Table of contentsContents


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
X☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 THE SECURITIES EXCHANGE ACT OF 1934
  
 
For the fiscal year ended December 31, 2016
2019
 
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from ................... to .................................................................
idcrp012cposa12.jpgipc012uposa05.jpg
 Exact name of registrants as specified inIRS Employer
Commission
File Number
their charters, address of principal executive
IRS Employer
File Number
offices, zip code and telephone number
Identification Number
1-14465IDACORP, Inc.82-0505802
1-3198Idaho Power Company82-0130980
 1221 W. Idaho Street 
 Boise,ID83702-5627 
 (208)388-2200 
 
State of incorporation:Idaho
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each classTrading 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 valueIDANew 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 CompanyYes(  )☐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 CompanyYes(  )☐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  (  )
Table of contentsContents


Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted 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 CompanyYes(X)☒No( )☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or 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(  )
Idaho Power Company:
Large accelerated filer(  )Accelerated filer(  )Non-accelerated filer(X)Smaller reporting company(  )
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 ☐

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. __

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 CompanyYes(  )☐No(X)☒
 
Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2016)2019):
IDACORP, Inc.: $4,052,238,968
 Idaho Power Company: None
IDACORP, Inc.:$5,017,481,695
 Idaho Power Company:None
Number of shares of common stock outstanding as of February 17, 2017:14, 2020:
IDACORP, Inc.:50,396,77350,409,901
Idaho Power Company:39,150,812, all held by IDACORP, Inc.


Documents Incorporated by Reference:
 
Part III, Items 10 - 14Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the 20172020 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.



Table of contentsContents


TABLE OF CONTENTS
   
  Page
   
Commonly Used Terms
4
Cautionary Note Regarding Forward-Looking Statements
5
   
Part I  
   
Item 1Business
7
 Information about our Executive Officers of the Registrants
18
Item 1ARisk Factors
1920
Item 1BUnresolved Staff Comments
2832
Item 2Properties
2832
Item 3Legal Proceedings
3034
Item 4Mine Safety Disclosures
3034
   
Part II  
   
Item 5Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
3035
Item 6Selected Financial Data
3237
Item 7Management's Discussion and Analysis of Financial Condition and Results of Operations
3338
Item 7AQuantitative and Qualitative Disclosures About Market Risk
7173
Item 8Financial Statements and Supplementary Data
7375
Item 9Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
128132
Item 9AControls and Procedures
128132
Item 9BOther Information
132136
   
Part III  
   
Item 10Directors, Executive Officers and Corporate Governance*
132136
Item 11Executive Compensation*
132136
Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*
132136
Item 13Certain Relationships and Related Transactions, and Director Independence*
133137
Item 14Principal Accountant Fees and Services*
133137
   
Part IV  
   
Item 15Exhibits and Financial Statement Schedules
134138
Item 16Form 10-K Summary
148
   
Signatures
145148
   
* 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 20172020 annual meeting of shareholders.

Table of contentsContents



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, 2019kWh-Kilowatt-hour
ADITC-Accumulated Deferred Investment Tax Credits IPUCLTICP-Idaho Public Utilities CommissionIDACORP 2000 Long-Term Incentive and Compensation Plan
AFUDC-Allowance for Funds Used During Construction IRP-Integrated Resource Plan
APCU-Annual Power Cost UpdateIRS-U.S. Internal Revenue Service
BCC-Bridger Coal Company, a joint venture of IERCokW-Kilowatt
BLM-U.S. Bureau of Land ManagementMATS-Mercury and Air Toxics Standards
CAAAOCI-Clean Air ActAccumulated Other Comprehensive Income MD&A-Management’s Discussion and Analysis of Financial Condition and Results of Operations
CO2
APCU		-Carbon DioxideAnnual Power Cost UpdateMMBtu-Million British Thermal Units
ASU-Accounting Standards Update MW-Megawatt
CSPPBCC-Cogeneration and Small Power ProductionBridger Coal Company, a joint venture of IERCo MWh-Megawatt-hour
CWABLM-Clean Water ActU.S. Bureau of Land Management NAAQS-National Ambient Air Quality Standards
EISCAA-Clean Air ActNEPA-National Environmental Impact StatementPolicy Act
CO2
-Carbon Dioxide NMFS-National Marine Fisheries Service
CWA-Clean Water ActNOAA Fisheries-National Oceanic and Atmospheric Administration's National Marine Fisheries Service
EIS-Environmental Impact Statement
NO2
-Nitrogen Dioxide
EPA-U.S. Environmental Protection Agency NOx
NOx
-Nitrogen Oxide
EPSESA-Earnings Per ShareEndangered Species Act O&M-Operations and Maintenance
ESAFASB-Endangered Species ActFinancial 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-IdahoIdaho-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 GasPURPA-Public Utility Regulatory Policies Act of 1978
GHGHCC-Greenhouse GasHells Canyon Complex REC-Renewable Energy Certificate
HCCIDACORP-Hells Canyon ComplexIDACORP, Inc., an Idaho CorporationRH 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 equitySEC-U.S. Securities and Exchange Commission
Ida-West-Ida-West Energy Company, a subsidiary of IDACORP, Inc. SECSCR-U.S. Securities and Exchange Commission
Idaho ROE-Idaho-jurisdiction return on year-end equitySMSP-Security Plan for Senior Management EmployeesSelective catalytic reduction equipment
IERCo-Idaho Energy Resources Co., a subsidiary of Idaho Power Company SO2SMSP-Sulfur Dioxide
IESCo-IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.USFWS-U.S. Fish and Wildlife ServiceSecurity Plan for Senior Management Employees
IFS-IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. 
SO2
-Sulfur Dioxide
IPUC-Idaho Public Utilities CommissionUSFWS-U.S. Fish and Wildlife Service
IRP-Integrated Resource PlanWestern EIM-Energy imbalance market implemented in the western United States
IRS-U.S. Internal Revenue ServiceWDEQ-Wyoming Department of Environmental Quality
Jim Bridger plantJim Bridger generating plantWPSC-Wyoming Public Service Commission
kW-Kilowatt   
Table of contentsContents


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 and other regulators that impact Idaho Power's ability to recover costs and earn a return;return on investment;
changes to or the expense and risks associated with capital expenditures for infrastructure, and the timing and availabilityelimination of Idaho Power's cost recovery for such expenditures;mechanisms;
changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, and 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, the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and the collection of receivables;
unseasonableabnormal or severe weather conditions, including conditions and events associated with climate change, wildfires, drought, and other natural phenomena and natural disasters, which affect customer demand, hydroelectricsales, 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 reduce loadsmay affect Idaho Power's sale or reducedelivery of electric power or introduce operational or cyber-security vulnerability to the needpower 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 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 saletransmission systems or of electric power;any interconnected transmission systems may constrain resources or cause Idaho Power to incur repair costs and purchase replacement power at increased costs;
administrationaccidents, 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 reliability, security,life, or result in the imposition of civil, criminal, and other requirementsregulatory fines and penalties for system infrastructure requiredwhich 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;
Table of Contents

failure to comply with state and federal laws, regulations, and orders, including new interpretations and enforcement initiatives by the Federal Energy Regulatory Commissionregulatory and other regulatory authorities,oversight bodies, which couldmay result in penalties and fines and increase costs;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 conditionsthe inability to obtain or cost of obtaining and over-appropriation of surfacecomplying 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 amountcost 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 inrecover those costs or the eventcosts of unanticipated power demands, lack of physical availability, transportation constraints,resulting operational changes through insurance or a credit downgrade;
accidents, fires (either atrates, or caused by Idaho Power facilities), 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;from third parties;
the increasedimpacts of economic conditions, including inflation, interest rates, supply costs, and operational challenges associated with purchasing and integrating intermittent renewable energy sources intopopulation growth or decline in Idaho Power's resource portfolio;
disruptions or outagesservice area, changes in customer demand for electricity, revenue from sales of Idaho Power's generation or transmission systems orexcess power, credit quality of any interconnected transmission system may cause Idaho Power to incur repair costscounterparties and purchase replacement power at increased costs;suppliers, and the collection of 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;
Table of contents

reductions in credit ratings, which could adversely impact access to capitaldebt and equity markets, increase borrowing costs, of borrowing, and would 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;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;
changesIdaho Power's concentration in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits,one industry and one region and the tax rates payable by IDACORP shareholders on common stock dividends;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;
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;
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 operational changes through insurance or rates, or from third parties;
the failure of information systems or the failure to secure data, failure to comply with privacy laws, security breaches, or the direct or indirect effect on the companies' business or operations resulting from cyber attacks, terrorist incidents or the threat of terrorist incidents, 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.


Table of contentsContents


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 and are IDACORP’s only reportable business segment.  Segment financial information is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report.operations. As of December 31, 2016,2019, IDACORP had 2,0081,985 full-time employees, 1,9991,976 of whom were employed by Idaho Power, and 128 part-time employees, 106 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;investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectrichydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co. (IESCo), the successor to IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003..


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 thisIDACORP's and Idaho Power's Annual Report on Form 10-K.  Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from10-K for the SEC’s website, www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.year ended December 31, 2019 (2019 Annual Report).
 
UTILITY OPERATIONS


Background
 
Idaho Power provided electric utility service to approximately 535,000 general business572,000 retail customers in southern Idaho and eastern Oregon as of December 31, 20162019. Over 444,000Approximately 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 7172 cities in Idaho and 97 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 one1.3 million.


Table of contentsContents


serviceterritorymap2015a04.jpg
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 general businessretail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Wyoming Public Service Commission of Wyoming(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, hydroelectrichydropower project relicensing, and system reliability, among other items.


Regulatory Accounting


Idaho Power is subject tomeets 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 is probable that theyexpects 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
Table of Contents

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 the amounts will be recovered from or returned to customers in future rates.

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. Idaho Power's three-partIDACORP's board of directors regularly reviews IDACORP's long-term strategy, can be summarizedwhich as follows:
Responsible Planning:  Idaho Power’s planning process is intended to ensure adequate generation, transmission, and distribution resources to meet anticipated population growth and increasing electricity demand.  This planning process integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the communities Idaho Power serves.
Table of contents

Responsible Development and Protection of Resources:  Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources upon which Idaho Powerdate of this report is focused on the following areas and the communities it serves depend.  Additionally, the strategy considers workforce planning and employee development and retention related to these strategic elements.initiatives:
Responsible Energy Use:  Idaho Power's business strategy includes energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standards legislation.  The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions, as well as operating Idaho Power's system in a manner that extracts additional value through changes in fuel mix and generation.
CornerstonesInitiatives
Grow Financial Strength
- 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
- Evaluate and Control Expenditures and Continue Efficient Operations
- Evaluate and Deploy Transformative Technology Solutions
- Continue Progress on Key Transmission Projects
- Continue Progress on Hydropower Relicensing Projects
- Continue Development of Regional Markets
Enhance Idaho Power's Brand
- Enhance Idaho Power's Customers' Experience and Interactions
- Communicate Progress Toward Environmental and Community Goals
- Share Idaho Power's Story
Keep Employees Safe and Engaged
- Continue Idaho Power's Strong Focus on Safety
- Facilitate Progress on Employee Engagement
- Evolve Workforce Development Strategy and Programs

Idaho Power’s business strategyIn executing the focus areas above, IDACORP seeks to balance the interests of owners,shareholders, Idaho Power customers, employees, and other stakeholders while maintaining the company’sstakeholders. Idaho Power is committed to working for strong, sustainable financial stabilityresults and flexibility.  Idaho Power's three-part business strategy includes three core focuses—improvingstrong credit ratings by continuing to provide safe, fair-priced, reliable service to its core business, growing revenues, and enhancing the brand and positioning the company for the future. IDACORP continues to focus on its core business and its goalcustomers from a diversified source of generating returns for its shareholders and long-term shareholder value.generation 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 the electric power and services Idaho Power sells 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 continuallyto 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, are 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
Table of Contents

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.


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 recordeddeferred or accrued under specific authorization from the IPUC or OPUC but deferred for recovery or refund.OPUC. Deferred amounts are generally collected from orand 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 rider.riders. 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 for certain Idaho customer classes and linking it instead to a set amount per customer. Separately,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 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. Increases in FCA recovery 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 an energy efficiency riderriders on customer bills.


Wholesale Markets: Idaho Power’s OATT transmission rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1.  The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and network reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation.  These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of transmission and reliability standards.
Table of contents

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 hydroelectrichydropower generation facilities are operated to optimize the water that is available by choosing when to run hydroelectrichydropower 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 off-systemwholesale energy sales revenues 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 off-system sales revenue.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 induring the winter.winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderatemild temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. The table that follows presentsAlternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power’s revenuesPower sales to existing customers. Also, development of new technologies and sales volumesservices to help energy consumers manage energy in new ways could continue to alter demand for the last three years, classified by customer type.Idaho Power's electric energy. Approximately 95 percent of Idaho Power’s general businessretail 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.”

Table of Contents

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,
  2016 2015 2014
General business revenues (thousands of dollars)  
  
  
Residential $514,954
 $512,068
 $500,195
Commercial 302,650
 306,178
 299,462
Industrial 182,590
 182,254
 182,675
Irrigation 156,505
 164,403
 158,654
Provision for rate refund for sharing mechanism —
 (3,159) (7,999)
Deferred revenue related to Hells Canyon Complex relicensing AFUDC (10,706) (10,706) (10,706)
Total general business revenues 1,145,993
 1,151,038
 1,122,281
Off-system sales 25,205
 30,887
 77,165
Other 88,155
 85,580
 79,205
Total revenues $1,259,353
 $1,267,505
 $1,278,651
Energy sales (thousands of MWh)  
  
  
Residential 5,004
 4,977
 4,965
Commercial 3,999
 4,045
 3,944
Industrial 3,243
 3,196
 3,217
Irrigation 1,950
 2,047
 1,966
Total general business 14,196
 14,265
 14,092
Off-system sales 1,186
 1,254
 2,220
Total 15,382
 15,519
 16,312
  Year Ended December 31,
  2019 2018 2017
Retail revenues (thousands of dollars):  
  
  
 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 181,372
 190,130
 195,124
Irrigation 135,850
 158,001
 150,030
Provision for sharing —
 (5,025) —
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (8,780) (10,706)
Total retail revenues 1,130,611
 1,175,152
 1,205,976
Wholesale energy sales 71,198
 52,845
 24,790
Transmission wheeling-related revenues 53,828
 59,094
 43,970
Energy efficiency program revenues 40,128
 35,703
 39,241
Other revenues 47,175
 43,788
 30,916
Total electric utility operating revenues $1,342,940
 $1,366,582
 $1,344,893
Energy sales (thousands of Megawatt-hour (MWh)):  
  
  
Residential 5,273
 5,135
 5,355
Commercial 4,092
 4,105
 4,099
Industrial 3,412
 3,371
 3,346
Irrigation 1,760
 1,976
 1,771
Total retail energy sales 14,537
 14,587
 14,571
Wholesale energy sales 2,171
 2,246
 1,934
Bundled energy sales 680
 617
 202
Total energy 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)
The IPUC 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'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. However, alternative methods of generation, including customer-owned solar and other forms of distributed generation, compete with Idaho Power for sales to existing customers.  Also, development of new technologies and services to help energy consumers manage energy in new ways could alter demand for Idaho Power's electric energy. Idaho Power also competes with fuel distribution companies, including natural gas providers, in serving the energy needs of customers for space heating, water heating, and appliances.
Table of contents



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. Separately, the Shoshone-Bannock Tribes, located in southeastern Idaho, has considered the adoption of a utility code applicable to electric utilities operating within the Shoshone-Bannock Tribal Reservation (Reservation). The tribal utility code, if adopted, could ultimately lead to Idaho Power's cessation of its historical provision of service to the Reservation and could result in either no or a limited electric service relationship with the Reservation, or could result solely in Idaho Power's sale of power to the Reservation pursuant to a power purchase agreement. Idaho Power estimates that the average load for the Reservation over the prior five years is approximately 14 Megawatts (MW).


