2020 through ~~2023.~~2024.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. As of February ~~15, 2019,~~14, 2020, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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their respective $100 million and $300 million revolving credit facilities;

IDACORP's shelf registration statement filed with the ~~SEC~~U.S. Securities and Exchange Commission (SEC) on May ~~20, 2016,~~17, 2019, which may be used for the issuance of debt securities and common stock;

Idaho Power's shelf registration statement filed with the SEC on May ~~20, 2016,~~17, 2019, which may be used for the issuance of first mortgage bonds and debt securities; ~~$280~~$500 million is available for issuance pursuant to state regulatory authority; and

IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities.

Based on planned capital expenditures and operating and maintenance expenses for ~~2019,~~2020, the companies believe they will be able to meet capital requirements and fund corporate expenses during ~~2019~~2020 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business, together with proceeds from either draws on credit facilities or Idaho Power's issuance of debt securities. IDACORP and Idaho Power believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.

IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness. To that end, in March 2018, Idaho Power issued $220 million in principal amount of 4.20% first mortgage bonds, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to its maturity, its $130 million in principal amount of 4.50% first mortgage bonds, Series H, due March 2020. In accordance with the redemption provisions of the original terms of the notes, the redemption included Idaho Power's payment of a make-whole premium of $4.6 million, the cost of which provided a flow-through tax deduction. Idaho Power used a portion of the net proceeds of the March 2018 sale of first mortgage bonds, medium term-notes to effect the redemption.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, ~~and~~ maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, ~~2018,~~2019, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:


	IDACORP	Idaho Power	IDACORP	Idaho Power
Debt	44%	46%	43%	45%
Equity	56%	54%	57%	55%

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IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.

Operating Cash Flows

IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and ~~pension~~ plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.

IDACORP’s and Idaho Power’s operating cash inflows in ~~2018~~2019 were ~~$492~~$367 million and ~~$418~~$344 million, respectively, ~~an increase~~decreases of ~~$57~~$125 million and $75 million for IDACORP and ~~a $1 million increase for~~ Idaho Power, respectively, when compared with ~~2017.~~2018. Significant items that affected the companies' operating cash flows in ~~2018~~2019 relative to ~~2017~~2018 were as follows:

a ~~$14~~$6 million increase and ~~$16~~$2 million increase in IDACORP and Idaho Power net income, respectively;

changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed ~~costs~~cost adjustment amounts accrued or deferred and refunded or collected under Idaho rate mechanisms, decreased operating cash inflows by $9$53 million;

~~changes in deferred taxes and in taxes accrued and receivable combined to decrease cash flows by $22 million and increase cash flows by $28 million at IDACORP and Idaho Power, respectively;~~

Idaho Power received ~~$29~~$19 million of distributions from IERCo's investment in BCC for ~~2018,~~2019, compared with ~~$23~~$29 million in ~~2017. Changes~~2018; changes in distributions from year to year are primarily driven by changes in the timing of cash needs associated with BCC; ~~and~~

~~changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, other current assets, accounts payable, and other current liabilities, as follows:~~


◦	timing of collections of accounts receivable balances increased operating cash flows by $6 million for Idaho Power. IDACORP collected an $8 million receivable in 2017 from a legal settlement, offsetting the increase in 2018;


◦	the changes in other current assets increased cash flows by $10 million, which was primarily due to a decrease in fuel stock as an increase in coal-fired generation in the fourth quarter of 2018 compared with 2017 decreased the related coal inventory; and


◦	timing of accounts payable payments increased operating cash flows by $47 million for IDACORP and decreased operating cash flows by $64 million for Idaho Power (the difference relates to the timing of estimated income tax payments from Idaho Power to IDACORP).

IDACORP's and Idaho Power's operating cash inflows in 2017 were $435 million and $417 million, respectively, an increase of $91 million for IDACORP and $110 million for Idaho Power when compared with 2016. Significant items that affected the companies' operating cash flows in 2017 relative to 2016 were as follows:

~~a $15 million increase and $17 million increase in IDACORP and Idaho Power net income, respectively, which includes a $19 million increase in non-cash depreciation and amortization at both companies;~~

changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho rate mechanisms, increased operating cash inflows by $63 million. The increase is mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho power cost adjustment and FCA mechanisms, partially offset by revenues accrued in excess of collections from the Valmy Plant settlement stipulation that will be collected in future periods;

changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $1$7 million and ~~decrease cash flows by $23~~$4 million at IDACORP and Idaho Power, respectively; and

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changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, other current assets, and accounts payable, as follows:


◦	timing of collections of accounts receivable balances ~~increased~~decreased operating cash flows by $7 million and $5 million for IDACORP and ~~decreased operating cash flows by $6 million for~~ Idaho ~~Power. IDACORP collected an $8 million receivable in 2017 from a legal settlement;~~Power, respectively;

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◦	the changes in other current assets ~~increased~~decreased cash flows by ~~$14~~$20 million, which was primarily due to ~~fluctuations in~~ the ~~balance in accrued unbilled revenues as energy sales near the end~~timing of ~~the respective periods were impacted by weather;~~purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants; and


◦	timing of accounts payable payments decreased operating cash flows by ~~$31~~$39 million for IDACORP and increased operating cash flows by ~~$25~~$16 million for Idaho Power (the difference relates to ~~a $55 million payable~~the timing of estimated income tax payments from Idaho Power to ~~IDACORP relating to estimated income tax payments)~~IDACORP).

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. Idaho Power's construction expenditures, including AFUDC, were $279 million and $278 million ~~$285 million,~~in 2019 and ~~$297 million in~~ 2018, ~~2017, and 2016,~~ respectively. These capital expenditures were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. As discussed in "Capital Requirements" below, Idaho Power received $2 million and $22 million in 2019 and ~~$6 million in~~ 2018 ~~and 2017~~ from Boardman-to-Hemingway project joint permitting participants relating to a portion of these ~~construction~~permitting expenditures.

Idaho Power has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased ~~available-for-sale~~equity securities of $11 million in both ~~2018~~2019 and ~~2017, and $15 million in 2016.~~2018. Idaho Power received $5 million of proceeds from the sales of ~~available-for-sale~~equity securities in both ~~2018~~2019 and 2017, and $16 million in 2016. Idaho Power did not use any of these proceeds to acquire company-owned life insurance in 2018 and 2017 but used $10 million of the proceeds to acquire company-owned life insurance in 2016.2018.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in ~~2018, 2017,~~2019 and ~~2016:~~2018:

onin August 2019, Idaho Power purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in 2024 decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent. Idaho Power expects the lower interest rates to reduce interest expense by approximately $5.6 million annually for the next five years and $3.9 million annually thereafter for the final two years of the longer-lived bonds;

in March ~~16,~~ 2018, Idaho Power issued $220 million in principal amount of 4.20% first mortgage bonds Series K, maturing March 1, 2048;

onin April ~~17,~~ 2018, Idaho Power redeemed, prior to maturity, $130 million of its 4.50% first mortgage bonds, Series H, due March 1, 2020, and paid a related make-whole premium of $4.6 million;

~~on March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05% first mortgage bonds, Series J, maturing on March 1, 2046;~~

on April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15% first mortgage bonds, Series H, due April 1, 2019, and paid a related make-whole premium of $14 million;

IDACORP and Idaho Power paid dividends of approximately $130 million and $121 million ~~$113 million,~~in 2019 and ~~$105 million in~~ 2018, ~~2017, and 2016, respectively;~~respectively.

~~IDACORP's net change in commercial paper borrowings used cash of $22 million and provided cash of $2 million in 2017 and 2016, respectively; and~~

~~Idaho Power borrowed $22 million in commercial paper in December 2016, which was paid off in January of 2017.~~

Financing Programs and Available Liquidity

IDACORP Equity Programs: From time to time, IDACORP enters into sales agency agreements under which it offers and sells shares of its common stock through a third-party agent. The most recent sales agency agreement terminated in May 2016. IDACORP has no current plans to issue equity securities other than under its equity compensation plans during 2020, and as of the date of this report, IDACORP has not pursued the execution of a new sales agency agreement.

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May ~~2016,~~2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing ~~Idaho Power~~the company to issue and sell from time to time up to $500 million in aggregate principal

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amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, ~~2019,~~2022, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of seven percent.

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~~On September 27, 2016,~~In May 2019, Idaho Power ~~entered into~~filed a ~~selling agency agreement with seven banks named in the agreement in connection~~shelf registration statement with the ~~potential issuance~~SEC, which became effective upon filing for the offer and sale ~~from time to time~~ of ~~up to $500 million in aggregate~~an unspecified principal amount of its first mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture (Forty-eighth Supplemental Indenture). The Forty-eighth Supplemental Indenture provides for, among other items, (a) the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture and (b) the increase of the maximum amount of obligations to be secured by the Indenture to $2.5 billion (which maximum amount may be further increased or decreased by Idaho Power without the consent of the holders of first mortgage bonds). As of the date of this report, Idaho Power has $280 million available for the issuance of first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the ~~Indenture.~~Idaho Power's Indenture of Mortgage and Deed of Trust dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

The Indenture limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, ~~2018,~~2019, was limited to approximately $669 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, ~~2018,~~2019, Idaho Power could issue approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

Pollution Control Tax-Exempt Bonds: In August 2019, Idaho Power purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in 2024 decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent. Idaho Power expects the lower interest rates to reduce interest expense by approximately $5.6 million annually for the next five years and $3.9 million annually thereafter for the final two years of the longer-lived bonds.

Refer to Note 5 - “Long-Term Debt” to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.

IDACORP and Idaho Power Credit Facilities: In ~~November 2015,~~December 2019, IDACORP and Idaho Power entered into amendments to credit agreements for their $100 million and $300 million credit facilities, respectively. ~~These facilities replaced IDACORP's and Idaho Power's existing Second Amended and Restated Credit Agreements, dated October 26, 2011, as amended.~~ Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $100 million at any one time outstanding, including swingline loans not to exceed $10 million at any one time and letters of credit not to exceed $50 million at any one time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time and letters of credit not to exceed ~~$100~~$50 million at any ~~time.~~one time outstanding. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR Market Index rate will not be less than zero percent. An alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating, as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities. The credit facilities terminate on December 6, 2024, though IDACORP and Idaho Power may request up to two-one-year extensions of the credit agreements, subject to certain conditions.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total

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capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, ~~2018,~~2019, the leverage ratios for IDACORP and Idaho Power were 4443 percent and 4645 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, ~~2018,~~2019, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during ~~2019.~~2020.

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The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

While the credit facilities provide for an original maturity date of November 6, 2020, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On November 7, 2016, IDACORP and Idaho Power executed the first extension agreement and on November 7, 2017, executed the second extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 4, 2022. No other terms of the credit facilities, including the amount of permitted borrowing under the credit agreements, were affected by the extensions.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings through ~~November 2022.~~December 2026.

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

The following table outlines available short-term borrowing liquidity as of the dates specified (in thousands):


	December 31, 2018					December 31, 2017					December 31, 2019					December 31, 2018
	IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power
Revolving credit facility	$	100,000	$	300,000		$	100,000	$	300,000		$	100,000	$	300,000		$	100,000	$	300,000
Commercial paper outstanding	—		—			—		-			—		—			—		-
Identified for other use⁽¹⁾	—		(24,245		)	—		(24,245		)	—		(24,245		)	—		(24,245		)
Net balance available	$	100,000	$	275,755		$	100,000	$	275,755		$	100,000	$	275,755		$	100,000	$	275,755
(1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.																					(2) Holding company only.

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~~The table below presents additional information about short-term~~IDACORP and Idaho Power had no short term commercial paper ~~borrowing~~outstanding during the years ended December 31, ~~2018~~2019 and ~~2017:~~

December 31, 2018 December 31, 2017

IDACORP⁽¹⁾
Idaho Power
IDACORP⁽¹⁾
Idaho Power
Commercial paper:
Year end:
Amount outstanding $ —
$ —
$ —
$ —
Weighted average interest rate — % — % — % — %
Daily average amount outstanding during the year $ —
$ —
$ 588
$ 839
Weighted average interest rate during the year — % — % 1.42 % 1.12 %
Maximum month-end balance $ —
$ —
$ 2,425
$ —
(1) Holding company only.

2018. At February ~~15, 2019,~~14, 2020, IDACORP had no loans outstanding under its credit facility and no commercial paper outstanding,

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and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding.

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors Service and Standard & Poor’s Ratings Services as of the date of this report:



	IDACORP	Idaho Power
Moody's Investors Service:
Rating Outlook	Stable	Stable
Long-Term Issuer Rating	Baa1	A3
First Mortgage Bonds	None	A1
Senior Secured Debt	None	A1
Commercial Paper	P-2	P-2
Standard & Poor's Rating Services:
Corporate Credit Rating	BBB	BBB
Rating Outlook	Stable	Stable
Short-Term Rating	A-2	A-2
Senior Secured Debt	None	A-

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

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, ~~2018,~~2019, Idaho Power had no$1.4 million of performance assurance collateral posted. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, ~~2018,~~2019, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately ~~$10.5~~$10.3 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

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Capital Requirements

On an accrual basis, Idaho Power's additions to electric plant, excluding AFUDC, were $295 million in 2019. Idaho Power's cash construction expenditures, excluding AFUDC,were $268 million during the year ended December 31, ~~2018.~~2019. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis ~~expenditures~~additions to electric plant for ~~construction for 2019~~2020 through ~~2023~~2024 (in millions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. However, given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table.

2019 2020 2021-2023
Expected capital expenditures (excluding AFUDC) $ 280-290 $ 285-300 $ 875-925



	2020		2021		2022-2024
Expected capital expenditures (excluding AFUDC)	$	300-310	$	305-315	$	1,000-1,050

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of small projects as Idaho Power continues to add to its system to accommodate growth and improve reliability and operational effectiveness. These projects involve significant capital expenditures. Examples of anticipated system enhancements planned for ~~2019~~2020 through ~~2023~~2024 and estimated costs include the following:

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$35-$65 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;

$85-$~~105~~125 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;

$~~20-~~15-$4035 million per year for ongoing improvements and replacements at ~~coal- and natural gas-fired~~thermal plants;

$~~50-~~60-$7095 million per year for ~~hydroelectric~~hydropower plant improvement programs, including relicensing costs; and

$40-$60 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, ~~500-kV~~high-voltage transmission project between a ~~station~~substation near Boardman, Oregon, and the Hemingway ~~station~~substation near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line, Idaho Power would seek to retain at least that percentage interest in the completed project. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate.

Approximately $106 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2019. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $72 million as of December 31, 2019, from project participants for their share of costs. As of the date of this report, no material co-participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power.

Idaho Power's share of the remaining permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, ~~in addition to~~which includes approximately ~~$50~~$105 million of Idaho Power's share of estimated costs related to design and early construction, ~~efforts,~~ which are primarily included in the table in the period ~~2021-2023.~~2022-2024. These preliminary estimates of Idaho Power’s share of early construction costs could significantly change as the construction timeline nears and as the project participants further align on future activities, allocation of ownership interests, and cost estimates.

Approximately $100 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2018. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $70 million as of December 31, 2018, due from project participants for their share of costs. As of the date of this report, no material participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power.

The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the ~~BLM,~~U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. ~~Idaho Power expects the U.S. Forest Service to issue its right-of-way easement in 2019. Idaho Power expects~~In September 2019, the Department of the Navy ~~to issue~~issued its record of decision ~~on whether to approve~~authorizing the project to cross approximately seven miles of Department of the Navy ~~lands~~lands. In November 2019, third parties filed a lawsuit in the ~~first quarter~~federal district court of ~~2019.~~Oregon, challenging the BLM and U.S. Forest Service records of decision for the Boardman-to-Hemingway project. On February 13, 2020, Idaho Power filed a motion to intervene in the legal proceeding. The litigation is in its initial phases and remains pending as of the date of this report.

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In the separate Oregon state permitting process, ~~in September 2018, Idaho Power's application for site certificate was deemed complete by~~ the Oregon Department of Energy (ODOE) issued a Draft Proposed Order in May 2019 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The ODOE is expected to issue a ~~draft proposed order on the application~~Proposed Order in the first half of ~~2019 providing~~2020. Idaho Power currently expects the ~~ODOE's recommendation on whether~~EFSC to issue a final order and site certificate ~~for construction~~ in ~~Oregon.~~2021. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date for the transmission line towill be in 2026 or ~~beyond.~~some time thereafter.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a ~~500-kV~~high-voltage transmission lines project between a ~~station~~substation located near Douglas, Wyoming, and the Hemingway ~~station~~substation located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately ~~$38~~$41 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, ~~2018.~~2019. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $250 million and $450 million,

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including AFUDC. Idaho Power's estimated share of ongoing expenditures for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.

The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. In May 2017, a federal bill was signed into law that issued a right-of-way for certain portions of the remaining Gateway West segments. In April 2018, the BLM published its record of decision for the outstanding portions of the remaining segments. PacifiCorp is currently constructing a 140-mile segment of their portion of the project in Wyoming, scheduled to be completed by the end of 2020. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 6870 percent of Idaho Power's ~~hydroelectric~~hydropower generating nameplate capacity and 3235 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022. Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial, but the company is currently unable to estimate those costs in light of the uncertainty surrounding the ultimate terms and conditions that may be included in the license. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process. 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 HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In ~~December 2017, Idaho Power filed with~~April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a ~~third party~~third-party intervenor recognizing that a total of $216.5 million in expenditures 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 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. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with IPUC and determined the associated costs to be reasonably and prudently incurred.

~~Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen dioxide (NO~~₂) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provided for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO₂ reductions on unit 2 by 2021 and unit 1 by 2022.The unit 3 SCR was operating as of November 2015, and the unit 4 SCR was operating as of November 2016. In light of the substantial estimated cost of SCR installation, as of the date of this report, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The expected capital expenditures in the table above do not include any estimated expenditures relating to the installation of SCR on units 1 and 2.

Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for ~~the installation of~~its hydropower relicensing efforts and could incur significant expenditures if required to install additional environmental controls at its Jim Bridger coal-fired ~~plants and for its hydroelectric relicensing efforts.~~plant. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business - Environmental Regulation and Costs" of this report. The capital portion of these amounts is included in the Capital Requirements table above but does not include costs related to

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possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.

Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June ~~2017.~~2019, which was amended in January 2020. The ~~2017~~2019 IRP identified a preferred resource portfolio and action plan, which includes the completion of the Boardman-to-Hemingway transmission line byin 2026, the end to Idaho Power's participation in coal-fired operations at the North Valmy ~~Plant~~plant units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger plant by 2030, with the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the ~~early retirement~~addition of ~~Jim Bridger units 1 and 2~~a 120 megawatt (MW) solar resource in ~~2032 and 2028, respectively, with no other new resource needs prior to 2026.~~2022. However, as noted in the ~~2017~~2019 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of ~~third party~~third-party development of renewable resources, fuel commodity prices, ~~environmental requirements,~~ the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant ~~operation and~~ retirements. These uncertainties, as well as others, ~~could~~likely will result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. Additional information on Idaho Power's ~~2017~~2019 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Potential Future Rate Base Additions

As noted previously in this MD&A, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Idaho Power's current rate

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base of $2.7 billion was established in June 2012, when the IPUC issued an order approving the inclusion of the investment and associated costs of the Langley Gulch plant in rates. Through December 31, 2019, Idaho Power has placed $0.7 billion of property, plant, and equipment in service since June 2012, net of accumulated depreciation. These assets could be included in future rate base if Idaho Power were to file a general rate case, though Idaho Power has no plans to do so in 2020. Idaho Power expects to place in service an additional $0.7 billion of rate base-eligible projects over the next five years. Idaho Power expects it could also add up to an additional $1.3 billion to rate base over the next several years by completing projects currently in process with uncertain in-service dates or due to additional spending required by completion of the projects. These projects include HCC relicensing, additional capital expenditures to comply with the expected requirements of a new HCC license, post-relicensing water temperature mitigation efforts at HCC, the Boardman-to-Hemingway project either at or above Idaho Power's current ownership percentage in the project, and certain distribution system modernization projects.

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $40 million to its defined benefit pension plan in each ~~year in 2018, 2017,~~of 2019 and ~~2016.~~2018. Idaho ~~Power estimates that it has no~~Power's minimum required contribution ~~requirement for 2019.~~to be made during 2020 is estimated to be $14 million. Depending on market conditions and cash flow considerations, ~~in 2019,~~ Idaho Power could contribute up to $40 million to the pension plan during ~~2019.~~2020. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond ~~2019,~~2020, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to ~~Note 12 - "Benefit Plans" to the consolidated financial statements included in this report and~~ the section titled "Contractual Obligations" below in this MD&A for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, ~~2018~~2019 and ~~2017,~~2018, Idaho Power's deferral balance associated with the Idaho jurisdiction was ~~$148~~$173 million and ~~$128~~$148 million, respectively. Deferred pension costs are expected to be amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions.

~~Income Tax Reform~~

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. The majority of the law changes, including the rate reductions, became effective on January 1, 2018. See "Regulatory Matters" in this MD&A for more Additional information on the regulatory assets related ~~regulatory proceedings~~to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial ~~impacts.~~statements included in this report.

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Contractual Obligations

The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, ~~2018,~~2019, for the respective periods in which they are due:


	Payments Due by Period											Payments Due by Period
	Total		2019		2020-2021		2022-2023		Thereafter			Total		2020		2021-2022		2023-2024		Thereafter
	(millions of dollars)											(millions of dollars)
Long-term debt⁽¹⁾	$	1,855	$	—	$	100	$	150	$	1,605		$	1,856	$	100	$	75	$	125	$	1,556
Future interest payments⁽²⁾	1,565		85		166		159		1,155			1,441		79		150		144		1,068
Purchase obligations:
Maintenance and service agreements⁽³⁾	131		34		26		16		55			148		48		30		14		56
FERC and other industry-related fees⁽³⁾	128		14		25		25		64			132		14		27		26		65
Cogeneration and small power production	4,042		239		490		508		2,805			4,010		242		500		529		2,739
Fuel supply agreements	201		43		57		17		84			192		56		44		17		75
Other⁽³⁾⁽⁴⁾	51		3		8		8		32			48		3		8		7		30
Pension and postretirement benefit plans⁽⁵⁾	326		11		110		153		52			323		26		117		128		52
Other long-term liabilities - IDACORP only⁽³⁾	2		—		—		—		2			2		—		—		—		2
Total(6)	$	8,301	$	429	$	982	$	1,036	$	5,854		$	8,152	$	568	$	951	$	990	$	5,643
(1) For additional information, see Note 5 – “Long-Term Debt” to the consolidated financial statements included in this report.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2018.
(3) Approximately $20 million of the amounts in maintenance and service agreements, $71 million of the amounts in FERC and other industry-related fees, $29 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2019.											(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2019.
(3) Approximately $48 million of the amounts in maintenance and service agreements, $131 million of the amounts in FERC and other industry-related fees, $27 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.											(3) Approximately $48 million of the amounts in maintenance and service agreements, $131 million of the amounts in FERC and other industry-related fees, $27 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(4) Other purchase obligations include right-of-way easements and the joint-operating agreement payments.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2023 with any level of precision, and amounts through 2023 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2024 with any level of precision, and amounts through 2024 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.											(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2024 with any level of precision, and amounts through 2024 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.
(6) Asset retirement obligations of $28.2 million are not included in the table as the settlement of these liabilities cannot be determined with certainty, however we believe these liabilities will be settled in more than five years. For more information on asset retirement obligations, refer to Note 14 – "Asset Retirement Obligations (ARO)" to the consolidated financial statements included in this report.											(6) Asset retirement obligations of $28.2 million are not included in the table as the settlement of these liabilities cannot be determined with certainty, however we believe these liabilities will be settled in more than five years. For more information on asset retirement obligations, refer to Note 14 – "Asset Retirement Obligations (ARO)" to the consolidated financial statements included in this report.

In March 2019, Idaho Power signed a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility. The agreement was approved by the IPUC in December 2019 and is, as of the date of this report, pending approval by the OPUC. If approved, the agreement would increase contractual obligations by $136 million over the 20-year term. In October 2019, Idaho Power exercised its right under the power purchase agreement to negotiate during the fourth quarter of 2019 for the acquisition by Idaho Power or one of its affiliates of the planned 120-MW solar facility. Idaho Power and its affiliates did not ultimately reach an agreement to acquire ownership of the facility.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio ~~of between 50 and 60 percent~~ of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions. In 2019, IDACORP's board of directors increased the target long-term dividend payout ratio to between 60 percent and 70 percent of sustainable IDACORP earnings from the previous policy adopted in 2011, that targeted a dividend payout ratio of between 50 percent to 60 percent of sustainable earnings. Notwithstanding the dividend policy adopted by IDACORP's board of directors,

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the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others. In September of ~~2018, 2017,~~2019 and ~~2016,~~2018, IDACORP's board of directors voted to increase the quarterly dividend to ~~$0.63 per share, $0.59~~$0.67 per share and ~~$0.55~~$0.63 per share of IDACORP common stock, respectively. IDACORP's dividends during ~~2018~~2019 were ~~53.5~~55.5 percent of actual ~~2018~~2019 earnings.

For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 7 – “Common Stock” to the consolidated financial statements included in this report.

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Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations 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 determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements

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 (WDEQ), was ~~$58.4~~$58.3 million at December 31, ~~2018,~~2019, representing IERCo's one-third share of BCC's total reclamation obligation of ~~$175.2~~$175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, ~~2018,~~2019, the value of the reclamation trust fund totaled ~~$101.9~~$139.5 million. During ~~2018,~~2019, the reclamation trust fund made ~~$6.7 million in~~no distributions 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.

In May 2019, the state of Wyoming enacted legislation that limits a mine operator's maximum amount of self-bonding. Idaho Power and the co-owners of BCC have until December 2020 to comply with the new regulations, which would reduce the portion of Idaho Power's guarantee of reclamation activities and obligations at BCC that Idaho Power is allowed to self-bond. As of the date of this report, Idaho Power believes the cost of any insurance, third-party assurance, or additional collateral that might be required for this guarantee due to the new law would be immaterial to the companies' consolidated financial statements.

REGULATORY MATTERS

Introduction

Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.

Idaho Power's development of regulatory ~~strategy~~filings takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of ~~rate~~these regulatory filings. These factors include, among others, in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during ~~2011, and Idaho Power filed a~~2011. In 2012, large single-issue rate ~~case~~cases 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.~~Oregon. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through

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retail rates in 2014 but without a resulting net increase in rates. The IPUC and OPUC have also approved base rate changes in single-issue cases subsequent to 2014. Between general rate cases, Idaho Power relies upon customer growth, a fixed cost adjustment mechanism, power cost adjustment mechanisms, tariff riders, and other mechanisms to ~~reduce~~mitigate 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. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. Idaho Power continues to assess the need and timing of filing a general rate case in its two retail jurisdictions, based on its consideration of the factors described above, but does not anticipate filing a general rate case in ~~2019.~~2020.

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Notable Retail Rate Changes in Idaho and Oregon

Included in the table that follows are notable regulatory developments during ~~2018, 2017,~~2019 and ~~2016~~2018 that affected Idaho Power's results for the periods or that will likely affect future periods. ~~Also refer to~~ Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report ~~for~~also provides a description of regulatory mechanism and associated orders of the IPUC and OPUC, ~~which~~and should be read in conjunction with the discussion of regulatory matters in this MD&A.

Description Effective Date
Estimated Annualized Rate Impact (millions)⁽¹⁾
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho base rates 6/1/2018 $ (19 )
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho PCA⁽²⁾
6/1/2018 (8 )
2018 Idaho PCA 6/1/2018 (23 )
2018 Idaho FCA 6/1/2018 (19 )
Oregon Tax Reform Settlement Stipulation 6/1/2018 (1 )
Oregon Valmy Plant Accelerated Depreciation Settlement Stipulation 6/1/2018 2
Oregon Valmy Plant Settlement Stipulation 7/1/2017 1
Idaho Valmy Plant Settlement Stipulation 6/1/2017 13
2017 Idaho PCA⁽³⁾
6/1/2017 11
2017 Idaho FCA 6/1/2017 7
2016 Idaho PCA⁽⁴⁾
6/1/2016 17
2016 Idaho FCA 6/1/2016 11

(1) The annual amount collected or refunded in rates is typically not recovered or refunded on a linear basis (i.e., 1/12th per month), and is instead recovered or refunded in proportion to retail sales volumes. The rate changes for the Idaho PCA and FCA are applicable only for one-year periods.
(2) 2018 Idaho PCA rates include $7.8 million decrease for the income tax benefits accrued from January 1 to May 31, 2018, and the income tax benefits related to Idaho Power's OATT rate. See "Income Tax Reform - Regulatory Treatment" below for more information.
(3) 2017 Idaho PCA rates reflect the application of $13.0 million of surplus Idaho energy efficiency rider funds.
(4) 2016 Idaho PCA rates reflect the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of an October 2014 settlement stipulation and (b) $4.0 million of surplus Idaho energy efficiency rider funds.