Table of Contents

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 hydroelectrichydropower 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 hydroelectrichydropower generation conditions increase production at Idaho Power’s hydroelectrichydropower 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 potentially adverse financial statement 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. TheIdaho Power reached its highest all-time system peak demand was 3,407 MW, setof 3,422 megawatts (MW) on July 2, 2013, at which time7, 2017. Idaho Power had deployed 30 MW of demand response programs to mitigate the load demand. On January 6, 2017, Idaho Power tied itsPower's highest all-time winter peak demand of 2,527 MW which was originally setlast achieved on December 10, 2009.  Idaho Power's peak demand during 2016 was 3,299 MW.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.
 MWh Percent of Total Generation Power Supply Percent of Total Generation
 2016 2015 2014 2016 2015 2014 2019 2018 2017 2019 2018 2017
 (thousands of MWh)    (thousands of MWh)   
Hydroelectric plants 6,408
 5,910
 6,170
 53% 47% 47%
Hydropower plants 8,294
 8,682
 8,900
 62% 65% 65%
Coal-fired plants 4,045
 4,676
 5,851
 33% 37% 44% 3,012
 3,274
 3,284
 22% 24% 24%
Natural gas-fired plants 1,722
 2,076
 1,175
 14% 16% 9% 2,114
 1,408
 1,504
 16% 11% 11%
Total system generation 12,175
 12,662
 13,196
 100% 100% 100% 13,420
 13,364
 13,688
 100% 100% 100%
  
  
  
  
  
  
  
  
  
  
  
  
Purchased power - cogeneration and small power production 2,314
 2,008
 2,286
  
  
  
 2,983
 3,045
 2,800
  
  
  
Purchased power - other 2,023
 1,784
 1,867
  
  
  
 2,217
 2,386
 1,442
  
  
  
Total purchased power 4,337
 3,792
 4,153
  
  
  
 5,200
 5,431
 4,242
  
  
  
Total power supply 16,512
 16,454
 17,349
  
  
  
 18,620
 18,795
 17,930
  
  
  
 
Table of contents

HydroelectricHydropower Generation: Idaho Power operates 17 hydroelectrichydropower projects located on the Snake River and its tributaries. Together, these hydroelectrichydropower facilities provide a total nameplate capacity of 1,7091,796 MW and annual generation of approximately 8.58.7 million Megawatt-hours (MWh)MWh under median water conditions. The amount of water available for hydroelectric powerhydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydroelectrichydropower 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 hydroelectrichydropower 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 hydropower generation, respectively. In 2017, above normal winter and spring precipitation resulted in 8.9 million MWh of hydropower generation. During low water years, when stream flows into Idaho Power’s hydroelectrichydropower projects are reduced, Idaho Power’s hydroelectrichydropower generation is reduced. The result isreduced, resulting in a greater reliance on other generation resources and wholesale power purchases. 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. In 2015, below-normal snow accumulation resulted in a lower than median hydro production of 5.9 million MWh. The Northwest River Forecast Center of the National Oceanic Atmospheric Administration reported that the 2016 April through July inflow volume into Brownlee Reservoir (the uppermost reservoir of Idaho Power's Hells Canyon Complex) was only 73 percent of normal. By comparison, the 2015 April through July Brownlee Reservoir inflow was 46 percent of normal. For 2017,2020, Idaho Power estimates annual generation from its hydroelectrichydropower facilities towill be between 7.06.5 million MWh and 9.08.5 million MWh.
 
Idaho Power obtains licenses for its hydroelectrichydropower projects from the FERC, similar to other utilities that operate nonfederal hydroelectrichydropower 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 Hells Canyon Complex,HCC, its largest hydroelectric hydropower
Table of Contents

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 HydroelectricHydropower Projects.”


Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydroelectrichydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectrichydropower 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 20172021 from the Black Butte Coal Company’s Black Butte mine located near the Jim Bridger plant. This contract supplements the BCC deliveries and provides another coal supply to operatefuel 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. Idaho Power's existing coal inventory at the North Valmy plant is expectedPower expects to meet Idaho Power's projected2020 fuel requirements through existing inventory and coal requirements at the plant through at least 2017. Idaho Powercontracts and expects to be able to obtainmeet future coal requirements through new or existing coal supply contracts. In October and November 2016, Idaho Power filed applications withhas an established process approved by the IPUC and OPUC respectively, requesting authorizationfor recovery of non-fuel costs related to accelerate depreciation forIdaho Power’s plan to end its participation in coal-fired operations at the North Valmy powerplant. Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019, as planned, and plans to allow the plant to be fully depreciatedend its participation in unit 2 by December 31, 2025. For additional information on the filings, see the “Regulatory Ma
Table of contents

tters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A).


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 2017. 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 planIdaho 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.
 
As of December 31, 2016,2019, Idaho Power had approximately 6.512.6 million MMBtu of natural gas was financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through June 2018.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.
 
Table of Contents

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 20162019 and 2015,2018, Idaho Power purchased 2.01.6 million MWh and 1.8 million MWh of power through wholesale market purchases at an average cost of $42.04$21.95 per MWh and $49.57$28.82 per MWh, respectively. During 2016both 2019 and 2015,2018, Idaho Power sold 1.2 million MWh and 1.32.2 million MWh of power in wholesale market sales, with an average price of $21.25$32.80 per MWh and $24.63$23.53 per MWh, respectively.


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


Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from itsthe Elkhorn Valley wind project located in eastern Oregon. The contract term is throughends 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 is throughends in 2037.
Clatskanie People's Utility - for the exchange of up to 18 MW of energygeneration from the Arrowrock hydroelectrichydropower 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 continues throughends 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 (nameplate generation)(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, through 2033.as of the date of this report, pending approval by the OPUC.
 
PURPA Power Purchase ContractsQualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA projectsqualifying facilities as mandated by federal law. As of December 31, 2016,2019, Idaho Power had contracts with on-line PURPA-related projectsPURPA qualifying facilities with a total of 9451,136 MW of nameplate generation capacity, with an additional 17811 MW nameplate capacity of projects projected to be on-line in 2017 and an additional 9 MW expected to be added in 2019.by 2022. The power purchase contractsenergy sales agreements for these projectsqualifying facilities have original contract terms
Table of contents

ranging from one to 35 years. The expense and volume of purchases from PURPA project power purchasesqualifying facilities during the last three years is included in the following table:
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
PURPA contract expense (in thousands) $153,665
 $131,340
 $144,617
PURPA contracts expense (in thousands) $187,344
 $189,722
 $169,788
MWh purchased under PURPA contracts (in thousands) 2,314
 2,008
 2,286
 2,983
 3,045
 2,800
Average cost per MWh from PURPA contracts $66.41
 $65.41
 $63.26
 $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"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 contracts.energy sales agreements under each state's jurisdiction. For PURPA power purchaseenergy 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 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 PCAIdaho-jurisdiction power cost adjustment (PCA) mechanism, and the OPUC jurisdictional portion is recovered through base rates and an Oregon power cost recoveryadjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.
The IPUC issued an order in August 2015 that revised the standard PURPA power purchase contract term for new contracts to 2 years from the previously required 20-year term.
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
Table of Contents

facilities that exceed these size limitations, Idaho Power is required to negotiate an applicable price (premisedusing 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 (premisedusing an avoided cost methodology based on avoided costs) for all other qualifying facilities based upon OPUC regulations.


Idaho Power, as well as other affected electric utilities, are engaged in proceedings at the OPUC relating to PURPA contracts. The OPUC issued orders in 2016 pertaining to contract term, project eligibility for standard rates, and standard avoided cost calculations. Other ongoing OPUC proceedings relate to, among other issues, the prices paid for energy purchased from PURPA projects and solar integration charges. Refer to Part II - Item 7 - MD&A - "Regulatory Matters - Renewable and Other Energy Contracts" for a summary of those proceedings.

Anticipated Participation in Western Energy Imbalance Market: UtilitiesIn April 2018, Idaho Power began participating in an energy imbalance market in the western United States outside(Western EIM) under which the California Independent System Operator (California ISO) have traditionally relied upon a combination of automated and manual dispatch within the hourparticipating parties enabled their systems to balance generation and load to maintain reliable supply. These utilities have limited capability to transact within the hour outside their balancing area.  In contrast, energy imbalance markets useinteract for automated intra-hour economic dispatch of generation from committed resources to serve loads.  The California ISO and PacifiCorp implemented a new energy imbalance market in 2014 (Western EIM) under which the parties enabled their systems to interact for dispatch purposes. 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. Following an evaluation of the potential power supply cost savings and other advantages, system upgrade requirements, and estimated capital and ongoing operating costs, in April 2016, Idaho Power executed an agreement under which it intends to, subject to regulatory approval and other conditions, participate in the Western EIM. Idaho Power anticipates that it will commence participation in the Western EIM in the spring of 2018. In August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its participation in the Western EIM. In January 2017, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment for costs associated with joining the Western EIM.  Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of t
Table of contents

he costs and the deferral balance or the end of 2018. Recovery of deferred costs will be addressed in a future IPUC proceeding.
 
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 WECC,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 lineproject is a proposed 300-mile, 500-kVhigh-voltage transmission projectline between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West lineproject is a proposed 1,000-mile, 500-kVhigh-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 2015.  Idaho Power is presently preparing the 2017 IRP,2019, which Idaho Power anticipates filingwas amended in June 2017.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-sidetransmission resource options, and identifies potential near-term and long-term actions. The four primary goals of the IRP are to: 

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, resourcesdemand-side, and demand-side measures;transmission resources; and
involve the public in the planning process in a meaningful way.
 
Table of Contents

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.


The load forecast assumptions Idaho Power expects to useused in the 2017its 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
Table of contents

development of resources, such as new generation plants or transmission infrastructure, to serve those loads.
 Forecast for 2016-2021 Period 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 1.3%1.4% 1.0%1.2%
2017 IRP 1.3%1.4% 1.0%1.4% 1.1%1.6% 0.9%1.4%
2015 IRP 1.1%1.6% 1.2%1.5% 1.5%1.8% 1.2%1.5%
2013 IRP 1.2%1.6% 1.1%1.4%


As noted above, on January 31, 2020, Idaho Power amended the originally filed 2019 IRP with additional information and modeling results. The 2015updated 2019 IRP identified a preferred resource portfolio and action plan, which includedincludes the completion of the Boardman-to-Hemingway 500-kV transmission line andin 2026, the potential early retirement ofend to Idaho Power's participation in coal-fired operations at the North Valmy power plant both in 2025, with no other new resource needs prior to 2025. The near-term action plan also included commencement of an economic evaluation of environmental control retrofits for units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger power plant.plant by 2030, including the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the addition of a 120-MW solar resource in 2022. However, as noted in the 20152019 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third partythird-party development of renewable resources, implementation of the U.S. Environmental Protection Agency's (EPA) rules under Section 111(d) of the Clean Air Act (CAA),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, couldas 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 2227 programs. These energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer.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 orand 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
membershipparticipation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.


In 2016,2019, Idaho Power’s energy efficiency programs reduced energy usage by approximately 142,000 MWh.205,000 MWh compared with 173,000 in 2018. For 2016,2019, Idaho Power had a demand response available capacity of approximately 392397 MW. In 20162019, 2018, and 2015,2017, Idaho Power expended approximately $43$49 million, $44 million, and $39$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 riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.


Table of Contents

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 the companies' ESG and sustainability programs. IDACORP and Idaho Power publicly release annual sustainability reports and 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. IDACORP’s and Idaho Power’s ESG initiatives include:

establishing responsible management goals to related to the companies’ impact on 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 C02 emissions 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 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 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 in December 2019, as planned, and plans to end 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 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.

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
Table of Contents

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 hydroelectrichydropower generating plants are subject to a broad range of environmental 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.


Table of contents

Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, especiallyparticularly given the additionalvolume of existing and proposed regulations proposed and issued 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 allowance for funds used during construction (AFUDC)AFUDC (in millions of dollars):
 2017 2018 - 2019 2020 2021-2022
Capital expenditures:        
License compliance and relicensing efforts at hydroelectric facilities $21
 $27
License compliance and relicensing efforts at hydropower facilities $30
 $46
Investments in equipment and facilities at thermal plants 5
 15
 8
 15
Total capital expenditures $26
 $42
 $38
 $61
Operating expenses:        
Operating costs for environmental facilities - hydroelectric $20
 $41
Operating costs for environmental facilities - hydropower $21
 $41
Operating costs for environmental facilities - thermal 12
 32
 11
 22
Total operations and maintenance $32
 $73
 $32
 $63
 
Idaho Power anticipates that finalization, and 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 substantially increasedsubstantial changes in operating and compliance costs, in addition to the amounts set forth above, 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 those increasedincreases in costs through the ratemaking process.

Idaho Power monitors Beyond increasing costs generally, these environmental requirementslaws 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 a February 2014 order of the IPUC, 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 thatregulations could impact the company's continued reliance on the North Valmy plant as a coal-fired resource. Idaho Power filed an application with the IPUC and OPUC in October and November 2016, respectively, requesting accelerated depreciation of the North Valmy plant in connection with the potential early closure of the plant. Idaho Power is also assessing the economic desirability of potential future investments in additional selective catalytic reduction technology at the Jim Bridger coal-fired plant.

Voluntary CO2 Intensity Reduction Goal: Idaho Power is engaged in voluntary greenhouse gas emissions (GHG) intensity reduction efforts. In September 2009,affect IDACORP's and Idaho Power's boardsresults of directors approved guidelines that establishedoperations and financial condition if the costs associated with these environmental requirements and potential early plant retirements cannot be fully recovered in rates on a goal to reduce Idaho Power's resource portfolio's average carbon dioxide (CO2) emissions intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO2 emissions intensity of 1,194 lbs CO2/MWh. The combination of effective utilization of hydroelectric projects, above average stream flows in some years, reduced usage of coal-fired facilities, the purchase of renewable energy, and the addition of the Langley Gulch natural gas-fired power plant positioned Idaho Power to extend its CO2 emissions intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period. Idaho Power achieved its initial reduction goal, as well as its extended goal, through 2015. Idaho Power's average CO2 emissions intensity from company-owned resources for the 2010 through 2015 period was 21 percent below the 2005 CO2 emissions intensity level.timely basis.


In 2015, Idaho Power further extended and expanded the goal, seeking to reduce the company-owned resource portfolio average CO2 emissions intensity to 15-20 percent below 2005 levels for the 2010-2017 period.

Idaho Power's estimated historic CO2 emissions intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was as follows:
  2011 2012 2013 2014 2015
Emissions Intensity (lbs CO2/MWh)
 677 871 1,135 1,019 952

Table of contents

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. IFS is no longer actively pursuing further investment opportunities, but will continue to maintain and manage its current portfolio of investments. At December 31, 2016,2019, the unamortized amount of IFS’s portfolio was approximately $8$4 million ($175126 million in gross tax credit investments, net of $167$122 million of accumulated amortization). IFS generated tax credits of $2.9 million in 2019 and $2.6 million $3.3 million,in both 2018 and $5.2 million in 2016, 2015,2017. In 2019, 2018, and 2014, respectively.  In 2016,2017, IFS received distributions related to fully-amortized affordable housing investments that reduced IDACORP's income tax expense by $1.7 million.$3.2 million, $0.3 million, and $1.1 million, respectively.


IDA-WEST ENERGY COMPANY
 
Ida-West operates and has a 50 percent ownership interest in nine hydroelectrichydropower projects that have a total generatingnameplate capacity of 4544 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 hydroelectrichydropower projects at a cost of approximately $8$9 million in 2019 and $10 million in both 20162018 and 2015 and $9 million in 2014.2017.


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. Mr. J. LaMont Keen, a member of IDACORP's and Idaho Power's boards of directors and former President and Chief Executive Officer of IDACORP and Idaho Power, and Mr. Steven R. Keen, are brothers. There are no other 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.


Table of Contents

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, 5861
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
Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 2009 - April 2014
Executive Vice President, Administrative Services and Chief Financial Officer of Idaho Power Company, October 2009 - December 2011September 2019
Member of the Boards of Directors of IDACORP, Inc. and Idaho Power Company since September 2013
 
BRIAN R. BUCKHAM, 3841
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 - presentFebruary 2017
In-house legal counsel of IDACORP, Inc. and Idaho Power Company, April 2010 - March 2016


SARAH E. GRIFFIN, 50
Vice President of Human Resources of Idaho Power Company, October 2019 - present
Director of Human Resources of Idaho Power Company, May 2014 - October 2019
 
LISA A. GROW, 5154
President of Idaho Power Company, October 2019 - present
Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - October 2019
Senior Vice President of Operations of Idaho Power Company, January 2016 - presentMarch 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, 5659
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
Vice President - Finance and Treasurer of IDACORP, Inc., June 2010 - April 2014
Senior Vice President - Finance and Treasurer of Idaho Power Company, January 2012 - December 2013
LONNIE KRAWL, 53
Senior Vice President of Administrative Services and Chief Human Resources Officer of Idaho Power Company, April 2016 - present
Senior Vice President of Administrative Services and Chief Information Officer of Idaho Power Company, January 2016 - March 2016
Vice President and Chief Information Officer of Idaho Power Company, October 2013 - December 2015
Director of Human Resources of Idaho Power Company, July 2009 - September 2013
Table of contents


JEFFREY L. MALMEN, 4952
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, 5558
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
Operating Projects Manager of Idaho Power Company, January 2011 - September 2012


KEN W. PETERSEN, 5356
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 AccountingOperating Officer of IDACORP, Inc. and Idaho Power Company, May 2010October 2019 - December 2013
N. VERN PORTER, 57present
Vice President of Customer Operations and Business Development of Idaho Power Company, January 2016March 2017 - presentOctober 2019
Senior Vice PresidentGeneral Manager of Customer Operations, of Idaho Power Company, April 2015 - December 2015
Vice President of Idaho Power Company,Engineering and Construction, January 2014 - April 2015February 2017
Vice President of Delivery Engineering and Construction of Idaho Power Company, May 2012 - December 2013
Vice President of Delivery Engineering and Operations of Idaho Power Company, October 2009 - May 2012


Table of Contents

ITEM 1A. RISK FACTORS
 
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.

IfIDACORP'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, publicor local regulators may impose additional requirements and costs on Idaho Power and the utility commissionsindustry, or the Federal Energy Regulatory Commission authorize retailrequire Idaho Power as a utility to make adverse changes to its business models, strategies, and practices.
State or transmissionfederal regulators may not approve customer rates that under-collectprovide timely or delay the collection through customer ratessufficient recovery of the amountIdaho Power's costs or allow Idaho Power needs to cover costs and earn a reasonable rate of return, which could cause IDACORP's and Idaho Power's financial condition and results of operations mayto 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 are incurred and when Idaho Power recovers those costs are recovered in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs embeddedincluded 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 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. In responseDecisions are subject to economic,judicial appeal, which could lead to further uncertainty in regulatory proceedings.