Description	Effective Date	Estimated Annualized Rate Impact (millions)⁽¹⁾
Oregon North Valmy plant Exit Framework Settlement Stipulation	1/1/2020		$	(3	)
Idaho North Valmy plant Exit Framework Settlement Stipulation	6/1/2019		1
2019 Idaho PCA⁽²⁾	6/1/2019		(50		)
2019 Idaho FCA	6/1/2019		19
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho base rates	6/1/2018		(19		)
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho PCA⁽³⁾	6/1/2018		(8		)
2018 Idaho PCA	6/1/2018		(23		)
2018 Idaho FCA	6/1/2018		(19		)
Oregon Tax Reform Settlement Stipulation	6/1/2018		(1		)
Oregon North Valmy plant Accelerated Depreciation Settlement Stipulation	6/1/2018		2

(1) The annual amount collected or refunded in rates is typically not recovered or refunded on a linear basis (i.e., 1/12th per month), and is instead recovered or refunded in proportion to retail sales volumes. The rate changes for the Idaho PCA and FCA are applicable only for one-year periods.
(2) 2019 Idaho PCA rates include a $5.0 million credit to customers for sharing of 2018 earnings under the IPUC order approving the extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019 (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation) and a $2.7 million credit for income tax reform benefits related to Idaho Power's OATT rate under a May 2018 Idaho tax reform settlement stipulation as described below in this MD&A.
(3) 2018 Idaho PCA rates include $7.8 million decrease for the income tax benefits accrued from January 1 to May 31, 2018, and the income tax benefits related to Idaho Power's OATT rate as described below in this MD&A.

Idaho and Oregon General Rate Cases

Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011. In the general rate case, the IPUC issued an order approving a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.

Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. In September 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the PCA mechanism and instead results in collecting that portion through base rates.

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~~Valmy Base Rate Adjustment Settlement Stipulations~~

In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the Valmy Plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017 in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 Oregon Income Tax Reform Settlement Stipulation described below, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement.

Other Notable Regulatory Matters

~~December 2011~~October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In ~~December 2011,~~October 2014, the IPUC issued an order ~~separate from~~approving an extension, with modifications, of the ~~then-pending~~terms of a December 2011 Idaho ~~general rate case proceeding, approving a~~ settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE ~~for 2012, 2013, or 2014~~ was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable ~~year.~~year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the ~~December 2011~~October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE ~~for any of those years~~ exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho ~~customers.~~

~~October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 settlement stipulation~~customers for the period from 2015 through ~~2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized.~~2019. The more specific terms and conditions of the October 2014 ~~settlement stipulation~~Idaho Earnings Support and Sharing Settlement Stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in ~~"Income~~"May 2018 Idaho Tax Reform ~~- Regulatory Treatment" below.~~Settlement Stipulation" of this MD&A.

In 2019, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year Idaho ROE was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its full-year Idaho ROE for 2018 was above 10.0 percent. In both 2017 and 2016, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation.customers.

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Idaho Power recorded the following amounts for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations (in millions):


Year	Recorded as Refunds to Customers		Recorded as a Pre-tax Charge to Pension Expense		Total		Recorded as Refunds to Customers		Recorded as a Pre-tax Charge to Pension Expense		Total
2019							$	—	$	—	$	—
2018	$	5.0	$	—	$	5.0	5.0		—		5.0
2017	—		—		—		—		—		—
2016	—		—		—		—		—		—
2015	3.2		—		3.2		3.2		—		3.2
2014	8.0		16.7		24.7		8.0		16.7		24.7
2013	7.6		16.5		24.1		7.6		16.5		24.1
2012	7.2		14.6		21.8		7.2		14.6		21.8
2011⁽¹⁾	27.1		20.3		47.4		27.1		20.3		47.4
Total	$	58.1	$	68.1	$	126.2	$	58.1	$	68.1	$	126.2

(1) The 2011 sharing amounts were recorded pursuant to a regulatory mechanism preceding the December 2011 Idaho Earnings Support and Sharing Settlement Stipulation.

~~Income~~May 2018 Idaho Tax Reform ~~- Regulatory Treatment:~~ Settlement Stipulation: 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 (1) record a regulatory liability for the estimated Idaho-jurisdictional share of financial benefits after January 1, 2018, from the changes in federal income tax law under the Tax Cuts and Jobs Act, and (2) file a report with the IPUC by March 30, 2018, identifying and quantifying the financial impact of the income tax changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates and corresponding revenues 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 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~~was provided to Idaho customers through PCA mechanism rates 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 OATT rate. The amount provided via the PCA mechanism ~~will decrease~~decreased to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate 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 provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism to become effective beginning January 1, ~~2020. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the~~2020, with no defined end date. The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during ~~their respective terms.~~its term. IDACORP and Idaho Power believe that the terms

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allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. At December 31, 2019, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.

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~~In December 2019, Idaho Power ~~to file a deferral request~~filed an application with the OPUC ~~by December 31, 2019, to begin tracking~~requesting approval of Idaho Power’s quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform ~~benefits beginning January~~and adjusting customer rates to reflect this amount, effective June 1, 2020, ~~at which time Idaho Power,~~until its next general rate case or other proceeding where the ~~OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.~~tax-related revenue requirement components are reflected in rates.

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For more information on the settlement stipulations and their impacts on results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy plant in 2019 and 2025, respectively. In May 2019, the IPUC issued an order approving the North Valmy plant exit agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1 and removed approximately $160 million from both Utility plant in service and Accumulated provision for depreciation on the consolidated balance sheets at December 31, 2019.

In June 2017, the OPUC also approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 Oregon Income Tax Reform Settlement Stipulation described below, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant exit agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.

Customer-Owned Generation Filing:~~In July 2017,~~Customer-owned generation allows customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it utilizes energy supplied by Idaho Power’s grid. If its system generates more energy than the customer uses, the energy goes back to the grid and Idaho Power ~~filed an application with~~applies a corresponding kWh credit to the ~~IPUC related to residential and small general service customers who install their own on-site generation, seeking to create two new customer classes, with no request to change pricing or compensation.~~customer’s bill. In May 2018, the IPUC issued an order authorizing the creation of ~~the~~two new customer ~~classes. In~~classes for residential and small commercial customers who install their own on-site generation, with no change to pricing or compensation. Since October 2018, Idaho Power ~~filed petitions requesting~~has initiated two cases related to studying the ~~IPUC open two new proceedings to study the fixed-costs~~costs and benefits of ~~providing electric service to customers,~~customer-owned generation on Idaho Power’s system, and exploring whether, and to ~~study~~ what extent, there should be modifications to the customer-owned generation pricing structure for residential and small general service customers (Residential and Small Commercial Case), and large commercial, industrial, and irrigation customers (Large Commercial, Industrial, and Irrigation Case). The IPUC issued orders in the Residential and Small Commercial Case during December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to

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the costs and benefits of customer generation before changes to the compensation structure are implemented, and ~~compensation of net excess energy supplied by customer~~(2) continue to allow customers with on-site generation ~~respectively. In November 2018,~~prior to December 20, 2019, to be subject to the ~~IPUC opened the proceedings.~~billing terms in place on that date until December 20, 2045. As of the date of this report, both the Residential and Small Commercial Case and Large Commercial, Industrial, and Irrigation Case are ongoing, and Idaho Power ~~and the parties in both proceedings are continuing~~does not expect these cases to ~~determine the procedural and substantive scope for each proceeding.~~materially affect its financial condition or results of operations.

~~Western Energy Imbalance Market Costs:~~Idaho Power's participation in the Western EIM commenced on April 4, 2018. The Western EIM is intended 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. Financial benefits or costs resulting from participation in the Western EIM are subject to Idaho Power's PCA mechanism as described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. In January 2017, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. In November 2017, Idaho Power filed an application with the IPUC requesting authorization to establish an interim method of recovery for Western EIM-related costs. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for recovery through Idaho Power's PCA mechanism. For more information on the order and its impact on financial results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Deferred (Accrued) Net Power Supply Costs

Deferred (accrued) power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery (refund) through customer rates. Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in ~~hydroelectric~~hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.

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The following table summarizes the change in deferred (accrued) net power supply costs over ~~the prior two years~~last year (in millions):


	Idaho			Oregon			Total			Idaho			Oregon			Total
Balance at December 31, 2016	$	53.5		$	0.4		$	53.9
Balance at December 31, 2018										(42.1		)	(0.2		)	(42.3		)
Current period net power supply costs accrued	(14.7		)	—			(14.7		)	(49.2		)	—			(49.2		)
Energy efficiency rider funds transferred to Idaho PCA mechanism	(13.0		)	—			(13.0		)
Prior amounts recovered through rates	(26.1		)	(0.5		)	(26.6		)
Sulfur Dioxide (SO₂) allowance and renewable energy certificate (REC) sales	(2.1		)	(0.1		)	(2.2		)
Interest and other	0.2			0.1			0.3
Balance at December 31, 2017	(2.2		)	(0.1		)	(2.3		)
Current period net power supply costs accrued	(41.5		)	—			(41.5		)
Tax reform revenue accrual to be refunded through Idaho PCA, net of amounts refunded	(1.9		)	—			(1.9		)
Revenue sharing										(5.0		)	—			(5.0		)
Western EIM cost recovery to be collected through Idaho PCA	2.2			—			2.2			3.2			—			3.2
Prior amounts refunded through rates	4.2			—			4.2			51.4			0.1			51.5
SO₂ allowance and REC sales	(2.6		)	(0.1		)	(2.7		)	(5.0		)	(0.2		)	(5.2		)
Interest and other	(0.3		)	—			(0.3		)	(1.5		)	—			(1.5		)
Balance at December 31, 2018	$	(42.1	)	$	(0.2	)	$	(42.3	)
Balance at December 31, 2019										$	(48.2	)	$	(0.3	)	$	(48.5	)

Open Access Transmission Tariff Rate Proceedings

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the ~~FERC.~~FERC and allows Idaho Power to recover costs for FERC-approved expenditures associated with its transmission system. In August ~~2018,~~2019, Idaho Power filed its ~~2018~~2019 final transmission rate with the FERC, reflecting a transmission rate of ~~$31.25~~$27.32 per kW-year, to be effective for the period from October 1, ~~2018,~~2019, to September 30, ~~2019.~~2020. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of ~~$123.1~~$107.0 million. The OATT rate in effect from October 1, ~~2017,~~2018, to September 30, ~~2018,~~2019, was ~~$34.90~~$31.25 per kW-year based on a net annual transmission revenue requirement of ~~$130.4~~$123.1 million. The decrease in the OATT rate is largely attributable to ~~an increase in~~federal tax reform and increased short-term firm and non-firm transmission revenues in ~~2017,~~2018, which ~~serves~~serve as an offset to the transmission revenue requirement. Historic OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Relicensing of ~~Hydroelectric~~Hydropower Projects

Overview: Idaho Power, like other utilities that operate non-federal ~~hydroelectric~~hydropower projects on qualified waterways, obtains licenses for its ~~hydroelectric~~hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's ~~hydroelectric~~hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through

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the regulatory ~~process~~process. In April 2018, the IPUC approved a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third-party intervenor and determined that $216.5 million in expenditures incurred for relicensing through December ~~2016, submitted~~31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a ~~request for a determination of prudence of HCC relicensing costs, which is described below.~~later date. Relicensing costs of ~~$297~~$326 million (including AFUDC) for the HCC, Idaho Power's largest ~~hydroelectric~~hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, ~~2018.~~2019. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Prior to the May 2018 Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, ~~2018,~~2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was ~~$135~~$152 million. In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's ~~hydroelectric~~hydropower generating plants.

Hells Canyon Complex: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 6870 percent of Idaho Power's ~~hydroelectric~~hydropower generating nameplate capacity and 3235 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into

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an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA) listed species pending the relicensing of the project. In August 2007, the FERC Staff issued a final environmental impact statement (EIS) for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The FERC may require an additional, updated EIS prior to the issuance of a new license for the HCC. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power's operation of the HCC. Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act (CWA) and formal consultations under the ESA, which remain unresolved.

In connection with its relicensing efforts, Idaho Power ~~has~~ filed water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Section 401 of the CWA requires that a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power ~~has been filing~~filed and ~~withdrawing~~withdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it ~~has been~~was working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, ~~provides~~provided that Idaho Power ~~shall~~ take no action that ~~may~~might result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approval of the State of Idaho. In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the ~~Federal Power Act (FPA)~~FPA pre-empts the Oregon state law. In January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide. In February 2017, Idaho Power sought rehearing before the FERC on the January 2017 order, which the FERC denied. In February 2018, Idaho Power filed an appeal of the FERC's January 2017 order with the D.C. Circuit Court, which is pending.

In April 2017, the governors of Oregon and Idaho jointly requested that Idaho Power withdraw and resubmit its Section 401 certification applications in both states to allow the states additional time to negotiate a potential resolution of the disputed issues. As of June 2018, the states had not resolved their differences, requiring Idaho Power to again withdraw and resubmit its Section 401 certification applications in both states. In December 2018,2019, the states of Idaho and Oregon, along with Idaho Power, reached a ~~proposed~~ settlement pertaining to the CWA Section 401 certification that resolved the fish passage conflict between the parties. The settlement requires Idaho Power to increase the number of Chinook salmon it releases each year through expanded hatchery production. Additionally, Idaho Power is required to fund a total of $12 million of research and water quality improvements in the HCC over a 20-year period following the issuance of the license. These measures are in exchange for Oregon removing the fish passage requirement from the Oregon Section 401 certification for at least the first 20 years after final license issuance. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million over the ~~term~~first 20 years of the new ~~license.~~license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third-party lawsuits were filed against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and ~~Oregon draft~~mercury issues associated with the Snake River and HCC. Idaho Power has intervened in one of the third-party lawsuits and may intervene in the other two as well. No parties challenged the Idaho CWA Section 401 ~~certifications were released for public comment in~~

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certification. On December ~~2018. After the public comment period closes in February~~30, 2019, Idaho Power ~~anticipates~~filed an Offer of Settlement with the ~~states will evaluate~~FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. The FERC has received several comments opposing the Offer of Settlement and ~~draft final 401 certifications, which must be completed by June 2019 for~~its decision relating to the ~~current cycle.~~Offer of Settlement is pending as of the date of this report. Idaho Power continues to expect the FERC to issue an HCC license no earlier than 2022.

In September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, under the NMFS's and USFWS's jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Each of the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.

Idaho Power continues to work with Idaho and Oregon ~~in the development of~~on measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards ~~so that appropriate water quality~~and associated measures identified in the final Section 401 certifications, ~~can be issued for the project,~~ and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns. ~~Idaho Power has begun~~Measures identified in the final Section 401 certifications included construction of ~~new~~ aerated runners at the Brownlee project (part of the HCC) at an estimated cost of $59 million. Three of four units were installed by the end of 2018 and Idaho Power plans to install the final unit in 2019. Other measures that have been proposed or considered have included, modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements ~~or the installation of a temperature~~

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~~control structure~~ to address water temperatures during a small portion of the year. ~~If Idaho Power is required to take these or~~These and any other additional measures to satisfy relicensing requirements ~~it could~~have added and will add substantially to project costs.

As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, as of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022. 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 HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate 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 expenditures 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 2017, which included $4.3 million for cost incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.

Renewable Energy Standards and Contracts

Renewable Portfolio Standards: Many states have enacted legislation that would require electric utilities to obtain a specified percentage of their electricity from renewable sources. These requirements are commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no State of Idaho RPS is in effect. Idaho Power will be required to comply with either a five- or ten-percent RPS in Oregon beginning in 2025 (depending on loads at that time), and Idaho Power expects to meet either RPS requirement with RECs obtained from the purchase of energy from the Elkhorn Valley wind project.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, ~~2018, 2017,~~2019, and ~~2016,~~2018, Idaho Power's REC sales totaled ~~$2.9 million, $2.3~~$5.5 million and ~~$1.0~~$2.9 million, respectively.

Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market. Historically, Idaho Power has generally not received the RECs associated with PURPA projects. However, an order issued by the IPUC in 2012 provides that Idaho Power will own a portion of the RECs generated by some PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.

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Renewable and Other Energy Contracts: Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small ~~hydroelectric~~hydropower and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of December 31, ~~2018,~~2019, Idaho Power had contracts to purchase energy from ~~127~~129 on-line PURPA projects. An additional three contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.

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The following table sets forth, as of December 31, ~~2018,~~2019, the resource type and nameplate capacity of Idaho Power's signed agreements for ~~energy~~power purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.


Resource Type	Total On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)	On-line megawatts (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:
Wind	627	—	627	627	—	627
Solar	290	27	317	310	9	319
Hydroelectric	146	2	148
Hydropower				147	2	149
Other	56	—	56	52	—	52
Total PURPA	1,119	29	1,148	1,136	11	1,147
Non-PURPA:
Wind	101	—	101	101	—	101
Geothermal	35	—	35	35	—	35
Solar				—	120	120
Total non-PURPA	136	—	136	136	120	256

The projects not yet on-line include one ~~hydroelectric~~hydropower PURPA project and ~~five~~two solar PURPA projects that are scheduled to be on-line in ~~2019.~~2020 and one solar PURPA project scheduled to be on-line in 2022. The non-PURPA solar project is scheduled to be on-line in 2022.

In September 2019, the FERC issued a Notice of Proposed Rulemaking that, if adopted, could affect how states determine PURPA project avoided cost rates for purchases of power generated from qualified facilities (QF), which facilities are eligible for QF status, whether and when certain QFs can enter into purchase agreements with utilities, and how parties can contest the eligibility of a generation facility seeking QF status. As of the date of this report, Idaho Power is unable to determine the impact of these potential changes on the company's future obligations for new PURPA power purchase contracts, as it would require further action by the state public utility commissions to implement many of the changes. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could reduce the number of future PURPA generation projects, which could reduce purchased power costs for Idaho Power. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

ENVIRONMENTAL MATTERS

Overview

Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Affordable Clean Energy (ACE) rule and other Clean Air Act (CAA), requirements, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three co-owned coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 ~~hydroelectric~~hydropower projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:

increase the operating costs of generating plants;

increase the construction costs and lead time for new facilities;

require the modification of existing generating plants, which could result in additional costs;

require the curtailment or shut-down of existing generating plants; or

reduce the output from current generating facilities.

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Current and future environmental laws and regulations will increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation as the cost of compliance makes the plants uneconomical to operate. The decision to agree to cease operation of the Boardman coal-fired plant, in which Idaho Power owns a 10 percent interest, by the end of 2020, was based in part on the significant future cost of compliance with environmental laws and regulations. The decision to pursue an end to participation in coal-fired operations at the North Valmy ~~Plant~~plant was also based primarily on the economics of operating the ~~plant. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of selective catalytic reduction equipment~~

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~~(SCR) installation, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power~~ plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from ~~2018~~2020 to ~~2020.~~2022. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond ~~2020,~~2022, though they could be substantial. Furthermore, several executive orders issued insince 2017 ~~and 2018~~ concerning environmental regulations, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. ~~For example, in August 2017, an executive order was issued to accelerate federal agencies' environmental review and permitting for major infrastructure projects.~~ The outcome of federal agencies' review of regulations covered by executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or reduction or elimination of permitting requirements. Executive orders resulting in modifications to federal regulations could, on the other hand, be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federal regulations or bolster environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations and environmental-related expenditures. Idaho Power plans to continue to monitor actions associated with or resulting from executive orders.

Endangered Species Act Matters

Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct generation, transmission, or distribution facilities or relicense or operate its ~~hydroelectric~~hydropower facilities. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward. In February 2016, the USFWS and the NMFS issued a set of regulatory and policy changes relating to critical habitat and adverse modification determinations under the ESA. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could result in the applicable agencies having greater authority in making designations of critical habitat and could increase the likelihood of adverse modification determinations.

In July 2018, the USFWS and the NMFS issued three proposals to revise ESA regulations (2018 ESA Proposals) related to the process and standards for listing species and designating critical habitat, the process for consultations with federal agencies under Section 7 of the ESA (including the definition of "destructive or adverse modification" of designated critical habitat), and the scope of protection of threatened species. Idaho Power believes that if the 2018 ESA Proposals are promulgated, the regulations could reduce Idaho Power’s obligations for mitigation under the ESA related to various construction and relicensing projects. Furthermore, in November 2018, the U.S. Supreme Court held that an area is eligible for designation as a critical habitat under the ESA only if it is also "habitat" for the species as defined in the statute, which generally means the area can support the species without modification, and as part of the designation, the USFWS must also consider the costs compared to the benefits of such designation. Idaho Power believes this ruling may limit the number of areas designated as critical habit and could also reduce Idaho Power’s obligations for mitigation under the ESA. Furthermore, in August 2019, the USFWS and the NMFS issued a set of regulatory changes to some of the standards under which listings, delisting, and reclassifications, and critical habitat designations are made. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could reduce the role of climate change models in listing decisions and the designations of critical habitat in areas where species are not present, which could also reduce Idaho Power's obligations for mitigation under the ESA related to various construction and relicensing projects.

The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's ~~hydroelectric~~hydropower projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has ~~hydroelectric~~hydropower facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's ~~hydroelectric~~hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may

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require operational adjustments and could adversely impact the amount of output from ~~hydroelectric~~hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

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Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statements across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.

In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.

In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In December 2018, the BLM issued draft resource management plan amendments and a final environmental impact statements to modify the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.

ESA Issues Related to Specific Projects:

Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has yet to be initiated and the NMFS and the USFWS continue to gather and consider information relative to the effects of relicensing on relevant ESA listed species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during ~~2019~~2020 is unlikely.

Boardman-to-Hemingway and Gateway West Transmission Projects: In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass. Most of the species are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed routes for the Boardman-to-Hemingway and Gateway West transmission line projects to continue to impact the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation. The USFWS has also indicated it intends to designate critical habitat for the species. If critical habitat is designated within the vicinity of the transmission line projects, Idaho Power expects that the designation could increase the cost of obtaining permits for the projects and could further delay the in-service date of the projects.

The Washington ground squirrel inhabits various locations throughout two of the counties within the proposed routes for Boardman-to-Hemingway. It is not listed under the federal ESA, but it is considered endangered under Oregon law and the Boardman-to-Hemingway project will need to avoid ground squirrel colonies during construction. If colonies are found within the proposed site boundary during pre-construction surveys, re-siting the transmission would require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the project.

Endangered Species Act and National Environmental Policy Act Developments: In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of ~~hydroelectric~~hydropower facilities owned and operated by the U.S. Army Corps of Engineers and located on the lower Snake River, National Oceanic and Atmospheric Administration's

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National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the National Environmental Policy Act (NEPA) by failing to prepare a comprehensive environmental impact statement on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could

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result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement process to examine ~~hydroelectric~~hydropower dams on the lower Snake River, which Idaho Power expects will take place over a five-year period. In January 2020, the presidential administration's Council on Environmental Quality proposed rules to narrow federal agencies' NEPA obligations, which if adopted, may expedite projects and reduce the number of actions subject to NEPA review. None of Idaho Power’s ~~hydroelectric~~hydropower facilities are included in the studies.

Climate Change and the Regulation of Greenhouse Gas Emissions

Overview: Long-term climate change could significantly affect Idaho Power's business in a variety of ways, including:

changes in temperature and precipitation could affect customer demand and energy loads;

extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;

changes in the amount and timing of snowpack and stream flows could affect ~~hydroelectric~~hydropower generation;

legislative and/or regulatory developments related to climate change could affect plants and operations, including restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources; and

consumer preference for, and resource planning decisions requiring, renewable or low ~~GHG-emitting~~greenhouse gas (GHG)-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.

Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing CO₂ emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. Some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate, particularly in light of continued low natural gas prices that decrease the cost to operate natural gas-fired power plants. As a result, Idaho Power ~~plans to end~~ended its participation in coal-fired operations at the North Valmy ~~Plant units~~plant unit 1 in December 2019 and plans to end its participation in unit 2 in ~~2019~~2025, and ~~2025, respectively, and~~plans to cease coal-fired operations at the Boardman power plant no later than December 31, 2020.

A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emission or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National GHG Initiatives; Clean Power ~~Plan:~~ Plan/Affordable Clean Energy Rule: The U.S. Environmental Protection Agency (EPA) has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

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In May 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. While the rule is complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.

In June 2014, the EPA released, under Section 111(d) of the CAA, a proposed rule for addressing GHG from existing fossil fuel-fired electric generating units (EGUs). The proposed rule was intended to achieve a 30 percent reduction in CO₂ emissions from the power sector by 2030. In August 2015, the EPA released the final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan (CPP), which required states to adopt plans to collectively reduce 2005 levels of power sector CO₂ emissions by 32 percent by the year 2030. ~~The final rule provided states until September 2018 to submit implementation plans, phasing in several compliance periods beginning in 2022 and achieving the final emissions goals by 2030.~~ In ~~August 2018,~~June 2019, the EPA ~~proposed~~released the ~~Affordable Clean Energy (ACE)~~ACE rule to replace the CPP under Section 111(d) of the CAA for existing electric

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utility generating units. The new ~~proposed~~ rule provides states with new emissions guidelines that inform the state development of standards of performance to reduce CO₂emissions from existing generation facilities and is limited to reduction and compliance measures that occur at the physical location of each plant, removing the proposal to require reductions outside the boundaries of plants. The ACE rule also provides for more state-specific control over implementation of the rule to address greenhouse gas emissions from existing coal-fired power plants, with a focus on state evaluation of improvement potential, technical feasibility, applicability, and remaining useful life of each unit. States are required to submit their compliance plans to the EPA by July 2022. In August 2019, twenty-two states sued the EPA in federal appeals court to challenge the ACE rule.

Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the existing and potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the presidential administration's executive orders and the EPA's proposal to repeal and replace the CPP discussed above, as of the date of this report ~~and in light of these executive actions,~~ Idaho Power is uncertain whether and to what extent the ~~replacement CPP~~ACE rule may impact its operations in the near term. Idaho Power's preliminary review of the rule indicates that it may not have substantial impacts on Idaho Power's operation of existing thermal generation units due to its planned retirements and other planned upgrades at generating facilities.

State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO₂ equivalent annually. The Boardman coal-fired power plant located in Oregon, in which Idaho Power is a 10-percent owner, is subject to and in compliance with Oregon's GHG reporting requirements but is scheduled to cease coal-fired operations in 2020.

In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, and requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

The State of Idaho has not passed legislation specifically regulating GHGs. Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry, a national, voluntary GHG ~~emission~~emissions reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG ~~emission~~emissions reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs."

Clean Air Act Matters

Overview: In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.

MATS Implementation: The final MATS rule under the CAA, previously referred to as the Utility Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in compliance

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with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending. In August 2018, the EPA began reconsidering the justification behind the MATS rule and reviewing the regulations emissions standards. In December 2018, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. The emissions standards and other requirements of the MATS rule, however, remain in place. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, ~~and~~which does not ~~expect the EPA’s review of the MATS rule to have a significant~~significantly impact on Idaho Power’s operations or financial results.

National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, NO₂, and SO₂. States are then required to develop ~~emission~~emissions reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items relevant to Idaho Power include the following:

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NO₂:In 2010, the EPA adopted a new NAAQS for NO₂ at a level of 100 parts per billion averaged over a ~~1-hour~~one-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO₂.

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period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO₂. The EPA indicated it would review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NO₂~~. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants.~~

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SO₂: In 2010, the EPA adopted a new NAAQS for SO₂ at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO₂ NAAQS because of a lack of definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO₂ standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO₂ for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.

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Ozone: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of U.S. counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.

~~Ozone~~: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of U.S. counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.

As of the date of this report and based on the EPA designations described above, Idaho Power does not expect these standards to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.

Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units at the Jim Bridger and the Boardman coal-fired plants. The RH BART rules would have required installation of a suite of emissions controls at the Boardman plant; however, in December 2010, the Oregon Environmental Quality Commission approved a plan to install a less costly suite of environmental controls and cease coal-fired operations at the Boardman power plant no later than December 31, 2020.