Economic, political, legislative, public policy, andor regulatory pressures Idaho Power may be subjectlead stakeholders to rate increase moratoriums,seek rate reductions or refunds, limits on rate increases, andor lower allowed rates of return on investments.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. Denial or probable denialThe IPUC and OPUC may adopt different methods of recovery by regulatorscalculating 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 causealso limit Idaho PowerPower's ability to record an impairment of its assets.operate profitably. In a number of proceedings in recent years,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 compensationcapital 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,
Table of contents

and Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and
Table of Contents

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 off-systemwholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differencedifferences between these two amounts is deferred for future recovery from, or refund to, customers through rates. In recent years, the volatilityVolatility in power supply costs has beencontinues to be significant, in large part due to fluctuations in hydroelectrichydropower 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 energy efficiency activities by allowingactivities. 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.  GrowthChanges 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, weak economic conditions, expansion or loss of service area, changes in customer needs and expectations, adoption rates of energy efficiency measures, customer-generated power such as from rooftop 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.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 ourits 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 1,0511,039 kWh in 20092010 to 954936 kWh in 2016.2019. 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 kWhvolume-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
Table of Contents

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 and severe weather, including as a result of 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
Table of contents

and the timing and amount of precipitation, among other factors, 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.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.


Some scientists have predicted that increasing concentrations of GHG in the earth's atmosphere may produce climate changes thatClimate 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. If such effects wereevents, and impact Idaho Power’s ability to occur, Idaho Power's operations could be adversely affected and its cost of providing service could increase. Extremegenerate or import power on transmission lines from other geographic areas. These extreme weather events and their associated impacts (such as fires, high winds,could damage transmission, distribution, and snow loading) can damage generation facilities, and disrupt transmission and distribution systems, causing service interruptions and extended or mass outages, through downed transmissionincreasing costs and distribution lines, increasing supply chain costsother 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 hydroelectrichydropower plants. The effect of the failure of

Idaho Power's facilitiescustomers' energy needs vary with weather and to operate as planned under extremethe extent weather conditions is particularly burdensome during peak demand periods, such as hot summer days. Damageare 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 disruption in generation, transmission and distribution systemsinfrastructure, while decreased energy use due to weather-related factors also often increases O&M expenses. Costs incurredweather 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 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 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 repairing and replacing infrastructure or liability for personal injury, loss of life, and 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,regulators. In addition, state and federal legislation and regulations have been proposed in recent years; including in the costsState of repairOregon, to limit the severity and replacing infrastructureimpact 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 liabilitygreenhouse gas emissions as a financial or investment risk for personal injury or property damage may not be coveredelectric 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 full by insurance.this report.


New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could decreasecause decreased customer energy demand and decreased revenues. The increasing cost of energyAdvances in technology and changes in customer demand and preferences in the electric utility industry hashave 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 taxand 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.businesses, which in turn could require changes in the way
Table of Contents

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.

CapitalActs 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. 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.
Table of Contents


Changes in capital expenditures for infrastructure and the risks associated with permitting and construction of thatutility 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-kVhigh-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
Table of contents

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
Table of Contents

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.

Table of Contents

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 as a result of the 2016 U.S. presidential and congressional elections may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. The recent presidential and congressional elections in the United States could result in significant changesChanges in, and uncertainty with respect to, federal, state, and local legislation, regulation, and government policy. While it is not possible to predict whether and when any such changes will occur, theypolicy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals discussed during and after the electionrecently enacted legislation that could have a material impact on IDACORP and Idaho Power include, but are not limited to, tax reform, of the federal tax code;utility regulation, infrastructure renewal programs;programs, environmental regulation, and modifications to accounting and public company reporting requirements and environmental regulation.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 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 reform discussionsand 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 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
Table of Contents

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.A 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, certificates, and health and safety are applicable to IDACORP's and Idaho Power's operations.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. For instance, Idaho Power recently installed environmental control apparatus in two units of its co-owned Jim Bridger power plant at a cost of $100 million, excluding AFUDC. Due to uncertainties resulting from pending environmental regulation and the substantial estimated cost of installing similar controls on the remaining two units, Idaho Power is assessing whether to move forward with the remaining installations. 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 or as a result of liabilities under, 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.  

TableIn response to state and federal regulatory requirements, judicial decisions and international accords, emissions of contents
greenhouse gases including, most significantly CO2 could be restricted in the future. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that would affect Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.



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, andplant closures, or clean-up of contamination, and regulators may not grant prior approval of cost recovery. For example, in 2013, the IPUC declined to approve Idaho Power's application requesting a binding commitment to provide rate base treatment for Idaho Power's estimated share of the capital investment in environmental control upgrades at the Jim Bridger power plant, instead reserving the prudence determination (and thus ratemaking treatment) for subsequent proceedings.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.

In addition, some For further discussion of environmental regulations are currently subject to litigation and not yet final, such as the EPA’s proposed regulations to reduce CO2 emissions as describedmatters that may affect Idaho Power, see "Environmental Matters" in Part II - Item 7 - "Management's"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters"Operations" in this report. As a result of this uncertainty, strategies to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot provide any assurance regarding the potential impacts these regulations would have on Idaho Power's operations or financial condition.


Factors contributing to lower hydroelectric 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 hydroelectric facilities. During 2016, 53 percent of Idaho Power's electric power generation was from hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric 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 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 off-system 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.

Obligations imposed in connection with hydroelectrichydropower license renewals may require large capital expenditures, increase operating costs, reduce hydroelectrichydropower 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
Table of Contents

largest hydroelectrichydropower 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 hydroelectrichydropower projects, which may be reflected in hydroelectrichydropower licenses, including for the Hells Canyon Complex. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydroelectrichydropower facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectrichydropower generation available to meet Idaho Power’s generation requirements. One particularly 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.  Idaho Power also cannot predict 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 hydroelectrichydropower generation, which could negatively affect results of operations and financial condition.


Idaho Power’s use of coalPower could be subject to penalties, reputational harm, and natural gas to fuel power generation facilities exposesoperational changes if it to commodity availabilityviolates mandatory reliability and price risk,security requirements, which cancould adversely affectimpact IDACORP's and Idaho Power's results of operations and financial condition.condition. As partan 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 contracts, often with variable pricing terms. Market prices for coal and natural gas are influenced by factors impacting supply
Table of contents

and demand such as weather conditions, 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 exposedsubject 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 mayto 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 gasFERC, 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 obligationsother 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 that inhibit their ability to deliver natural gas or coal. Defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative,be subject to less favorable legislative and potentially more costly, sourcesregulatory outcomes or increased regulatory oversight. The imposition of fuel or relyany of the foregoing on other generation sources or wholesale market power purchases. Idaho Power may not be ablefor its actual or alleged failure to fully or timely recover these increased costs through rates, which may adversely affect IDACORP'scomply 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'sPower 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.

If Similarly, the assumptions underlying coal mine reclamation at Bridger Coal Companyterms of resolution could require the companies to change their operational practices 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 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,procedures, 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’salso have a negative effect on their financial positions and Idaho Power’s results of operationsoperations.

Financial and financial condition could be adversely affected.Investment Risks


Idaho Power’s generation, transmission,Financial and distribution facilities are subjectinvestment risks relate 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, 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, 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, or not being able to access lower cost sources of electric energy.

Accidents, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to claims for personal injury and property damage, interest, and attorneys' fees. Fires alleged to have been caused by Idaho Power's system could also expose Idaho Power to claims for fire suppression costs and claims related to fires based on claims of negligence, trespass or otherwise. 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 to cover Idaho Power’s ultimate liability. Idaho Power is also subject to the risk that insurers and other parties will dispute, or be unable to perform, their obligations to Idaho Power with respect to such claims, which could have an adverse effect on IDACORP's and Idaho Power's ability to meet financial conditionobligations and resultsmitigate exposure to market risks, including liquidity risks and the ability to raise capital and cost of operations.funding, risks related to credit ratings, credit risk, liquidity, interest rates, and commodity prices.


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
Table of contents

banks to make those loans and issue letters of credit is subject to specified conditions.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 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.
Table of Contents

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. Without additional state regulatory approval, as of the date of this report the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Also, 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 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, 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.

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
Table of Contents

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. Further, forecastsIdaho 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.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.

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 Further, the bankruptcy or insolvency of a bulk power transmission system,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. Idaho Power is subject to mandatory reliabilitya participant in the energy markets, including the Western EIM, and security standards issued by the North American Electric Reliability Corporationengages in direct and enforced by the FERC.indirect power purchase and sale transactions in connection with that participation. The standards areWestern EIM has collateral posting requirements based on established credit criteria, but there is no assurance the functionscollateral will be sufficient to cover obligations that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Idaho Power has receivedcounterparties may owe each other in recent years notices of violations from, and regularly self-reports reliability
Table of contents

standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council.  Potential monetaryEIM and non-monetary penalties forany such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a violation of FERC regulations may be substantial, andparticipant in some circumstances monetary penalties may be as high as $1 million per day per violation.  The imposition of penaltiesthe Western EIM to make payments when due on Idaho Power for its actual or alleged failure to comply with reliability and security requirementsobligations could have a negativeripple effect on itsvarious Idaho Power counterparties in the power, gas, and IDACORP’s results of operationsderivative markets if those counterparties experience ancillary liquidity issues, 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 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 oncould generally result in a decline in the operationability 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 lawPower’s counterparties 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. 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.perform on their obligations.  


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 commissionsIPUC 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 equity and debtinvestment 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 1112 - "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
Table of Contents

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 67 - "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
Table of contents

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 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 20172020 and in the near-term. At December 31, 2016,2019, approximately 2322 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 subjectalso hires third-party vendors to costsassist 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 andthings. 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 numberrising prices for many forms of uncertainties, and management is often unable to predictthird-party vendor services. While Idaho Power does not rely entirely on third-party vendors for many of these business functions, the outcomeunavailability of such matters; resulting liabilitiesvendors could exceed amounts currently reserved or insured against with respect to such matter. The legal costsadversely affect the quality and final resolution of matters in which IDACORP or Idaho Power are involved could have a 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.

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 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.  Somecost of Idaho Power's facilities are deemed "critical infrastructure," in that incapacity or destruction of the facilities could have a debilitatingelectric service and negatively 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 facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack (whether originating internally or externally) may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power.  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.  

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 sophisticated. Attacks on Idaho Power's infrastructure could result from acts of those organizations or other third parties as well as Idaho Power employees or contractors. At the same time, Idaho Power's energy infrastructure is becoming more reliant on network-based infrastructure. Idaho Power's operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power collects sensitive and confidential customer and employee information and proprietary information of Idaho Power. Although Idaho Power actively monitors developments in cyber security, no security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, 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. The loss of data could result in violations of privacy and other laws, financial loss to Idaho Power or to its customers, customer dissatisfaction, and significant litigation exposure, all of which could materially affect Idaho Power's financial condition and results of operations.operation.


Changes in 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 taxes.  Amounts of 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. In recent years, tax settlements, as well as state regulatory mechanisms with tax-related provisions (such
Table of contents

as Idaho Power's October 2014 regulatory settlement stipulation with the IPUC), has significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of ongoing and future income tax proceedings, or the state public utility commissions' treatment of those tax outcomes, could differ materially from the amounts 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 tax benefits 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 flow-through accounting as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than other companies.

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
Table of Contents

operations nor the timing of such changes. Idaho Power meets conditionsthe requirements under generally accepted accounting principles (GAAP)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 hydroelectrichydropower 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, 2016,2019, the system also includes approximately 4,8614,830 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 2421 transmission substations, 109 switching stations, 22331 mixed-use transmission and distribution substations, 185 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,26327,968 pole-miles of distribution lines.


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


Table of contentsContents


Idaho Power's hydroelectrichydropower 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 12,500
 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) 1,166,900
 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 11,300
    9,300
   
Total Hydroelectric 1,709,045
   
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 3,594,398
   3,542,498
  
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.
(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.
(2) Licensed on an annual basis while the application for a new multi-year license is pending.
(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.
(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.
(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 306,000305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,000,8541,113,631 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 FPAFederal 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 BCCBridger 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-percent50-
Table of Contents

percent interests in nine hydroelectrichydropower plants that have a total generatingnameplate capacity of 4544 MW. These plants are located in Idaho and California.


Table of contents

ITEM 3. LEGAL PROCEEDINGS
 
Refer to Note 1011 – “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.


Table of Contents

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 17, 2017,14, 2020, there were 10,0298,583 holders of record of IDACORP common stock and the closing stock price was $80.00 per share.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.

IDACORP and Idaho Power paid dividends of $105 million, $97 million, and $89 million in 2016, 2015, and 2014, respectively. The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors, subject to other restrictions.  The board of directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, 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. The IDACORP board of directors has aFor information regarding IDACORP's dividend policy, for IDACORP that provides for a target long-term dividend payout ratio of between 50see Part II - Item 7 - MD&A - "Liquidity 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 the board of director's dividend decisions. IDACORP's dividends during 2016 were 53 percent of actual 2016 earnings. Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends IDACORP pays remainCapital Resources - Dividends" in the discretion of the board of directors who, when evaluating the dividend amount, will take into account the foregoing factors, among others.
IDACORP's and Idaho Power's payment of dividends is subject to a number of restrictions.this report. For information relating to those restrictions on dividends see, Note 67 - “Common Stock”"Common Stock" to the consolidated financial statements included in this report.

TheDuring the quarter ended December 31, 2019, IDACORP effected the following table shows the reported high and low sales pricerepurchases of IDACORP’s common stock and dividends paid for 2016 and 2015 as reported by the NYSE:stock:

  2016 2015
Quarter High Low Dividends paid per share High Low Dividends paid per share
1st $74.96
 $65.03
 $0.51
 $70.48
 $59.21
 $0.47
2nd 81.36
 69.83
 0.51
 64.22
 55.40
 0.47
3rd 83.40
 75.14
 0.51
 64.94
 55.96
 0.47
4th 81.81
 72.93
 0.55
 70.33
 63.38
 0.51
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, 2019128
103.94
—
—
December 1, 2019 - December 31, 2019244
106.80
—
—
Total372
$105.82
—
—
(1) These shares were withheld for taxes upon vesting of restricted stock.

IDACORP did not repurchase any shares of its common stock during the fourth quarter of 2016.

Table of contentsContents


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, 2011,2014, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
ida123116_charta04.jpg
Source: Bloomberg and EEI
 2011 2012 2013 2014 2015 2016 2014 2015 2016 2017 2018 2019
IDACORP $100.00
 $105.67
 $130.51
 $171.81
 $182.01
 $221.73
 $100.00
 $105.85
 $128.94
 $150.12
 $156.97
 $184.73
S&P 500 100.00
 115.98
 153.51
 174.47
 176.88
 197.98
 100.00
 101.37
 113.49
 138.25
 132.18
 173.79
EEI Electric Utilities Index 100.00
 102.09
 115.37
 148.72
 142.92
 167.84
 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.


Table of contentsContents


ITEM 6. SELECTED FINANCIAL DATA
IDACORP, Inc.SUMMARY OF OPERATIONS(thousands of dollars, except per share amounts and statistics)
 2016 2015 2014 2013 2012 2019 2018 2017 2016 2015
Operating revenues $1,262,020
 $1,270,289
 $1,282,524
 $1,246,214
 $1,080,662
 $1,346,383
 $1,370,752
 $1,349,486
 $1,262,020
 $1,270,289
Operating income 271,776
 282,097
 253,696
 291,742
 242,602
 298,326
 296,922
 315,545
 283,582
 297,048
Net income attributable to IDACORP, Inc. 198,288
 194,679
 193,480
 182,417
 173,014
 232,854
 226,801
 212,419
 198,288
 194,679
Diluted earnings per share 3.94
 3.87
 3.85
 3.64
 3.46
 4.61
 4.49
 4.21
 3.94
 3.87
Dividends declared per share 2.08
 1.92
 1.76
 1.57
 1.37
 2.56
 2.40
 2.24
 2.08
 1.92
                    
Financial Condition:              
  
  
  
Total assets (1)
 $6,289,897
 $6,023,314
 $5,701,037
 $5,347,380
 $5,274,147
 $6,641,201
 $6,382,754
 $6,045,405
 $6,289,897
 $6,023,314
Long-term debt (including current portion) (1)
 $1,745,678
 $1,726,474
 $1,599,686
 $1,599,139
 $1,520,553
 $1,836,659
 $1,834,788
 $1,746,123
 $1,745,678
 $1,726,474
                    
Financial Statistics:              
  
  
  
Times interest charges earned:              
  
  
  
Before tax(2)(1)
 3.54
 3.61
 3.38
 3.87
 3.41
 3.65
 3.55
 3.82
 3.54
 3.61
After tax(3)(2)
 3.15
 3.12
 3.19
 3.06
 3.02
 3.40
 3.36
 3.30
 3.15
 3.12
Book value per share(4)(3)
 $42.74
 $40.88
 $38.85
 $36.84
 $34.73
 $48.90
 $47.04
 $44.68
 $42.74
 $40.88
Market-to-book ratio (5)(4)
 188% 166% 170% 141% 125% 218% 198% 204% 188% 166%
Payout ratio (6)(5)
 53% 50% 46% 43% 40% 56% 53% 53% 53% 50%
Return on year-end common equity (7)(6)
 9.2% 9.5% 9.9% 9.9% 9.9% 9.4% 9.6% 9.4% 9.2% 9.5%
                    
(1) Amounts in 2012-2014 adjusted to reflect IDACORP's 2015 adoption of Accounting Standards Update 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:
(2) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
(3) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income from continuing operations divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
(4) Total equity, excluding non-controlling interests, at the end of the year divided by shares outstanding at the end of the year.
(5) 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.
(6) Dividends paid per common share divided by diluted earnings per share.
(7) Net income attributable to IDACORP divided by total equity, excluding non-controlling interests, 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.


Table of contentsContents


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 formed in 1998 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”"IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the IPUC, OPUC,Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and FERC.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 territories,areas, as well as from the wholesale sale and transmission of electricity.  Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.  Idaho Power’s rates are established through regulatory proceedings that affect its ability to recover its costs and the potential to earn a return on its investment.


Idaho Power is the parent of IERCo,Idaho Energy Resources Co. (IERCo), a joint venturer in BCC,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 IFS,IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; and Ida-West Energy Company, an operator of small hydroelectrichydropower generation projects that satisfy the requirements of the PURPA; and IDACORP Energy Services Co. (IESCo), which is the former limited partnerPublic Utility Regulatory Policies Act of and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.1978 (PURPA).


EXECUTIVE OVERVIEW


Management's Outlook

Customer growth in Idaho Power's service area continues to benefit Idaho Power's revenues. To encourage continued responsible and sustainable growth, and as part of its planning for the future, Idaho Power actively participates in and supports state and local economic development initiatives. At the same time that Idaho Power pursues customer growth, it must also plan for that growth. Idaho Power plans for infrastructure that will support anticipated growth and allow it to continue to provide reliable, fair-priced electric powerIDACORP is committed to its customers. To that end, Idaho Power's noteworthy capital projects include the replacement of aging assets, upgrades to generation plants, a multi-year planfocus on competitive total returns and generating long-term value for replacement of underground conductor, ongoing system upgrades, and continued permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines. As of the date of this report, Idaho Power estimates total capital expenditures of approximately $1.5 billion over the next five years.

Idaho Power operates within what it believes to be a constructive regulatory framework, achieved through general rate cases, subject-specific rate filings, tariff riders, and cost recovery mechanisms that share risks and benefits with Idaho Power's customers. To complement the regulatory framework, Idaho Power focuses on controlling power supply, operating, maintenance, and capital costs through process review and improvement initiatives, and by empowering employees to identify new means to reduce costs, increase efficiencies, and enhance individual and enterprise performance for the benefit of IDACORP's shareholders, Idaho Power's customers, and other stakeholders. Idaho Power's base rates were most recently reset in 2012 through general rate cases in Idaho and Oregon. During 2017, Idaho Power will continue to assess the need to file a general rate case to reset base rates in the coming years in Idaho or Oregon.

Separately, during 2016, IDACORP continued to make meaningful progress toward its target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, which expanded on the progress made in previous years. From 2012 through 2016, IDACORP's board of directors approved a collective 83 percent increase in the quarterly dividend, from $0.30 to $0.55 per share.

Table of contents

2016 Accomplishments and 2017 Initiatives

shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Forbusiness, since Idaho Power’s regulated electric utility operations are the past several years, Idaho Power has been executing its three-part strategyprimary driver of responsible planning, responsible development and protection of resources, and responsible energy use.IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business""Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements and recognitions during 2016 under its three-part business strategy2019 include:


IDACORP achieved net income growth for a ninthtwelfth consecutive year;
IDACORP provided a 1913 percent cumulative annual total shareholder return over the past three years, including share price appreciation and dividends paid, rankingpaid;
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 88th percentile among peers;nation, as rated by an independent third party;
Idaho Power continued its strong performance in system reliability, slightly behind 2018's record reliability score;
IDACORP increased IDACORP'sits quarterly common stock dividend from $0.51$0.63 per share to $0.55$0.67 per share;share, as a part of a 123 percent increase in quarterly dividends approved over the last eight years;
producedIDACORP 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 best yearprevious policy adopted in 2011 that targeted a dividend payout ratio of performance forbetween 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 electric system reliability since formal measurement beganparticipation in 2006;
executed on business optimization initiatives, focusing on improvingcoal-fired operations at units 1 and controlling expenditures;
made continued progress toward the permitting2 of its jointly-owned North Valmy coal-fired power plant in 2019 and 2025, respectively. As planned, Idaho Power ended its participation in unit 1 of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects;North Valmy plant in December 2019;
•
achieved Idaho Power's COPower 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;of 29 percent since 2010.
earned
Table of Contents


Summary of 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 highest rolling 12-monthyears ended December 31, 2019, 2018, and 2017 (in thousands, except earnings per share amounts):
  Year Ended December 31,
  2019 2018 2017
Idaho Power net income $224,437
 $222,334
 $206,347
Net income attributable to IDACORP, Inc. $232,854
 $226,801
 $212,419
Average outstanding shares – diluted (000’s) 50,537
 50,510
 50,424
IDACORP, Inc. earnings per diluted share $4.61
 $4.49
 $4.21

The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2019, from the year ended December 31, 2018 (items are in millions and are before tax unless otherwise noted):
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 18.8
  
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms (21.4)  
Idaho fixed cost adjustment (FCA) revenues 1.0
  
Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms (2.8)  
Transmission wheeling-related revenues (5.3)  
Other operations and maintenance (O&M) expenses 8.7
  
Other changes in operating revenues and expenses, net (1.7)  
Prior year provision for sharing with customers 5.0
  
Increase in Idaho Power operating income 2.3
  
Non-operating income and expenses, net 9.9
  
Income tax expense (10.1)  
Total increase in Idaho Power net income   2.1
Other IDACORP changes (net of tax)   4.0
Net income attributable to IDACORP, Inc. - December 31, 2019   $232.9
IDACORP's net income increased $6.1 million for 2019 compared with 2018, primarily due to higher net income at Idaho Power and IFS.

Idaho Power's customer relationship index score (Idahogrowth of 2.5 percent added $18.8 million to Idaho Power's internal measure ofoperating income compared with 2018. Lower sales volumes on a per-customer basis decreased operating income by $21.4 million in 2019 compared with 2018, primarily due to lower irrigation sales. 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 satisfaction) ever recordedto operate irrigation pumps during 2019 compared with 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 $2.8 million in 2019 compared with 2018. As provided by the company; and
settlement stipulation approved by the IPUC in 2018 related to income tax reform, retail revenues per MWh in 2019 were reduced by $7.4 million of non-cash accruals for future amortization related to regulatory deferrals that would otherwise be a future liability of Idaho Power tiedcustomers, compared with a $1.5 million revenue reduction in 2018. In 2018, a corresponding $4.0 million of non-cash accruals were recorded as other O&M expense for 5th placethe amortization of specified deferrals. The decrease in retail revenues per MWh from these non-cash accruals was partially offset by changes in the annual "Best Energy Companies" rankings published by Public Utilities Fortnightly.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.

Table of Contents


For 2017, IDACORPDuring 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 have establishedPower's continued focus on managing other O&M expenses resulted in lower expenses across a number of organizational initiatives, includingareas. 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 following:settlement stipulation approved by the IPUC in 2018 related to income tax reform.


continueBased 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 Idaho regulatory settlement stipulation approved in October 2014. In 2018, Idaho Power recorded a $5.0 million provision against 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 executethe consolidated financial statements included in this report, a 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 average construction work in progress balance was higher throughout 2019 compared with 2018. Also, investment income from the 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 income tax reform and $1.3 million for tax-deductible bond redemption costs incurred in 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 expense in 2019 compared with 2018. Amortization of vintage investment tax credits that became available in 2019 lowered income tax expense by $3.4 million, most of which is not expected to recur.

At IFS, a $3.0 million increase in distributions from the three core focuses for 2017—sale of low-income housing properties led to higher IFS net income in 2019 compared with 2018.

2020 Initiatives and Strategy

IDACORP’s strategy is focused on four areas: growing financial strength, improving Idaho Power's core business, growing revenues, and enhancing theIdaho Power’s brand, and positioningkeeping employees safe and engaged. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the company for the future;
continue to enhance and promote Idaho Power’s safety culture;
grow financial strength by supporting business development in Idaho Power's service area while actively managing costs;
continue upward progress within IDACORP’s target dividend payout ratio range;
pursue responsible investments that address customer growth while improving reliability, enhancinginterests of shareowners, Idaho Power customers’ experience, increasing shareholder value,customers, employees, and managing carbon impacts; andother stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to provide safe, fair-priced, reliable service to its customers from diversified generation resources. For more information on the business strategy of the companies, see Part I, Item 1 – “Business - Business Strategy” in this report.
integrate new renewable generation resources into Idaho Power’s grid and continue progress toward participation in the Western EIM, anticipated to begin in the spring of 2018, which is expected to capture intra-hour market opportunities to help achieve greater reliability and improve system dispatch.


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 laterbelow 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 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
Table of Contents

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. Because of the significant impact of ratemaking decisions, and in pursuit of its goal of advancing a purposeful regulatory strategy, Idaho Power focuses on timely recovery of its costs through filings with the company's regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE). During 2017, Idaho Power will continue to assess the need to file a general rate case to reset base rates.
rates, but does not anticipate filing a rate case in the next twelve months.


Economic Conditions and Loads: Economic conditions impact consumer demand for electricity and revenues, collectability of accounts, the volume of off-system 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 inreleased its service area—in 2016, its customer count grew by 1.8 percent—and in employment in Idaho Power's service area, which grew by approximately 3.5 percent in 2016 based on Idaho Department of Labor preliminary December 2016 data. Idaho Power expects its number of customers to continue to
Table of contents

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 2016, Idaho Power began preparing its 2017 IRP,2019 Integrated Resource Plan (IRP), Idaho Power's long-term forecast of loads and resources. Theresources, which was amended in January 2020. For more information on the 2019 IRP, including the load forecast assumptions Idaho Power expects to use in the 2017 IRP are included in the table below. For comparison purposes, the analogous average annual growth rates used in the prior two IRPs are included.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.
  Forecast for 2016-2021 Period 20-Year Forecast
  
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)
2017 IRP 1.3%1.4% 1.0%1.4%
2015 IRP 1.1%1.6% 1.2%1.5%
2013 IRP 1.2%1.6% 1.1%1.4%

Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined so as 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, 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, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects, 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 and thermal generation facilities also require continuing upgrades and component replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydroelectric generation resource.  Idaho Power expects to include completed capital projects in its next general rate case or, in circumstances where appropriate, a single-issue rate case for individual projects with a significant capital cost. Depending on the outcome of the regulatory process and items such as the rate of return authorized by the IPUC and OPUC, this growth in rate base has the potential to increase Idaho Power's revenues and earnings.
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 residential and small commercial customers is mitigated through the Idaho FCA mechanism.


Further, as Idaho Power's hydroelectrichydropower facilities comprise nearlyover one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydroelectrichydropower generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydroelectrichydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectrichydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from off-system sales of its excess power.wholesale energy 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.
Mitigation of Impact of Fuel and Purchased Power Expense:  In addition to hydroelectric generation, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms 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 of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market
•
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,
Table of contentsContents


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.

Changes in legislation, regulation, and government policy as a result of the 2016 U.S. presidential and congressional elections: The recent presidential and congressional elections in the United States could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy. While it is uncertain whether and when any such changes will occur, they could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals discussed during and after the election that could have a material impact on IDACORP and Idaho Power include, but are not limited to, reform of the federal tax code; infrastructure renewal programs; and modifications to public company reporting requirements and environmental regulation.

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, and the North American Electric Reliability Corporation.Corporation, and Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. EnvironmentalRecently, 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, andincluding Idaho Power's coal-fired plants, 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. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations by the end of 2020, a decision driven in large part by the substantial cost of environmental controls required by existing regulations. Similarly, Idaho Power is assessing the early closure of the North Valmy coal-fired power plant, of which Idaho Power owns a 50-percent interest, and in October and November 2016 filed applications with the IPUC and OPUC, respectively, requesting accelerated depreciation of the facility. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade.
decade, and due to economic factors in part associated with the costs of compliance with environmental regulation, has accelerated the retirement dates of its jointly-owned coal-fired 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 will continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.

Summary of 2016 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, 2016, 2015, and 2014 (in thousands, except earnings per share amounts):
  Year Ended December 31,
  2016 2015 2014
Idaho Power net income $189,242
 $190,983
 $189,387
Net income attributable to IDACORP, Inc. $198,288
 $194,679
 $193,480
Average outstanding shares – diluted (000’s) 50,373
 50,292
 50,199
IDACORP, Inc. earnings per diluted share $3.94
 $3.87
 $3.85

Table of contents

The table below provides a reconciliation of net income attributable to IDACORP, Inc. for year ended December 31, 2016 from the year ended December 31, 2015 (items are in millions and are before tax unless otherwise noted):
Net income attributable to IDACORP, Inc. - December 31, 2015   $194.7
Change in Idaho Power net income:    
Customer growth, net of associated power supply costs 11.2
  
Usage per customer, net of associated power supply costs (14.7)  
Other operating and maintenance expenses (9.7)  
Depreciation expense (5.6)  
Other changes in operating revenues and expenses, net (1.5)  
Change in Idaho Power operating income prior to sharing mechanisms (20.3)  
Change in operating income as a result of sharing mechanisms 3.2
  
Change in Idaho Power operating income (17.1)  
Non-operating income and expenses 4.4
  
Income tax expense 11.0
  
Total decrease in Idaho Power net income   (1.7)
IESCo income from legal settlement (net of tax)   3.7
Other changes (net of tax)   1.6
Net income attributable to IDACORP, Inc. - December 31, 2016   $198.3
IDACORP's 2016 net income increased $3.6 million compared with 2015. While Idaho Power's 2016 net income was relatively flat, decreasing $1.7 million compared with 2015, net income from other subsidiaries increased IDACORP's net income by $5.3 million.

Continued customer growth at Idaho Power increased operating income by $11.2 million, which was more than offset by a $14.7 million decrease from lower usage per customer in 2016 compared with 2015. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 led to lower sales volumes, revenues, and operating income. Other operating and maintenance (O&M) expenses were $9.7 million higher in 2016 compared with 2015, largely related to higher variable labor-related costs.

During 2015, Idaho Power recorded a total of $3.2 million as a provision against current revenue related to the October 2014 Idaho regulatory settlement stipulation that required sharing with Idaho customers of a portion of 2015 earnings that exceeded 10.0 percent. During 2016, no such sharing provision was recorded as Idaho Power's Idaho ROE did not exceed 10.0 percent. At December 31, 2016, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho regulatory settlement stipulation.

Idaho Power's income tax expense was lower in 2016 compared with 2015 due primarily to greater net flow-through income tax benefits, additional share-based compensation tax benefits related to the adoption of Accounting Standards Update 2016-09, and lower pretax income. These decreases were partially offset by a smaller flow-through benefit of a tax deductible make-whole premium that Idaho Power paid in connection with the early redemption of long-term debt in 2016 compared with the flow-through benefit of an early bond redemption in 2015.

IDACORP's 2016 net income also included a $3.7 million increase, net of tax, in IESCo's earnings, a result of a December 2016 settlement relating to the California energy market proceedings. Refer to Note 10 - “Contingencies” to the consolidated financial statements included in this report for additional information on the settlement. IDACORP also benefited from distributions related to fully-amortized affordable housing investments at IFS, which reduced IDACORP's income tax expense.


RESULTS OF OPERATIONS
 
This section of the 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 20162019 are compared with 2015 and the results for 2015 are compared with 2014.
Table of contents

Utility Operations2018.
 
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last threetwo years.
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018
General business sales 14,196
 14,265
 14,092
Off-system sales 1,186
 1,254
 2,220
Retail energy sales 14,537
 14,587
Wholesale energy sales 2,171
 2,246
Bundled energy sales 680
 617
Total energy sales 15,382
 15,519
 16,312
 17,388
 17,450
Hydroelectric generation 6,408
 5,910
 6,170
Hydropower generation 8,294
 8,682
Coal generation 4,045
 4,676
 5,851
 3,012
 3,274
Natural gas and other generation 1,722
 2,076
 1,175
 2,114
 1,408
Total system generation 12,175
 12,662
 13,196
 13,420
 13,364
Purchased power 4,337
 3,792
 4,153
 5,200
 5,431
Line losses (1,130) (935) (1,037) (1,232) (1,345)
Total energy supply 15,382
 15,519
 16,312
 17,388
 17,450


Sales Volume and Generation: In 2016, general business sales volumes decreased less than 1 percent compared with the prior year. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 led to lower sales volumes. Also, a shorter irrigation season due to a later start in 2016 compared with 2015 resulted in lower usage per irrigation customer than during 2015.

Off-system sales volumes decreased 68 thousand MWh, or 5 percent, during 2016 compared with 2015. Low wholesale market prices reduced economic benefitsFor purposes of operating Idaho Power's non-hydroelectric generation facilities for off-system sales.

Favorable hydroelectric generating conditions from greater snowpack in the spring of 2016 compared with the spring of 2015 led to increased hydroelectric generation in 2016. Coal-fired generation decreased in 2016 compared with 2015 as low wholesale market prices led to an increase in purchased power.

The financial impacts of fluctuations in off-system 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 later in this MD&A.