In December 2009, the WDEQ issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install ~~SCR~~selective catalytic reduction (SCR) equipment for nitrogen oxide (NO_x) control at Jim Bridger units 3 and 4 by December 31, 2015, and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017, to install add-on NO_x controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. ~~Idaho Power is assessing whether to move forward with installation of SCR equipment at units 1 and 2.~~ In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming regional haze SIP that are consistent with the terms of the settlement agreement. In January 2014, the EPA approved Wyoming's regional haze SIP as to the Jim Bridger plant, with the NO_x control compliance dates set forth in the settlement agreement. ~~Several interested parties have appealed~~

In February 2019, PacifiCorp submitted to the ~~EPA's decisions on Wyoming's~~WDEQ an alternative regional haze ~~SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent~~compliance plan for the Jim Bridger plant ~~could be affected.~~that includes a reduced plant-wide monthly limit on emissions for NO_xand SO₂and an annual total emissions cap of NO_xand SO₂for units 1-4. If approved as proposed, the alternative plan would likely eliminate the requirement to install add-on NO_x controls at Jim Bridger units 1 and 2. If the compliance plan as proposed is not approved by WDEQ and finalized, Idaho Power

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will re-evaluate options with PacifiCorp to ensure it complies with EPA and WDEQ rules, but does not believe it would move forward with the installation of SCR equipment at units 1 and 2.

Clean Water Act Matters

Definition of “Waters of the United States” Under the CWA: OnIn August ~~28,~~ 2015, the ~~EPA's~~EPA and U.S. Army Corps of Engineers' (USACE) final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS Rule). Idaho Power believes that the ~~final~~2015 rule potentially expanded federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. The WOTUS Rule was widely challenged in both federal district and circuit courts. ~~The State of Idaho, and several other parties, challenged the rule in North Dakota federal court. That court held that it had jurisdiction and enjoined the implementation of the WOTUS Rule.~~ In ~~February 2017, President Trump issued an executive order directing~~January 2020, the EPA and USACE finalized the U.S. Army Corps of Engineers to rescind the WOTUS Rule. In July 2017, the EPA and the U.S. Army Corps of Engineers issued a notice of their intent to rescind and replace the definition of "waters of the United States" under the CWA, which Idaho Power expects would reduce the number of waters in Idaho Power's service area subject to the WOTUS Rule. In November 2017, the EPA issued a notice that it will delay the effectiveness of the WOTUS Rule until 2020

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while the U.S. Army Corps of Engineers considers a replacement rule. In January 2018, the U.S. Supreme Court issued a unanimous ruling that challenges to the WOTUS Rule must begin with the federal district courts, effectively negating a nationwide stay issued by the Sixth Circuit in 2016. However, because the State of Idaho remains a party to the federal court action in North Dakota, that court’s enjoinder remains in effect, meaning the WOTUS Rule currently does not apply to actions brought in Idaho. In July 2018, the EPA and the U.S. Army Corps of Engineers issued a supplemental notice seeking additional comment on their 2017 proposalrule to repeal the definition of the term WOTUS Rule under the CWA. In August 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction on the EPA’s suspension of the WOTUS Rule, resulting in the WOTUS Rule taking effect in twenty-two states and Washington D.C. The WOTUS Rule does not currently apply in twenty-eight states, including Idaho, and litigation over both the WOTUS Rule and set new and more expansive standards for determining which waters are subject to the ~~EPA’s suspension of~~CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule.

Idaho Power believes the repeal rule and the WOTUS Rule ~~continues. In December 2018, the EPA and U.S. Army Corps of Engineers proposed a rule~~will continue to ~~significantly limit the definition of "waters of the United States" under the CWA.~~

~~Idaho Power has analyzed the WOTUS Rule and~~be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho and should the revised definition take effect in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area. Similarly, because the CWA, as interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its ~~hydroelectric~~hydropower plants, Idaho Power does not expect ~~this proposal to~~reinstatement would have a material ~~benefit to~~impact on Idaho Power's operations or financial condition.

CWA Matters Related to ~~Hydroelectric~~Hydropower Relicensing: Idaho Power is also addressing CWA issues associated with the relicensing of its HCC. See “Relicensing of ~~Hydroelectric~~Hydropower Projects” in this MD&A for additional information on the impact of the CWA on that relicensing effort.

Review of Federal Coal Leases

In January 2016, the Secretary of the U.S. Department of the Interior issued an order directing the BLM to prepare a Programmatic Environmental Impact Statement (PEIS) to analyze potential reforms to the federal coal lease program and placed a moratorium on new federal coal leasing, with limited exceptions, pending completion of the PEIS. In January 2017, the Secretary of the Department of the Interior ordered a cessation of all work on the PEIS and in March 2017 lifted the moratorium on new federal coal leases. As of the date of this report, Idaho Power believes that BCC has adequate reserves under existing leases to satisfy its coal delivery obligations to the Jim Bridger plant during the term of the existing coal supply contract through 2024, and that the Jim Bridger plant will otherwise have access to sufficient coal supplies for its operation for the foreseeable future. However, the lifting of the moratorium could increase the availability of BCC's coal resources and lower the cost of leases for those coal resources.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

When preparing financial statements in accordance with the accounting principles generally accepted in the United States of America (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related ~~disclosure of contingent assets and liabilities.~~disclosures. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

Accounting for Rate Regulation

Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.

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Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately ~~$1.2~~$1.4 billion of regulatory assets and $0.8 billion of regulatory liabilities at December 31, ~~2018.~~

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2019. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters.

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are recorded for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.

Pension and Other Postretirement Benefits

Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, and two unfunded nonqualified deferred compensation ~~plan~~plans for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits).

The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, ~~2018,~~2019, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the ~~2019~~2020 pension expense will be ~~increased~~decreased to ~~4.55~~3.60 percent from the ~~3.95~~4.55 percent rate used in ~~2018.~~2019.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when

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interest rates were generally much higher. The long-term rate of return used to calculate the ~~2019~~2020 pension expense will be decreased to 7.4 percent from the 7.5 percent ~~the same assumption as was~~ used ~~for 2018.~~in 2019.

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Gross net periodic pension and other postretirement benefit cost for these plans totaled ~~$51.2 million, $50.4~~$50.0 million and ~~$51.8~~$51.2 million for the years ended December 31, ~~2018, 2017,~~2019 and ~~2016,~~2018, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For ~~2019,~~2020, gross pension and other postretirement benefit costs are expected to total approximately ~~$51.4~~$54.9 million, which takes into account the change in the discount rate noted above.

Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:


	Discount rate						Rate of return						Discount rate						Rate of return
	2019			2018			2019			2018			2020			2019			2020			2019
	(millions of dollars)												(millions of dollars)
Effect of 0.5% rate increase on net periodic benefit cost	$	(7.0	)	$	(7.9	)	$	(3.5	)	$	(3.7	)	$	(8.7	)	$	(7.0	)	$	(4.0	)	$	(3.5	)
Effect of 0.5% rate decrease on net periodic benefit cost	7.8			8.8			3.4			3.6			9.7			7.8			4.0			3.4

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a ~~$76.2~~$97.1 million decrease in the combined benefit obligations of the plans as of December 31, ~~2018.~~2019. A 0.5 percent decrease in the plans' discount rates would have resulted in an ~~$85.7~~$110.0 million increase in the combined benefit obligations of the plans as of December 31, ~~2018.~~2019.

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, ~~2018,~~2019, a total of ~~$148~~$173 million of expense was deferred as a regulatory asset. ~~Approximately $23~~Idaho Power expects to defer approximately $26 million ~~is expected to be deferred~~of expense in ~~2019.~~2020. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million in ~~2018, 2017,~~2019 and ~~2016.~~2018.

Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

RECENTLY ISSUED ACCOUNTING AND AUDITING PRONOUNCEMENTS

On June 1, 2017, the Public Company Accounting Oversight Board (PCAOB) issued Auditing Standard 3101, The Auditor's Report on an Audit of Financial Statements When the Auditor Expresses an Unqualified Opinion (AS 3101). AS 3101 includes a new requirement to describe critical audit matters arising from the audit of the current period's financial statements in the auditor's report. The requirements related to critical audit matters in AS 3101 were effective for audits of fiscal years ending on or after June 30, 2019, for large accelerated filers; and for fiscal years ending on or after December 15, 2020, for all other companies to which the requirements apply. Therefore, critical audit matters are included in the Report of Independent Registered Public Accounting Firm for IDACORP's consolidated financial statements as of and for the year ended December 31, 2019, and AS 3101 will be effective for Idaho Power as of and for the year ending December 31, 2020.

For a listing of other new and recently adopted accounting standards, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the consolidated financial statements included in this report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, ~~2018.~~2019. IDACORP and Idaho Power have not entered into any of these market-risk-sensitive instruments for trading purposes.

Interest Rate Risk

IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt: As of December 31, ~~2018,~~2019, IDACORP and Idaho Power had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt.

Fixed Rate Debt: As of December 31, ~~2018,~~2019, both IDACORP and Idaho Power had $1.8 billion in fixed rate debt, with a fair market value of approximately ~~$1.9~~$2.1 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately ~~$276.8~~$262.2 million if market interest rates were to decline by one percentage point from their December 31, ~~2018,~~2019, levels.

Commodity Price Risk

IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These effects of changes in commodity prices on Idaho Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk.

A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.

The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy ~~(Policy)~~ and associated standards implementing the Risk Management Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), ~~comprises~~comprised of selected Idaho Power officers and other senior ~~staff,~~managers, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to ~~the~~ Idaho ~~Power~~Power's Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Risk Management Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its ~~IRP.~~Integrated Resource Plan. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.

The Risk Management Policy and associated standards require monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The power supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, ~~and orders~~

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and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Risk Management Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by the power supply unit for consistency and compliance with the Risk Management Policy and associated standards. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.

Credit Risk

IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, ~~2018,~~2019, Idaho Power had no$1.4 million of performance assurance collateral posted related to these contracts. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, ~~2018,~~2019, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately ~~$10.5~~$10.3 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.

Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements and Financial Statement Schedules



Consolidated Financial Statements	Page

IDACORP, Inc.:
Consolidated Statements of Income	7776
Consolidated Statements of Comprehensive Income	7877
Consolidated Balance Sheets	7978
Consolidated Statements of Cash Flows	8180
Consolidated Statements of Equity	8281

Idaho Power Company:
Consolidated Statements of Income	8382
Consolidated Statements of Comprehensive Income	8483
Consolidated Balance Sheets	8584
Consolidated Statements of Cash Flows	8786
Consolidated Statements of Retained Earnings	8887

Notes to the Consolidated Financial Statements	8988
Reports of Independent Registered Public Accounting Firm	~~130~~128

Supplemental Financial Information and Financial Statement Schedules

Supplemental Financial Information (unaudited)	~~132~~131
Financial Statement Schedules:
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant	~~146~~145
IDACORP, Inc. ~~- Schedule II - Consolidated Valuation~~ and ~~Qualifying Accounts~~	~~148~~
Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts	~~149~~147

All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included.

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IDACORP, Inc.

Consolidated Statements of Income


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars except for per share amounts)									(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility revenues	$	1,366,582		$	1,344,893		$	1,259,353		$	1,342,940		$	1,366,582		$	1,344,893
Other	4,170			4,593			2,667			3,443			4,170			4,593
Total operating revenues	1,370,752			1,349,486			1,262,020			1,346,383			1,370,752			1,349,486

Operating Expenses:
Electric utility:
Purchased power	293,814			248,950			245,764			285,266			293,814			248,950
Fuel expense	133,198			145,829			179,491			156,872			133,198			145,829
Power cost adjustment	42,106			52,024			(5,330		)	2,047			42,106			52,024
Other operations and maintenance	364,456			346,695			349,290			355,770			364,456			346,695
Energy efficiency programs	35,703			39,241			33,754			40,128			35,703			39,241
Depreciation	165,190			162,091			143,661			169,210			165,190			162,091
Taxes other than income taxes	34,792			34,089			32,823			34,044			34,792			34,089
Total electric utility expenses	1,069,259			1,028,919			979,453			1,043,337			1,069,259			1,028,919
Other	4,571			5,022			(1,015		)	4,720			4,571			5,022
Total operating expenses	1,073,830			1,033,941			978,438			1,048,057			1,073,830			1,033,941
Operating Income	296,922			315,545			283,582			298,326			296,922			315,545
Allowance for Equity Funds Used During Construction	24,353			20,784			22,031			27,112			24,353			20,784
Earnings of Unconsolidated Equity-Method Investments	12,449			11,374			12,871			12,370			12,449			11,374
Other Expense, Net	(2,867		)	(2,109		)	(1,932		)
Other Income (Expense), Net										6,502			(2,867		)	(2,109		)
Interest Expense:
Interest on long-term debt	84,408			81,198			81,956			82,457			84,408			81,198
Other interest	11,691			11,242			10,273			14,721			11,691			11,242
Allowance for borrowed funds used during construction	(10,151		)	(8,694		)	(10,194		)	(10,703		)	(10,151		)	(8,694		)
Total interest expense, net	85,948			83,746			82,035			86,475			85,948			83,746
Income Before Income Taxes	244,909			261,848			234,517			257,835			244,909			261,848
Income Tax Expense	17,386			48,660			36,429			24,507			17,386			48,660
Net Income	227,523			213,188			198,088			233,328			227,523			213,188
Adjustment for (income) loss attributable to noncontrolling interests	(722		)	(769		)	200
Adjustment for income attributable to noncontrolling interests										(474		)	(722		)	(769		)
Net Income Attributable to IDACORP, Inc.	$	226,801		$	212,419		$	198,288		$	232,854		$	226,801		$	212,419
Weighted Average Common Shares Outstanding - Basic (000’s)	50,432			50,361			50,298			50,502			50,432			50,361
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,510			50,424			50,373			50,537			50,510			50,424
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	4.50		$	4.22		$	3.94		$	4.61		$	4.50		$	4.22
Earnings Attributable to IDACORP, Inc. - Diluted	$	4.49		$	4.21		$	3.94		$	4.61		$	4.49		$	4.21

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Statements of Comprehensive Income


	Year Ended December 31,								Year Ended December 31,
	2018			2017			2016		2019			2018			2017
	(thousands of dollars)								(thousands of dollars)

Net Income	$	227,523		$	213,188		$	198,088	$	233,328		$	227,523		$	213,188
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $2,815, $(1,555), and $253	8,120			(5,990		)	394
Unfunded pension liability adjustment, net of tax of $(4,658), $2,815, and $(1,555)									(13,440		)	8,120			(5,990		)
Total Comprehensive Income	235,643			207,198			198,482		219,888			235,643			207,198
Comprehensive (income) loss attributable to noncontrolling interests	(722		)	(769		)	200
Comprehensive income attributable to noncontrolling interests									(474		)	(722		)	(769		)
Comprehensive Income Attributable to IDACORP, Inc.	$	234,921		$	206,429		$	198,682	$	219,414		$	234,921		$	206,429

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Balance Sheets


	December 31,						December 31,
	2018			2017			2019			2018
	(in thousands)						(in thousands)
Assets

Current Assets:
Cash and cash equivalents	$	267,492		$	76,649		$	217,254		$	267,492
Receivables:
Customer (net of allowance of $1,725 and $2,013, respectively)	77,178			75,249
Other (net of allowance of $264 and $180, respectively)	7,476			30,438
Customer (net of allowance of $1,401 and $1,725, respectively)							72,675			77,178
Other (net of allowance of $343 and $264, respectively)							18,789			7,476
Income taxes receivable	4,356			8,147			3,106			4,356
Accrued unbilled revenues	69,318			75,120			64,545			69,318
Materials and supplies (at average cost)	54,987			55,745			56,660			54,987
Fuel stock (at average cost)	47,979			56,638			57,448			47,979
Prepayments	16,492			16,984			17,638			16,492
Current regulatory assets	48,707			48,613			56,626			48,707
Other	3,655			18			405			3,655
Total current assets	597,640			443,601			565,146			597,640

Investments	101,178			115,698			98,218			101,178

Property, Plant and Equipment:
Utility plant in service	6,103,856			5,906,162			6,113,567			6,103,856
Accumulated provision for depreciation	(2,210,781		)	(2,098,274		)	(2,155,783		)	(2,210,781		)
Utility plant in service - net	3,893,075			3,807,888			3,957,784			3,893,075
Construction work in progress	480,259			452,424			552,499			480,259
Utility plant held for future use	4,751			8,075			3,872			4,751
Other property, net of accumulated depreciation	17,650			15,488			17,299			17,650
Property, plant and equipment - net	4,395,735			4,283,875			4,531,454			4,395,735

Other Assets:
Company-owned life insurance	59,852			59,323			58,922			59,852
Regulatory assets	1,165,467			1,083,483			1,326,433			1,165,467
Other	62,882			59,425			61,028			62,882
Total other assets	1,288,201			1,202,231			1,446,383			1,288,201

Total	$	6,382,754		$	6,045,405		$	6,641,201		$	6,382,754

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Balance Sheets


	December 31,						December 31,
	2018			2017			2019			2018
	(in thousands)						(in thousands)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt							$	100,000		$	—
Accounts payable	$	110,824		$	90,277		110,745			110,824
Taxes accrued	12,009			11,075			11,501			12,009
Interest accrued	23,622			22,379			20,999			23,622
Accrued compensation	55,121			47,018			52,550			55,121
Current regulatory liabilities	25,883			1,404			33,987			25,883
Advances from customers	20,037			18,414			28,452			20,037
Other	11,096			10,182			16,625			11,096
Total current liabilities	258,592			200,749			374,859			258,592

Other Liabilities:
Deferred income taxes	699,878			660,940			746,231			699,878
Regulatory liabilities	738,994			698,044			748,198			738,994
Pension and other postretirement benefits	431,475			438,869			519,570			431,475
Other	43,216			44,566			45,131			43,216
Total other liabilities	1,913,563			1,842,419			2,059,130			1,913,563

Long-Term Debt	1,834,788			1,746,123			1,736,659			1,834,788

Commitments and Contingencies

Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000 shares authorized; shares issued 50,420)	863,593			857,207			868,307			863,593
Retained earnings	1,531,543			1,426,528			1,634,525			1,531,543
Accumulated other comprehensive loss	(22,844		)	(30,964		)	(36,284		)	(22,844		)
Treasury stock (27 and 28 shares at cost, respectively)	(1,932		)	(1,386		)
Treasury stock (22 and 27 shares at cost, respectively)							(1,920		)	(1,932		)
Total IDACORP, Inc. shareholders’ equity	2,370,360			2,251,385			2,464,628			2,370,360
Noncontrolling interests	5,451			4,729			5,925			5,451
Total equity	2,375,811			2,256,114			2,470,553			2,375,811

Total	$	6,382,754		$	6,045,405		$	6,641,201		$	6,382,754

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Statements of Cash Flows


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars)									(thousands of dollars)
Operating Activities:
Net income	$	227,523		$	213,188		$	198,088		$	233,328		$	227,523		$	213,188
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	169,120			165,933			147,294			173,800			169,120			165,933
Deferred income taxes and investment tax credits	11,292			33,245			35,732			22,389			11,292			33,245
Changes in regulatory assets and liabilities	48,392			57,131			(5,650		)	(4,310		)	48,392			57,131
Pension and postretirement benefit plan expense	32,256			28,911			29,581			27,804			32,256			28,911
Contributions to pension and postretirement benefit plans	(45,899		)	(46,589		)	(45,301		)	(48,525		)	(45,899		)	(46,589		)
Earnings of unconsolidated equity-method investments	(12,449		)	(11,374		)	(12,871		)
Distributions from unconsolidated equity-method investments	31,115			24,975			25,641
Earnings of equity-method investments										(12,370		)	(12,449		)	(11,374		)
Distributions from equity-method investments										21,800			31,115			24,975
Allowance for equity funds used during construction	(24,353		)	(20,784		)	(22,031		)	(27,112		)	(24,353		)	(20,784		)
Gain on sale of investments and assets	(155		)	(131		)	(103		)	(285		)	(155		)	(131		)
Other non-cash adjustments to net income, net	9,152			8,454			5,108			8,325			9,152			8,454
Change in:
Accounts receivable	729			1,045			(6,315		)	(5,996		)	729			1,045
Accounts payable and other accrued liabilities	29,666			(17,208		)	13,300			(9,526		)	29,666			(17,208		)
Taxes accrued/receivable	4,725			4,361			662			742			4,725			4,361
Other current assets	12,707			2,814			(10,887		)	(8,820		)	12,707			2,814
Other current liabilities	6,848			1,017			(3,283		)	(799		)	6,848			1,017
Other assets	(7,488		)	(8,734		)	(3,764		)	(4,375		)	(7,488		)	(8,734		)
Other liabilities	(1,555		)	(1,093		)	(1,006		)	555			(1,555		)	(1,093		)
Net cash provided by operating activities	491,626			435,161			344,195			366,625			491,626			435,161
Investing Activities:
Additions to property, plant and equipment	(277,853		)	(285,488		)	(296,950		)	(278,705		)	(277,853		)	(285,488		)
Payments received from transmission project joint funding partners	21,587			6,074			7,586			2,442			21,587			6,074
Purchase of available-for-sale securities	(11,390		)	(11,356		)	(14,917		)
Proceeds from sale of available-for-sale securities	5,007			4,989			15,693
Purchase of life insurance investment	—			—			(10,000		)
Purchase of equity securities										(10,896		)	(11,390		)	(11,356		)
Proceeds from sale of equity securities										5,080			5,007			4,989
Other	4,472			5,340			4,655			1,587			4,472			5,340
Net cash used in investing activities	(258,177		)	(280,441		)	(293,933		)	(280,492		)	(258,177		)	(280,441		)
Financing Activities:
Issuance of long-term debt	220,000			—			120,000			166,100			220,000			—
Retirement of long-term debt	(130,000		)	(1,064		)	(101,064		)	(166,100		)	(130,000		)	(1,064		)
Dividends on common stock	(121,421		)	(113,127		)	(104,984		)	(129,677		)	(121,421		)	(113,127		)
Net change in short-term borrowings	—			(21,800		)	1,800			—			—			(21,800		)
Acquisition of treasury stock	(3,614		)	(3,212		)	(3,329		)	(4,160		)	(3,614		)	(3,212		)
Make-whole premium on retirement of long-term debt	(4,607		)	—			(13,895		)	—			(4,607		)	—
Other	(2,964		)	(348		)	(2,112		)
Debt issuance costs and other										(2,534		)	(2,964		)	(348		)
Net cash used in financing activities	(42,606		)	(139,551		)	(103,584		)	(136,371		)	(42,606		)	(139,551		)
Net increase (decrease) in cash and cash equivalents	190,843			15,169			(53,322		)
Net (decrease) increase in cash and cash equivalents										(50,238		)	190,843			15,169
Cash and cash equivalents at beginning of the year	76,649			61,480			114,802			267,492			76,649			61,480
Cash and cash equivalents at end of the year	$	267,492		$	76,649		$	61,480		$	217,254		$	267,492		$	76,649
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Income taxes	$	5,272		$	14,742		$	3,302		$	14,055		$	5,272		$	14,742
Interest (net of amount capitalized)	$	80,951		$	80,004		$	78,334		$	85,260		$	80,951		$	80,004
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	29,528		$	33,220		$	34,603		$	38,815		$	29,528		$	33,220

The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, Inc.

Consolidated Statements of Equity


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars)									(thousands of dollars)
Common Stock:
Balance at beginning of year	$	857,207		$	851,833		$	849,112		$	863,593		$	857,207		$	851,833
Cumulative effect of change in accounting principle	—			—			234
Share-based compensation expense	9,362			7,384			5,561			8,788			9,362			7,384
Treasury shares issued	(3,068		)	(2,069		)	(3,143		)	(4,172		)	(3,068		)	(2,069		)
Other	92			59			69			98			92			59
Balance at end of year	863,593			857,207			851,833			868,307			863,593			857,207

Retained Earnings:
Balance at beginning of year	1,426,528			1,323,198			1,230,105			1,531,543			1,426,528			1,323,198
Cumulative effect of change in accounting principle	—			4,092			(234		)	—			—			4,092
Net income attributable to IDACORP, Inc.	226,801			212,419			198,288			232,854			226,801			212,419
Common stock dividends ($2.40, $2.24, and $2.08 per share, respectively)	(121,786		)	(113,181		)	(104,961		)
Common stock dividends ($2.56, $2.40, and $2.24 per share, respectively)										(129,872		)	(121,786		)	(113,181		)
Balance at end of year	1,531,543			1,426,528			1,323,198			1,634,525			1,531,543			1,426,528

Accumulated Other Comprehensive (Loss) Income:
Balance at beginning of year	(30,964		)	(20,882		)	(21,276		)	(22,844		)	(30,964		)	(20,882		)
Cumulative effect of change in accounting principle	—			(4,092		)	—			—			—			(4,092		)
Unfunded pension liability adjustment (net of tax)	8,120			(5,990		)	394			(13,440		)	8,120			(5,990		)
Balance at end of year	(22,844		)	(30,964		)	(20,882		)	(36,284		)	(22,844		)	(30,964		)

Treasury Stock:
Balance at beginning of year	(1,386		)	(243		)	(57		)	(1,932		)	(1,386		)	(243		)
Issued	3,068			2,069			3,143			4,172			3,068			2,069
Acquired	(3,614		)	(3,212		)	(3,329		)	(4,160		)	(3,614		)	(3,212		)
Balance at end of year	(1,932		)	(1,386		)	(243		)	(1,920		)	(1,932		)	(1,386		)

Total IDACORP, Inc. shareholders’ equity at end of year	2,370,360			2,251,385			2,153,906			2,464,628			2,370,360			2,251,385

Noncontrolling Interests:
Balance at beginning of year	4,729			3,960			4,160			5,451			4,729			3,960
Net income (loss) attributable to noncontrolling interests	722			769			(200		)
Net income attributable to noncontrolling interests										474			722			769
Balance at end of year	5,451			4,729			3,960			5,925			5,451			4,729

Total equity at end of year	$	2,375,811		$	2,256,114		$	2,157,866		$	2,470,553		$	2,375,811		$	2,256,114

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Statements of Income


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars)									(thousands of dollars)

Operating Revenues	$	1,366,582		$	1,344,893		$	1,259,353		$	1,342,940		$	1,366,582		$	1,344,893

Operating Expenses:
Operation:
Purchased power	293,814			248,950			245,764			285,266			293,814			248,950
Fuel expense	133,198			145,829			179,491			156,872			133,198			145,829
Power cost adjustment	42,106			52,024			(5,330		)	2,047			42,106			52,024
Other operations and maintenance	364,456			346,695			349,290			355,770			364,456			346,695
Energy efficiency programs	35,703			39,241			33,754			40,128			35,703			39,241
Depreciation	165,190			162,091			143,661			169,210			165,190			162,091
Taxes other than income taxes	34,792			34,089			32,823			34,044			34,792			34,089
Total operating expenses	1,069,259			1,028,919			979,453			1,043,337			1,069,259			1,028,919

Income from Operations	297,323			315,974			279,900			299,603			297,323			315,974

Other Income (Expense):
Allowance for equity funds used during construction	24,353			20,784			22,031			27,112			24,353			20,784
Earnings of unconsolidated equity-method investments	10,712			9,267			10,855			10,285			10,712			9,267
Other expense, net	(5,851		)	(4,756		)	(4,547		)
Other income (expense), net										2,266			(5,851		)	(4,756		)
Total other income	29,214			25,295			28,339			39,663			29,214			25,295

Interest Charges:
Interest on long-term debt	84,408			81,198			81,956			82,457			84,408			81,198
Other interest	11,634			11,156			10,050			14,658			11,634			11,156
Allowance for borrowed funds used during construction	(10,151		)	(8,694		)	(10,194		)	(10,703		)	(10,151		)	(8,694		)
Total interest charges	85,891			83,660			81,812			86,412			85,891			83,660

Income Before Income Taxes	240,646			257,609			226,427			252,854			240,646			257,609

Income Tax Expense	18,312			51,262			37,185			28,417			18,312			51,262

Net Income	$	222,334		$	206,347		$	189,242		$	224,437		$	222,334		$	206,347

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Statements of Comprehensive Income


	Year Ended December 31,							Year Ended December 31,
	2018		2017			2016		2019			2018		2017
	(thousands of dollars)							(thousands of dollars)

Net Income	$	222,334	$	206,347		$	189,242	$	224,437		$	222,334	$	206,347
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $2,815, $(1,555), and $253	8,120		(5,990		)	394
Unfunded pension liability adjustment, net of tax of $(4,658), $2,815, and $(1,555)								(13,440		)	8,120		(5,990		)
Total Comprehensive Income	$	230,454	$	200,357		$	189,636	$	210,997		$	230,454	$	200,357

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Balance Sheets


	December 31,						December 31,
	2018			2017			2019			2018
	(in thousands)						(in thousands)
Assets