Table of contents

General Business Revenues:  The table below presents Idaho Power’s general business revenues (in thousands), MWh sales (in thousands), and number of customers for the last three years.
  Year Ended December 31,
  2016 2015 2014
Revenue  
  
  
Residential $514,954
 $512,068
 $500,195
Commercial 302,650
 306,178
 299,462
Industrial 182,590
 182,254
 182,675
Irrigation 156,505
 164,403
 158,654
Total 1,156,699
 1,164,903
 1,140,986
Provision for sharing —
 (3,159) (7,999)
Deferred revenue related to HCC relicensing AFUDC(1)
 (10,706) (10,706) (10,706)
Total general business revenues $1,145,993
 $1,151,038
 $1,122,281
Volume of Sales (MWh)  
  
  
Residential 5,004
 4,977
 4,965
Commercial 3,999
 4,045
 3,944
Industrial 3,243
 3,196
 3,217
Irrigation 1,950
 2,047
 1,966
Total MWh sales 14,196
 14,265
 14,092
Number of customers at year-end  
  
  
Residential 444,431
 436,102
 428,294
Commercial 69,344
 68,352
 67,522
Industrial 121
 118
 121
Irrigation 20,638
 20,293
 19,826
Total customers 534,534
 524,865
 515,763
(1)Idaho Power is collecting approximately $10.7 million annually in the Idaho jurisdiction for AFUDC on HCC construction work in progress, but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs are placed in service.

Changes in rates, changes in customer demand, and changes in FCA revenues are typically the primary causes of fluctuations in general business revenue from period to period.  See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last three years. The primary influences on changes in customer demand for electricity are weather, economic conditions, and energy efficiency.  Extreme temperatures increase sales to customers who use electricity for cooling and heating, while moderate 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.illustration, Boise, Idaho, weather-related information for the last threetwo years is presented in the following table.table that follows.
 Year Ended December 31,   Year Ended December 31,  
 2016 2015 2014 
Normal(2)
 2019 2018 
Normal(2)
Heating degree-days(1)
 4,807
 4,694
 4,976
 5,514
 5,314
 4,984
 5,514
Cooling degree-days(1)
 1,001
 1,280
 1,129
 942
 1,020
 1,116
 942
Precipitation (inches) 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 of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature 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.

Table of Contents


Sales Volume and Generation: In 2019, retail sales volumes decreased less than 1 percent compared with 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 partially offset the decrease in sales volumes per customer during 2019 compared with 2018, with the number of Idaho Power's customers growing by 2.5 percent.

Total system generation in 2019 was consistent with that of the prior year. An increase in natural gas generation more than offset decreases in hydropower and coal generation.

Wholesale energy sales volumes decreased 75 thousand MWh, or 3 percent, during 2019 compared with 2018, due primarily to a decrease in purchased power, both in market purchases and in purchases under PURPA contracts, resulting in 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 two years.
  Year Ended December 31,
  2019 2018 
Retail revenues:  
  
 
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 181,372
 190,130
 
Irrigation 135,850
 158,001
 
Provision for sharing —
 (5,025) 
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (8,780) 
Total retail revenues $1,130,611
 $1,175,152
 
Volume of Sales (MWh)  
  
 
Residential 5,273
 5,135
 
Commercial 4,092
 4,105
 
Industrial 3,412
 3,371
 
Irrigation 1,760
 1,976
 
Total retail MWh sales 14,537
 14,587
 
Number of retail customers at year-end  
  
 
Residential 477,404
 464,670
 
Commercial 72,855
 71,680
 
Industrial 131
 120
 
Irrigation 21,387
 21,175
 
Total customers 571,777
 557,645
 
      
(1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.
(2) The IPUC 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.

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 structure provideschanges implemented over the last two years. The primary influences on customer demand for electricity are weather, economic
Table of Contents

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 the summer when system loadspeak load periods, and residential customer rates are at their highest, and includes tiers such thattiered, providing for higher rates increase as a customer's consumption level increases. Thesebased on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.
Table of contents



General BusinessRetail Revenues - 2016 Compared with 2015: General business revenueRetail revenues decreased $5.0$44.5 million in 20162019 compared with 2015.2018. The primary factors affecting general businessretail revenues includedduring the following:

Rates:  Rate changes decreased general business revenue by $3.9 million for 2016 compared with 2015, primarily due to a decrease in the recovery of power cost adjustment amounts in 2016. The recovery of power cost adjustment amounts in rates has no effect on operating income as it is amortized into expense in the same period it is recovered through rates.

Customers:  Customer growth of 1.8 percent increased general business revenue by $15.6 million in 2016 compared with 2015.

Usage:  Lower usage (on a per customer basis), primarily by irrigation, commercial, and residential customers, decreased general business revenue by $21.3 million in 2016 compared with 2015. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 compared with 2015 led to lower sales volumes. Also, a shorter irrigation season due to a later start in 2016 compared with 2015 resulted in lower usage per irrigation customer in 2016 than during 2015. Greater customer participation in energy efficiency programs also contributed to lower usage during 2016 compared with 2015.

Sharing: Idaho Power's sharing mechanism is associated with an Idaho regulatory settlement agreement that provides for the sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. The impact of this mechanism is partially recorded as a reduction to general business revenue. During 2015, Idaho Power recorded a total of $3.2 million as a provision against current revenue related to the sharing mechanism. In 2016, no such sharing provision was recorded as Idaho Power's Idaho ROE did not exceed 10.0 percent.

Idaho FCA Revenue: Partially offsetting lower usage per customer, the Idaho FCA mechanism increased revenues by $1.4 million in 2016 compared with 2015. Idaho Power accrued $30.3 million of Idaho FCA revenues in 2016, compared with $28.9 million in 2015.

General Business Revenues - 2015 Compared with 2014: General business revenue increased $28.8 million in 2015 compared with 2014.  The factors affecting general business revenues included 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.

RatesWholesale Energy Sales:  Two rate changes impacted general business revenue—an Idaho PCA rate increase effective June 1, 2014, and Idaho PCA rate decrease effective June 1, 2015, both described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. Overall, rate changes combined to decrease general business revenue by $2.2 million in 2015.

Customers:  Customer growth of 1.8 percent increased general business revenue by $14.1 million.

Usage:  Lower usage per customer in 2015, primarily driven by the impact of more moderate winter weather on residential customer usage, as well as Wholesale energy efficiency, decreased general business revenue by $0.7 million. Residential usage per customer was 1.4 percent lower in 2015.

Sharing: Revenue sharing of $3.2 million and $8.0 million were recorded in 2015 and 2014, respectively. This sharing resulted in a net increase to general business revenue of $4.8 million in 2015 compared with 2014.

Idaho FCA Revenue: FCA mechanism revenues increased $12.7 million compared with 2014, including the impacts of weather and of modifications made to the mechanism by the IPUC effective January 1, 2015. Idaho Power accrued $28.9 million of Idaho FCA revenues in 2015, compared with $16.2 million in 2014. The modifications to the FCA mechanism are described in more detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.


Table of contents

Off-System Sales:  Off-system sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy.energy, and sales into the Western EIM, and do not include derivative transactions. The following table below presents Idaho Power’s off-systemwholesale energy sales for the last threetwo years (in thousands, except for MWh amounts): . 
  Year Ended December 31,
  2016 2015 2014
Revenue $25,205
 $30,887
 $77,165
MWh sold 1,186
 1,254
 2,220
Revenue per MWh $21.25
 $24.63
 $34.76
  Year Ended December 31,
  2019 2018
Wholesale energy revenues $71,198
 $52,845
Wholesale MWh sold 2,171
 2,246
Wholesale energy revenues per MWh $32.80
 $23.53
 
Off-System Sales - 2016 Compared with 2015: Off-system salesIn 2019, wholesale energy revenue decreasedincreased by $5.7$18.4 million, or 18 percent. Off-system35 percent, compared with 2018. Wholesale energy sales volumes decreased 53 percent in 20162019 compared with 2018, but the same periods in 2015 as low wholesale market prices reduced the economic benefits of operating Idaho Power's non-hydroelectric generation facilities for off-system sales. The average price of off-systemwholesale energy sales was 39 percent higher for 2016 was 14 percent lower2019 compared with 2015.2018. 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

Table of Contents
Off-System Sales - 2015 Compared
the 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 2019 compared with 2014: Off-system sales revenue2018. Idaho Power's OATT rates decreased by $46.3 million, or 6010 percent in 2015. Off-system salesOctober 2018 and 13 percent October 2019. To a lesser extent, lower volumes decreased 44 percent, as 2014 sales benefited from more favorable market conditions, at times, for selling power off-system. The average price of off-system sales transactions in 2015 was 29 percent lower than 2014, indicative of generally lower market prices in 2015. Decreases in output from hydroelectric resources and an increase in overall load due to customer growth also reduced the amount of surplus power availabletransmission wheeling-related revenues. Refer to "Regulatory Matters" in this MD&A for sale off-system during 2015.more information on Idaho Power's OATT rate.


Other Revenues:  The table below presents the components of other revenues for the last three years (in thousands): 
  Year Ended December 31,
  2016 2015 2014
Transmission services and other $54,401
 $55,048
 $52,051
Energy efficiency 33,754
 30,532
 27,154
Total other revenues $88,155
 $85,580
 $79,205
Other Revenues - 2016 Compared with 2015: Other revenues increased $2.6 million, or 3 percent, in 2016 compared with 2015. Greater customer participation inEnergy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency programs increased revenue and corresponding expense in 2016 compared with 2015. Mostriders fund energy efficiency activities are funded through a rider mechanism on customer bills.  Energy efficiency program expendituresexpenditures. Expenditures funded through the riderriders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variancevariances between expenditures and amounts collected through the rider isriders are recorded as a regulatory assetassets or liability pending future collection from, or obligation to, customers.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, 2016,2019, Idaho Power's energy efficiency rider balances were a $5.6$0.3 million regulatory asset in the Idaho jurisdiction and a $1.2 million regulatory asset in the Oregon jurisdiction and a $10.7 million regulatory liability in the Idaho jurisdiction.


Other Revenues - 2015 Compared with 2014: Other revenues increased $6.4 million, or 8 percent, in 2015. The increases in 2015 were primarily the result of increased electricity transmission (wheeling) volumes and greater customer participation in energy efficiency programs.Operating Expenses



Table of contents

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last threetwo years (in thousands, except for MWh amounts): . 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018
Expense          
PURPA contracts $153,665
 $131,340
 $144,617
 $187,344
 $189,722
Other purchased power (including wheeling) 85,040
 88,430
 92,071
 97,922
 104,092
Demand response incentive payments 7,059
 6,701
 7,940
Total purchased power expense $245,764
 $226,471
 $244,628
 $285,266
 $293,814
MWh purchased          
PURPA contracts 2,314
 2,008
 2,286
 2,983
 3,045
Other purchased power 2,023
 1,784
 1,867
 2,217
 2,386
Total MWh purchased 4,337
 3,792
 4,153
 5,200
 5,431
Cost per MWh from PURPA contracts $66.41
 $65.41
 $63.26
 $62.80
 $62.31
Cost per MWh from other purchased power $42.04
 $49.57
 $49.31
Weighted average - all sources (excluding demand response incentive payments) $55.04
 $57.96
 $56.99
Cost per MWh from other sources $44.17
 $43.63
Weighted average - all sources $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 themost PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectrichydropower 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 off-systemwholesale 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 off-systemwholesale 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’sPower'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 purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale 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 - 2016 Compared with 2015: Purchased power expense increased $19.3 million, or 9 percent, in 2016. The increase was due primarily to increased volumes purchased from both PURPA and non-PURPA sources attributable largely to lower market prices at times that encouraged market purchases rather than operating some generating units. Volume increases were partially offset by lower non-PURPA wholesale market prices.

Purchased Power - 2015 Compared with 2014: Purchased power expense decreased $18.2$8.5 million, or 3 percent, in 2019 compared with 2018, primarily due to a 7 percent decrease in 2015. The decrease was due primarilythe volume of other non-PURPA power purchases. Other non-PURPA purchased power volumes decreased as Idaho Power used its own generation to reduced volumes purchased from both PURPA and non-PURPA sources. Volumemeet customer demand. These volume decreases were partially offset by increases in average pricescost per MWh of both PURPA and non-PURPApower purchased from all sources.


Table of contentsContents


Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last threetwo years (in thousands, except per MWh amounts):.
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018
Expense  
  
    
  
Coal (1)
 $137,689
 $131,286
 $156,172
Natural gas(2)
 41,802
 54,945
 45,069
Coal $105,257
 $115,524
Natural gas(1)
 51,615
 17,674
Total fuel expense $179,491
 $186,231
 $201,241
 $156,872
 $133,198
MWh generated  
  
    
  
Coal (1)
 4,045
 4,676
 5,851
Natural gas(2)
 1,722
 2,076
 1,175
Coal 3,012
 3,274
Natural gas(1)
 2,114
 1,408
Total MWh generated 5,767
 6,752
 7,026
 5,126
 4,682
Cost per MWh - Coal $34.04
 $28.08
 $26.69
 $34.95
 $35.29
Cost per MWh - Natural gas 24.28
 26.47
 38.36
 $24.42
 $12.55
Weighted average, all sources $31.12
 $27.58
 $28.64
 $30.60
 $28.45
    
(1) 2015 excludes 147 MWh of generation from the Jim Bridger power plant for which costs were capitalized during feasibility testing of capital projects under contemplation.
(2)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 expenseexpenses 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 - 2016 Compared with 2015: In 2016, fuel expense decreased $6.7increased $23.7 million, or 418 percent, in 2019 compared with 2015, due principally to decreased output from coal-fired plants and natural gas plants during 2016. Overall generation decreased 15 percent2018, due to a change9 percent increase in resource mix resulting from increased purchase requirements from cogenerationthermal generation volume and small power production (CSPP) projects, resource constraints at various generating locations, including Langley and Bridger, due to scheduled maintenance and other factors, and more open market purchases for economic reasons. The volume decreases were partially offset by higher coal prices due to higher miningaverage costs at BCC. The higher mining costs resulted in part due to issues with underground mining equipment that is no longer in service.

Fuel Expense - 2015 Compared with 2014: In 2015, fuel expense decreased $15.0 million, or 7 percent, compared with 2014, due principally to decreased output from coal-fired plants during 2015 combined with lower regional natural gas prices for fuel used at the natural gas plants. Overall generation decreased 4 percent due to lower system loads and lower wholesale energy prices. The expense per MWh for natural gas. Higher gas decreased approximately 30 percentgeneration 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 20152019 compared with 2014. These2018. In 2019, gains on financial gas hedges included in fuel expense were $8.7 million lower than in 2018, increasing average costs per MWh for natural gas. In October 2018, a natural gas prices led to a shift of generation from coal-fired plants topipeline ruptured in British Columbia, Canada, which disrupted natural gas plants.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 financial gas hedges at the time of the rupture. Most of these realized hedging gains benefit customers through the power cost adjustment mechanisms described below.


Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less off-systemwholesale 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 hydroelectrichydropower 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.


Table of contentsContents


The table that followsbelow presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last threetwo years (in thousands). 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018
Idaho power supply cost deferrals $(43,841) $(35,802) $(48,104)
Power supply cost accrual $49,234
 $41,535
Amortization of prior year authorized balances 38,511
 52,568
 70,339
 (47,187) 571
Total power cost adjustment expense $(5,330) $16,766
 $22,235
 $2,047
 $42,106

The power supply accruals (deferrals) represent the portion of the power supply cost fluctuations accrued (deferred) 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 2019 and 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 all periods presented, 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 PCApower cost adjustment year that were deferred or accrued in the prior PCApower cost adjustment year (the true-up component of the PCA)power cost adjustment mechanism).

Idaho Power Cost Adjustment Mechanisms - 2016 Comparedaccrued $7.7 million more in power supply costs in 2019 compared with 2015: Actual2018 as actual net power supply cost deferrals increased in 2016costs were lower relative to 2015, a change of $8.0 million—from $35.8 million to $43.8 million. The increase in the deferral is due in part to higher fuel costs related to coal and purchased power with less surplus sales than forecasted. The $38.5forecasted costs. In addition, Idaho Power recorded $47.2 million of amortization offsetsof the collection from customers of prior years' deferrals and was lowerprior-year authorized balances in 2016 as Idaho Power is amortizing a smaller deferral balance in the current year than the prior year.

Power Cost Adjustment Mechanisms - 2015 Compared2019, compared with 2014: Actual net power supply cost deferrals decreased in 2015 relative to 2014, a change of $12.3 million—from $48.1 million to $35.8 million. Power supply costs collected through base rates increased on June 1, 2015, resulting in less costs needing to be recovered through the power cost adjustment mechanisms since that time. The $52.6 million$0.6 million of amortization offsets the collection from customers of prior years' deferrals.in 2018.


Other Operations and Maintenance Expenses: The changesOther 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.

resulted in lower expenses across a number of areas. Lower bad debt expense reduced other O&M - 2016 Compared with 2015: Other O&M expense increasedexpenses by $9.7$1.1 million, in 2016 compared with 2015, an increase of 3 percent, due primarily to the following factors:

labor-related expenses increased $6.5 million, or 3 percent, in 2016 due to normal escalations in laborenhanced collection efforts and benefits costs and higher variable employee costs;
scheduled maintenance at the Langley Gulch natural gas-fired generation plant increaseda strong economy. Also, other O&M expenses $1.6 million; and
a $1.1in 2018 included $4.0 million increase primarily related to transmission agreements entered into in October 2015, which also resulted in a corresponding increase in other revenue.