Electric Plant:
In service (at original cost)	$	6,103,856		$	5,906,162		$	6,113,567		$	6,103,856
Accumulated provision for depreciation	(2,210,781		)	(2,098,274		)	(2,155,783		)	(2,210,781		)
In service - net	3,893,075			3,807,888			3,957,784			3,893,075
Construction work in progress	480,259			452,424			552,499			480,259
Held for future use	4,751			8,075			3,872			4,751
Electric plant - net	4,378,085			4,268,387			4,514,155			4,378,085

Investments and Other Property	90,019			99,904			87,104			90,019

Current Assets:
Cash and cash equivalents	165,460			44,646			98,950			165,460
Receivables:
Customer (net of allowance of $1,725 and $2,013, respectively)	77,178			75,249
Other (net of allowance of $264 and $180, respectively)	7,206			30,274
Customer (net of allowance of $1,401 and $1,725, respectively)							72,675			77,178
Other (net of allowance of $343 and $264, respectively)							17,107			7,206
Income taxes receivable	11,829			26,492			9,279			11,829
Accrued unbilled revenues	69,318			75,120			64,545			69,318
Materials and supplies (at average cost)	54,987			55,745			56,660			54,987
Fuel stock (at average cost)	47,979			56,638			57,448			47,979
Prepayments	16,374			16,866			17,520			16,374
Current regulatory assets	48,707			48,613			56,626			48,707
Other	3,655			18			405			3,655
Total current assets	502,693			429,661			451,215			502,693

Deferred Debits:
Company-owned life insurance	59,852			59,323			58,922			59,852
Regulatory assets	1,165,467			1,083,483			1,326,433			1,165,467
Other	58,284			54,677			56,330			58,284
Total deferred debits	1,283,603			1,197,483			1,441,685			1,283,603

Total	$	6,254,400		$	5,995,435		$	6,494,159		$	6,254,400

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Balance Sheets


	December 31,						December 31,
	2018			2017			2019			2018
	(in thousands)						(in thousands)
Capitalization and Liabilities

Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)	$	97,877		$	97,877		$	97,877		$	97,877
Premium on capital stock	712,258			712,258			712,258			712,258
Capital stock expense	(2,097		)	(2,097		)	(2,097		)	(2,097		)
Retained earnings	1,409,245			1,308,702			1,503,805			1,409,245
Accumulated other comprehensive loss	(22,844		)	(30,964		)	(36,284		)	(22,844		)
Total common stock equity	2,194,439			2,085,776			2,275,559			2,194,439
Long-term debt	1,834,788			1,746,123			1,736,659			1,834,788
Total capitalization	4,029,227			3,831,899			4,012,218			4,029,227

Current Liabilities:
Current maturities of long-term debt							100,000			—
Accounts payable	110,597			89,978			110,581			110,597
Accounts payable to affiliates	2,088			57,562			2,053			2,088
Taxes accrued	11,750			10,904			11,481			11,750
Interest accrued	23,622			22,379			20,999			23,622
Accrued compensation	54,910			46,832			52,267			54,910
Current regulatory liabilities	25,883			1,404			33,987			25,883
Advances from customers	20,037			18,414			28,452			20,037
Other	10,198			9,556			15,629			10,198
Total current liabilities	259,085			257,029			375,449			259,085

Deferred Credits:
Deferred income taxes	753,239			725,942			794,402			753,239
Regulatory liabilities	738,994			698,044			748,198			738,994
Pension and other postretirement benefits	431,475			438,869			519,570			431,475
Other	42,380			43,652			44,322			42,380
Total deferred credits	1,966,088			1,906,507			2,106,492			1,966,088

Commitments and Contingencies

Total	$	6,254,400		$	5,995,435		$	6,494,159		$	6,254,400

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Statements of Cash Flows


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars)									(thousands of dollars)
Operating Activities:
Net income	$	222,334		$	206,347		$	189,242		$	224,437		$	222,334		$	206,347
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	168,519			165,337			146,694			173,205			168,519			165,337
Deferred income taxes and investment tax credits	(2,272		)	(10,875		)	25,780			14,889			(2,272		)	(10,875		)
Changes in regulatory assets and liabilities	48,392			57,131			(5,651		)	(4,310		)	48,392			57,131
Pension and postretirement benefit plan expense	32,240			28,894			29,597			27,788			32,240			28,894
Contributions to pension and postretirement benefit plans	(45,883		)	(46,573		)	(45,317		)	(48,509		)	(45,883		)	(46,573		)
Earnings of unconsolidated equity-method investments	(10,712		)	(9,267		)	(10,855		)
Distributions from unconsolidated equity-method investments	29,400			23,000			23,716
Earnings of equity-method investments										(10,285		)	(10,712		)	(9,267		)
Distributions from equity-method investments										19,450			29,400			23,000
Allowance for equity funds used during construction	(24,353		)	(20,784		)	(22,031		)	(27,112		)	(24,353		)	(20,784		)
Gain on sale of investments and assets	(155		)	(131		)	(103		)	(285		)	(155		)	(131		)
Other non-cash adjustments to net income, net	(210		)	1,069			(454		)	(463		)	(210		)	1,069
Change in:
Accounts receivable	633			(5,282		)	(54		)	(4,724		)	633			(5,282		)
Accounts payable	(25,532		)	38,111			13,308			(9,463		)	(25,532		)	38,111
Taxes accrued/receivable	15,509			(3,601		)	(17,299		)	2,281			15,509			(3,601		)
Other current assets	12,707			2,812			(10,902		)	(8,821		)	12,707			2,812
Other current liabilities	6,822			996			(3,322		)	(870		)	6,822			996
Other assets	(7,488		)	(8,734		)	(3,764		)	(4,280		)	(7,488		)	(8,734		)
Other liabilities	(1,476		)	(967		)	(829		)	584			(1,476		)	(967		)
Net cash provided by operating activities	418,475			417,483			307,756			343,512			418,475			417,483
Investing Activities:
Additions to utility plant	(277,823		)	(285,471		)	(296,948		)	(278,707		)	(277,823		)	(285,471		)
Payments received from transmission project joint funding partners	21,587			6,074			7,586			2,442			21,587			6,074
Purchase of available-for-sale securities	(11,390		)	(11,356		)	(14,917		)
Proceeds from the sale of available-for-sale securities	5,007			4,989			15,693
Purchase of life insurance investment	—			—			(10,000		)
Purchase of equity securities										(10,896		)	(11,390		)	(11,356		)
Proceeds from the sale of equity securities										5,080			5,007			4,989
Other	4,320			5,176			4,511			4,117			4,320			5,176
Net cash used in investing activities	(258,299		)	(280,588		)	(294,075		)	(277,964		)	(258,299		)	(280,588		)
Financing Activities:
Issuance of long-term debt	220,000			—			120,000			166,100			220,000			—
Retirement of long-term debt	(130,000		)	(1,064		)	(101,064		)	(166,100		)	(130,000		)	(1,064		)
Dividends on common stock	(121,791		)	(113,284		)	(105,121		)	(129,877		)	(121,791		)	(113,284		)
Net change in short term borrowings	—			(21,800		)	21,800			—			—			(21,800		)
Make-whole premium on retirement of long-term debt	(4,607		)	—			(13,895		)	—			(4,607		)	—
Other	(2,964		)	(241		)	(2,017		)
Debt issuance costs										(2,181		)	(2,964		)	(241		)
Net cash used in financing activities	(39,362		)	(136,389		)	(80,297		)	(132,058		)	(39,362		)	(136,389		)
Net increase (decrease) in cash and cash equivalents	120,814			506			(66,616		)
Net (decrease) increase in cash and cash equivalents										(66,510		)	120,814			506
Cash and cash equivalents at beginning of the year	44,646			44,140			110,756			165,460			44,646			44,140
Cash and cash equivalents at end of the year	$	165,460		$	44,646		$	44,140		$	98,950		$	165,460		$	44,646
Supplemental Disclosure of Cash Flow Information:
Cash paid to IDACORP related to income taxes	$	63,914		$	12,444		$	29,341		$	19,856		$	63,914		$	12,444
Cash paid for interest (net of amount capitalized)	$	80,894		$	79,918		$	78,111		$	85,198		$	80,894		$	79,918
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	29,528		$	33,220		$	34,603		$	38,815		$	29,528		$	33,220

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Consolidated Statements of Retained Earnings


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
	(thousands of dollars)									(thousands of dollars)

Retained Earnings, Beginning of Year	$	1,308,702		$	1,211,547		$	1,127,426		$	1,409,245		$	1,308,702		$	1,211,547
Net Income	222,334			206,347			189,242			224,437			222,334			206,347
Dividends on Common Stock	(121,791		)	(113,284		)	(105,121		)	(129,877		)	(121,791		)	(113,284		)
Cumulative Effect of Change in Accounting Principle	—			4,092			—			—			—			4,092
Retained Earnings, End of Year	$	1,409,245		$	1,308,702		$	1,211,547		$	1,503,805		$	1,409,245		$	1,308,702

The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to the 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, sales, 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 (Jim Bridger plant) owned in part by Idaho Power.

IDACORP’s other notable 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~~hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues and expenses of each company and its wholly-owned subsidiaries listed above, as well as any variable interest entities (VIEs) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

IDACORP also consolidates one variable interest entity (VIE), Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, ~~2018,~~2019, Marysville had approximately $18 million of assets, primarily a ~~hydroelectric~~hydropower plant, and approximately $8$6 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

The BCC joint venture is also a VIE, but because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner, Idaho Power is not the primary beneficiary. The carrying value of Idaho Power's investment in BCC was ~~$49.9~~$40.7 million at December 31, ~~2018,~~2019, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a ~~$58.4~~$58.3 million guarantee for mine reclamation costs, which is discussed further in Note 10 - "Commitments."

IFS's affordable housing limited partnership and other real estate investments are also VIEs for which IDACORP is not the primary beneficiary. IFS's limited partnership interests range from 4 to 99 percent and were acquired between 1996 and ~~2010.~~2019. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was ~~$3.4~~$3.7 million at December 31, ~~2018.~~2019.

Ida-West's other investments in PURPA facilities, Idaho Power's investment in BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 15 - "Investments").

Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation.

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The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly-owned plants (see Note 13 - "Property, Plant and Equipment and Jointly-Owned Projects").

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.

Idaho Power meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. 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."

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.

System of Accounts

The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.

Cash and Cash Equivalents

Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.

Receivables and Allowance for Uncollectible Accounts

Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of ~~one~~1 percent per month may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off.

Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.

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There were no0 impaired receivables without related allowances at December 31, ~~2018~~2019 and ~~2017.~~2018. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.

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Derivative Financial Instruments

Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Revenues

On January 1, 2018, IDACORP and Idaho Power adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power. Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues."

Property, Plant and Equipment and Depreciation

The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.

All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.9 percent in 2019, 2.8 percent in 2018, and 2.9 percent in ~~2017, and 2.6 percent in 2016.~~2017.

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek recovery of such costs in customer rates, although there can be no guarantee such recovery would be granted.

Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no0 material impairments of long-lived assets in 2019, 2018, ~~2017,~~ or ~~2016.~~2017.

Allowance for Funds Used During Construction

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells Canyon Complex (HCC) relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power’s weighted-average monthly AFUDC rate was 7.6 percent for 2019, 2018 ~~2017~~ and ~~2016.~~2017.

Income Taxes

IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial

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statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. In general, deferred income tax expense or benefit

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for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. ~~Regulated enterprises are required to recognize~~Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

IDACORP and Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless accounted for using flow-through.

~~The state of Idaho allows a three percent investment tax credit on qualifying plant additions.~~ Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. ~~Credits earned on non-regulated assets or investments are recognized in the year earned.~~

Income taxes are discussed in more detail in Note 2 - "Income Taxes."

Other Accounting Policies

Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issues. Losses on reacquired debt and associated costs are amortized over the life of the associated replacement debt, as allowed under regulatory accounting.

~~Reclassifications~~

In these 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, 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.

New and Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In ~~May 2014,~~February 2016, the ~~Financial Accounting Standards Board (FASB)~~FASB issued ASU ~~2014-09,~~ ~~Revenue from Contracts with Customers~~2016-02, Leases (Topic ~~606). ASU 2014-09 is~~842), intended to ~~enable users of~~improve financial ~~statements~~reporting on leasing transactions. The ASU requires lessees to ~~better understand~~recognize a right-of-use asset and ~~consistently analyze an entity's revenue across industries, transactions, and geographies. Under~~lease liability on the ~~ASU, recognition of revenue occurs when a customer obtains control of promised goods or services.~~balance sheet for most leases. In addition, the ASU ~~requires disclosure~~revises the definition of a lease in regards to when an arrangement conveys the right to control the use 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~~identified asset under the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients.arrangement. IDACORP and Idaho Power adopted ASU ~~2014-09~~2016-02 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 consolidated statements of income and also added disclosures. To conform with current period presentation, "Electric utility revenues" and "Operating Revenues" on

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IDACORP's and Idaho Power's consolidated statements of income, respectively, for the year ended December 31, 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, 2018.2019. The adoption did not have a material impact on ~~the companies'~~their respective 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.statements. Neither IDACORP ~~and~~nor Idaho Power ~~adopted~~has material agreements that meet the definition of a lease under 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 $3.0 million and $3.6 million of company-owned life insurance proceeds received, for the year ended December 31, 2017 and 2016, respectively, from "Change in accounts receivable" and $0.1 million and $0.1 million of prepaid insurance premiums paid, for the year ended December 31, 2017 and 2016, respectively, from "Change in other assets" (net reclassification of $2.9 million and $3.5 million, respectively) within "Operating Activities" to "Other" within "Investing Activities" on the consolidated statement of cash flows.2016-02.

~~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 cost (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 year ended December 31, 2018. For IDACORP, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, were reclassified out of "Other operations and maintenance" and $8.2 million and $9.2 million, respectively, were reclassified out of "Other" operating expenses for a total of $11.2 million and $11.8 million, respectively, reclassified to "Other Expense, Net" to conform to current period presentation. For Idaho Power, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, was reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation.

Recent Accounting Pronouncements Not Yet Adopted

In ~~August 2018,~~June 2016, the FASB issued ASU ~~2018-15,~~ ~~Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40)~~2016-13, Financial Instruments—Credit Losses (Topic 326): ~~Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~Measurement of Credit Losses on Financial Instruments, to provide ~~guidance~~financial statement users with more information about expected credit losses on ~~implementation costs~~financial instruments. The ASU revises the incurred inloss impairment methodology to reflect current expected credit losses and requires consideration of a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software.broader range of information to estimate credit losses. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. IDACORP and Idaho Power are ~~evaluating~~finalizing the ~~impact~~assessment of the financial impacts of adoption, but do not believe that the adoption of ASU ~~2018-15~~2016-13 will have a material impact on their respective financial statements.

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In ~~February 2016,~~August 2018, the FASB issued ASU ~~2016-02,~~ ~~Leases (Topic 842)~~2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ~~intended~~ to ~~improve financial reporting about leasing transactions. The~~provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU ~~requires lessees~~2018-15 aligns the recognition of such implementation costs with the accounting for costs incurred to ~~recognize a right-of-use asset and lease liability on~~implement an internal-use software solution. However, the balance sheet line item for ~~most leases. In addition,~~presentation of capitalized implementation costs for a cloud arrangement that is a service contract should be the ~~ASU revises~~same as that for the ~~definition~~prepayment of ~~a lease in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes~~fees related to the ~~classification of~~same arrangement, while capitalized implementation costs for internal-use software solutions are often included in property, plant, and equipment as an ~~arrangement as a lease. ASU 2016-02 was~~intangible asset. The new standard is effective ~~on January 1,~~for interim and annual reporting periods beginning after December 15, 2019, ~~and IDACORP and Idaho Power will record any effects of the~~with early adoption ~~in the first quarter of 2019. While~~permitted. IDACORP and Idaho Power are finalizing the assessment of the financial impacts of ~~the~~ adoption, but do not believe the adoption of ASU ~~2016-02~~2018-15 will not have a material impact on their respective financial statements.

2. INCOME TAXES

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:



	IDACORP									Idaho Power
	2019			2018			2017			2019			2018			2017
	(thousands of dollars)
Federal income tax expense at statutory rate	$	54,046		$	51,279		$	91,378		$	53,099		$	50,536		$	90,163
Change in taxes resulting from:
AFUDC	(7,941		)	(7,246		)	(10,318		)	(7,941		)	(7,246		)	(10,318		)
Capitalized interest	976			928			1,513			976			928			1,513
Investment tax credits	(6,252		)	(2,929		)	(3,081		)	(6,252		)	(2,929		)	(3,081		)
Removal costs	(3,139		)	(3,471		)	(6,280		)	(3,139		)	(3,471		)	(6,280		)
Capitalized overhead costs	(7,140		)	(6,720		)	(11,200		)	(7,140		)	(6,720		)	(11,200		)
Capitalized repair costs	(18,480		)	(17,850		)	(28,700		)	(18,480		)	(17,850		)	(28,700		)
Bond redemption costs	—			(1,029		)	—			—			(1,029		)	—
Remeasurement of deferred taxes	—			(5,411		)	1,690			—			(5,664		)	1,970
State income taxes, net of federal benefit	8,627			8,512			8,153			8,401			8,532			8,108
Depreciation	14,641			13,110			18,953			14,641			13,110			18,953
Excess deferred income tax reversal	(6,181		)	(7,289		)	—			(6,181		)	(7,289		)	—
Income tax return adjustments	745			(5,076		)	(3,710		)	993			(4,968		)	(3,601		)
Affordable housing tax credits	(2,874		)	(2,560		)	(2,559		)	—			—			—
Affordable housing investment distributions	(3,232		)	(267		)	(1,124		)	—			—			—
Affordable housing investment amortization	1,825			1,519			1,271			—			—			—
Other, net	(1,114		)	1,886			(7,326		)	(560		)	2,372			(6,265		)
Total income tax expense	$	24,507		$	17,386		$	48,660		$	28,417		$	18,312		$	51,262
Effective tax rate	9.5%			7.1%			18.6%			11.2%			7.6%			19.9%

IDACORP Idaho Power
2018 2017 2016 2018 2017 2016
(thousands of dollars)
Federal income tax expense at statutory rate $ 51,279
$ 91,378
$ 82,151
$ 50,536
$ 90,163
$ 79,250
Change in taxes resulting from:

AFUDC (7,246 ) (10,318 ) (11,278 ) (7,246 ) (10,318 ) (11,278 )
Capitalized interest 928
1,513
2,000
928
1,513
2,000
Investment tax credits (2,929 ) (3,081 ) (2,922 ) (2,929 ) (3,081 ) (2,922 )
Removal costs (3,471 ) (6,280 ) (5,559 ) (3,471 ) (6,280 ) (5,559 )
Capitalized overhead costs (6,720 ) (11,200 ) (10,500 ) (6,720 ) (11,200 ) (10,500 )
Capitalized repair costs (17,850 ) (28,700 ) (28,000 ) (17,850 ) (28,700 ) (28,000 )
Bond redemption costs (1,029 ) —
(4,997 ) (1,029 ) —
(4,997 )
Remeasurement of deferred taxes (5,411 ) 1,690
—
(5,664 ) 1,970
—
State income taxes, net of federal benefit 8,512
8,153
5,071
8,532
8,108
4,880
Depreciation 13,110
18,953
18,673
13,110
18,953
18,673
Excess deferred income tax reversal (7,289 ) —
—
(7,289 ) —
—
Share-based compensation (894 ) (1,508 ) (1,614 ) (883 ) (1,483 ) (1,583 )
Income tax return adjustments (5,076 ) (3,710 ) (3,539 ) (4,968 ) (3,601 ) (3,669 )
Affordable housing tax credits (2,560 ) (2,559 ) (2,579 ) —
—
—
Affordable housing investment distributions (267 ) (1,124 ) (1,717 ) —
—
—
Affordable housing investment amortization 1,519
1,271
1,380
—
—
—
Other, net 2,780
(5,818 ) (141 ) 3,255
(4,782 ) 890
Total income tax expense $ 17,386
$ 48,660
$ 36,429
$ 18,312
$ 51,262
$ 37,185
Effective tax rate 7.1% 18.6% 15.5% 7.6% 19.9% 16.4%

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The items comprising income tax expense are as follows:



	IDACORP									Idaho Power
	2019			2018			2017			2019			2018			2017
	(thousands of dollars)
Income taxes current:
Federal	$	8,830		$	5,390		$	11,726		$	25,338		$	24,919		$	51,575
State	4,865			3,328			5,418			(4,392		)	(2,049		)	10,562
Total	13,695			8,718			17,144			20,946			22,870			62,137
Income taxes deferred:
Federal	9,486			1,649			24,018			(4,599		)	(15,388		)	(13,002		)
State	1,159			30			(154		)	10,054			5,425			(5,298		)
Total	10,645			1,679			23,864			5,455			(9,963		)	(18,300		)
Investment tax credits:
Deferred	8,268			8,334			10,506			8,268			8,334			10,506
Restored	(6,252		)	(2,929		)	(3,081		)	(6,252		)	(2,929		)	(3,081		)
Total	2,016			5,405			7,425			2,016			5,405			7,425
Affordable housing investments	(1,849		)	1,584			227			—			—			—
Total income tax expense	$	24,507		$	17,386		$	48,660		$	28,417		$	18,312		$	51,262

IDACORP Idaho Power
2018 2017 2016 2018 2017 2016
(thousands of dollars)
Income taxes current:
Federal $ 5,390
$ 11,726
$ 1,181
$ 24,919
$ 51,575
$ 7,639
State 3,328
5,418
2,158
(2,049 ) 10,562
3,766
Total 8,718
17,144
3,339
22,870
62,137
11,405
Income taxes deferred:

Federal 1,649
24,018
33,205
(15,388 ) (13,002 ) 27,506
State 30
(154 ) 100
5,425
(5,298 ) (2,031 )
Total 1,679
23,864
33,305
(9,963 ) (18,300 ) 25,475
Investment tax credits:

Deferred 8,334
10,506
3,227
8,334
10,506
3,227
Restored (2,929 ) (3,081 ) (2,922 ) (2,929 ) (3,081 ) (2,922 )
Total 5,405
7,425
305
5,405
7,425
305
Affordable housing investments 1,584
227
(520 ) —
—
—
Total income tax expense $ 17,386
$ 48,660
$ 36,429
$ 18,312
$ 51,262
$ 37,185

The components of the net deferred tax liability are as follows:



	IDACORP				Idaho Power
	2019		2018		2019		2018
	(thousands of dollars)
Deferred tax assets:
Regulatory liabilities	$	96,599	$	98,042	$	96,599	$	98,042
Deferred compensation	21,946		21,871		21,946		21,826
Deferred revenue	39,039		35,137		39,039		35,137
Tax credits	76,125		100,041		24,489		44,532
Partnership investments	7,911		4,200		4,912		1,086
Retirement benefits	114,124		91,867		114,124		91,867
Other	11,347		9,299		11,107		9,121
Total	367,091		360,457		312,216		301,611
Deferred tax liabilities:
Property, plant and equipment	286,583		294,471		286,583		294,471
Regulatory assets	646,886		614,144		646,886		614,144
Partnership investments	3,565		3,875		—		—
Retirement benefits	132,764		108,440		132,764		108,440
Other	43,524		39,405		40,385		37,795
Total	1,113,322		1,060,335		1,106,618		1,054,850
Net deferred tax liabilities	$	746,231	$	699,878	$	794,402	$	753,239

IDACORP Idaho Power
2018 2017 2018 2017
(thousands of dollars)
Deferred tax assets:

Regulatory liabilities $ 98,042
$ 98,744
$ 98,042
$ 98,744
Deferred compensation 21,871
21,066
21,826
21,025
Deferred revenue 35,137
31,086
35,137
31,086
Tax credits 100,041
109,673
44,532
44,106
Partnership investments 4,200
3,540
1,086
—
Retirement benefits 91,867
94,493
91,867
94,493
Other 9,299
8,636
9,121
8,435
Total 360,457
367,238
301,611
297,889
Deferred tax liabilities:

Property, plant and equipment 294,471
306,002
294,471
306,002
Regulatory assets 614,144
584,329
614,144
584,329
Fixed cost adjustment 10,940
8,016
10,940
8,016
Partnership investments 3,875
5,182
—
980
Retirement benefits 108,440
103,407
108,440
103,407
Other 28,465
21,242
26,855
21,097
Total 1,060,335
1,028,178
1,054,850
1,023,831
Net deferred tax liabilities $ 699,878
$ 660,940
$ 753,239
$ 725,942

IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the consolidated balance sheets of Idaho Power. See Note 1 - "Summary of Significant Accounting Policies" for further discussion of accounting policies related to income taxes.

Tax Credit Carryforwards

As of December 31, ~~2018,~~2019, IDACORP had ~~$60.5~~$36.7 million of general business credit carryforwards for federal income tax purposes and ~~$39.5~~$39.4 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from ~~2027~~2032 to ~~2038,~~2039, and the Idaho investment tax credit expires from ~~2023~~2024 to ~~2032.~~2033.

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Uncertain Tax Positions

IDACORP and Idaho Power believe that they have no0 material income tax uncertainties for ~~2018~~2019 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.

IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. The open tax years for examination are ~~2018~~2019 for federal and ~~2014-2018~~2016-2019 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. In ~~2018~~2019, the IRS completed its examination of IDACORP's ~~2017~~2018 tax year with no unresolved income tax issues.

Income Tax Reform

InOn December 22, 2017, the Tax Cuts and Jobs Act was signed into law, which significantly ~~reforms~~reformed the Internal Revenue Code of 1986, as amended. Effective January 1, 2018, the Tax Cuts and Jobs Act permanently lowers the corporate tax rate to 21 percent from the existing maximum rate of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense, eliminates the alternative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of executive compensation. Public utility companies, such as Idaho Power, retain the full deductibility of interest expense and are excluded from the bonus depreciation provisions; however, traditional accelerated tax depreciation methods are still available.

Due to the enactment of the Tax Cuts and Jobs Act and following generally accepted accounting principles, at December 31, 2017, IDACORP and Idaho Power remeasured all deferred income tax assets and liabilities. The effects of these adjustments resulted in a net tax expense for 2017, as shown in the rate reconciliation table above. Also, as shown above, in 2018, a net tax benefit was recognized for the remeasurement of deferred taxes for the adjustment of temporary differences as a result of IDACORP's 2017 consolidated income tax return filings.

Additionally, in 2017, the net deferred tax liabilities at both companies decreased by approximately $672 million. Idaho Power's regulatory asset deferred income tax liability item decreased as the related regulatory asset was reduced in two primary ways: (1) the decrease in the federal income tax rate decreased the future cost to customers for funding the net deferred income tax liabilities resulting from the cumulative impacts of using the flow-through income tax accounting method for regulatory purposes and (2) the decrease in the federal income tax rate also reduced the net-to-gross multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in income tax law also reduced the deferred income tax liability for depreciation-related timing differences under the normalized tax accounting method. As this reduction will flow back to customers in the future under the statutorily prescribed average rate assumption method, it was recorded as a regulatory liability on the consolidated balance sheets of the companies. See Note 3 - "Regulatory Matters" for more information.

On March 12, 2018, Idaho House Bill 463 was enacted which lowered the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent effective January 1, 2018. The Idaho tax rate reduction did not have a material impact on IDACORP's and Idaho Power's 2018 income tax expense or deferred tax asset and liability balances.

3. REGULATORY MATTERS

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.

Regulatory Assets and Liabilities

The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those expenses and revenues. 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.