O&M - 2015 Compared with 2014: Other O&Mof non-cash amortization expense decreased by $12.4 million in 2015 compared with 2014, a decrease of 3.5 percent, due to the following factors:

$16.7 million was recorded as additional pension expense in 2014 related to a December 2011 Idaho regulatory settlement agreement, which required sharing with Idaho customers of a portion of earnings in excess of a 10.0 percent Idaho ROE (thereby reducing customers' future pension obligations). There were no additional expenses relateddeferrals pursuant to the settlement agreementstipulation approved by the IPUC in 2015;2018 related to income tax reform.
excluding the additional 2014 pension expense, labor-related expenses increased $2.1 million, or 1.1 percent, in 2015 due to normal escalations in labor and benefits costs; and
hydroelectric generation expenses increased $2.0 million, primarily due to increased repair costs and purchased services.

Income Taxes


IDACORP's and Idaho Power's 20162019 income tax expense decreased $9.3increased $7.1 million and $11.0$10.1 million, respectively, when compared to 2015. The decrease was primarily due to greater net flow-throughwith 2018. During 2018 Idaho Power recorded tax benefits for a $5.7 million remeasurement of deferred taxes resulting from income tax benefits atreform and $1.3 million for tax-deductible bond redemption costs incurred in 2018. There was no such remeasurement or bond redemption in 2019. Also, 2018 included a benefit from plant-related income tax return adjustments, which reduced Idaho Power a tax benefit from the adoption of a new accounting standard for share-based compensation, distributions related to fully-amortized affordable housing investments at IDACORP, and lower Idaho Power pre-tax earnings in 2016.
Table of contents


Incomeincome tax expense in 2015 increased significantly2018. These items, combined with greater 2019 net income, resulted in higher income tax expense in 2019 compared with 2014, principally as2018. 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 IFS, a result$3.0 million increase in distributions from the sale of a 2014 flow-throughlow-income housing properties reduced income tax benefit related to the cumulative impact of tax accounting method changes for Idaho Power’s capitalized repairs deduction that did not recurexpense at IDACORP in 2015. 2019 compared with 2018.
For additional information relating to IDACORP's and Idaho Power's income taxes includingand 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 hydroelectrichydropower and thermal generation facilities also require continuing upgrades and component replacement. On an accrual basis, Idaho Power's expenditures for property,additions to electric plant, and equipment, excluding AFUDC, were $287$295 million in 2016, $2842019 and $274 million in 2015,2018. Cash construction expenditures, excluding AFUDC and $265excluding net costs of removing assets from service, were $268 million in 2014.each of 2019 and 2018. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of approximately $1.5more than $1.6 billion expected over the period from 20172020 through 2021. 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 17, 2017,14, 2020, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


Table of Contents

their respective $100 million and $300 million revolving credit facilities;
IDACORP's shelf registration statement filed with the SECU.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; $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 2017,2020, the companies believe they will be able to meet capital requirements and fund corporate expenses during 20172020 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 issued with more favorable terms. To that end, 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, its $100 million in principal amount of 6.15% first mortgage bonds, Series H, due April 2019. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of $14 million. The make-whole premium resulted in a current income tax deduction, which under Idaho Power's regulatory flow-through tax accounting produced an income tax benefit of approximately $5.6 million recorded in the second quarter of 2016. Idaho Power also expects to receive an incremental net benefit to net income as a result of the lower interest rate of the notes issued in March 2016 compared with the interest rate associated with the redeemed notes. Idaho Power used a portion of the net proceeds of the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption. The companies do not expect to redeem any existing outstanding debt during 2017.indebtedness.


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, 2016,2019, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
Table of contents

  IDACORP Idaho Power
Debt 43% 45%
Equity 57% 55%
  IDACORP Idaho Power
Debt 45% 47%
Equity 55% 53%


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 20162019 were $348$367 million and $311$344 million, respectively, a decreasedecreases of $5$125 million and $75 million for IDACORP and $35 million decrease for Idaho Power, respectively, when compared with 2015.2018. Significant items that affected the companies' operating cash flows in 20162019 relative to 20152018 were as follows:
a $6 million increase and $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 costscost adjustment amounts accrued or deferred and refunded or collected under the Idaho rate mechanisms, decreased operating cash inflows by $19$53 million;
changes in deferred taxes and in taxes accrued and receivable combined to decrease cash flows by $3 million and $34 million at IDACORP and Idaho Power, respectively;
Idaho Power received $24$19 million of distributions from IERCo's investment in BCC for 2016,2019, compared with $11$29 million in 2015. Changes2018; changes in distributions from year to year are primarily driven by changes in the timing of cash needs associated with BCC; and
comparative changes in working capital and other assets and liabilities increased cash flows by $7 million in 2016 compared with 2015, primarily related to changes in accounts payable due to timing of payments.

IDACORP's and Idaho Power's operating cash inflows in 2015 were $353 million and $346 million, respectively, a decrease of $11 million for IDACORP and a slight increase for Idaho Power when compared with 2014. Significant items that affected the companies' operating cash flows in 2015 relative to 2014 were as follows:

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, decreased operating cash inflows by $18 million;
Idaho Power made $39 million of cash contributions to its defined benefit pension plan in 2015, compared with $30 million of cash contributions during 2014;
changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $34$7 million and $50$4 million at IDACORP and Idaho Power, respectively; and
comparative
Table of Contents

changes in working capital balances due primarily to timing—principally related to a smaller decreasetiming, including fluctuations in accounts receivable, in 2015 compared to the decrease inother current assets, and accounts receivable in 2014. Changes in accounts receivable balances reduced operating cash flows $16 million and $18 million for IDACORP and Idaho Power, respectively.payable, as follows:
◦timing of collections of accounts receivable balances decreased operating cash flows by $7 million and $5 million for IDACORP and Idaho Power, respectively;
◦the changes in other current assets decreased cash flows by $20 million, which was primarily due to the timing of 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 $39 million for IDACORP and increased operating cash flows by $16 million for Idaho Power (the difference relates to the timing of estimated income tax payments from Idaho Power to 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 the allowance for borrowed funds used during construction,AFUDC, were $297 million, $294$279 million and $274$278 million in 2016, 2015,2019 and 2014,2018, 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 $8$2 million and $11$22 million in 20162019 and 20152018 from Boardman-to-Hemingway project joint permitting participants relating to a portion of these constructionpermitting expenditures.

Table of contents


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 $15equity securities of $11 million $14 million,in both 2019 and $8 million of available-for-sale securities in 2016, 2015, and 2014, respectively. In 2016 and 2015,2018. Idaho Power received $16$5 million and $34 million, respectively, of proceeds from the sales of available-for-saleequity securities in both 2019 and used $10 million and $30 million of the proceeds, respectively, to acquire company-owned life insurance.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 2016, 2015,2019 and 2014:2018:


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 10, 2016,2018, Idaho Power issued $120$220 million in principal amount of 4.05%4.20% first mortgage bonds Series J,K, maturing March 1, 2046;2048;
onin April 11, 2016,2018, Idaho Power redeemed, prior to maturity, $100$130 million of its 6.15%4.50% first mortgage bonds, Series H, due AprilMarch 1, 2019,2020, and paid a related make-whole premium of $14 million;
on March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, Series J, maturing on March 1, 2045;
on April 23, 2015, Idaho Power redeemed, prior to maturity, $120 million in principal amount of 6.025% first mortgage bonds, medium-term notes due July 2018, and paid a related make-whole premium of $18$4.6 million;
IDACORP and Idaho Power paid dividends of approximately $105 million, $97$130 million and $88$121 million in 2016, 2015,2019 and 2014, respectively;2018, respectively.
IDACORP's net change in commercial paper borrowings provided cash of $2 million in 2016 and used cash of $11 million and $23 million in 2015 and 2014, respectively; and
Idaho Power borrowed $22 million in commercial paper in December 2016.


Financing Programs and Available Liquidity


IDACORP Equity Programs:In recent years From time to time, IDACORP has enteredenters into sales agency agreements under which IDACORP could offerit offers and sellsells shares of its common stock from time to time through BNY Mellon Capital Markets, LLC as IDACORP'sa third-party agent. The most recent sales agency agreement terminated in May 2016, but2016. IDACORP may choosehas no current plans to enter into a new sales agency agreement in the future. On May 20, 2016, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the potential offerissue equity securities other than under its equity compensation plans during 2020, and sale of an unspecified amount of shares of common stock. Asas of the date of this report, IDACORP is assessing whether to executehas not pursued the execution of a new sales agency agreement for the issuance and sale of common stock, as the company does not anticipate issuing any shares of its common stock outside of its equity or deferral compensation programs in 2017.agreement.


Since 2012, IDACORP has not used original issue shares of common stock for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan or the Idaho Power Company Employee Savings Plan, but instead plan administrators have used market purchases of IDACORP common stock. However, IDACORP may determine at any time to use original issuances of common stock under those plans. As noted above, an important component of that determination will be IDACORP's and Idaho Power's capital structure.

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 Powerthe company to issue and sell from time to time up to $500 million in aggregate principal
Table of Contents

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.


On September 27, 2016,In May 2019, Idaho Power entered intofiled a selling agency agreement with seven banks named in the agreement in connectionshelf registration statement with the potential issuanceSEC, which became effective upon filing for the offer and sale from time to time of up to $500 million in aggregatean 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
Table of contents

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 had not sold any 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, 2016,2019, was limited to approximately $759$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, 2016,2019, Idaho Power could issue approximately $1.7$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 45 - “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
Table of Contents

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, 2016,2019, the leverage ratios for IDACORP and Idaho Power were 4543 percent and 4745 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, 2016,2019, 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 2017.2020.


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
Table of contents

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 with the consent of all the lenders, extending the maturity date under both credit agreements to November 5, 2021. 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: specified (in thousands):
 December 31, 2016 December 31, 2015 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 —
 (21,800) (20,000) —
 —
 —
 —
 -
Identified for other use(1)
 —
 (24,245) —
 (24,245) —
 (24,245) —
 (24,245)
Net balance available $100,000
 $253,955
 $80,000
 $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.
(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.
(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.
(2) Holding company only.
(2) Holding company only.
Table of contents

The table below presents additional information about short-termIDACORP and Idaho Power had no short term commercial paper borrowingoutstanding during the years ended December 31, 20162019 and 2015:
  December 31, 2016 December 31, 2015
  
IDACORP(1)
 Idaho Power 
IDACORP(1)
 Idaho Power
Commercial paper:        
Year end:        
Amount outstanding $—
 $21,800
 $20,000
 $—
Weighted average interest rate —% 1.13% 0.88% —%
Daily average amount outstanding during the year $15,692
 $438
 $22,054
 $—
Weighted average interest rate during the year 0.82% 1.13% 0.53% —%
Maximum month-end balance $23,900
 $21,800
 $43,400
 $—
(1) Holding company only.
        
2018. At February 17, 2017,14, 2020, IDACORP had no loans outstanding under its credit facility and no commercial paper outstanding,
Table of Contents

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 DebtNoneA-


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, 2016,2019, Idaho Power had posted no$1.4 million of performance assurance collateral.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, 2016,2019, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $11.6$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.
 
Table of contents

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 $287$268 million during the year ended December 31, 2016.2019. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated cash requirementsaccrual-basis additions to electric plant for construction, excluding AFUDC, for 20172020 through 20212024 (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.
  2017 2018 2019-2021
Expected capital expenditures (excluding AFUDC) $290-300 $285-295 $900-950
  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 20172020 through 20212024 and estimated costs include the following:

Table of Contents


$35-$65 million per year for construction and replacement of transmission system projectslines and stations other than the Boardman-to-Hemingway and Gateway West projects;
$75-85-$95125 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
$25-15-$4535 million per year for ongoing improvements and replacements at coal- and natural gas-firedthermal plants;
$45-60-$6595 million per year for hydroelectrichydropower plant improvement programs, including relicensing and mitigation costs; and
$45-40-$6560 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.


Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners recently completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NOx) 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 NOx reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power has expended $100 million, excluding AFUDC, on SCR installation at units 3 and 4 through December 31, 2016. 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 uncertainty resulting from pending environmental regulation and the substantial estimated cost of the SCR installation, as of the date of this report, Idaho Power is assessing 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.

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kVhigh-voltage transmission project between a stationsubstation near Boardman, Oregon, and the Hemingway stationsubstation near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power’s 2015 IRP. 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. Assuming both other participants fund their full share of the total cost of the permitting phase of the project, Idaho Power's estimated share of the cost of the permitting phase of the project is approximately $44 million, including Idaho Power's AFUDC. 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 towhich includes approximately $45$105 million of Idaho Power's share of estimated costs related to design and early construction, effortswhich are primarily included in the periods 2019-2021.table in the period 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.

Table of contents

Approximately $87 million has been expended on the Boardman-to-Hemingway project through December 31, 2016. Pursuant to the terms of the joint funding arrangements, Idaho Power has received approximately $42 million of that amount as reimbursement from the project participants as of December 31, 2016. Idaho Power has accrued in receivables approximately $16 million more that will be billed by Idaho Power in the future to the project participants for expenses Idaho Power has incurred, for a total amount reimbursable by joint permitting participants of $58 million. In addition to the $58 million amount, $6 million is subject to reimbursement at a later date from the joint permitting participants, assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.


The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, the Army Corps of Engineers, and certain other federal agencies. The BLM as the lead federal agency on the National Environmental Policy Act review, issued a final environmental impact statement (EIS)its record of decision for the project onin November 25, 2016. As2017, 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. In September 2019, the Department of the Navy issued its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands. In November 2019, third parties filed a lawsuit in the federal district court of 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, the BLM's schedule provides for the issuance of a record of decision in 2017. report.

In the separate Oregon state permitting process, Idaho Power expects its amended preliminary application for site certificate to be deemed complete by the Oregon Department of Energy (ODOE) issued a Draft Proposed Order in 2017.May 2019 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The ODOE is expected to issue a Proposed Order in the first half of 2020. Idaho Power is unablecurrently expects the EFSC to determine an in-service date for the line but, givenissue a final order and site certificate in 2021. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date wouldfor the transmission line will be in 20232026 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-kVhigh-voltage transmission lines project between a stationsubstation 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's estimated cost for the permitting phase of the Gateway West project is approximately $60 million, including AFUDC. Idaho Power has expended approximately $32$41 million, onincluding Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2016.2019. 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 $200$250 million and $400$450 million,
Table of Contents

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 in addition to approximately $35 million ofabove. Idaho Power's share of costs related to early construction efforts primarily in the periods 2019-2021. These preliminary estimates of Idaho Power’s share ofpotential early construction costs could significantly change asare excluded from the capital requirements table above because the timing of construction timeline nears and asof Idaho Power's portion of the project participants further align on future activities and estimates.is uncertain.


The permitting phase of the Gateway West project iswas 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. On January 20,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 releasedpublished its record of decision for the remaining two transmission line segments. In September 2016, the U.S. Department of Interior Board of Land Appeals affirmed the BLM's November 2013 record of decision, which was challenged by certain third-parties. In February 2017, the State of Idaho and others filed with the U.S. Department of Interior Board of Land Appeals notices of appeal and requests for a stayoutstanding portions of the BLM’s recordremaining segments. PacifiCorp is currently constructing a 140-mile segment of decision.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 hydroelectrichydropower 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 $25$30 million to $35$40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2021.2022. 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. Refer to "Regulatory Matters"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 this MD&Aretail rates in a future rate proceeding. In April 2018, the IPUC issued an order approving 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 additional details relating to the relicensing process.inclusion in customer rates at a later date.


Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for the installation ofits 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""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 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.


Table of contents

Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. Idaho Power filed its most recent IRP in June 2015 and expects to file its 2017 IRP in June 2017. 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 resourcetransmission options, and identifies potential near-term and long-term actions. The 2015 IRP included as near-term action items the continued permitting and planning for the Boardman-to-Hemingway transmission line and further investigation of the early retirement of the North Valmy power plant in collaboration with the plant's co-owner. Idaho Power filed applicationsits most recent IRP with the IPUC and OPUC in OctoberJune 2019, which was amended in January 2020. The 2019 IRP identified a preferred resource portfolio and November 2016, respectively, requesting accelerated depreciationaction plan, which includes the completion of the Boardman-to-Hemingway transmission line in 2026, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant in connection with the potential early closure of the plant, which remain pending. The near-term action plan also included commencement of an economic evaluation of environmental control retrofits for units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger power plant.plant by 2030, with the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the addition of a 120 megawatt (MW) solar resource in 2022. However, as noted in the 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 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 uncertainties, as well as others, 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 2015 IRP and 20172019 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
Table of Contents

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, $39 million, and $30 million to its defined benefit pension plan in 2016, 2015,each of 2019 and 2014, respectively.2018. Idaho Power's minimum required contribution to be made during 2020 is estimated to be $14 million. Depending on market conditions and cash flow considerations, Idaho Power estimates that it has no minimum contribution requirement for 2017, though it planscould contribute up to contribute between $20 million and $40 million to the pension plan during 2017.2020. 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. In 2017 and beyond,Beyond 2020, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 11 - "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. As ofAt December 31, 2016,2019 and 2018, Idaho Power's deferral balance associated with the Idaho jurisdiction was $105 million.$173 million and $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. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Table of contentsContents




Contractual Obligations


The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2016,2019, for the respective periods in which they are due:
  Payments Due by Period
  Total 2017 2018-2019 2020-2021 Thereafter
  (millions of dollars)
Long-term debt(1)
 $1,766
 $1
 $—
 $230
 $1,535
Future interest payments(2)
 1,464
 82
 163
 151
 1,068
Operating leases(3)
 48
 3
 8
 8
 29
Purchase obligations:  
  
  
  
  
Cogeneration and small power production(4)
 4,309
 229
 465
 465
 3,150
Fuel supply agreements 206
 57
 31
 17
 101
Other(4)
 181
 39
 40
 22
 80
Pension and postretirement benefit plans(5)
 246
 8
 78
 115
 45
Other long-term liabilities 1
 1
 —
 —
 —
Total $8,221
 $420
 $785
 $1,008
 $6,008
(1) For additional information, see Note 4 – “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, 2016.
(3) The operating leases include right-of-way easements. Approximately $13 million of the obligations included 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.
(4) Approximately $6 million of the amounts in cogeneration and small power production and $23 million of the amounts in other purchase obligations 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. Other purchase obligations also includes Idaho Power's estimated proportionate funding obligation for goods and services under non-fuel purchase agreements at its jointly-owned generation facilities. In some instances, Idaho Power is not a direct party to an underlying purchase agreement, but is obligated under the instruments governing the joint ventures to reimburse the co-owner for payments the co-owner makes pursuant to the purchase agreement. Those estimated amounts have been included in the table above.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2021 with any level of precision, and amounts through 2021 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 11 – "Benefit Plans" to the consolidated financial statements included in this report.
  Payments Due by Period
  Total 2020 2021-2022 2023-2024 Thereafter
  (millions of dollars)
Long-term debt(1)
 $1,856
 $100
 $75
 $125
 $1,556
Future interest payments(2)
 1,441
 79
 150
 144
 1,068
Purchase obligations:  
  
  
  
  
Maintenance and service agreements(3)
 148
 48
 30
 14
 56
FERC and other industry-related fees(3)
 132
 14
 27
 26
 65
Cogeneration and small power production 4,010
 242
 500
 529
 2,739
Fuel supply agreements 192
 56
 44
 17
 75
Other(3)(4)
 48
 3
 8
 7
 30
Pension and postretirement benefit plans(5)
 323
 26
 117
 128
 52
Other long-term liabilities - IDACORP only(3)
 2
 —
 —
 —
 2
Total(6)
 $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, 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.
(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 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.


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,
Table of Contents

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 2014, 2015,2019 and 2016,2018, IDACORP's board of directors voted to increase the quarterly dividend to $0.47 per share, $0.51$0.67 per share and $0.55$0.63 per share of IDACORP common stock, respectively. IDACORP's dividends during 20162019 were 5355.5 percent of actual 20162019 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 67 – “Common Stock” to the consolidated financial statements included in this report.


Table of contents

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 $71$58.3 million at December 31, 2016,2019, representing IERCo's one-third share of BCC's total reclamation obligation of $212$175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2016,2019, the value of the reclamation trust fund totaled $78$139.5 million. During 2016,2019, the reclamation trust fund distributed approximately $6 millionmade 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 addshas the ability to, and does, add a per-ton surcharge to coal sales.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 strategyfilings takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of ratethese 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 a2011. In 2012, large single-issue rate casecases 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
Table of Contents

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 reducemitigate 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. During 2017, Idaho Power plans to continuecontinues to assess itsthe need to file, and timing of filing a general rate case in its two retail jurisdictions, based on its consideration of the factors described above.above, but does not anticipate filing a general rate case in 2020.


Notable Retail Rate Changes in Idaho and Oregon


Included in the table that follows are notable regulatory developments during 2014, 2015,2019 and 20162018 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 foralso provides a description of regulatory mechanism and associated orders of the IPUC and OPUC, whichand should be read in conjunction with the discussion of regulatory matters in this MD&A.
Table of contents

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.
Description Effective Date 
Estimated Annualized Revenue Impact (millions)(1)
2014 Idaho FCA(2)
 6/1/2014  $6
2014 Idaho PCA(2)(3)
 6/1/2014  (88)
Transfer of power supply costs from the Idaho PCA mechanism to Idaho base rates(4)
 6/1/2014  99
2015 Idaho FCA(2)
 6/1/2015  2
2015 Idaho PCA(2)(5)
 6/1/2015  (12)
2016 Idaho FCA(2)
 6/1/2016  11
2016 Idaho PCA(2)(6)
 6/1/2016  17
      
(1) The annual amount collected in rates is typically not recovered on a linear basis (i.e., 1/12th per month), and is instead recovered in proportion to general business sales volumes.
(2) The rate changes for the Idaho PCA and FCA are applicable only for one-year periods. Similarly, a portion of the rate changes from the Oregon APCU are applicable only for one-year periods.
(3) 2014 PCA rates reflect (a) the application of $20.0 million of surplus Idaho energy efficiency rider funds, (b) $8.0 million of customer revenue sharing for the year 2013 under a regulatory settlement agreement approved in December 2011, and (c) a $99.0 million shift in base net power supply expenses from recovery via the PCA mechanism to recovery through base rates.
(4) See footnote (3) above. Approval of the transfer of collection of specified power supply costs from the Idaho PCA mechanism to Idaho base rates resulted in no net change in customer rates.
(5) 2015 Idaho PCA rates reflect the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of a December 2011 settlement stipulation, (b) a $1.5 million customer benefit relating to a change to the PCA methodology described below, and (c) $4.0 million of surplus Idaho energy efficiency rider funds.
(6) 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.


Idaho and Oregon General Rate Cases and Base Rate Adjustments




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. OnIn September 20, 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.

Table of contentsContents


Non-Base Rate
Other Notable Regulatory Matters

October 2014 Idaho Regulatory Settlement Stipulations

Earnings Support and Sharing Settlement Stipulation for 2012 to 2014: In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional 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. The more specific terms and conditions of the December 2011 Idaho settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. Under the December 2011 settlement stipulation, when Idaho Power's actual Idaho ROE for any of those years exceeded 10.0 percent, Idaho Power was required to share a portion of its Idaho-jurisdiction earnings with Idaho customers.

Settlement Stipulation for 2015 to 2019: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of thea December 2011 Idaho 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 was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho 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 stipulationIdaho 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. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "May 2018 Idaho Tax Reform 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.
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
2019 $—
 $—
 $—
2018 5.0
 —
 5.0
2017 —
 —
 —
2016 —
 —
 —
2015 3.2
 —
 3.2
2014 8.0
 16.7
 24.7
2013 7.6
 16.5
 24.1
2012 7.2
 14.6
 21.8
2011(1)
 27.1
 20.3
 47.4
Total $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.

May 2018 Idaho Tax Reform 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 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 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 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, 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 its term. IDACORP and Idaho Power believe that the terms
Table of Contents

allowing amortization of additional ADITC in the October 2014 settlement stipulationMay 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.

In 2016, Idaho Power's Idaho ROE was between 9.5 and 10.0 percent, and thus Idaho Power recorded no additional ADITC amortization and no provision for sharing with customers. Accordingly, at At December 31, 2016,2019, the full $45 million of additional ADITC remainsremained available for future use under the terms of the settlement stipulation.May 2018 Idaho Tax Reform Settlement Stipulation.

Idaho Power recordedAlso in May 2018, the following 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
2016 $— $—
2015 $3.2 $—
2014 $8.0 $16.7
2013 $7.6 $16.5
2012 $7.2 $14.6

Modifications to Idaho Annual Rate Adjustment Mechanisms

PCA Mechanism: In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties evaluated Idaho Power's application of the true-up component of the PCA mechanism. The July 2014 docket arose from a priorOPUC issued an order of the IPUC, which noted that the IPUC Staff believed that Idaho Power's application of the true-up component introduced a line-loss bias that inflated the true-up revenue that Idaho Power collects under the PCA. In May 2015, the IPUC approvedapproving a settlement stipulation that modifiedprovides 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 calculationOPUC 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 true-up component oftax-related revenue requirement components are reflected in rates.

For more information on the PCA mechanism. The mechanics of the PCA mechanismsettlement stipulations and the terms of the PCA settlement stipulation are described intheir impacts on results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

FCA Mechanism:Also in July 2014,Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC openedapproved a docket to allowsettlement 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 Staff,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 interested partiesexit 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 further evaluatepursue 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: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 applies a corresponding kWh credit to the customer’s bill. In May 2018, the IPUC Staff's concerns regardingissued an order authorizing the applicationcreation of the FCA. Concerns cited included the application of weather-normalization, thetwo new customer count methodology, the rate adjustment cap, cross-subsidization issues, and whether the FCA is in fact effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs.

The FCA is designed to remove 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.  Stated generally, under the FCA Idaho Power chargesclasses for residential and small commercial customers when it recovers less "actual fixedwho install their own on-site generation, with no change to pricing or compensation. Since October 2018, Idaho Power has initiated two cases related to studying the costs per customer" thanand benefits of customer-owned generation on Idaho Power’s system, and exploring whether, and to what extent, there should be modifications to the base level of fixed costs that thecustomer-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 authorized for recovery through ratesissued orders in the last general rate case,Residential and Small Commercial Case during December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to
Table of Contents

the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) continue to allow customers with on-site generation prior to December 20, 2019, to be subject to the 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 credits those customers whendoes not expect these cases to materially affect its "actual fixed costs per customer" recovered exceed that base levelfinancial condition or results of fixed costs. The FCA is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.
operations.
Table of contents

In years when actual sales per customer are higher than weather-normalized sales due to high summer or low winter temperatures, Idaho Power expects that the new FCA methodology will be less favorable to Idaho Power than the prior methodology. Conversely, Idaho Power expects that the new FCA methodology will be more favorable to Idaho Power in years when actual sales per customer are lower than weather normalized sales due to cooler summer or warmer winter temperatures.


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 or refund(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 hydroelectrichydropower generation conditions, market energy prices and the volume of off-systemwholesale 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.

As noted above under the heading "Idaho and Oregon General Rate Cases and Base Rate Adjustments," in light of the existence of permanent increases in power supply costs, in March 2014 the IPUC issued an order approving Idaho Power's application requesting recovery of a portion of its ongoing power supply costs through base rates rather than through the PCA mechanism.


The following table summarizes the change in deferred (accrued) net power supply costs over the prior two years.last year (in millions):
  Idaho 
Oregon(1)
 Total
Balance at December 31, 2014 $54,512
 $4,677
 $59,189
Current period net power supply costs deferred 35,802
 —
 35,802
Revenue sharing (7,999) —
 (7,999)
Energy efficiency rider funds (4,000) —
 (4,000)
Prior amounts recovered through rates (32,519) (2,294) (34,813)
SO2 allowance and renewable energy certificate (REC) sales
 (1,575) (70) (1,645)
Interest and other 335
 351
 686
Balance at December 31, 2015 44,556
 2,664
 47,220
Current period net power supply costs deferred 43,841
 —
 43,841
Revenue sharing (3,171) —
 (3,171)
Energy efficiency rider funds (3,970) —
 (3,970)
Prior amounts recovered through rates (27,316) (2,502) (29,818)
SO2 allowance and renewable energy certificate (REC) sales
 (874) (41) (915)
Interest and other 376
 307
 683
Balance at December 31, 2016 $53,442
 $428
 $53,870
(1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million).  Deferrals are amortized sequentially.
  Idaho Oregon Total
Balance at December 31, 2018 (42.1) (0.2) (42.3)
Current period net power supply costs accrued (49.2) —
 (49.2)
Revenue sharing (5.0) —
 (5.0)
Western EIM cost recovery to be collected through Idaho PCA 3.2
 —
 3.2
Prior amounts refunded through rates 51.4
 0.1
 51.5
SO2 allowance and REC sales
 (5.0) (0.2) (5.2)
Interest and other (1.5) —
 (1.5)
Balance at December 31, 2019 $(48.2) $(0.3) $(48.5)
 
Table of contents


Anticipated Participation in Western Energy Imbalance Market

In January 2017, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment for costs associated with joining the Western EIM.  Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of the costs and the deferral balance or the end of 2018. Idaho Power anticipates that it will begin participating in the Western EIM in the spring of 2018. 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. Refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report for additional information relating to Idaho Power's anticipated participation in the Western EIM.

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 2016,2019, Idaho Power filed its 20162019 final transmission rate with the FERC, reflecting a transmission rate of $25.52$27.32 per kW-year, to be effective for the period from October 1, 2016,2019, to September 30, 2017.2020. 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 $127.4$107.0 million. The OATT rate in effect from October 1, 2018, to September 30, 2019, was $31.25 per kW-year based on a net annual transmission revenue requirement of $123.1 million. The decrease in the OATT rate is largely attributable to federal tax reform and increased short-term firm and non-firm transmission revenues in 2018, which 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.

Transmission Revenues Associated with Asset Exchange Transaction

Effective in October 2015, Idaho Power and PacifiCorp each transferred to the other certain interests in transmission-related equipment. In connection with that transaction, the companies terminated or amended a number of long-term agreements between Idaho Power and PacifiCorp related to the ownership and operation of transmission-related equipment and transmission services. In 2014, Idaho Power collected approximately $8 million in transmission revenues under long-term transmission agreements that were terminated in connection with the asset exchange transaction. As a result of the transaction and termination of those long-term transmission agreements, Idaho Power's OATT rate increased; however, in accordance with a FERC order, the current formula rate methodology will phase in the increase over a two-year period from October 1, 2016 through September 30, 2018.

In compliance with the IPUC's order approving the asset exchange transaction, Idaho Power submitted to the IPUC a request for verification that its regulatory accounting method reflecting a symmetrical tracking of changes in transmission revenues resulting specifically from the asset exchange with PacifiCorp complies with the IPUC’s order. As an alternative proposed by Idaho Power to its symmetrical tracking, in August 2016, the IPUC ordered that any changes in transmission revenues resulting from the asset exchange will be addressed, prospectively, in Idaho Power's next general rate case.

Depreciation Rate Requests

In October and November 2016, Idaho Power filed applications with the IPUC and OPUC, respectively, requesting authorization to (a) accelerate depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31, 2025, (b) establish a balancing account to track the incremental costs and benefits associated with the accelerated depreciation date, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement in an aggregate amount of $29.6 million. Idaho Power also filed applications with the IPUC and OPUC requesting approval to institute revised depreciation rates for Idaho Power's other electric plant-in-service and adjust base rates by an aggregate of $7.4 million to reflect the revised depreciation rates applied to electric plant-in-service balances subject to the most recent general rate case. The depreciation filings are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.


Relicensing of HydroelectricHydropower Projects
 
Overview: Idaho Power, like other utilities that operate non-federal hydroelectrichydropower projects on qualified waterways, obtains licenses for its hydroelectrichydropower 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 hydroelectrichydropower projects are recorded in construction work in progress until a new multi-year license islicenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power will submitexpects to seek recovery of relicensing costs and costs related to a new licenses to regulators for recoverylong-term license through
Table of contentsContents


through the ratemaking processregulatory 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 December 2016, submitted a requestexpenditures incurred for a determination of prudency, which is described below. As ofrelicensing through December 31, 2016, relicensing2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date. Relicensing costs of $249$326 million (including AFUDC) for the HCC, Idaho Power's largest hydroelectrichydropower complex and a major relicensing effort, were included in construction work in progress.progress at December 31, 2019. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5$8.8 million annually ($10.7 million when grossed-up for the effect of income taxes) 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 nowcurrently will reduce the amount collected in the future oncecollections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2016,2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $103$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 hydroelectrichydropower 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 hydroelectrichydropower 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 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 EISenvironmental 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 filingfiled and withdrawingwithdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it has beenwas 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, specifically forbidsprovided that Idaho Power from reintroducing certaintake no action that might result in the reintroduction or establishment of spawning populations of any fish protected under the ESA,species into Idaho's waters. Onwaters without consultation with and express approval of the State of Idaho. In November 30, 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 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. AsIn 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 2019, the states of Idaho and Oregon, along with Idaho Power, reached a 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 first 20 years of the new 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 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
Table of Contents

certification. On December 30, 2019, Idaho Power filed an Offer of Settlement with the 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 its decision relating to the Offer of Settlement is pending as of the date of this report,report. Idaho Power is considering other actions it may takecontinues to obtain a resolution ofexpect the issue.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 ofon measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water qualityand 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 begunMeasures identified in the process forfinal Section 401 certifications included construction of new aerated runners at the Brownlee project (part of the HCC) at an estimated cost of $50 million. The first of four units was installed in 2016 and Idaho Power plans to install one unit in each year from 2017 through 2019. Other measures that have been proposed or considered have included, modification of spillways at twothe three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements or the installation of a temperature control structure to address water temperatures during a small portion of the year. If Idaho Power is required to take these orThese and any other additional measures to satisfy relicensing requirements it couldhave added and will add substantially to
Table of contents

project costs. Idaho Power continues to work with the Oregon and Idaho Departments of Environmental Quality on the water quality certification issue and the water quality measures that will be required to obtain 401 certification.


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 $25$30 million to $35$40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2021. In light of the costs incurred and the considerable passage of time, 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.2022.