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The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):


		As of December 31, 2018											As of December 31, 2019
	Remaining Amortization Period	Earning a Return⁽¹⁾			Not Earning a Return		Total as of December 31,					Remaining Amortization Period	Earning a Return⁽¹⁾		Not Earning a Return			Total as of December 31,
Description				2018			2017				2019		Earning a Return⁽¹⁾		Not Earning a Return		2018
Regulatory Assets:	Remaining Amortization Period	Earning a Return⁽¹⁾			Not Earning a Return							Remaining Amortization Period
Income taxes⁽²⁾		$	—		$	614,144	$	614,144	$	584,329			$	—	$	646,886		$	646,886	$	614,144
Unfunded postretirement benefits⁽³⁾		—			278,674		278,674		280,166				—		347,935			347,935		278,674
Pension expense deferrals(4)		126,811			21,025		147,836		127,721				150,350		22,287			172,637		147,836
Energy efficiency program costs⁽⁴⁾⁽⁵⁾		1,398			—		1,398		6,273				1,465		—			1,465		1,398
Power supply costs⁽⁵⁾		—			—		—		3,137
Fixed cost adjustment⁽⁵⁾	2019-2020	34,502			8,001		42,503		30,856
Valmy Plant settlements⁽⁵⁾	2019-2028	77,512			—		77,512		44,633
Asset retirement obligations⁽⁶⁾		—			17,655		17,655		15,767
Fixed cost adjustment⁽⁶⁾												2020-2021	35,208		18,808			54,016		42,503
North Valmy plant settlements⁽⁶⁾												2020-2028	107,525		—			107,525		77,512
Asset retirement obligations⁽⁷⁾													—		18,835			18,835		17,655
Long-term service agreement	2019-2043	16,095			10,653		26,748		27,907			2020-2043	15,412		10,178			25,590		26,748
Other	2019-2055	720			6,984		7,704		11,307			2020-2055	2,804		5,366			8,170		7,704
Total		$	257,038		$	957,136	$	1,214,174	$	1,132,096			$	312,764	$	1,070,295		$	1,383,059	$	1,214,174
Regulatory Liabilities:
Income taxes⁽⁷⁾		$	—		$	98,042	$	98,042	$	98,744
Depreciation-related excess deferred income taxes⁽⁸⁾		190,062			—		190,062		193,991
Removal costs⁽⁶⁾		—			183,798		183,798		184,993
Income taxes⁽⁸⁾													$	—	$	96,599		$	96,599	$	98,042
Depreciation-related excess deferred income taxes⁽⁹⁾													183,881		—			183,881		190,062
Removal costs⁽⁷⁾													—		185,685			185,685		183,798
Investment tax credits		—			92,790		92,790		87,385				—		94,806			94,806		92,790
Deferred revenue-AFUDC⁽⁹⁾		95,660			39,486		135,146		119,666
Energy efficiency program costs⁽⁴⁾		5,259			—		5,259		408
Power supply costs⁽⁵⁾	2019-2020	35,815			6,507		42,322		5,443
Settlement agreement sharing mechanism⁽⁵⁾	2019-2020	5,025			—		5,025		—
Mark-to-market assets⁽¹⁰⁾		—			3,700		3,700		22
Deferred revenue-AFUDC⁽¹⁰⁾													109,921		41,747			151,668		135,146
Energy efficiency program costs⁽⁵⁾													—		—			—		5,259
Power supply costs⁽⁶⁾												2020-2021	46,022		2,470			48,492		42,322
Settlement agreement sharing mechanism⁽⁶⁾													—		—			—		5,025
Tax reform accrual for future amortization⁽¹¹⁾													—		9,139			9,139		—
Other		2,419			6,314		8,733		8,796				6,636		5,279			11,915		12,433
Total		$	334,240		$	430,637	$	764,877	$	699,448			$	346,460	$	435,725		$	782,185	$	764,877

(1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.

(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."

(3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 12 - "Benefit Plans."

(4) ~~The energy efficiency~~Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its Idaho jurisdiction, Idaho Power’s inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the ~~Oregon jurisdiction balance~~difference between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the ~~liability represents the~~amounts are provided for in Idaho ~~jurisdiction balance.~~retail revenues.


(5)	The energy efficiency asset includes the Oregon jurisdiction balance at December 31, 2019 and 2018. The Idaho jurisdiction balance was an asset at December 31, 2019, and a liability at December 31, 2018.

~~(5)~~(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."

~~(6)~~(7) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement ~~Obligations.~~Obligations (ARO)."

~~(7)~~(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."

~~(8) The Tax Cuts and Jobs Act, enacted on December 22,~~(9) In 2017, income tax reform reduced ~~the~~ deferred income tax assets and liabilities. For depreciation-related timing differences under the normalized tax accounting method, this reduction will flow back to customers under the statutorily prescribed average rate assumption method.

~~(9)~~(10) Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

~~(10) Mark-to-market assets and liabilities are discussed in Note 17 - "Fair Value Measurements."~~(11) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers.

Idaho Power’s regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.

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Power Cost Adjustment Mechanisms and Deferred Power Supply Costs

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

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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 sheets 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. The Idaho deferral period or Idaho-jurisdiction power cost adjustment (PCA) year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:

a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and ~~shareholders~~Idaho Power (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and

a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC:



Effective Date	$ Change (millions)			Notes
June 1, 2019	$	(50.1	)	The $50.1 million decrease includes a $5.0 million credit to customers for sharing of 2018 earnings under the IPUC order approving the extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019 (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation) and a $2.7 million credit for income tax reform benefits related to Idaho Power's OATT rate under a May 2018 Idaho tax reform settlement stipulation as described below in this Note 3 - Regulatory Matters.
June 1, 2018	$	(30.4	)	The $30.4 million total decrease in PCA rates includes a $7.8 million one-time benefit for income tax benefits accrued from January 1 to May 31, 2018, and the income taxes related to Idaho Power's open access transmission tariff (OATT) rate as described below in this Note 3 - Regulatory Matters.
June 1, 2017	$	10.6		The net increase in PCA rates included an offsetting $13.0 million reduction for the refund of previously collected Idaho energy efficiency rider funds.

Effective Date $ Change (millions) Notes
June 1, 2018 $ (30.4 ) The $30.4 million total decrease in PCA rates includes a $7.8 million one-time benefit for income tax benefits accrued from January 1 to May 31, 2018, and the income taxes related to Idaho Power's open access transmission tariff (OATT) rate. See "Income Tax Reform - Regulatory Treatment" below for more information.
June 1, 2017 $ 10.6
The net increase in PCA rates included an offsetting $13.0 million reduction for the refund of previously collected Idaho energy efficiency rider funds.
June 1, 2016 $ 17.3
The net increase in PCA rates included the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of the October 2014 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds.

Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power’s actual Oregon-jurisdictional return on equity (Oregon ROE) for the year is at least 100 basis points below Idaho Power’s last authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power’s actual Oregon ROE for that year is at least 100 basis points above Idaho Power’s last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2019, 2018, ~~2017,~~ and ~~2016~~2017 did not have a material impact on the companies' financial statements.

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Notable Idaho ~~Regulatory Matters~~

~~Idaho~~ Base Rate ~~Changes:~~ Adjustments

Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and ~~2018.~~ 2019.

January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were

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subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.

~~As noted above in this Note 3, the~~The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. ~~In June 2018, the IPUC issued an order adjusting base rates for the impacts of income tax reform, as discussed below in "Income Tax Reform - Regulatory Treatment."~~

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: 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 or the full $45 million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (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 - Idaho Regulatory Treatment" below.

In ~~2018,~~2019 and 2017, Idaho Power recorded ~~a $5.0 million~~0 provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) for ~~2018 was above 10.0 percent. In both 2016 and 2017, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in~~ both years was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers as Idaho ROE was above 10.0 percent. Accordingly, at December 31, ~~2018,~~2019, the full $45 million of additional ADITC ~~remains~~remained available for future use under the terms of the ~~October 2014~~May 2018 Idaho ~~Earnings Support and Sharing~~Tax Reform Settlement ~~Stipulation. The October 2014 Idaho Earning Support and Sharing Settlement~~ Stipulation ~~was modified and indefinitely extended, as~~ described in "Income Tax Reform - Idaho Regulatory Treatment" below.

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 and corresponding revenues 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 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~~provided 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~~was provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism 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 OATT rate. The amount provided via the PCA mechanism ~~will decrease~~decreased to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

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The May 2018 Idaho Tax Reform Settlement Stipulation also provides for the indefinite extension, with modifications, of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019.

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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~~became 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~~The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during ~~their~~its respective ~~terms.~~term.

~~Also~~Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May ~~2018,~~31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the ~~Public Utility Commission~~regulatory accrual or deferral of ~~Oregon (OPUC)~~the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North

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Valmy coal-fired power plant in 2019 and 2025, respectively. In May 2019, the IPUC 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 earlier resolved in a regulatory proceeding, the ~~settlement stipulation requires~~North Valmy plant agreement and allowing Idaho Power to ~~file a deferral request~~recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with ~~the OPUC by~~required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, ~~to begin tracking income tax reform benefits beginning January 1, 2020, at which time~~as planned, Idaho Power ~~the OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.~~ended its participation in coal-fired operations of North Valmy plant unit 1.

Other Notable Idaho Regulatory Matters

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho 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

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included in the variable kilowatt-hour charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection 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. ~~Any~~The IPUC has discretion to cap the annual increase in the FCA recovery ~~is capped~~ at 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:



FCA Year	Period Rates in Effect	Annual Amount (in millions)
2018	June 1, 2019-May 31, 2020	$34.8
2017	June 1, 2018-May 31, 2019	$15.6
2016	June 1, 2017-May 31, 2018	$35.0

FCA Year Period Rates in Effect Annual Amount
(in millions)
2017 June 1, 2018-May 31, 2019 $15.6
2016 June 1, 2017-May 31, 2018 $35.0
2015 June 1, 2016-May 31, 2017 $28.1

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 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. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as other operations and maintenance (O&M) expense and $2.5 million was recorded as a reduction to AFUDC. 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.

~~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 January 2017, in response to Idaho Power's request to match costs with benefits of Western EIM participation, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. In November 2017, Idaho Power filed an application with the IPUC requesting authorization to establish an interim method of recovery for costs associated with participation in the Western EIM. Through March 2018, Idaho Power had deferred $1.0 million of incremental other O&M costs. In the second quarter of 2018, Idaho Power amortized those costs in accordance with the provisions of the May 2018 Idaho Tax Reform Settlement Stipulation discussed above. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for recovery of ongoing Western EIM-related costs through Idaho Power's PCA mechanism, beginning April 2018. 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. From April through December 2018, Idaho Power recorded $2.2 million as a regulatory asset within the PCA balance per the stipulation in order to match the costs with the benefits of the Western EIM.

~~Valmy Base Rate Adjustment Settlement Stipulations~~

In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant). The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the

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difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 settlement stipulation associated with income tax reform described above, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement.

Notable Oregon Regulatory Matters

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012.In February 2012, the ~~OPUC~~Public Utility Commission of Oregon (OPUC) issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.

In ~~June~~May 2018, the OPUC ~~also~~ issued an order ~~adjusting~~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. In December 2019, Idaho Power filed an application with the OPUC requesting approval of Idaho Power’s quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.

In June 2017, the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase in the ~~impacts~~Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the

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May 2018 settlement stipulation associated with income tax reform ~~as discussed~~described above, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in ~~"Income Tax Reform - Regulatory Treatment."~~coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.

Federal Regulatory Matters - Open Access Transmission Tariff Rates



Applicable Period	OATT Rate (per kW-year)
October 1, 2019 to September 30, 2020	$	27.32
October 1, 2018 to September 30, 2019	$	31.25
October 1, 2017 to September 30, 2018	$	34.90
October 1, 2016 to September 30, 2017	$	25.52

Applicable Period OATT Rate (per kW-year)
October 1, 2018 to September 30, 2019 $ 31.25
October 1, 2017 to September 30, 2018 $ 34.90
October 1, 2016 to September 30, 2017 $ 25.52
October 1, 2015 to September 30, 2016 $ 23.43

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of ~~$123.1~~$107.0 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.

4. REVENUES

~~On January 1, 2018,~~ IDACORP and Idaho Power adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), using the modified retrospective ~~method.~~method on January 1, 2018. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, the companies recorded no0 cumulative-effect adjustment. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):



	Year Ended December 31,
	2019		2018		2017
Electric utility operating revenues:
Revenue from contracts with customers	$	1,285,286	$	1,312,112	$	1,320,004
Alternative revenue programs and derivative revenues	57,654		54,470		24,889
Total electric utility operating revenues	$	1,342,940	$	1,366,582	$	1,344,893

Year Ended December 31,
2018 2017 2016
Electric utility operating revenues:
Revenue from contracts with customers $ 1,312,112
$ 1,320,004
$ 1,216,796
Alternative revenue programs and other revenues 54,470
24,889
42,557
Total electric utility operating revenues $ 1,366,582
$ 1,344,893
$ 1,259,353

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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, Revenue from Contracts with Customers (Topic 606). 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 (in thousands):


	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
Revenues from contracts with customers:
Retail revenues:
Residential (includes $34,625, $17,320 and $29,170, respectively, related to the FCA⁽¹⁾)	$	530,527		$	552,333		$	514,954
Commercial(includes $1,299, $876 and $1,087, respectively, related to the FCA⁽¹⁾)	310,299			319,195			302,650
Residential (includes $35,587, $34,625 and $17,320, respectively, related to the FCA⁽¹⁾)										$	526,966		$	530,527		$	552,333
Commercial(includes $1,336, $1,299, and $876, respectively, related to the FCA⁽¹⁾)										295,203			310,299			319,195
Industrial	190,130			195,124			182,590			181,372			190,130			195,124
Irrigation	158,001			150,030			156,505			135,850			158,001			150,030
Provision for sharing	(5,025		)	—			—			—			(5,025		)	—
Deferred revenue related to HCC relicensing AFUDC⁽²⁾	(8,780		)	(10,706		)	(10,706		)	(8,780		)	(8,780		)	(10,706		)
Total retail revenues	1,175,152			1,205,976			1,145,993			1,130,611			1,175,152			1,205,976
Less: FCA mechanism revenues⁽¹⁾	(35,924		)	(18,196		)	(30,257		)	(36,923		)	(35,924		)	(18,196		)
Wholesale energy sales	52,845			24,790			11,900			71,198			52,845			24,790
Transmission wheeling revenues	59,094			43,970			32,496
Transmission wheeling-related revenues										53,828			59,094			43,970
Energy efficiency program revenues	35,703			39,241			33,754			40,128			35,703			39,241
Other revenues from contracts with customers	25,242			24,223			22,910			26,444			25,242			24,223
Total revenues from contracts with customers	$	1,312,112		$	1,320,004		$	1,216,796		$	1,285,286		$	1,312,112		$	1,320,004

(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.

(2) ~~As part of its January 30, 2009, general rate case order, the~~The IPUC ~~is allowing~~allows Idaho Power to recover a portion of the 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 energy and 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 $2.6 million, $3.6 million, and $4.7 million for 2019, 2018, and ~~$4.2 million for 2018,~~ 2017, ~~and 2016,~~ respectively.

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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.

Provision for Sharing: Idaho Power's sharing mechanism is associated with the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation that provides for the sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. Based on full-year ~~2018~~2019 Idaho ROE, Idaho Power recorded ~~a $5.0 million~~0 provision against current revenues for sharing of earnings with customers for ~~2018. During 2017 and 2016,~~2019. Idaho Power recorded no$5.0 million of sharing of earnings with ~~customers.~~customers during 2018 and no provision was recorded during 2017. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in Note 3 - "Regulatory Matters."

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 ~~Wheeling~~Wheeling-Related 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 ~~wheeling~~wheeling-related revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission ~~wheeling~~wheeling-related revenues are affected by changes in Idaho Power’s OATT 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 December 31, ~~2018,~~2019, Idaho Power's energy efficiency rider balances were a ~~$5.3~~$0.3 million regulatory ~~liability~~asset in the Idaho jurisdiction and a ~~$1.4~~$1.2 million regulatory asset in the Oregon jurisdiction.

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Alternative Revenue Programs and ~~Other~~Derivative Revenues

While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of the FCA mechanism, which may increase or decrease tariff-based rates billed to customers. The FCA mechanism is described in detail in Note 3 - "Regulatory Matters." 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~~derivative revenues (in thousands):



	Year Ended December 31,
	2019		2018		2017
Alternative revenue programs and derivative revenues:
FCA mechanism revenues	$	36,923	$	35,924	$	18,196
Derivative revenues	20,731		18,546		6,693
Total alternative revenue programs and derivative revenues	$	57,654	$	54,470	$	24,889

Year Ended December 31,
2018 2017 2016
Alternative revenue programs and other revenues:
FCA mechanism revenues $ 35,924
18,196
$ 30,257
Derivative revenues 18,546
6,693
12,300
Total alternative revenue programs and other revenues $ 54,470
$ 24,889
$ 42,557

IDACORP's Other Revenues

IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small ~~hydroelectric~~hydropower generation projects that satisfy the requirements of PURPA.

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5. LONG-TERM DEBT

The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars):



	2019			2018
First mortgage bonds:
3.40% Series due 2020	$	100,000		$	100,000
2.95% Series due 2022	75,000			75,000
2.50% Series due 2023	75,000			75,000
6.00% Series due 2032	100,000			100,000
5.50% Series due 2033	70,000			70,000
5.50% Series due 2034	50,000			50,000
5.875% Series due 2034	55,000			55,000
5.30% Series due 2035	60,000			60,000
6.30% Series due 2037	140,000			140,000
6.25% Series due 2037	100,000			100,000
4.85% Series due 2040	100,000			100,000
4.30% Series due 2042	75,000			75,000
4.00% Series due 2043	75,000			75,000
3.65% Series due 2045	250,000			250,000
4.05% Series due 2046	120,000			120,000
4.20% Series due 2048	220,000			220,000
Total first mortgage bonds	1,665,000			1,665,000
Pollution control revenue bonds:
1.45% Series due 2024⁽¹⁾	49,800			49,800
1.70% Series due 2026⁽¹⁾	116,300			116,300
Variable Rate Series 2000 due 2027	4,360			4,360
Total pollution control revenue bonds	170,460			170,460
American Falls bond guarantee	19,885			19,885
Unamortized issuance costs and discounts	(18,686		)	(20,557		)
Total IDACORP and Idaho Power outstanding debt⁽²⁾	1,836,659			1,834,788
Current maturities of long-term debt	(100,000		)	—
Total long-term debt	$	1,736,659		$	1,834,788

2018 2017
First mortgage bonds:
4.50% Series due 2020 $ —
$ 130,000
3.40% Series due 2020 100,000
100,000
2.95% Series due 2022 75,000
75,000
2.50% Series due 2023 75,000
75,000
6.00% Series due 2032 100,000
100,000
5.50% Series due 2033 70,000
70,000
5.50% Series due 2034 50,000
50,000
5.875% Series due 2034 55,000
55,000
5.30% Series due 2035 60,000
60,000
6.30% Series due 2037 140,000
140,000
6.25% Series due 2037 100,000
100,000
4.85% Series due 2040 100,000
100,000
4.30% Series due 2042 75,000
75,000
4.00% Series due 2043 75,000
75,000
3.65% Series due 2045 250,000
250,000
4.05% Series due 2046 120,000
120,000
4.20% Series due 2048 220,000
—
Total first mortgage bonds 1,665,000
1,575,000
Pollution control revenue bonds:
5.15% Series due 2024⁽¹⁾
49,800
49,800
5.25% Series due 2026⁽¹⁾
116,300
116,300
Variable Rate Series 2000 due 2027 4,360
4,360
Total pollution control revenue bonds 170,460
170,460
American Falls bond guarantee 19,885
19,885
Unamortized issuance costs and discounts (20,557 ) (19,222 )
Total IDACORP and Idaho Power outstanding debt⁽²⁾
1,834,788
1,746,123
Current maturities of long-term debt —
—
Total long-term debt $ 1,834,788
$ 1,746,123

(1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds outstanding at December 31, ~~2018,~~2019, to $1.831 billion. These two bonds were purchased and remarketed in August of 2019. See "Long-Term Debt Issuances, Maturities, and Redemptions" below.

(2) At December 31, ~~2018~~2019 and ~~2017,~~2018, the overall effective cost rate of Idaho Power's outstanding debt was ~~4.83~~4.50 percent and ~~4.87~~4.83 percent, respectively.

At December 31, ~~2018,~~2019, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):



2020		2021		2022		2023		2024		Thereafter
$	100,000	$	—	$	75,000	$	75,000	$	49,800	$	1,555,545

2019 2020 2021 2022 2023 Thereafter
$ —
$ 100,000
$ —
$ 75,000
$ 75,000
$ 1,605,345

Long-Term Debt Issuances, Maturities, and ~~Availability~~Redemptions

In March 2018, Idaho Power issued ~~$220~~$220.0 million in principal amount of 4.20% first mortgage bonds, secured medium-term notes, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, ~~$130~~$130.0 million in principal amount of 4.50% first mortgage bonds, secured 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 of $4.6 ~~million. Idaho~~

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million. Idaho Power used a portion of the net proceeds offrom the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption.

In ~~March 2016,~~August 2019, Idaho Power ~~issued $120.0 million~~purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of ~~4.05% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2046. In April 2016, Idaho Power redeemed, prior to maturity, $100.0~~$49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of ~~6.15% first mortgage~~$116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds ~~secured medium-term notes, Series H, due April 2019. In accordance~~were remarketed with substantially the ~~redemption provisions~~same terms, but with lower term interest rates. The term interest rate of the ~~notes,~~series due in 2024 decreased from 5.15 percent to 1.45 percent and the ~~redemption included Idaho Power's payment of a make-whole premium of $14.0 million. Idaho Power used a portion~~term interest rate of the ~~net proceeds~~series due in 2026 decreased from ~~the March 2016 sale of first mortgage bonds, medium-term notes~~5.25 percent to ~~effect the redemption.~~1.70 percent.

Idaho Power First Mortgage ~~Bonds:~~ Bonds

Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May ~~2016,~~2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing ~~Idaho Power~~the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, ~~2019,~~2022, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of 7.0 percent.

~~On September 27, 2016,~~In May 2019, Idaho Power ~~entered into~~filed a ~~selling agency agreement with seven banks in connection~~shelf registration statement with the ~~potential issuance~~SEC, which became effective upon filing, for the offer and sale ~~from time to time~~ of ~~up to $500 million aggregate~~an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds ~~secured medium term notes, Series K (Series K Notes), under~~requires that Idaho ~~Power’s~~Power meet interest coverage and security provisions set forth in the Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). AtFuture issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the ~~same time,~~Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

As of the date of this report, Idaho Power has not entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture. The Forty-eighth Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture. As of December 31, 2018, $280 million in principal amount of Series K Notes remained available for issuancea selling agency agreement under the ~~Indenture.~~

new shelf agreement. The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects ~~and clouds~~ common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.

The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

As of December 31, ~~2018,~~2019, Idaho Power could issue under its Indenture approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-eighth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, ~~2018~~2019 was limited to approximately $669 million under the Indenture.

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6. NOTES PAYABLE

Credit Facilities

On ~~November~~December 6, ~~2015,~~2019, IDACORP and Idaho Power entered into amendments to their outstanding Credit Agreements, ~~replacing the existing Second Amended and Restated Credit Agreements, dated October 26, 2011, to~~which provide credit facilities that may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed ~~$100~~$50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than ~~zero percent.~~0 percent. An alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original maturity date of ~~November~~December 6, ~~2020,~~2024, the credit agreements grant IDACORP and Idaho Power the right to request up to ~~two~~2 one-year extensions, subject to certain conditions. On November 7, 2017, IDACORP and Idaho Power executed the second extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 4, 2022. No other terms of the credit facilities, included the amount of permitted borrowing under the credit agreements, were affected by the extensions.

At December 31, ~~2018,~~2019, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, ~~2018,~~2019, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. ~~Balances (in thousands of dollars) and interest rates of~~ IDACORP’s and Idaho Power's short-term borrowings were ~~as follows~~zero at December 31, ~~2018,~~2019, and December 31, ~~2017:~~

IDACORP Idaho Power Total
2018 2017 2018 2017 2018 2017
Commercial paper balances:
At the end of year $ —
$ —
$ —
$ —
$ —
$ —
Average during the year $ —
$ 588
$ —
$ 839
$ —
$ 1,427
Weighted-average interest rate
At the end of the year — % — % — % — % — % — %
2018.

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7. COMMON STOCK

IDACORP Common Stock

The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, ~~2018~~2019:



	Shares issued			Shares reserved
	2019	2018	2017	December 31, 2019
Balance at beginning of year	50,420,017	50,420,017	50,420,017
Continuous equity program (inactive)	—	—	—	3,000,000
Dividend reinvestment and stock purchase plan	—	—	—	2,576,723
Employee savings plan	—	—	—	3,567,954
Long-term incentive and compensation plan⁽¹⁾	—	—	—	1,356,729
Balance at end of year	50,420,017	50,420,017	50,420,017

Shares issued Shares reserved
2018 2017 2016 December 31, 2018
Balance at beginning of year 50,420,017
50,420,017
50,352,051

Continuous equity program (inactive) —
—
—
3,000,000
Dividend reinvestment and stock purchase plan —
—
—
2,576,723
Employee savings plan —
—
—
3,567,954
Long-term incentive and compensation plan⁽¹⁾
—
—
67,966
1,302,869
Balance at end of year 50,420,017
50,420,017
50,420,017

(1) During 2019, 2018, and 2017, IDACORP granted 70,419, 75,761, and 72,397 restricted stock unit awards, respectively, to employees and 9,594, 12,950, and 12,050 shares of common stock, respectively, to directors but made no0 original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan.

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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 December 31, ~~2018,~~2019, the leverage ratios for IDACORP and Idaho Power were 4443 percent and 4645 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to ~~$1.4~~$1.5 billion and ~~$1.2~~$1.3 billion, respectively, at December 31, ~~2018.~~2019. 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 December 31, ~~2018,~~2019, IDACORP and Idaho Power were in compliance with those covenants.

Idaho Power’s Revised Policy and 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 December 31, ~~2018,~~2019, Idaho Power's common equity capital was 5455 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 no0 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.

8. SHARE-BASED COMPENSATION

IDACORP has one share-based compensation plan — the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units (together, Restricted Stock), performance shares and performance-based units (together, Performance-Based Shares), and several other types of share-based awards. At December 31, ~~2018,~~2019, the maximum number of shares available under the LTICP was ~~720,408.~~613,394.

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Restricted Stock and Performance-Based Shares Awards

Restricted Stock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights, except that holders of restricted stock units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period, reduced for any forfeitures during the vesting period.

Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of performance-based units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded can range from ~~zero~~0 to 200 percent of the target award. Dividends or dividend equivalents, as applicable, are accrued during the vesting period and paid out based on the final number of shares awarded.

The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense over the requisite service period based on the estimated achievement of performance targets, reduced for any forfeitures during the vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance targets based on historical returns

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relative to the peer group. The fair value of this portion of the awards is charged to compensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained.

A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:



	IDACORP				Idaho Power
	Number of Shares/Units		Weighted-Average Grant Date Fair Value		Number of Shares/Units		Weighted-Average Grant Date Fair Value
Nonvested shares/units at January 1, 2019	206,035		$	81.31	204,859		$	81.31
Shares/units granted	98,868		92.58		98,362		92.59
Shares/units forfeited	(4,640	)	94.57		(4,640	)	94.57
Shares/units vested	(97,353	)	71.95		(96,761	)	71.95
Nonvested shares/units at December 31, 2019	202,910		$	90.99	201,820		$	90.99

IDACORP Idaho Power
Number of
Shares/Units Weighted-Average
Grant Date
Fair Value Number of
Shares/Units Weighted-Average
Grant Date
Fair Value
Nonvested shares/units at January 1, 2018 201,078
$ 72.37
199,652
$ 72.39
Shares/units granted 106,992
79.28
106,402
79.29
Shares/units forfeited (5,179 ) 85.07
(5,179 ) 85.07
Shares/units vested (96,856 ) 60.30
(96,016 ) 60.31
Nonvested shares/units at December 31, 2018 206,035
$ 81.31
204,859
$ 81.31

The total fair value of shares vested was $9.4 million in 2019, $8.3 million in 2018, and $7.5 million in ~~2017, and $8.3 million in 2016.~~2017. At December 31, ~~2018,~~2019, IDACORP had ~~$8.0~~$7.9 million of total unrecognized compensation cost related to nonvested share-based compensation. Idaho Power's share of this amount was ~~$7.9~~$7.8 million. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue and/or treasury shares for these awards.

In ~~2018,~~2019, a total of ~~12,950~~9,594 shares were awarded to directors at a grant date fair value of ~~$81.05~~$98.41 per share. Directors elected to defer receipt of ~~3,237~~3,198 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.

Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):



	IDACORP						Idaho Power
	2019		2018		2017		2019		2018		2017
Compensation cost	$	8,788	$	9,362	$	7,384	$	8,639	$	9,276	$	7,304
Income tax benefit⁽¹⁾	2,262		2,410		2,887		2,224		2,388		2,856

IDACORP Idaho Power
2018 2017 2016 2018 2017 2016
Compensation cost $ 9,362
$ 7,384
$ 5,561
$ 9,276
$ 7,304
$ 5,494
Income tax benefit⁽¹⁾
2,410
2,887
2,174
2,388
2,856
2,148

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(1) Due to ~~the Tax Cuts and Jobs Act,~~tax reform, the effective income tax rate was reduced in 2018 for both IDACORP and Idaho Power, which is described in Note 2 - "Income Taxes."

NoNaN equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the consolidated statements of income.

9. EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2019, 2018, ~~2017,~~ and ~~2016~~2017 (in thousands, except for per share amounts):



	Year Ended December 31,
	2019		2018		2017
Numerator:
Net income attributable to IDACORP, Inc.	$	232,854	$	226,801	$	212,419
Denominator:
Weighted-average common shares outstanding - basic	50,502		50,432		50,361
Effect of dilutive securities	35		78		63
Weighted-average common shares outstanding - diluted	50,537		50,510		50,424
Basic earnings per share	$	4.61	$	4.50	$	4.22
Diluted earnings per share	$	4.61	$	4.49	$	4.21

Year Ended December 31,
2018 2017 2016
Numerator:

Net income attributable to IDACORP, Inc. $ 226,801
$ 212,419
$ 198,288
Denominator:

Weighted-average common shares outstanding - basic 50,432
50,361
50,298
Effect of dilutive securities 78
63
75
Weighted-average common shares outstanding - diluted 50,510
50,424
50,373
Basic earnings per share $ 4.50
$ 4.22
$ 3.94
Diluted earnings per share $ 4.49
$ 4.21
$ 3.94

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10. COMMITMENTS

Purchase Obligations

At December 31, ~~2018,~~2019, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):



	2020		2021		2022		2023		2024		Thereafter
Cogeneration and power production	$	241,835	$	248,481	$	251,964	$	262,735	$	266,061	$	2,739,123
Fuel	55,693		36,069		8,389		8,379		8,371		75,074

2019 2020 2021 2022 2023 Thereafter
Cogeneration and power production $ 238,748
$ 242,206
$ 248,258
$ 251,216
$ 256,403
$ 2,805,159
Fuel 43,163
29,121
28,010
8,389
8,379
84,182

As of December 31, ~~2018,~~2019, Idaho Power had ~~1,119~~1,136 MW nameplate capacity of PURPA-related projects on-line, with an additional 2911 MW nameplate capacity of projects projected to be on-line ~~in 2019.~~by 2022. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $187 million in 2019, $190 million in 2018, and $170 million in ~~2017,~~2017.

Also, in March 2019, Idaho Power signed a 20-year power purchase agreement to purchase the output from a planned 120-megawatt solar facility. The agreement was approved by the IPUC in December 2019 and ~~$154~~is, as of the date of this report, pending approval by the OPUC. If approved, the agreement would increase contractual obligations by $136 million ~~in 2016.~~over the 20-year term.

Idaho Power also has the following long-term commitments (in thousands of dollars):



	2020		2021		2022		2023		2024		Thereafter
Joint-operating agreement payments⁽¹⁾	$	2,678	$	2,678	$	2,678	$	2,678	$	2,678	$	13,391
Easements and other payments	269		1,124		1,072		1,062		1,055		16,408
Maintenance and service agreements⁽¹⁾	47,547		13,797		16,468		7,143		7,354		55,768
FERC and other industry-related fees⁽¹⁾	14,178		13,874		13,056		13,056		13,056		65,278

2019 2020 2021 2022 2023 Thereafter
Joint-operating agreement payments⁽¹⁾
$ 2,902
$ 2,902
$ 2,902
$ 2,902
$ 2,902
$ 14,512
Easements and other payments 240
1,321
1,321
1,331
1,328
16,831
Maintenance and service agreements⁽¹⁾
34,089
15,694
10,739
11,713
4,140
54,927
FERC and other industry-related fees⁽¹⁾
14,277
12,714
12,714
12,714
12,714
63,568

(1) Approximately ~~$29~~$27 million, ~~$20~~$48 million, and ~~$71~~$131 million of the obligations included in joint-operating agreement payments, maintenance and service agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.

IDACORP’s expense for operating leases was not material for the years ended 2019, 2018, ~~2017,~~ and ~~2016.~~2017.

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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 (WDEQ), was ~~$58.4~~$58.3 million at December 31, ~~2018,~~2019, representing IERCo's one-third share of BCC's total reclamation obligation of ~~$175.2~~$175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, ~~2018,~~2019, the value of the reclamation trust fund was ~~$101.9~~$139.5 million. During ~~2018,~~2019, the reclamation trust fund made 0 distributions ~~of $6.7 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

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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 December 31, ~~2018,~~2019, 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 consolidated balance sheets with respect to these indemnification obligations.

11. 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, although there is no assurance that such recovery would be granted.

IDACORP and Idaho Power are parties to legal claims and legal, tax, 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. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company’s provision of electric service and the operation of its generation, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. In recent years, Idaho Power has regularly received claims by ~~both~~ governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims 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.

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12. BENEFIT PLANS

Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.

Pension Plans

Idaho Power has two pension plans–a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, 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 these plans are based on years of service and the employee's final average earnings.

~~Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act~~

Table of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2018, 2017, and 2016, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.Contents

The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):



	Pension Plan						SMSP
	2019			2018			2019			2018

Change in projected benefit obligation:
Benefit obligation at January 1	$	951,857		$	999,344		$	102,318		$	110,303
Service cost	34,061			37,836			(181		)	(316		)
Interest cost	42,312			38,833			4,575			4,248
Actuarial loss (gain)	147,784			(84,758		)	17,888			(7,050		)
Plan amendment	—			—			2,839			—
Benefits paid	(41,262		)	(39,398		)	(4,996		)	(4,867		)
Projected benefit obligation at December 31	1,134,752			951,857			122,443			102,318
Change in plan assets:
Fair value at January 1	650,604			697,683			—			—
Actual return (loss) on plan assets	113,777			(47,681		)	—			—
Employer contributions	40,000			40,000			—			—
Benefits paid	(41,262		)	(39,398		)	—			—
Fair value at December 31	763,119			650,604			—			—
Funded status at end of year	$	(371,633	)	$	(301,253	)	$	(122,443	)	$	(102,318	)
Amounts recognized in the statement of financial position consist of:
Other current liabilities	$	—		$	—		$	(5,911	)	$	(5,158	)
Noncurrent liabilities	(371,633		)	(301,253		)	(116,532		)	(97,160		)
Net amount recognized	$	(371,633	)	$	(301,253	)	$	(122,443	)	$	(102,318	)
Amounts recognized in accumulated other comprehensive income consist of:
Net loss	$	347,785		$	278,720		$	45,851		$	30,496
Prior service cost	56			62			3,143			399
Subtotal	347,841			278,782			48,994			30,895
Less amount recorded as regulatory asset⁽¹⁾	(347,841		)	(278,782		)	—			—
Net amount recognized in accumulated other comprehensive income	$	—		$	—		$	48,994		$	30,895
Accumulated benefit obligation	$	958,586		$	814,549		$	109,966		$	94,630

Pension Plan SMSP
2018 2017 2018 2017

Change in projected benefit obligation:

Benefit obligation at January 1 $ 999,344
$ 895,060
$ 110,303
$ 99,570
Service cost 37,836
33,742
(316 ) 759
Interest cost 38,833
38,957
4,248
4,315
Actuarial (gain) loss (84,758 ) 67,758
(7,050 ) 10,635
Benefits paid (39,398 ) (36,173 ) (4,867 ) (4,976 )
Projected benefit obligation at December 31 951,857
999,344
102,318
110,303
Change in plan assets:

Fair value at January 1 697,683
607,568
—
—
Actual (loss) return on plan assets (47,681 ) 86,288
—
—
Employer contributions 40,000
40,000
—
—
Benefits paid (39,398 ) (36,173 ) —
—
Fair value at December 31 650,604
697,683
—
—
Funded status at end of year $ (301,253 ) $ (301,661 ) $ (102,318 ) $ (110,303 )
Amounts recognized in the statement of financial position consist of:

Other current liabilities $ —
$ —
$ (5,158 ) $ (5,010 )
Noncurrent liabilities (301,253 ) (301,661 ) (97,160 ) (105,293 )
Net amount recognized $ (301,253 ) $ (301,661 ) $ (102,318 ) $ (110,303 )
Amounts recognized in accumulated other comprehensive income consist of:

Net loss $ 278,720
$ 277,052
$ 30,496
$ 41,333
Prior service cost 62
68
399
498
Subtotal 278,782
277,120
30,895
41,831
Less amount recorded as regulatory asset (278,782 ) (277,120 ) —
—
Net amount recognized in accumulated other comprehensive income $ —
$ —
$ 30,895
$ 41,831
Accumulated benefit obligation $ 814,549
$ 850,763
$ 94,630
$ 100,222

~~Table~~(1) Changes in the funded status of ~~Contents~~

the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.

The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2019 are due primarily to decreases in the assumed discount rates of both plans from December 31, 2018, to December 31, 2019. The actuarial gains affecting the benefit obligations for the pension and SMSP plans in 2018 are due primarily to increases in the assumed discount rates from December 31, 2017, to December 31, 2018. For more information on discount rates, see “Plan Assumptions” below in this Note 12.

As a non-qualified plan, the SMSP has no0 plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately ~~$92.5~~$97.6 million and ~~$85.7~~$92.5 million at December 31, ~~2018~~2019 and ~~2017,~~2018, respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.

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The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets.


	Pension Plan									SMSP							Pension Plan									SMSP
	2018			2017			2016			2018			2017		2016		2019			2018			2017			2019			2018			2017
Service cost	$	37,836		$	33,742		$	32,019		$	(316	)	$	759	$	1,228	$	34,061		$	37,836		$	33,742		$	(181	)	$	(316	)	$	759
Interest cost	38,833			38,957			37,813			4,248			4,315		4,275		42,312			38,833			38,957			4,575			4,248			4,315
Expected return on assets	(52,302		)	(45,138		)	(42,081		)	—			—		—		(48,623		)	(52,302		)	(45,138		)	—			—			—
Amortization of net loss	13,558			13,190			13,331			3,788			2,963		3,532		13,564			13,558			13,190			2,533			3,788			2,963
Amortization of prior service cost	6			28			59			98			127		168		6			6			28			96			98			127
Net periodic pension cost	37,931			40,779			41,141			7,818			8,164		9,203		41,320			37,931			40,779			7,023			7,818			8,164
Regulatory deferral of net periodic benefit cost⁽¹⁾	(36,153		)	(38,699		)	(39,335		)	—			—		—		(39,379		)	(36,153		)	(38,699		)	—			—			—
Previously deferred pension cost recognized⁽¹⁾	17,154			17,154			17,154			—			—		—		17,154			17,154			17,154			—			—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾⁽²⁾	$	18,932		$	19,234		$	18,960		$	7,818		$	8,164	$	9,203	$	19,095		$	18,932		$	19,234		$	7,023		$	7,818		$	8,164

(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 ~~$15.2~~$15.1 million, ~~$16.2~~$15.2 million, and ~~$16.4~~$16.2 million respectively, was recognized in "Other operations and maintenance" and $11.0 million, and $11.6 million, ~~$11.2 million,~~ and ~~$11.8~~$11.2 million respectively, was recognized in "Other expense, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2019, 2018, ~~2017,~~ and ~~2016.~~2017.

The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):



	Pension Plan									SMSP
	2019			2018			2017			2019			2018			2017
Actuarial (loss) gain during the year	$	(82,631	)	$	(15,226	)	$	(26,608	)	$	(17,888	)	$	7,049		$	(10,635	)
Plan amendment service cost	—			—			—			(2,839		)	—			—
Reclassification adjustments for:
Amortization of net loss	13,564			13,558			13,190			2,533			3,788			2,963
Amortization of prior service cost	6			6			28			96			98			127
Adjustment for deferred tax effects	17,776			428			1,744			4,658			(2,815		)	1,555
Adjustment due to the effects of regulation	51,285			1,234			11,646			—			—			—
Other comprehensive (loss) income recognized related to pension benefit plans	$	—		$	—		$	—		$	(13,440	)	$	8,120		$	(5,990	)

Pension Plan SMSP
2018 2017 2016 2018 2017 2016
Actuarial (loss) gain during the year $ (15,226 ) $ (26,608 ) $ (23,753 ) $ 7,049
$ (10,635 ) $ (2,933 )
Plan amendment service cost —
—
(81 ) —
—
(120 )
Reclassification adjustments for:
Amortization of net loss 13,558
13,190
13,331
3,788
2,963
3,532
Amortization of prior service cost 6
28
59
98
127
168
Adjustment for deferred tax effects 428
1,744
4,083
(2,815 ) 1,555
(253 )
Adjustment due to the effects of regulation 1,234
11,646
6,361
—
—
—
Other comprehensive income recognized related to pension benefit plans $ —
$ —
$ —
$ 8,120
$ (5,990 ) $ 394

In 2019, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $16.5 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2018, relating to the pension plan and SMSP. This amount consists of $13.9 million of amortization of net loss for the pension plan and $2.5 million of amortization of net loss and $0.1 million of amortization of prior service cost for the SMSP.

The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):



	2020		2021		2022		2023		2024		2025-2029
Pension Plan	$	40,727	$	42,674	$	44,576	$	46,670	$	48,694	$	273,700
SMSP	6,010		6,186		6,281		6,700		6,724		33,304

2019 2020 2021 2022 2023 2023-2028
Pension Plan $ 38,177
$ 40,287
$ 42,403
$ 44,489
$ 46,671
$ 264,707
SMSP 5,266
5,716
5,901
6,071
6,431
31,867

Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2019, 2018, and 2017, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of ~~December 31, 2018,~~the date of this report, IDACORP's and Idaho Power's minimum required ~~contributions~~contribution to the pension plan ~~are~~is estimated to be ~~zero in 2019.~~$14 million during 2020. Depending on market conditions and cash flow considerations in ~~2019,~~2020, Idaho Power could contribute up to

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~~$40~~ $40 million to the pension plan during ~~2019~~2020 in order to help 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.

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Postretirement Benefits

Idaho Power 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. Retirees hired on or after January 1, 1999, have access to the standard medical option at full cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power’s future obligations under this plan.

The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):


	2018			2017			2019			2018
Change in accumulated benefit obligation:
Benefit obligation at January 1	$	70,051		$	63,876		$	66,453		$	70,051
Service cost	1,051			973			853			1,051
Interest cost	2,643			2,783			2,989			2,643
Actuarial (gain) loss	(2,688		)	5,769
Actuarial loss (gain)							5,298			(2,688		)
Benefits paid⁽¹⁾	(4,604		)	(3,562		)	(4,564		)	(4,604		)
Plan amendments	—			212						—
Benefit obligation at December 31	66,453			70,051			71,029			66,453
Change in plan assets:
Fair value of plan assets at January 1	38,294			34,999			33,391			38,294
Actual (loss) return on plan assets	(1,330		)	5,112
Actual return (loss) on plan assets							7,269			(1,330		)
Employer contributions⁽¹⁾	1,031			1,745			3,529			1,031
Benefits paid⁽¹⁾	(4,604		)	(3,562		)	(4,564		)	(4,604		)
Fair value of plan assets at December 31	33,391			38,294			39,625			33,391
Funded status at end of year (included in noncurrent liabilities)	$	(33,062	)	$	(31,757	)	$	(31,404	)	$	(33,062	)

(1) Contributions and benefits paid are each net of ~~$3.1~~$3.3 million and ~~$3.4~~$3.1 million of plan participant contributions for ~~2018~~2019 and ~~2017,~~2018, respectively.

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):



	2019			2018
Net loss	$	(81	)	$	(330	)
Prior service cost	174			222
Subtotal	93			(108		)
Less amount recognized in regulatory assets	(93		)	108
Net amount recognized in accumulated other comprehensive income	$	—		$	—

2018 2017
Net (loss) gain $ (330 ) $ 2,777
Prior service cost 222
269
Subtotal (108 ) 3,046
Less amount recognized in regulatory assets 108
(3,046 )
Net amount recognized in accumulated other comprehensive income $ —
$ —

The net periodic postretirement benefit cost was as follows (in thousands of dollars):



	2019			2018			2017
Service cost	$	853		$	1,051		$	973
Interest cost	2,989			2,643			2,783
Expected return on plan assets	(2,220		)	(2,467		)	(2,307		)
Immediate recognition of loss from temporary deviation⁽¹⁾	—			4,216			—
Amortization of prior service cost	48			47			47
Net periodic postretirement benefit cost	$	1,670		$	5,490		$	1,496

2018 2017 2016
Service cost $ 1,051
$ 973
$ 1,116
Interest cost 2,643
2,783
2,766
Expected return on plan assets (2,467 ) (2,307 ) (2,474 )
Immediate recognition of loss from temporary deviation⁽¹⁾
4,216
—
—
Amortization of prior service cost 47
47
26
Net periodic postretirement benefit cost $ 5,490
$ 1,496
$ 1,434

(1) In 2018, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other expense, net" on the consolidated statements of income of the companies.

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The following table shows the components of other comprehensive income for the plan (in thousands of dollars):



	2019			2018			2017
Actuarial loss during the year	$	(249	)	$	(1,109	)	$	(2,964	)
Prior service cost arising during the year	—			—			(212		)
Reclassification adjustments for:
Immediate recognition of loss from temporary deviation⁽¹⁾	—			4,216			—
Reclassification adjustments for amortization of prior service cost	48			47			47
Adjustment for deferred tax effects	52			270			807
Adjustment due to the effects of regulation	149			(3,424		)	2,322
Other comprehensive income related to postretirement benefit plans	$	—		$	—		$	—

2018 2017 2016
Actuarial loss during the year $ (1,109 ) $ (2,964 ) $ (1,600 )
Prior service cost arising during the year —
(212 ) —
Reclassification adjustments for:
Immediate recognition of loss from temporary deviation⁽¹⁾
4,216
—
—
Reclassification adjustments for amortization of prior service cost 47
47
26
Adjustment for deferred tax effects 270
807
615
Adjustment due to the effects of regulation (3,424 ) 2,322
959
Other comprehensive income related to postretirement benefit plans $ —
$ —
$ —

The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):



	2020		2021		2022		2023		2024		2025-2028
Expected benefit payments	$	5,552	$	4,932	$	4,750	$	4,532	$	4,289	$	19,133

2019 2020 2021 2022 2023 2023-2027
Expected benefit payments $ 5,438
$ 5,051
$ 4,894
$ 4,732
$ 4,549
$ 20,080

Plan Assumptions

The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:


	Pension Plan				SMSP				Postretirement Benefits				Pension Plan				SMSP				Postretirement Benefits
	2018		2017		2018		2017		2018		2017		2019		2018		2019		2018		2019		2018
Discount rate	4.55	%	3.95	%	4.60	%	3.95	%	4.60	%	3.95	%	3.60	%	4.55	%	3.65	%	4.60	%	3.60	%	4.60	%
Rate of compensation increase⁽¹⁾	4.25	%	4.17	%	4.75	%	4.75	%	—		—		4.37	%	4.25	%	4.75	%	4.75	%	—		—
Medical trend rate	—		—		—		—		6.3	%	6.8	%	—		—		—		—		6.7	%	6.3	%
Dental trend rate	—		—		—		—		4.0	%	4.0	%	—		—		—		—		4.0	%	4.0	%
Measurement date	12/31/2018		12/31/2017		12/31/2018		12/31/2017		12/31/2018		12/31/2017		12/31/2019		12/31/2018		12/31/2019		12/31/2018		12/31/2019		12/31/2018

(1) The ~~2018~~2019 rate of compensation increase assumption for the pension plan includes an inflation component of ~~2.50%~~2.40% plus a ~~1.75%~~1.97% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0%0.6% for employees in their fortieth year of service and beyond.

The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:



	Pension Plan						SMSP						Postretirement Benefits
	2019		2018		2017		2019		2018		2017		2019		2018		2017
Discount rate	4.55	%	3.95	%	4.45	%	4.60	%	3.95	%	4.45	%	4.60	%	3.95	%	4.45	%
Expected long-term rate of return on assets	7.50	%	7.50	%	7.50	%	—		—		—		6.75	%	6.75	%	6.75	%
Rate of compensation increase	4.37	%	4.25	%	4.17	%	4.75	%	4.75	%	4.75	%	—		—	%	—	%
Medical trend rate	—		—		—		—		—		—		6.7	%	6.3	%	6.8	%
Dental trend rate	—		—		—		—		—		—		4.0	%	4.0	%	4.0	%

Pension Plan SMSP
Postretirement
Benefits
2018 2017 2016 2018 2017 2016 2018 2017 2016
Discount rate 3.95 % 4.45 % 4.60 % 3.95 % 4.45 % 4.60 % 3.95 % 4.45 % 4.60 %
Expected long-term rate of return on assets 7.50 % 7.50 % 7.50 % —
—
—
6.75 % 6.75 % 7.25 %
Rate of compensation increase 4.25 % 4.17 % 4.11 % 4.75 % 4.75 % 4.50 % —
— % — %
Medical trend rate —
—
—
—
—
—
6.3 % 6.8 % 8.3 %
Dental trend rate —
—
—
—
—
—
4.0 % 4.0 % 5.0 %

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The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was ~~6.3~~6.7 percent in ~~2018~~2019 and is assumed to decrease to ~~5.7~~5.9 percent in ~~2019,~~2020, 5.2 percent in 2021, 5.1 percent in ~~2020, 5.1 percent in 2021~~2022 and to gradually decrease to ~~4.1~~3.9 percent by ~~2076.~~2091. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.0 percent, or equal to the medical trend rate if lower, for all years. ~~A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2018 (in thousands of dollars):~~

One-Percentage-Point
Increase Decrease
Effect on total of cost components $ 339
$ (247 )
Effect on accumulated postretirement benefit obligation 3,222
(2,483 )

Plan Assets

Pension Asset Allocation Policy:The target allocation and actual allocations at December 31, ~~2018,~~2019, for the pension asset portfolio by asset class is set forth below:



Asset Class	Target Allocation		Actual Allocation December 31, 2019
Debt securities	24	%	23	%
Equity securities	56	%	59	%
Real estate	7	%	6	%
Other plan assets	13	%	12	%
Total	100	%	100	%

Asset Class
Target
Allocation

Actual
Allocation
December 31, 2018
Debt securities 24 % 26 %
Equity securities 56 % 56 %
Real estate 7 % 6 %
Other plan assets 13 % 12 %
Total 100 % 100 %

Assets are rebalanced as necessary to keep the portfolio close to target allocations.

The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.

The three major goals in Idaho Power’s asset allocation process are to:

determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;

match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of ~~benefit payments and cash allocations sufficient to cover the current year~~ benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and

maintain a prudent risk profile consistent with ERISA fiduciary standards.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 2030 years when interest rates were generally much higher.

Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.

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Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 17 - "Fair Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).


	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets at December 31, 2018
Assets at December 31, 2019
Cash and cash equivalents	$	9,717	$	—	$	—	$	9,717	$	10,878	$	—	$	—	$	10,878
Short-term bonds	20,644		—		—		20,644		21,628		—		—		21,628
Intermediate bonds	20,595		87,646		—		108,241		22,369		134,931		—		157,300
Long-term bonds	—		40,857		—		40,857		—		—		—		—
Equity Securities: Large-Cap	71,176		—		—		71,176		92,852		—		—		92,852
Equity Securities: Mid-Cap	71,419		—		—		71,419		81,663		—		—		81,663
Equity Securities: Small-Cap	53,401		—		—		53,401		67,075		—		—		67,075
Equity Securities: Micro-Cap	30,387		—		—		30,387		31,469		—		—		31,469
Equity Securities: International	7,104		—		—		7,104		13,817		—		—		13,817
Equity Securities: Emerging Markets	6,519		—		—		6,519		8,245		—		—		8,245
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: Global and International							95,653
Equity Securities: Emerging Markets							29,757
Commingled Fund: Equity Securities: Global and International															114,975
Commingled Fund: Equity Securities: Emerging Markets															40,059
Commingled Fund: Commodities fund															34,793
Real estate							39,846								47,570
Private market investments							35,041								40,795
Commodities fund							30,842
Total	$	290,962	$	128,503	$	—	$	650,604	$	349,996	$	134,931	$	—	$	763,119
Postretirement plan assets⁽¹⁾	$	758	$	32,633	$	—	$	33,391	$	641	$	38,984	$	—	$	39,625



	Level 1		Level 2		Level 3		Total
Assets at December 31, 2018
Cash and cash equivalents	$	9,717	$	—	$	—	$	9,717
Short-term bonds	20,644		—		—		20,644
Intermediate bonds	20,595		87,646		—		108,241
Long-term bonds	—		40,857		—		40,857
Equity Securities: Large-Cap	71,176		—		—		71,176
Equity Securities: Mid-Cap	71,419		—		—		71,419
Equity Securities: Small-Cap	53,401		—		—		53,401
Equity Securities: Micro-Cap	30,387		—		—		30,387
Equity Securities: International	7,104		—		—		7,104
Equity Securities: Emerging Markets	6,519		—		—		6,519
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: International							95,653
Commingled Fund: Equity Securities: Emerging Markets							29,757
Commingled Fund: Commodities fund							30,842
Real estate							39,846
Private market investments							35,041
Total	$	290,962	$	128,503	$	—	$	650,604
Postretirement plan assets⁽¹⁾	$	758	$	32,633	$	—	$	33,391

Level 1 Level 2 Level 3 Total
Assets at December 31, 2017

Cash and cash equivalents $ 20,852
$ —
$ —
$ 20,852
Short-term bonds 20,475
—
—
20,475
Intermediate bonds 20,699
82,923
—
103,622
Long-term bonds —
40,707
—
40,707
Equity Securities: Large-Cap 95,179
—
—
95,179
Equity Securities: Mid-Cap 81,127
—
—
81,127
Equity Securities: Small-Cap 62,502
—
—
62,502
Equity Securities: Micro-Cap 32,753
—
—
32,753
Equity Securities: International 6,774
—
—
6,774
Equity Securities: Emerging Markets 8,785
—
—
8,785
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: International

83,589
Equity Securities: Emerging Markets

36,255
Real estate

38,435
Private market investments

31,618
Commodities fund

35,010
Total $ 349,146
$ 123,630
$ —
$ 697,683
Postretirement plan assets⁽¹⁾
$ 567
$ 37,727
$ —
$ 38,294

(1) The postretirement benefits assets are primarily life insurance contracts.

For the years ended December 31, ~~2018~~2019 and ~~2017,~~2018, there were no0 material transfers into or out of Levels 1, 2, or 3.

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Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:

Level 2 Bonds: These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.

Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.

Commingled Funds: These funds, made up of the ~~global,~~ international and emerging markets equity securities and commodities fund measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.

Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 9 years. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Employee Savings Plan

Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were approximately $7.7 million, $7.7 million, and $7.4 million in 2019, 2018, and ~~$7.5 million in 2018,~~ 2017, ~~and 2016,~~ respectively.

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Post-employment Benefits

Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-employment benefits included in other deferred credits on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, ~~2018,~~2019, and ~~2017,~~2018, were approximately $2 million.

13. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS

The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, ~~2018~~2019 and ~~2017~~2018 (in thousands of dollars):



	2019					2018
	Balance			Avg Rate		Balance			Avg Rate
Production	$	2,535,938		3.19	%	$	2,654,201		3.10	%
Transmission	1,220,703			1.89	%	1,201,092			1.89	%
Distribution	1,882,136			2.25	%	1,792,284			2.24	%
General and Other	474,790			6.17	%	456,279			6.40	%
Total in service	6,113,567			2.87	%	6,103,856			2.84	%
Accumulated provision for depreciation	(2,155,783		)			(2,210,781		)
In service - net	$	3,957,784				$	3,893,075

2018 2017
Balance Avg Rate Balance Avg Rate
Production $ 2,654,201
3.10 % $ 2,598,940
3.07 %
Transmission 1,201,092
1.89 % 1,163,240
1.94 %
Distribution 1,792,284
2.24 % 1,710,126
2.44 %
General and Other 456,279
6.40 % 433,856
6.01 %
Total in service 6,103,856
2.84 % 5,906,162
2.87 %
Accumulated provision for depreciation (2,210,781 )
(2,098,274 )
In service - net $ 3,893,075

$ 3,807,888

At December 31, ~~2018,~~2019, Idaho Power's construction work in progress balance of ~~$480.3~~$552.5 million included relicensing costs of ~~$297.0~~$326.0 million for the HCC, Idaho Power's largest ~~hydroelectric~~hydropower complex. In 2019, 2018, ~~2017,~~ and ~~2016, the IPUC authorized~~2017, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes in 2019 and 2018 and $10.7 million when grossed-up for the effect of income taxes in 2017 ~~and 2016~~ prior to income tax reform described in Note 2 - "Income Taxes") of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, ~~2018,~~2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was ~~$135.1~~$151.7 million.

Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, ~~2018~~2019 (in thousands of dollars):



Name of Plant	Location	Utility Plant in Service		Construction Work in Progress		Accumulated Provision for Depreciation		Ownership %	MW⁽¹⁾⁽²⁾
Jim Bridger units 1-4	Rock Springs, WY	$	745,096	$	4,622	$	353,254	33	771
Boardman	Boardman, OR	82,501		12		78,411		10	64
North Valmy unit 2⁽²⁾	Winnemucca, NV	252,921		217		166,419		50	145

Name of Plant Location Utility Plant in Service
Construction
Work in Progress

Accumulated
Provision for Depreciation
Ownership %
MW⁽¹⁾
Jim Bridger units 1-4 Rock Springs, WY $ 733,451
$ 5,141
$ 334,731
33 771
Boardman Boardman, OR 82,459
4
74,748
10 64
Valmy units 1 and 2 Winnemucca, NV 410,947
248
279,643
50 284

(1) Idaho Power’s share of nameplate capacity.

(2) Idaho Power ended its participation in coal-fired operations at unit 1 of the North Valmy plant on December 31, 2019.

IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power’s coal purchases from the joint venture were $73.6 million in 2019, $81.8 million in 2018, and $86.4 million in ~~2017, and $92.9 million in 2016.~~2017.

Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8.6 million in 2019, $9.7 million in 2018, and $9.8 million in ~~2017, and $7.8 million in 2016.~~2017.

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IDACORP's consolidated VIE, Marysville, owns a ~~hydroelectric~~hydropower plant with a net book value of ~~$15.2~~$14.7 million and ~~$15.7~~$15.2 million at December 31, ~~2018~~2019 and ~~2017,~~2018, respectively.

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14. ASSET RETIREMENT OBLIGATIONS (ARO)

The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under this order do not earn a return on investment. Accretion, depreciation, and gains or losses related to the Boardman generating facility are exempted from such regulatory treatment as Idaho Power is now collecting amounts related to the decommissioning of Boardman in rates.

Idaho Power’s recorded AROs relate to the ~~removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities and the~~ reclamation and removal costs at its jointly-owned coal-fired generation facilities.

Idaho Power also has additional AROs associated with its transmission system, ~~hydroelectric~~hydropower facilities, natural gas-fired generation facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.

Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, ~~2018~~2019 and ~~2017.~~2018.

The following table presents the changes in the carrying amount of AROs (in thousands of dollars):



	2019			2018
Balance at beginning of year	$	26,792		$	26,415
Accretion expense	1,115			1,055
Revisions in estimated cash flows	365			(751		)
Liability incurred	—			129
Liability settled	(81		)	(56		)
Balance at end of year	$	28,191		$	26,792

2018 2017
Balance at beginning of year $ 26,415
$ 26,257
Accretion expense 1,055
1,015
Revisions in estimated cash flows (751 ) (791 )
Liability incurred 129
—
Liability settled (56 ) (66 )
Balance at end of year $ 26,792
$ 26,415

15. INVESTMENTS

The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):



	2019		2018
Idaho Power investments:
Bridger Coal Company (equity method investment)	$	40,713	$	49,878
Exchange traded short-term bond funds and cash equivalents	42,648		36,471
Executive deferred compensation plan investments	90		17
Total Idaho Power investments	83,451		86,366
Investments in affordable housing (IDACORP Financial Services)	3,665		3,446
Ida-West joint ventures (equity method investments)	11,102		11,366
Total IDACORP investments	$	98,218	$	101,178

2018 2017
Idaho Power investments:

Bridger Coal Company (equity method investment) $ 49,878
$ 68,566
Exchange traded short-term bond funds and cash equivalents 36,471
30,249
Executive deferred compensation plan investments 17
17
Total Idaho Power investments 86,366
98,832
Investments in affordable housing (IDACORP Financial Services) 3,446
5,521
Ida-West joint ventures (equity method investments) 11,366
11,345
Total IDACORP investments $ 101,178
$ 115,698

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Equity Method Investments

Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture, Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings of unconsolidated equity-method investments (in thousands of dollars):



	2019		2018		2017
Bridger Coal Company (Idaho Power)	$	10,285	$	10,712	$	9,267
Ida-West joint ventures	2,085		1,737		2,107
Total	$	12,370	$	12,449	$	11,374

2018 2017 2016
Bridger Coal Company (Idaho Power) $ 10,712
$ 9,267
$ 10,855
Ida-West joint ventures 1,737
2,107
2,016
Total $ 12,449
$ 11,374
$ 12,871

Investments in Equity Securities

Investments in ~~securities classified as available-for-sale~~equity securities are reported at fair value. Any unrealized gains or losses on ~~available-for-sale~~equity securities are included in ~~income, as the fair value option has been elected for these instruments.~~income. Unrealized gains and losses on ~~available-for-sale~~equity securities were immaterial at December 31, ~~2018~~2019 and December 31, ~~2017.~~2018. The following table summarizes sales of ~~available-for-sale~~equity securities (in thousands of dollars):



	2019		2018		2017
Proceeds from sales	$	5,080	$	5,007	$	4,989
Gross realized gains from sales	—		—		—

2018 2017 2016
Proceeds from sales $ 5,007
$ 4,989
$ 15,693
Gross realized gains from sales —
—
54

Investments in Affordable Housing

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified affordable housing projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.

16. 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 below.

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The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018, ~~2017,~~ and ~~2016~~2017 (in thousands of dollars):


	Location of Realized Gain/(Loss) on Derivatives Recognized in Income		Gain/(Loss) on Derivatives Recognized in Income⁽¹⁾											Location of Realized Gain/(Loss) on Derivatives Recognized in Income		Gain/(Loss) on Derivatives Recognized in Income⁽¹⁾
		2018				2017				2016					2019				2018				2017
Financial swaps		Operating revenues		$	1,316			$	902			$	1,405		Operating revenues		$	904			$	1,316			$	902
Financial swaps	Purchased power		7,828				166				586			Purchased power		(2,183		)		7,828				166
Financial swaps	Fuel expense		22,563				701				(1,947		)	Fuel expense		13,811				22,563				701
Financial swaps	Other operations and maintenance		118				(84		)		(161		)	Other operations and maintenance		—				118				(84		)
Forward contracts	Operating revenues		41				55				(54		)	Operating revenues		285				41				55
Forward contracts	Purchased power		(54		)		(69		)		86			Purchased power		(270		)		(54		)		(69		)
Forward contracts	Fuel expense		(186		)		4				139			Fuel expense		565				(186		)		4

(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 17 - "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 December 31, ~~2018~~2019 and ~~2017~~2018 (in thousands of dollars):



		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
December 31, 2019
Current:
Financial swaps	Other current assets	$	2,426	$	(2,034	)		$	392	$	2,034	$	(2,034	)	$	—
Financial swaps	Other current liabilities	134		(134		)		—		924		(134		)	790
Forward contracts	Other current assets	13		—				13		—		—			—
Forward contracts	Other current liabilities	—		—				—		32		—			32
Long-term:
Financial swaps	Other assets	3		(3		)		—		27		(3		)	24
Total		$	2,576	$	(2,171	)		$	405	$	3,017	$	(2,171	)	$	846

December 31, 2018
Current:
Financial swaps	Other current assets	$	4,639	$	(984	)	⁽¹⁾	$	3,655	$	938	$	(938	)	$	—
Financial swaps	Other current liabilities	—		—				—		806		—			806
Forward contracts	Other current liabilities	—		—				—		104		—			104
Long-term:
Financial swaps	Other liabilities	—		—				—		64		—			64
Total		$	4,639	$	(984	)		$	3,655	$	1,912	$	(938	)	$	974

Asset Derivatives Liability Derivatives
Balance Sheet Location Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities

December 31, 2018
Current:

Financial swaps Other current assets $ 4,639
$ (984 )
⁽¹⁾
$ 3,655
$ 938
$ (938 ) $ —
Financial swaps Other current liabilities —
—
—
806
—
806
Forward contracts Other current liabilities —
—
—
104
—
104
Long-term:

Financial swaps Other liabilities —
—
—
64
—
64
Total $ 4,639
$ (984 ) $ 3,655
$ 1,912
$ (938 ) $ 974

December 31, 2017
Current:

Financial swaps Other current assets $ 18
$ —
$ 18
$ —
$ —
$ —
Financial swaps Other current liabilities 553
(553 ) —
1,971
(748 )
⁽²⁾
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 asset derivative amounts offset include $45 thousandof collateral payable ~~for the period ending~~at December 31, 2018.

~~(2) Current liability derivative amounts offset include $196 thousandof collateral receivable for the period ending December 31, 2017.~~

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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, ~~2018~~2019 and ~~2017~~2018 (in thousands of units):



		December 31,
Commodity	Units	2019	2018
Electricity purchases	MWh	91	52
Electricity sales	MWh	138	39
Natural gas purchases	MMBtu	14,053	7,514
Natural gas sales	MMBtu	78	446

December 31,
Commodity Units 2018 2017
Electricity purchases MWh 52
312
Electricity sales MWh 39
224
Natural gas purchases MMBtu 7,514
7,028
Natural gas sales MMBtu 446
140

Credit Risk

At December 31, ~~2018,~~2019, 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 WSPP, Inc. 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 of Idaho Power's 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 December 31, ~~2018,~~2019, was ~~$1.9~~$3.0 million. Idaho Power posted no$1.4 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, ~~2018,~~2019, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional ~~$7.8~~$6.7 million to cover open liability positions as well as completed transactions that have not yet been paid.

17. 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 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 for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.

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• 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 no0 transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, ~~2018~~2019 and ~~2017.~~2018.

The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, ~~2018~~2019 and ~~2017~~2018 (in thousands of dollars):


	December 31, 2018								December 31, 2017								December 31, 2019								December 31, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds and commercial paper
IDACORP⁽¹⁾	$	97,833	$	—	$	—	$	97,833	$	28,038	$	—	$	—	$	28,038	$	64,173	$	—	$	—	$	64,173	$	97,833	$	—	$	—	$	97,833
Idaho Power	79,228		—		—		79,228		10,260		—		—		10,260		26,510		—		—		26,510		79,228		—		—		79,228
Derivatives	3,655		—		—		3,655		22		—		—		22		392		13		—		405		3,655		—		—		3,655
Equity securities	36,488		—		—		36,488		30,266		—		—		30,266		42,738		—		—		42,738		36,488		—		—		36,488
Liabilities:
Derivatives	$	870	$	104	$	—	$	974	$	1,223	$	2	$	—	$	1,225	$	814	$	32	$	—	$	846	$	870	$	104	$	—	$	974

(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 December 31, ~~2018~~2019 and ~~2017,~~2018, using available market information and appropriate valuation methodologies (in thousands).


	December 31, 2018				December 31, 2017				December 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(thousands of dollars)								(thousands of dollars)
IDACORP
Assets:
Notes receivable⁽¹⁾	$	3,804	$	3,804	$	3,804	$	3,804	$	3,804	$	3,804	$	3,804	$	3,804
Liabilities:
Long-term debt⁽¹⁾	1,834,788		1,942,773		1,746,123		1,915,459
Long-term debt (including current portion)⁽¹⁾									1,836,659		2,083,931		1,834,788		1,942,773
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	$	1,834,788	$	1,942,773	$	1,746,123	$	1,915,459
Long-term debt (including current portion)⁽¹⁾									$	1,836,659	$	2,083,931	$	1,834,788	$	1,942,773

(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 17 - "Fair Value Measurements."

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~~hydropower conditions. Long-term debt is not traded on an exchange and is valued using

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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.

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18. 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~~hydropower 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		Utility Operations		All Other			Eliminations			Consolidated Total
2018
2019
Revenues	$	1,366,582	$	4,170		$	—		$	1,370,752	$	1,342,940	$	3,443		$	—		$	1,346,383
Operating income	295,256		1,666			—			296,922		297,652		674			—			298,326
Other income, net	11,646		(1		)	—			11,645		20,362		1			—			20,363
Interest income	8,923		1,573			(655		)	9,841		10,968		3,052			(769		)	13,251
Equity-method income	10,712		1,737			—			12,449		10,285		2,085			—			12,370
Interest expense	85,891		712			(655		)	85,948		86,412		832			(769		)	86,475
Income before income taxes	240,646		4,263			—			244,909		252,854		4,981			—			257,835
Income tax expense (benefit)	18,312		(926		)	—			17,386		28,417		(3,910		)	—			24,507
Income attributable to IDACORP, Inc.	222,334		4,467			—			226,801		224,437		8,417			—			232,854
Total assets	6,254,400		163,540			(35,186		)	6,382,754		6,494,159		220,620			(73,578		)	6,641,201
Expenditures for long-lived assets	277,823		30			—			277,853		278,707		(2		)	—			278,705

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	Utility Operations		All Other			Eliminations			Consolidated Total
2018
Revenues	$	1,366,582	$	4,170		$	—		$	1,370,752
Operating income	295,256		1,666			—			296,922
Other income, net	11,646		(1		)	—			11,645
Interest income	8,923		1,573			(655		)	9,841
Equity-method income	10,712		1,737			—			12,449
Interest expense	85,891		712			(655		)	85,948
Income before income taxes	240,646		4,263			—			244,909
Income tax expense (benefit)	18,312		(926		)	—			17,386
Income attributable to IDACORP, Inc.	222,334		4,467			—			226,801
Total assets	6,254,400		163,540			(35,186		)	6,382,754
Expenditures for long-lived assets	277,823		30			—			277,853

2017
Revenues	$	1,344,893	$	4,593		$	—		$	1,349,486
Operating income	313,602		1,943			—			315,545
Other income, net	12,356		191			—			12,547
Interest income	6,044		295			(211		)	6,128
Equity-method income	9,267		2,107			—			11,374
Interest expense	83,660		297			(211		)	83,746
Income before income taxes	257,609		4,239			—			261,848
Income tax expense (benefit)	51,262		(2,602		)	—			48,660
Income attributable to IDACORP, Inc.	206,347		6,072			—			212,419
Total assets	5,995,435		143,696			(93,726		)	6,045,405
Expenditures for long-lived assets	285,471		17			—			285,488

Utility
Operations

All
Other
Eliminations
Consolidated
Total
2017
Revenues $ 1,344,893
$ 4,593
$ —
$ 1,349,486
Operating income 313,602
1,943
—
315,545
Other income, net 12,356
191
—
12,547
Interest income 6,044
295
(211 ) 6,128
Equity-method income 9,267
2,107
—
11,374
Interest expense 83,660
297
(211 ) 83,746
Income before income taxes 257,609
4,239
—
261,848
Income tax expense (benefit) 51,262
(2,602 ) —
48,660
Income attributable to IDACORP, Inc. 206,347
6,072
—
212,419
Total assets 5,995,435
143,696
(93,726 ) 6,045,405
Expenditures for long-lived assets 285,471
17
—
285,488

2016
Revenues $ 1,259,353
$ 2,667
$ —
$ 1,262,020
Operating income 277,297
6,285
—
283,582
Other income, net 15,852
6
—
15,858
Interest income 4,235
127
(121 ) 4,241
Equity-method income 10,855
2,016
—
12,871
Interest expense 81,812
344
(121 ) 82,035
Income before income taxes 226,427
8,090
—
234,517
Income tax expense (benefit) 37,185
(756 ) —
36,429
Income attributable to IDACORP, Inc. 189,242
9,046
—
198,288
Total assets 6,236,744
73,137
(19,984 ) 6,289,897
Expenditures for long-lived assets 296,948
2
—
296,950

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19. OTHER INCOME AND EXPENSE

The following table presents the components of IDACORP’s other ~~expense,~~income (expense), net and Idaho Power's other ~~expense,~~income (expense), net (in thousands of dollars):



IDACORP	2019			2018			2017
Interest and dividend income, net	$	8,181		$	5,605		$	3,872
Carrying charges on regulatory assets	5,494			4,075			2,310
Pension and postretirement non-service costs⁽¹⁾	(10,976		)	(15,781		)	(11,194		)
Income from life insurance investments	4,104			2,779			2,090
Other (expense) income	(301		)	455			813
Total other income (expense), net	$	6,502		$	(2,867	)	$	(2,109	)

Idaho Power
Interest and dividend income, net	$	5,898		$	4,688		$	3,787
Carrying charges on regulatory assets	5,494			4,075			2,310
Pension and postretirement non-service costs⁽¹⁾	(10,976		)	(15,781		)	(11,194		)
Income from life insurance investments	4,104			2,779			2,090
Other expense	(2,254		)	(1,612		)	(1,749		)
Total other income (expense), net	$	2,266		$	(5,851	)	$	(4,756	)

IDACORP 2018 2017 2016
Interest and dividend income, net $ 5,605
$ 3,872
$ 4,466
Carrying charges on regulatory assets 4,075
2,310
2,082
Pension and postretirement non-service costs⁽¹⁾
(15,781 ) (11,194 ) (11,806 )
Income from life insurance investments 2,779
2,090
2,588
Other income 455
813
738
Total other expense, net $ (2,867 ) $ (2,109 ) $ (1,932 )

Idaho Power
Interest and dividend income, net $ 4,688
$ 3,787
$ 4,460
Carrying charges on regulatory assets 4,075
2,310
2,082
Pension and postretirement non-service costs⁽¹⁾
(15,781 ) (11,194 ) (11,806 )
Income from life insurance investments 2,779
2,090
2,588
Other expense (1,612 ) (1,749 ) (1,871 )
Total other expense, net $ (5,851 ) $ (4,756 ) $ (4,547 )

(1) The 2018 pension and postretirement non-service costs includes $4.2 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 12 - "Benefit Plans."

20. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the years ended December 31, 2019, 2018, ~~2017,~~ and ~~2016~~2017 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.



	Year Ended December 31,
	2019			2018			2017
Defined benefit pension items
Balance at beginning of period	$	(22,844	)	$	(30,964	)	$	(20,882	)
Other comprehensive income before reclassifications	(15,392		)	5,234			(7,872		)
Amounts reclassified out of AOCI to net income	1,952			2,886			1,882
Net current-period other comprehensive income	(13,440		)	8,120			(5,990		)
Cumulative effect of change in accounting principle⁽¹⁾	—			—			(4,092		)
Balance at end of period	$	(36,284	)	$	(22,844	)	$	(30,964	)

Year Ended December 31,
2018 2017 2016
Defined benefit pension items
Balance at beginning of period $ (30,964 ) $ (20,882 ) $ (21,276 )
Other comprehensive income before reclassifications 5,234
(7,872 ) (1,859 )
Amounts reclassified out of AOCI to net income 2,886
1,882
2,253
Net current-period other comprehensive income 8,120
(5,990 ) 394
Cumulative effect of change in accounting principle⁽¹⁾
—
(4,092 ) —
Balance at end of period $ (22,844 ) $ (30,964 ) $ (20,882 )

(1) The cumulative effect of change in accounting principle relates to the 2017 adoption of ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220).

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The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2019, 2018, ~~2017,~~ and ~~2016~~2017 (in thousands of dollars). Items in parentheses indicate increases to net income.


	Amount Reclassified from AOCI									Amount Reclassified from AOCI
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2019			2018			2017
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	98		$	127		$	168		$	96		$	98		$	127
Net loss	3,788			2,963			3,532			2,533			3,788			2,963
Total before tax	3,886			3,090			3,700			2,629			3,886			3,090
Tax benefit⁽²⁾	(1,000		)	(1,208		)	(1,447		)	(677		)	(1,000		)	(1,208		)
Net of tax	2,886			1,882			2,253			1,952			2,886			1,882
Total reclassification for the period	$	2,886		$	1,882		$	2,253		$	1,952		$	2,886		$	1,882

(1) Amortization of these items is included in IDACORP's consolidated income statements in other operating expenses and in Idaho Power's consolidated income statements in other expense, net.

(2) The tax benefit is included in income tax expense in the consolidated income statements of both IDACORP and Idaho Power.

21. RELATED PARTY TRANSACTIONS

IDACORP:Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.8 million in 2019 and $0.7 million in both 2018 and ~~2017 and $0.8 million in 2016.~~2017.

At December 31, ~~2018~~2019 and ~~2017,~~2018, Idaho Power had a $1.9 million ~~and $57.3 million~~ payable to IDACORP, ~~respectively,~~ which was included in its accounts payable to affiliates balance on its consolidated balance sheets. In ~~2018,~~2019, Idaho Power paid IDACORP certain estimated income taxes that had been accrued at December 31, ~~2017.~~2018.

Ida-West:Idaho Power purchases all of the power generated by four of Ida-West’s ~~hydroelectric~~hydropower projects located in Idaho. Idaho Power paid Ida-West $8.6 million in 2019, $9.7 million in 2018, and $9.8 million in 2017 ~~and $7.8 million in 2016~~ for that power.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of IDACORP, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, ~~2018~~2019 and ~~2017,~~2018, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, ~~2018,~~2019, and the related notes and the schedules listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2018~~2019 and ~~2017,~~2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2018,~~2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, ~~2018,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February ~~21, 2019,~~20, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements

Critical Audit Matter Description

Idaho Power Company ("Idaho Power"), the principal operating subsidiary of the Company, is subject to rate regulation by the Federal Energy Regulatory Commission and the Idaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Idaho and Oregon. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense.

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Idaho Power’s rates are subject to regulatory rate-setting processes. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects Idaho Power to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

Additionally, consistent with orders and directives of the Commissions, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers for amounts collected prior to costs being incurred. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions and the application of flow-through accounting for income taxes included the following, among others:

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities.

We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

We read relevant regulatory orders issued by the Commissions for Idaho Power and evaluated whether such orders were appropriately reflected in the Company's financial statements.

For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders.

With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 20, 2020

We have served as the Company's auditor since 1932.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and the Board of Directors of Idaho Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February ~~21, 2019~~20, 2020

~~We have served as the Company's auditor since 1932.~~

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~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

~~To the shareholder and the Board of Directors of Idaho Power Company~~

~~Opinion on the Financial Statements~~

We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in ~~Internal Control - Integrated Framework (2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2019, expressed an unqualified opinion on the Company’s internal control over financial reporting.

~~Basis for Opinion~~

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

~~/s/~~ ~~DELOITTE & TOUCHE LLP~~

~~Boise, Idaho~~

~~February 21, 2019~~

We have served as the Company's auditor since 1932.

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SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA

The following unaudited information is presented for each quarter of ~~2018~~2019 and ~~2017~~2018 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.


	Quarter Ended								Quarter Ended
	March 31		June 30		September 30		December 31		March 31		June 30		September 30		December 31
IDACORP, Inc.
2019
Revenues									$	350,319	$	316,895	$	386,320	$	292,849
Operating income									58,119		71,780		114,156		54,271
Net income									42,637		53,400		90,218		47,073
Net income attributable to IDACORP, Inc.									42,686		53,156		89,876		47,136
Basic earnings per share									$	0.85	$	1.05	$	1.78	$	0.93
Diluted earnings per share									$	0.84	$	1.05	$	1.78	$	0.93
2018
Revenues	$	310,107	$	339,952	$	408,801	$	311,892	$	310,107	$	339,952	$	408,801	$	311,892
Operating income	50,589		82,835		115,233		48,265		50,589		82,835		115,233		48,265
Net income	36,111		62,593		102,591		26,228		36,111		62,593		102,591		26,228
Net income attributable to IDACORP, Inc.	36,142		62,288		102,231		26,140		36,142		62,288		102,231		26,140
Basic earnings per share	$	0.72	$	1.24	$	2.03	$	0.52	$	0.72	$	1.24	$	2.03	$	0.52
Diluted earnings per share	$	0.72	$	1.23	$	2.02	$	0.52	$	0.72	$	1.23	$	2.02	$	0.52
2017
Idaho Power Company
2019
Revenues	$	302,544	$	333,006	$	408,324	$	305,612	$	349,771	$	315,774	$	385,028	$	292,367
Operating income⁽¹⁾	53,627		81,907		123,707		56,304
Income from operations									58,734		71,749		113,924		55,196
Net income	33,006		50,096		91,076		39,010		41,584		51,176		87,979		43,698
Net income attributable to IDACORP, Inc.	33,102		49,831		90,634		38,852
Basic earnings per share	$	0.66	$	0.99	$	1.80	$	0.77
Diluted earnings per share	$	0.66	$	0.99	$	1.80	$	0.77
Idaho Power Company
2018
Revenues	$	309,461	$	338,699	$	407,355	$	311,067	$	309,461	$	338,699	$	407,355	$	311,067
Income from operations	51,120		82,659		114,963		48,581		51,120		82,659		114,963		48,581
Net income	35,857		60,637		100,194		25,646		35,857		60,637		100,194		25,646
2017
Revenues	$	301,964	$	331,768	$	406,655	$	304,506
Income from operations⁽¹⁾	54,350		81,777		123,293		56,554
Net income	32,482		48,381		88,329		37,155

(1) Operating income in 2017 reflects the 2018 adoption of Accounting Standards Update 2017-07. Retrospective adjustments were made to prior periods to conform with current period presentation. For additional information, refer to Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures - IDACORP, Inc.

The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, ~~2018,~~2019, have concluded that IDACORP, Inc.’s disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - IDACORP, Inc.

Management’s Annual Report on Internal Control Over Financial Reporting

The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, ~~2018.~~2019. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).

Based on its assessment, management concluded that, as of December 31, ~~2018,~~2019, IDACORP’s internal control over financial reporting is effective based on those criteria.

IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, ~~2018.~~2019.

February ~~21, 2019~~20, 2020

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of IDACORP, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, ~~2018,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2018,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements ~~and financial statement schedules~~ as of and for the year ended December 31, ~~2018~~2019, of the Company and our report dated February ~~21, 2019~~20, 2020, expressed an unqualified opinion on those financial ~~statements and financial statement schedules.~~statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control ~~over~~Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February ~~21, 2019~~20, 2020

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Disclosure Controls and Procedures - Idaho Power Company

The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, ~~2018,~~2019, have concluded that Idaho Power Company's disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - Idaho Power Company

Management’s Annual Report on Internal Control Over Financial Reporting

The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, ~~2018.~~2019. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).

Based on its assessment, management concluded that, as of December 31, ~~2018,~~2019, Idaho Power’s internal control over financial reporting is effective based on those criteria.

Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, ~~2018.~~2019.

February ~~21, 2019~~20, 2020

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and the Board of Directors of Idaho Power Company

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, ~~2018,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2018,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements ~~and financial statement schedule~~ as of and for the year ended December 31, ~~2018~~2019, of the Company and our report dated February ~~21, 2019~~20, 2020, expressed an unqualified opinion on those financial ~~statements and financial statement schedule.~~statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Definition and Limitations of Internal Control over Financial Reporting

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February ~~21, 2019~~20, 2020

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Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company

There have been no changes in IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting during the quarter ended December 31, ~~2018~~2019 that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” ~~“Section~~“Delinquent Section 16(a) ~~Beneficial Ownership Reporting Compliance,~~Reports,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders are hereby incorporated by reference.

Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”

ITEM 11. EXECUTIVE COMPENSATION

The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers, and Five-Percent Shareholders” to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, ~~2018,~~2019, with respect to the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) pursuant to which equity securities of IDACORP may be issued.

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Equity Compensation Plan Information


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights			(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))			(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights			(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by shareholders	139,353	⁽¹⁾	$	—	⁽²⁾	720,408	⁽³⁾		232,550	⁽¹⁾	$	—	⁽²⁾	613,394	⁽³⁾
Equity compensation plans not approved by shareholders	—		$	—		—			—		$	—		—
Total	139,353		$	—		720,408			232,550		$	—		613,394

(1) Represents shares subject to outstanding time-based restricted stock units and performance-based restricted stock units (at target).
(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Restricted stock unit awards and director deferred stock unit awards may be settled only for shares of common stock on a one-for-one basis.								(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Restricted stock unit awards and director deferred stock unit awards may be settled only for shares of common stock on a one-for-one basis.
(2) Time-based restricted stock units and performance-based restricted stock units have no exercise price.
(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards. The number of shares listed in this column excludes (i) issued but unvested performance-based restricted shares and (ii) issued but unvested time-based restricted shares, in both cases as of December 31, 2018.
(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards. The number of shares listed in this column excludes (i) unvested performance-based restricted stock units (at target), (ii) unvested time-based restricted stock units, and (iii) deferred director stock unit awards, in all cases as of December 31, 2019.								(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards. The number of shares listed in this column excludes (i) unvested performance-based restricted stock units (at target), (ii) unvested time-based restricted stock units, and (iii) deferred director stock unit awards, in all cases as of December 31, 2019.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders are hereby incorporated by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

IDACORP:The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the ~~2019~~2020 annual meeting of shareholders is hereby incorporated by reference.

Idaho Power:The table below presents the aggregate fees of Idaho Power's principal independent registered public accounting firm, Deloitte & Touche LLP, billed or is expected to bill to Idaho Power for the fiscal years ended December 31, ~~2018~~2019 and ~~2017:~~2018:


		2018		2017			2019		2018
Audit fees		$	1,437,100	$	1,379,000		$	1,515,701	$	1,437,100
Audit-related fees⁽¹⁾		29,550		39,400			3,927		29,550
Tax fees⁽²⁾		26,125		40,000			3,993		26,125
All other fees⁽³⁾		1,895		2,000			1,895		1,895
Total		$	1,494,670	$	1,460,400		$	1,525,516	$	1,494,670

(1)Includes accounting-related consultation services.	(1)Includes accounting-related consultation services.					(1)Includes accounting-related consultation services.
(2) Includes fees for consultation related to tax planning and accounting.											(3) Accounting research tool subscription.

Policy on Audit Committee Pre-Approval:

Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For ~~2018~~2019 and ~~2017,~~2018, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee.

In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed

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by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed services; however, the Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.

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In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:

• the independent public accounting firm cannot function in the role of management of Idaho Power; and

• the independent public accounting firm cannot audit its own work.

The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) and (2) Refer to Part II, Item 8 - “Financial Statements and Supplementary Data” for a complete listing of consolidated financial statements and financial statement schedules.

(3) Exhibits. Note Regarding Reliance on Statements in Agreements: The agreements filed as exhibits to ~~this~~IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2019 are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements.

Incorporated by Reference
Exhibit No. Exhibit Description Form File No. Exhibit No. Date Included Herewith
2
Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998
S-4 333-48031 A 3/16/1998
3.1 Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989 S-3 Post-Effective Amend. No. 2 33-00440* 4(a)(xiii) 6/30/1989
3.2 Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991 S-3 33-65720* 4(a)(ii) 7/7/1993
3.3 Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993 S-3 33-65720* 4(a)(iii) 7/7/1993
3.4
Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998
S-8 Post-Effective Amend. No. 1 33-56071-99 3(d) 10/1/1998
3.5
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000
10-Q 1-3198 3(a)(iii) 8/4/2000
3.6
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005
8-K 1-3198 3.3 1/26/2005
3.7
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007
8-K 1-3198 3.3 11/19/2007



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
2	Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998	S-4	333-48031	A	3/16/1998

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Incorporated by Reference
Exhibit No. Exhibit Description Form File No. Exhibit No. Date Included Herewith
3.8
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012
8-K 1-3198 3.14 5/21/2012
3.9
Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect
8-K 1-3198 3.2 11/19/2007
3.10
Articles of Incorporation of IDACORP, Inc.
S-3 333-64737 3.1 11/4/1998
3.11
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998
S-3 Amend. No. 1 333-64737 3.2 11/4/1998
3.12
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998
S-3 Post-Effective Amend. No. 1 333-00139-99 3(b) 9/22/1998
3.13
Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012
8-K 1-14465 3.13 5/21/2012
3.14
Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect
10-Q 1-14465 3.15 10/30/2014
4.1 Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees 2-3413* B-2
4.2 Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:
File number 1-MD, as Exhibit B-2-a, First, July 1, 1939*
File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943*
File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947*
File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948*
File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949*
File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951*
File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957*
File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957*
File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957*
File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958*
File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958*
File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959*
File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960*
File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961*
File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964*
File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966*
File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966*
File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972*
File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974*
File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974*
File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974*
File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976*
File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978*
File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979*
File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981*
File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982*
File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986*
File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989*
File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990*
File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991*
File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991*



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
3.1	Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989	S-3 Post-Effective Amend. No. 2	33-00440*	4(a)(xiii)	6/30/1989
3.2	Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991	S-3	33-65720*	4(a)(ii)	7/7/1993
3.3	Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993	S-3	33-65720*	4(a)(iii)	7/7/1993
3.4	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998	S-8 Post-Effective Amend. No. 1	33-56071-99	3(d)	10/1/1998
3.5	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000	10-Q	1-3198	3(a)(iii)	8/4/2000
3.6	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005	8-K	1-3198	3.3	1/26/2005
3.7	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007	8-K	1-3198	3.3	11/19/2007
3.8	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012	8-K	1-3198	3.14	5/21/2012
3.9	Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect	8-K	1-3198	3.2	11/19/2007
3.10	Articles of Incorporation of IDACORP, Inc.	S-3	333-64737	3.1	11/4/1998
3.11	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998	S-3 Amend. No. 1	333-64737	3.2	11/4/1998
3.12	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998	S-3 Post-Effective Amend. No. 1	333-00139-99	3(b)	9/22/1998
3.13	Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012	8-K	1-14465	3.13	5/21/2012
3.14	Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect	10-Q	1-14465	3.15	10/30/2014
4.1	Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees		2-3413*	B-2
4.2	Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:
	File number 1-MD, as Exhibit B-2-a, First, July 1, 1939*
	File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943*
	File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947*
	File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948*
	File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949*
	File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951*
	File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957*
	File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957*
	File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957*
	File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958*
	File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958*

Table of Contents

Incorporated by Reference
Exhibit No. Exhibit Description Form File No. Exhibit No. Date Included Herewith
File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992*
File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993*
File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993*

File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000

File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001

File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003

File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003

File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003

File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005

File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006

File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007

File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007

File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008

File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010

File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010

File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013

File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016
4.3
Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.16)
10-Q 1-3198 4(b) 8/4/2000
4.4 Agreement of Idaho Power Company to furnish certain debt instruments S-3 33-65720* 4(f) 7/7/1993
4.5
Agreement of IDACORP, Inc. to furnish certain debt instruments
10-Q 1-14465 4(c)(ii) 11/6/2003
4.6 Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating Corporation S-3 Post-Effective Amend. No. 2 33-00440* 2(a)(iii) 6/30/1989
4.7
Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
8-K 1-14465 4.1 2/28/2001
4.8
First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
8-K 1-14465 4.2 2/28/2001
4.9
Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
S-3 333-67748 4.13 8/16/2001
4.10
Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010
10-Q 1-3198 4.12 8/5/2010
10.1
Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp
10-K 1-14465, 1-3198 10.4 2/19/2015
10.2
Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp
10-K 1-14465, 1-3198 10.5 2/19/2015
10.3 Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rights S-3 33-65720* 10(h) 7/7/1993
10.4 Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 S-3 33-65720* 10(h)(i) 7/7/1993



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
	File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959*
	File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960*
	File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961*
	File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964*
	File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966*
	File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966*
	File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972*
	File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974*
	File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974*
	File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974*
	File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976*
	File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978*
	File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979*
	File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981*
	File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982*
	File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986*
	File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989*
	File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990*
	File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991*
	File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991*
	File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992*
	File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993*
	File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993*
	File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003
	File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005
	File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006
	File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007
	File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007
	File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008
	File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010
	File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010
	File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013
	File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016
4.3	Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.13)	10-Q	1-3198	4(b)	8/4/2000
4.4	Agreement of Idaho Power Company to furnish certain debt instruments	S-3	33-65720*	4(f)	7/7/1993
4.5	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating Corporation	S-3 Post-Effective Amend. No. 2	33-00440*	2(a)(iii)	6/30/1989
4.6	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	8-K	1-14465	4.1	2/28/2001

Table of Contents

Incorporated by Reference
Exhibit No. Exhibit Description Form File No. Exhibit No. Date Included Herewith
10.5 Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 S-3 33-65720* 10(h)(ii) 7/7/1993
10.6
Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.3
10-Q 1-14465* 10.58 5/7/2009
10.7 Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company Limited S-3 33-65720* 10(m) 7/7/1993
10.8
Credit Agreement, dated November 6, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein
8-K 1-14465, 1-3198 10.1 11/9/2015
10.9
Credit Agreement, dated November 6, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein
8-K 1-14465, 1-3198 10.2 11/9/2015
10.10
Letter Agreement, effective as of November 7, 2016, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10-K 1-14465, 1-3198 10.20 2/23/2017
10.11
Letter Agreement, effective as of November 7, 2016, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10-K 1-14465, 1-3198 10.21 2/23/2017
10.12
Letter Agreement, effective as of November 7, 2017, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement
10-K 1-14465, 1-3198 10.12 2/22/2018



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
4.7	First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	8-K	1-14465	4.2	2/28/2001
4.8	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	S-3	333-67748	4.13	8/16/2001
4.9	Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010	10-Q	1-3198	4.12	8/5/2010
4.10	Description of the Registrant's Securities					X
10.1	Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp	10-K	1-14465, 1-3198	10.4	2/19/2015
10.2	Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp	10-K	1-14465, 1-3198	10.5	2/19/2015
10.3	Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rights	S-3	33-65720*	10(h)	7/7/1993
10.4	Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3	S-3	33-65720*	10(h)(i)	7/7/1993
10.5	Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3	S-3	33-65720*	10(h)(ii)	7/7/1993
10.6	Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.3	10-Q	1-14465*	10.58	5/7/2009
10.7	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company Limited	S-3	33-65720*	10(m)	7/7/1993
10.8	Credit Agreement, dated November 6, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein	8-K	1-14465, 1-3198	10.1	11/9/2015
10.9	Credit Agreement, dated November 6, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein	8-K	1-14465, 1-3198	10.2	11/9/2015
10.10	First Amendment to Credit Agreement, dated December 6, 2019, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and MUFG Bank, LTD., as documentation agents and LC Issuers; Wells Fargo Securities, LLC, and JPMorgan Chase Bank, N.A., as joint lead arrangers and joint book runners; and the other lenders named therein	8-K	1-14465, 1-3198	10.1	12/10/2019

Table of Contents

Incorporated by Reference
Exhibit No. Exhibit Description Form File No. Exhibit No. Date Included Herewith
10.13
Letter Agreement, effective as of November 7, 2017, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement
10-K 1-14465, 1-3198 10.13 2/22/2018
10.14
Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company
8-K 1-3198 10.1 10/10/2006
10.15 Guaranty Agreement, dated February 10, 1992, between Idaho Power Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. S-3 33-65720* 10(m)(i) 7/7/1993
10.16
Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho
10-Q 1-3198 10(c) 8/4/2000
10.17¹
Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008
10-K 1-14465, 1-3198 10.15 2/26/2009
10.18¹
Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I
10-Q 1-14465, 1-3198 10.62 11/1/2012
10.19¹
Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017
10-K 1-14465, 1-3198 10.31 2/23/2017
10.20¹
Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017
10-Q 1-14465, 1-3198 10.1 8/3/2017
10.21¹
Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006
10-Q 1-14465, 1-3198 10(h)(viii) 11/2/2006
10.22¹
IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 16, 2017
10-K 1-14465, 1-3198 10.22 2/22/2018
10.23¹
Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006
10-Q 1-14465, 1-3198 10(h)(xix) 11/2/2006
10.24¹
Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006
10-Q 1-14465, 1-3198 10(h)(xx) 11/2/2006
10.25¹
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008
10-K 1-14465, 1-3198 10.24 2/26/2009
10.26¹
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008
10-K 1-14465, 1-3198 10.25 2/26/2009
10.27¹
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010
8-K 1-14465, 1-3198 10.1 3/24/2010
10.28¹
IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 19, 2019
X
10.29¹
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017
10-K 1-14465, 1-3198 10.41 2/23/2017
10.30¹
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)
X



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
10.11	First Amendment to Credit Agreement, dated December 6, 2019, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and MUFG Bank, LTD., as documentation agents and LC Issuers; Wells Fargo Securities, LLC, and JPMorgan Chase Bank, N.A., as joint lead arrangers and joint book runners; and the other lenders named therein	8-K	1-14465, 1-3198	10.2	12/10/2019
10.12	Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company	8-K	1-3198	10.1	10/10/2006
10.13	Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho	10-Q	1-3198	10(c)	8/4/2000
10.14¹	Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008	10-K	1-14465, 1-3198	10.15	2/26/2009
10.15¹	Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I	10-Q	1-14465, 1-3198	10.62	11/1/2012
10.16¹	Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017	10-K	1-14465, 1-3198	10.31	2/23/2017
10.17¹	Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017	10-Q	1-14465, 1-3198	10.1	8/3/2017
10.18¹	Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006	10-Q	1-14465, 1-3198	10(h)(viii)	11/2/2006
10.19¹	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 21, 2019					X
10.20¹	Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006	10-Q	1-14465, 1-3198	10(h)(xix)	11/2/2006
10.21¹	Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006	10-Q	1-14465, 1-3198	10(h)(xx)	11/2/2006
10.22¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008	10-K	1-14465, 1-3198	10.24	2/26/2009
10.23¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008	10-K	1-14465, 1-3198	10.25	2/26/2009
10.24¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010	8-K	1-14465, 1-3198	10.1	3/24/2010
10.25¹	IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 1, 2020					X
10.26¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017	10-K	1-14465, 1-3198	10.41	2/23/2017
10.27¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)	10-K	1-14465, 1-3198	10.30	2/21/2019
10.28¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)	10-K	1-14465, 1-3198	10.31	2/21/2019
10.29¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)	10-K	1-14465, 1-3198	10.32	2/21/2019

Table of Contents



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
~~10.31~~10.30¹	~~IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)~~					X
~~10.32~~¹	~~IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)~~					X
~~10.33~~¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting) (For 2017 and 2018 Outstanding Awards)	10-K	1-14465, 1-3198	10.42	2/23/2017
~~10.34~~10.31¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal) (For 2017 and 2018 Outstanding Awards)	10-K	1-14465, 1-3198	10.43	2/23/2017
~~10.35~~10.32¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal) (For 2017 and 2018 Outstanding Awards)	10-K	1-14465, 1-3198	10.44	2/23/2017
~~10.36~~10.33¹	IDACORP, Inc. Executive Incentive Plan, as amended and restated November 14, 2018	10-K	1-14465, 1-3198	10.36	2/21/2019		X
~~10.37~~10.34¹	Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008	10-K	1-14465, 1-3198	10.32	2/26/2009
~~10.38~~10.35¹	IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, ~~2019~~2020					X
~~10.39~~10.36¹	Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.46	2/26/2009
~~10.40~~10.37¹	Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement (November 16, 2008)	10-K	1-14465, 1-3198	10.47	2/26/2009
~~10.41~~10.38¹	Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.48	2/26/2009
~~10.42~~10.39¹	Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.49	2/26/2009
~~10.43~~10.40¹	Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.50	2/26/2009
~~10.44~~10.41¹	Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred Compensation Agreement (November 16, 2008)	10-K	1-14465, 1-3198	10.51	2/26/2009
~~10.45~~10.42¹	Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.52	2/26/2009
~~10.46~~10.43¹	Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.53	2/26/2009
~~10.47~~10.44¹	Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016	10-K	1-14465, 1-3198	10.59	2/18/2016
~~10.48~~10.45¹	Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016	10-K	1-14465, 1-3198	10.61	2/23/2017
~~10.49~~10.46¹	Second Amendment to the Idaho Power Company Employee Savings Plan, as amended January 1, 2018	10-Q	1-14465, 1-3198	10.1	11/2/2017
~~10.50~~10.47¹	Third Amendment to the Idaho Power Company Employee Savings Plan, as amended April 26, 2018	10-Q	1-14465, 1-3198	10.4	5/3/2018
10.48¹	Fourth Amendment to the Idaho Power Company Employee Savings Plan, executed October 24, 2019 and effective January 1, 2020	10-Q	1-14465, 1-3198	10.1	10/31/2019
21.1	Subsidiaries of IDACORP, Inc.					X
23.1	Consent of Registered Independent Accounting Firm					X
23.2	Consent of Registered Independent Accounting Firm					X
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification					X
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification					X
31.3	Idaho Power Rule 13a-14(a) CEO certification					X
31.4	Idaho Power Rule 13a-14(a) CFO certification					X
32.1	IDACORP, Inc. Section 1350 CEO certification					X
32.2	IDACORP, Inc. Section 1350 CFO certification					X

Table of Contents



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
~~32.1~~	~~IDACORP, Inc. Section 1350 CEO certification~~					X
~~32.2~~	~~IDACORP, Inc. Section 1350 CFO certification~~					X
32.3	Idaho Power Section 1350 CEO certification					X
32.4	Idaho Power Section 1350 CFO certification					X
95.1	Mine Safety Disclosures					X
~~101.INS~~	~~XBRL Instance Document~~					X
101.SCH	XBRL Taxonomy Extension Schema Document					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					X
104	Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.)						X
* Exhibit originally filed with the U.S. Securities and Exchange Commission in paper format and as such, a hyperlink is not available.
(1) Management contract or compensatory plan or arrangement

Table of Contents

IDACORP, INC.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
	2019			2018			2017
	(thousands of dollars)
Income:
Equity in income of subsidiaries	$	231,534		$	226,567		$	211,974
Investment income	2,214			865			26
Total income	233,748			227,432			212,000
Expenses:
Operating expenses	816			668			708
Interest expense	831			713			294
Other expenses	30			—			30
Total expenses	1,677			1,381			1,032
Income Before Income Taxes	232,071			226,051			210,968
Income Tax Benefit	(783		)	(750		)	(1,451		)
Net Income Attributable to IDACORP, Inc.	232,854			226,801			212,419
Other comprehensive (loss) income	(13,440		)	8,120			(5,990		)
Comprehensive Income Attributable to IDACORP, Inc.	$	219,414		$	234,921		$	206,429

The accompanying note is an integral part of these statements.

Year Ended December 31,
2018 2017 2016
(thousands of dollars)
Income:

Equity in income of subsidiaries $ 226,567
$ 211,974
$ 198,061
Investment income 865
26
3
Total income 227,432
212,000
198,064
Expenses:

Operating expenses 668
708
716
Interest expense 713
294
333
Other expenses —
30
45
Total expenses 1,381
1,032
1,094
Income Before Income Taxes 226,051
210,968
196,970
Income Tax Benefit (750 ) (1,451 ) (1,318 )
Net Income Attributable to IDACORP, Inc. 226,801
212,419
198,288
Other comprehensive income (loss) 8,120
(5,990 ) 394
Comprehensive Income Attributable to IDACORP, Inc. $ 234,921
$ 206,429
$ 198,682

The accompanying note is an integral part of these statements.

IDACORP, INC.

CONDENSED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2019			2018			2017
	(thousands of dollars)
Operating Activities:
Net cash provided by operating activities	$	112,745		$	197,185		$	113,849
Investing Activities:
Net cash provided by investing activities	—			—			—
Financing Activities:
Dividends on common stock	(129,682		)	(121,421		)	(113,127		)
Decrease in short-term borrowings	—			—			—
Change in intercompany notes payable	37,588			(2,867		)	17,097
Other	(4,410		)	(3,614		)	(3,321		)
Net cash used in financing activities	(96,504		)	(127,902		)	(99,351		)
Net increase in cash and cash equivalents	16,241			69,283			14,498
Cash and cash equivalents at beginning of year	98,900			29,617			15,119
Cash and cash equivalents at end of year	$	115,141		$	98,900		$	29,617

The accompanying note is an integral part of these statements.

Year Ended December 31,
2018 2017 2016
(thousands of dollars)
Operating Activities:

Net cash provided by operating activities $ 197,185
$ 113,849
$ 139,077
Investing Activities:

Net cash provided by (used in) investing activities —
—
—
Financing Activities:

Dividends on common stock (121,421 ) (113,127 ) (104,985 )
Decrease in short-term borrowings —
—
(20,000 )
Change in intercompany notes payable (2,867 ) 17,097
2,421
Other (3,614 ) (3,321 ) (3,422 )
Net cash used in financing activities (127,902 ) (99,351 ) (125,986 )
Net increase in cash and cash equivalents 69,283
14,498
13,091
Cash and cash equivalents at beginning of year 29,617
15,119
2,028
Cash and cash equivalents at end of year $ 98,900
$ 29,617
$ 15,119

The accompanying note is an integral part of these statements.

Table of Contents

IDACORP, INC.

CONDENSED BALANCE SHEETS



	December 31,
	2019		2018
Assets	(thousands of dollars)
Current Assets:
Cash and cash equivalents	$	115,141	$	98,900
Receivables	2,125		2,046
Other	98		98
Total current assets	117,364		101,044
Investment in subsidiaries	2,379,680		2,294,464
Other Assets:
Deferred income taxes	45,864		17,593
Other	429		277
Total other assets	46,293		17,870
Total assets	$	2,543,337	$	2,413,378
Liabilities and Shareholders’ Equity
Current Liabilities:
Taxes accrued	$	5,622	$	8,354
Other	996		899
Total current liabilities	6,618		9,253
Other Liabilities:
Intercompany notes payable	71,285		32,929
Other	806		836
Total other liabilities	72,091		33,765
IDACORP, Inc. Shareholders’ Equity	2,464,628		2,370,360
Total Liabilities and Shareholders' Equity	$	2,543,337	$	2,413,378
The accompanying note is an integral part of these statements.

December 31,
2018 2017
Assets (thousands of dollars)
Current Assets:

Cash and cash equivalents $ 98,900
$ 29,617
Receivables 2,046
52,359
Other 98
98
Total current assets 101,044
82,074
Investment in subsidiaries 2,294,464
2,189,017
Other Assets:
Deferred income taxes 17,593
34,040
Other 277
374
Total other assets 17,870
34,414
Total assets $ 2,413,378
$ 2,305,505
Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable $ —
$ 17
Taxes accrued 8,354
17,423
Other 899
626
Total current liabilities 9,253
18,066
Other Liabilities:
Intercompany notes payable 32,929
35,140
Other 836
914
Total other liabilities 33,765
36,054
IDACORP, Inc. Shareholders’ Equity 2,370,360
2,251,385
Total Liabilities and Shareholders' Equity $ 2,413,378
$ 2,305,505
The accompanying note is an integral part of these statements.

NOTE TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Pursuant to rules and regulations of the U.S. Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the ~~2018~~2019 Form 10-K, Part II, Item 8.

Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $133 million, $124 million, and $116 million in 2019, 2018, and ~~$108 million in 2018,~~ 2017, ~~and 2016,~~ respectively.

Table of Contents

IDACORP, INC. AND IDAHO POWER COMPANY

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31,~~2018~~2019, ~~2017,~~2018, and ~~2016~~2017

Additions
Charged
Balance at Charged (Credited) Balance at
Beginning to to Other End
Classification of Year Income Accounts
Deductions⁽¹⁾
of Year
(thousands of dollars)
2018:
Reserves deducted from applicable assets:
Reserve for uncollectible accounts $ 2,193
$ 3,363
$ 392
$ 3,959
$ 1,989
Reserve for uncollectible notes 402
—
—
—
402
Other Reserves:
Injuries and damages 1,469
855
—
447
1,877
2017:

Reserves deducted from applicable assets:

Reserve for uncollectible accounts $ 1,132
$ 5,753
$ 324
$ 5,016
$ 2,193
Reserve for uncollectible notes 402
—
—
—
402
Other Reserves:

Injuries and damages 1,792
687
—
1,010
1,469
2016:

Reserves deducted from applicable assets:

Reserve for uncollectible accounts $ 1,355
$ 3,917
$ 263
$ 4,403
$ 1,132
Reserve for uncollectible notes 552
—
—
150
402
Other Reserves:

Injuries and damages 1,874
848
—
930
1,792



			Additions
					Charged
	Balance at		Charged		(Credited)				Balance at
	Beginning		to		to Other				End
Classification	of Year		Income		Accounts		Deductions⁽¹⁾		of Year
	(thousands of dollars)
2019:
Reserve for uncollectible accounts	$	1,989	$	2,381	$	227	$	2,853	$	1,744
Injuries and damages	1,877		390		—		519		1,748
2018:
Reserve for uncollectible accounts	$	2,193	$	3,363	$	392	$	3,959	$	1,989
Injuries and damages	1,469		855		—		447		1,877
2017:
Reserve for uncollectible accounts	$	1,132	$	5,753	$	324	$	5,016	$	2,193
Injuries and damages	1,792		687		—		1,010		1,469

(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, and notes reserves, includes reversals of amounts previously reserved.

~~Table of Contents~~

~~IDAHO POWER COMPANY~~

~~SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS~~

~~Years Ended December 31, 2018, 2017, and 2016~~

Additions
Charged
Balance at Charged (Credited) Balance at
Beginning to to Other End
Classification of Year Income Accounts
Deductions⁽¹⁾
of Year
(thousands of dollars)
2018:

Reserves deducted from applicable assets:
Reserve for uncollectible accounts $ 2,193
$ 3,363
$ 392
$ 3,959
$ 1,989
Other Reserves:
Injuries and damages 1,469
855
—
447
1,877
2017:

Reserves deducted from applicable assets:

Reserve for uncollectible accounts $ 1,132
$ 5,753
$ 324
$ 5,016
$ 2,193
Other Reserves:

Injuries and damages 1,792
687
—
1,010
1,469
2016:

Reserves deducted from applicable assets:

Reserve for uncollectible accounts $ 1,355
$ 3,917
$ 263
$ 4,403
$ 1,132
Other Reserves:

Injuries and damages 1,874
848
—
930
1,792

~~(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, includes reversals of amounts previously reserved.~~

Table of Contents

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



February ~~21, 2019~~20, 2020		IDACORP, INC.
Date
	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

~~Table of Contents~~

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ ~~Robert A. Tinstman~~Richard J. Dahl	Chairman of the Board	February ~~21, 2019~~20, 2020
~~Robert A. Tinstman~~Richard J. Dahl

/s/ Darrel T. Anderson	(Principal Executive Officer)	February ~~21, 2019~~20, 2020
Darrel T. Anderson
President and Chief Executive Officer and Director

/s/ Steven R. Keen	(Principal Financial Officer)	February ~~21, 2019~~20, 2020
Steven R. Keen
Senior Vice President, Chief Financial
Officer, and Treasurer

/s/ Kenneth W. Petersen	(Principal Accounting Officer)	February ~~21, 2019~~20, 2020
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer

/s/ Thomas Carlile	Director	February ~~21, 2019~~20, 2020
Thomas Carlile

~~/s/ Richard J. Dahl~~	~~Director~~	~~February 21, 2019~~
~~Richard J. Dahl~~

/s/ Annette G. Elg	Director	February ~~21, 2019~~20, 2020
Annette G. Elg

/s/ Lisa A. Grow	Director	February 20, 2020
Lisa A. Grow

/s/ Ronald W. Jibson	Director	February ~~21, 2019~~20, 2020
Ronald W. Jibson

/s/ Judith A. Johansen	Director	February ~~21, 2019~~20, 2020
Judith A. Johansen

/s/ Dennis L. Johnson	Director	February ~~21, 2019~~20, 2020
Dennis L. Johnson

/s/ Christine King	Director	February ~~21, 2019~~20, 2020
Christine King

/s/ Richard J. Navarro	Director	February ~~21, 2019~~20, 2020
Richard J. Navarro

Table of Contents

SIGNATURES



February ~~21, 2019~~20, 2020		Idaho Power Company
Date
	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			~~President and~~ Chief Executive Officer



Signature	Title	Date

/s/ ~~Robert A. Tinstman~~Richard J. Dahl	Chairman of the Board	February ~~21, 2019~~20, 2020
~~Robert A. Tinstman~~Richard J. Dahl

/s/ Darrel T. Anderson	(Principal Executive Officer)	February ~~21, 2019~~20, 2020
Darrel T. Anderson
~~President and~~ Chief Executive Officer and Director

/s/ Steven R. Keen	(Principal Financial Officer)	February ~~21, 2019~~20, 2020
Steven R. Keen
Senior Vice President, Chief Financial
Officer, and Treasurer

/s/ Kenneth W. Petersen	(Principal Accounting Officer)	February ~~21, 2019~~20, 2020
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer

/s/ Thomas Carlile	Director	February ~~21, 2019~~20, 2020
Thomas Carlile

~~/s/ Richard J. Dahl~~	~~Director~~	~~February 21, 2019~~
~~Richard J. Dahl~~

/s/ Annette G. Elg	Director	February ~~21, 2019~~20, 2020
Annette G. Elg

/s/ Lisa A. Grow	Director	February 20, 2020
Lisa A. Grow

/s/ Ronald W. Jibson	Director	February ~~21, 2019~~20, 2020
Ronald W. Jibson

/s/ Judith A. Johansen	Director	February ~~21, 2019~~20, 2020
Judith A. Johansen

/s/ Dennis L. Johnson	Director	February ~~21, 2019~~20, 2020
Dennis L. Johnson

/s/ Christine King	Director	February ~~21, 2019~~20, 2020
Christine King

/s/ Richard J. Navarro	Director	February ~~21, 2019~~20, 2020
Richard J. Navarro

~~152~~149



	2019		2020		2021-2023
Expected capital expenditures (excluding AFUDC)	$	280-290	$	285-300	$	875-925



	2018			2017
Net (loss) gain	$	(330	)	$	2,777
Prior service cost	222			269
Subtotal	(108		)	3,046
Less amount recognized in regulatory assets	108			(3,046		)
Net amount recognized in accumulated other comprehensive income	$	—		$	—



	One-Percentage-Point
	Increase		Decrease
Effect on total of cost components	$	339	$	(247	)
Effect on accumulated postretirement benefit obligation	3,222		(2,483		)



Asset Class	Target Allocation		Actual Allocation December 31, 2018
Debt securities	24	%	26	%
Equity securities	56	%	56	%
Real estate	7	%	6	%
Other plan assets	13	%	12	%
Total	100	%	100	%