Renewable Energy Standards and Contracts


Renewable Portfolio Standards: Numerous proponentsMany states have introducedenacted legislation in the U.S. Congress that would require electric utilities to obtain a specified percentage of their electricity from renewable sources,sources. These requirements are commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no federal or 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 Renewable Energy Certificates (REC)RECs obtained from the purchase of powerenergy 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%95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, 2016, 2015,2019, and 2014,2018, Idaho Power's REC sales totaled $1.0 million, $1.8$5.5 million and $3.2$2.9 million, respectively.  The comparative decrease in REC sales resulted primarily from the elimination of a REC purchase and sale agreement with a third party.


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 December 2012 described below, 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.


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

Table of December 31, 2016, Idaho Power had contracts to purchase energy from 117 on-line CSPP projects, twelve additional projects expected to come on-line in 2017, and three projects expected to come on-line in 2019. Contents

The following table sets forth, as of December 31, 2016,2019, the resource type and nameplate capacity of Idaho Power's signed CSPPagreements for power purchases from PURPA and non-CSPP related agreements.non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.
Table of contents

Resource Type Total On-line (MW) Began operating during 2016 (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)
CSPP: 
PURPA:      
Wind 577 — 50 627 627
 —
 627
Solar 170 170 129 299 310
 9
 319
Hydroelectric 148 1 8 156
Hydropower 147
 2
 149
Other 50 — — 50 52
 —
 52
Total CSPP 945 171 187 1,132
Non-CSPP:      
Total PURPA 1,136
 11
 1,147
Non-PURPA:      
Wind 101 — — 101 101
 —
 101
Geothermal 35 — — 35 35
 —
 35
Total non-CSPP 136 — — 136
Solar —
 120
 120
Total non-PURPA 136
 120
 256
 
All but three of theThe projects not yet on-line are expected to be on-line no later than mid-year 2017 (threeinclude one hydropower PURPA project and 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 April 2015, Idaho Power made filings withSeptember 2019, the OPUC requesting, among other things,FERC issued a reduction in the termNotice of standardProposed 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 from 20 years to two years for projects above 100 kW, inwith utilities, and how parties can contest the eligibility of a manner consistent with its Idaho jurisdiction where the IPUC reduced the length of PURPA contracts that involve avoided-cost-based pricing to two years, and a temporary suspension of Idaho Power's obligation to enter into new fixed-price standard PURPA agreements during the pendencygeneration facility seeking QF status. As of the proceedings. In March 2016, the OPUC issued an order permanently reducing the eligibility cap for solar project standard contracts to 3 MW, with all other resource types retaining an eligibility capdate of 10 MW. In its order, the OPUC retained the requirement for up to 20-year contract lengths for Oregon jurisdictional projects, comprised of 15 years of fixed prices and five years of market index prices.

In June 2016, the FERC held a technical conference on implementation issues under PURPA, including the mandatory power purchase obligation and the methods for determining avoided costs for those purchases. The conference also involved a discussion of PURPA project siting issues and minimum contract term lengths. In September 2016, the FERC filed a notice inviting post-technical conference comments on (1) the use of the "one-mile rule" to determine the size of an entity seeking certification as a small power production qualifying facility and (2) minimum standards for PURPA-purchase contracts. In November 2016, Idaho Power provided comments to the FERC specifically addressing Idaho Power’s position regarding the two items of which the FERC invited comments.this report, Idaho Power is unable to predict what policy or rulemaking actions or proceedings, if any,determine the impact of these potential changes on PURPA-related issues will result from the technical conference.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 isPower'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 CAA,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 hydroelectrichydropower projects are also further subject to a number of water discharge standards and other environmental requirements.

Table of contents


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.


Table of Contents

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. Idaho Power filedThe decision to pursue an application with the IPUC and OPUCend to participation in October and November 2016, respectively, requesting accelerated depreciation ofcoal-fired operations at the North Valmy plant in connection withwas also based primarily on the potential early closureeconomics of operating the plant. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of SCR controls, Idaho Power is assessing whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger coal-fired power plant.

In addition toBeyond 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 20172020 to 2019.2022. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond 2019,2022, though they could be substantial. Furthermore, the recent presidential and congressional elections in the United Statesseveral executive orders issued since 2017 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. 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 may delay making operational changesis 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 environmental-related expenditures while such changes are pending to avoid implementing uncertain laws, rules, and policies.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 hydroelectrichydropower 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,November 2018, the U.S. FishSupreme 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 Wildlife Service (USFWS)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 policy changes relating toreclassifications, and critical habitat and adverse modification determinations under the ESA.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 resultreduce the role of climate change models in listing decisions and the applicable agencies having greater authority in making 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 could increase the likelihood of adverse modification determinations.relicensing projects.


The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's hydroelectrichydropower 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 hydroelectrichydropower 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 hydroelectrichydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may
Table of Contents

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


Table of contents

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 transferedtransferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. As of the date of this report, 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 20172020 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 hydroelectrichydropower 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
Table of Contents

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 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 hydroelectrichydropower 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 hydroelectrichydropower 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;
Table of contents

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 adversely affect hydroelectrichydropower 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-emittinggreenhouse 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 ended its participation in coal-fired operations at the North Valmy plant unit 1 in December 2019 and plans to end its participation in unit 2 in 2025, 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 position,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; Final Rule Under CAA Section 111(d): Clean Power Plan/Affordable Clean Energy Rule: The EPAU.S. Environmental Protection Agency (EPA) has become increasinglybeen 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.


Table of Contents

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. The final rule “tailors” the requirements of these CAA permitting programs to limit which facilities will be required to obtain Prevention of Significant Deterioration (PSD) and Title V permits. The rules require the use of "best available control technology" for GHG emissions if a new major source or modification of an existing major source is projected to result in GHG emissions of at least 75,000 tons per year (CO2 equivalent). In addition, Title V permit renewals or modifications for existing major sources must include applicable requirements relating to GHGs. While the rules arerule 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. OnIn August 3, 2015, the EPA released the final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan (CPP), which requiresrequired states to adopt plans to collectively reduce 2005 levels of power sector CO2 emissions by 32 percent by the year 2030. In June 2019, the EPA released the ACE rule to replace the CPP under Section 111(d) of the CAA for existing electric utility generating units. The finalnew rule provides states until September 2018with new emissions guidelines that inform the state development of standards of performance to submit implementation plans, phasing in severalreduce CO2 emissions from existing generation facilities and is limited to reduction and compliance periods beginning in 2022 and achievingmeasures that occur at the final emissions goals by 2030.

On February 9, 2016,physical location of each plant, removing the U.S. Supreme Court issued an order stayingproposal to require reductions outside the boundaries of plants. The ACE rule also provides for more state-specific control over implementation of the rule pendingto 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 completion of certain legal challenges, which has an uncertain impact onEPA by July 2022. In August 2019, twenty-two states sued the ultimate timeline for implementation ofEPA in federal appeals court to challenge the ACE rule. Idaho Power's owned and co-owned generation facilities are in the states of Idaho, Nevada, Oregon, and Wyoming. Despite the current stay on implementation, Idaho Power is working with state representatives, neighboring utilities, and others as it analyzes the rule and prepares for compliance.

Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the 2016 U.S. presidential and congressional elections, as of the date of this report Idaho Power is unableuncertain whether and to determinewhat extent the financial or operational impactsACE rule may impact its operations in the near term. Idaho Power's preliminary review of the final rule.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.
Table of contents



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 may requirerequires certain large 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, but in May 2007, Idaho’s governor issued Executive Order 2007-05, which directed the Idaho Department of Environmental Quality to work with the state government to implement GHG reductions within each agency, complete a statewide emissions inventory, and provide recommendations to the governor, among other tasks.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 emissionemissions reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emissionemissions 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 (NSR/PSD)
Rules, and the Regional Haze Rule.


MATS Implementation:The final MATS rule under the CAA, previously referred to as the Utility MACTMaximum 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
Table of Contents

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, which does not significantly impact Idaho Power’s operations or financial results.


Table of contents

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, nitrogen dioxide,NO2, and sulfur dioxide.SO2. States are then required to develop emissionemissions 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:


•
NOx2:In 2010, the EPA adopted a new NAAQS for NOx2 at a level of 100 parts per billion averaged over a 1-hourone-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 NOx2. 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 NOx. 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.


•
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. As a result,Since January 2018, the EPA is waiting to propose designation actionshas finalized designations of “unclassifiable/attainment” for those states, and is likely to proceed with designation actions once additional data is gathered.SO2 for all areas in which Idaho Power expectsowns or has an interest in a natural gas or coal-fired power plant.

•
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 Nevada and Wyoming will also be addressedall of the counties in which Idaho Power owns or has an interest in a separate future action.natural gas or coal-fired power plant and determined that they meet the standard.


Ozone: In late 2014,As of 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. On October 1, 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 majoritydate of U.S. counties will meet the standards by 2025 with federalthis report and state rules and programs now in place or underway. The EPA's plan provides for finalizing non-attainment designations in 2017, and it plans to propose rules and guidance over the next year to help states with potential non-attainment areas implement the revised standards. Non-attainment areas will have until 2020 to late 2037 to meet the new standard, with attainment dates varying based on the ozone level in the area. Due to high levels of background ozone, which can be caused by factors such as elevation, vegetation, wildfire, and international transport, attainment in areas within the Intermountain West may be difficult, and the formulation of state implementation plans to bring an area into compliance with the new standard may be challenging due to the existence of ozone caused by factors outside of local control. If the EPA were to make non-attainment determinations in areas wheredesignations described above, Idaho Power owns or co-owns power plants, or proposes to construct power plants, the state implementation plan for those areas could result in changes to the nature and frequency of operation of existing generation plants and make more difficult or costly the construction of new power generation plants. Idaho Power will seek to work with state regulators on implementation plans for any non-attainment areas, in an effort to reduce the potential adverse impact on Idaho Power's operation of its existing power generation plants and construction of future facilities.

Because the EPA hasdoes not yet completed the designation of areas as attaining or not attaining the NAAQS for NOx, SO2, and ozone, Idaho Power is unable to predict what impact the adoption and implementation ofexpect these standards may have onto significantly impact its operations though it does expect at least some increases inor materially increase Idaho Power’s capital and operating costs from the standards if areas in which Idaho Power operate, or adjacent areas, receive non-attainment designations.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 Wyoming Department of Environmental Quality (WDEQ)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 SCRselective catalytic reduction (SCR) equipment for NOnitrogen oxide (NOx) 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 NOx controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022.2022, which was submitted in December 2017. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under
Table of contents

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 NOx 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'sWDEQ 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 extentcompliance plan for the Jim Bridger plant could be affected.that includes a reduced plant-wide monthly limit on emissions for NOx and SO2 and an annual total emissions cap of NOx and SO2 for units 1-4. If approved as proposed, the alternative plan would likely eliminate the requirement to install add-on NOx controls at Jim Bridger units 1 and 2. If the compliance plan as proposed is not approved by WDEQ and finalized, Idaho Power

Table of Contents

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'sEPA and U.S. Army Corps of Engineers' (USACE) final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective.effective (WOTUS Rule). Idaho Power believes that the final2015 rule potentially expandsexpanded 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. As a result ofThe WOTUS Rule was widely challenged in both federal district and circuit courts. In January 2020, the potential expansion,EPA and USACE finalized the final rule may result in additional permittingto repeal the WOTUS Rule and regulatory requirements under multiple provisions ofset new and more expansive standards for determining which waters are subject to the CWA. CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule.

Idaho Power has analyzedbelieves the finalrepeal rule and the WOTUS Rule will continue to 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 andarea. Similarly, because the existing application ofCWA, as interpreted even prior to the CWAWOTUS Rule, applies to most of Idaho Power's facilities, including its hydroelectric plants.hydropower plants, Idaho Power does not expect reinstatement would have a material impact on Idaho Power's operations or financial condition.


In October 2015, the United States Court of Appeals for the Sixth Circuit issued a nationwide stay of the final waters of the United States rule from becoming effective. In response to the Sixth Circuit's decision, the EPA resumed nationwide use of the agency's prior regulations defining the term “waters of the United States.” The EPA stated that those regulations will be implemented as they were prior to August 27, 2015, by applying relevant case law, applicable policy, and the best science and technical data on a case-by-case basis in determining which waters are protected by the CWA.

CWA Matters Related to HydroelectricHydropower Relicensing: Idaho Power is also addressing CWA issues associated with the relicensing of its HCC. See “Relicensing of HydroelectricHydropower 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 announced that it would launchissued an order directing the BLM to prepare a comprehensive reviewProgrammatic Environmental Impact Statement (PEIS) to identify and evaluateanalyze potential reforms to the federal coal lease program. The review is intended to address questions such as how, when,program and where to lease coal resources, how to account for the environmental and public health impacts ofplaced a moratorium on new federal coal production, and how to ensure taxpayers are earning a fair return for the useleasing, with limited exceptions, pending completion of the coal resources. The U.S.PEIS. In January 2017, the Secretary of the Department of the Interior stated that it will not issueordered a cessation of all work on the PEIS and in March 2017 lifted the moratorium on new federal coal leases during the pendencyleases. As of the review, except under limited circumstances, but mining under existing leases will not be suspended during the review. BCC, which mines and supplies coal to the Jim Bridger coal-fired power plant, currently leases its coal under federal, state, and private coal leases. It is uncertain how new federal lease applications will be handled during the U.S. Departmentdate of the Interior's coal lease review.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, depending on the outcomelifting of the Department of the Interior's review,moratorium could increase the availability of BCC's coal resources could decline and lower the cost of leases for those coal resources could increase, which could increase the fuel cost for each of Idaho Power's co-owned coal-fired plants.resources.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
When preparing financial statements in accordance with GAAP,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.
 
Table of contents

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 territoryarea must lack competitive pressures to reduce rates below the rates set by the regulator.
 
Table of Contents

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 $1.5approximately $1.4 billion of regulatory assets and $447 million$0.8 billion of regulatory liabilities at December 31, 2016.2019. 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.  Either circumstanceliabilities, 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 providesrecords 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 providedrecorded 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 providedrecorded 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, anand two unfunded nonqualified deferred compensation planplans for certain senior management employees and directors called the Security Plan for Senior Management Employees (SMSP)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 stock marketcapital 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, 2016,2019, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 20172020 pension expense will be decreased to 4.453.60 percent from the 4.604.55 percent rate used in 2016.2019.
 
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
Table of contents

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
Table of Contents

interest rates were generally much higher. The long-term rate of return used to calculate the 20172020 pension expense will be decreased to 7.4 percent from the 7.5 percent the same assumption as was used for 2016.in 2019.


Gross net periodic pension and other postretirement benefit cost for these plans totaled $52 million, $51$50.0 million and $32$51.2 million for the years ended December 31, 2016, 2015,2019 and 2014,2018, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2017,2020, gross pension and other postretirement benefit costs are expected to total approximately $51$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
 2017 2016 2017 2016 2020 2019 2020 2019
 (millions of dollars) (millions of dollars)
Effect of 0.5% rate increase on net periodic benefit cost $(7.2) $(6.9) $(3.2) $(2.9) $(8.7) $(7.0) $(4.0) $(3.5)
Effect of 0.5% rate decrease on net periodic benefit cost 7.9
 7.6
 3.2
 2.9
 9.7
 7.8
 4.0
 3.4
 
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $74$97.1 million decrease in the combined benefit obligations of the plans as of December 31, 2016.2019. A 0.5 percent decrease in the plans' discount rates would have resulted in an $83$110.0 million increase in the combined benefit obligations of the plans as of December 31, 2016.2019.


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, 2016,2019, a total of $105$173 million of expense was deferred as a regulatory asset. Approximately $23Idaho Power expects to defer approximately $26 million is expected to be deferredof expense in 2017.2020. Idaho Power recorded pension expense in 2016, 2015, and 2014on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million $19 million,in 2019 and $35 million, respectively.2018.
 
Refer to Note 1112 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.
Contingent Liabilities

An estimated loss from a loss contingency is charged to income if (a) it is probable that a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated.  If a probable loss cannot be reasonably estimated, no accrual is recorded but disclosure of the contingency, if material, in the notes to the financial statements is required.  Gain contingencies are not recorded until realized. IDACORP and Idaho Power have a number of unresolved issues related to regulatory and legal matters.  If the recognition criteria have been met, liabilities have been recorded.  Estimates of this nature are highly subjective and the final outcome of these matters could vary significantly from the amounts that have been included in the financial statements.


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.



Table of contentsContents


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, 2016.2019. 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, 2016,2019, IDACORP and Idaho Power had $1.1 million and $16.1 million inno net floating rate debt, netas the carrying value of short-term investments. The fair marketinvestments exceeded the carrying value of this debt approximates the net carrying amount as the cost of borrowing is variable and approximates current market rates. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on December 31, 2016, annual interest expense would increase and pre-tax earnings would decrease by an insignificant amount for both IDACORP and Idaho Power.outstanding variable-rate debt.
 
Fixed Rate Debt: As of December 31, 2016,2019, both IDACORP and Idaho Power had $1.7$1.8 billion in fixed rate debt, with a fair market value of approximately $1.8$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 $256$262.2 million if market interest rates were to decline by one percentage point from their December 31, 2016,2019, 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), 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 PowerPower'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.
 
Table of contents

The Risk Management Policy requiresand 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,
Table of Contents

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 Policy.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, 2016,2019, Idaho Power had no$1.4 million of performance assurance collateral posted.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, 2016,2019, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $11.6$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 1112 - "Benefit Plans" to the consolidated financial statements included in this report.


Table of contentsContents




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Index to Financial Statements and Financial Statement Schedules


Consolidated Financial StatementsPage
  
IDACORP, Inc.: 
Consolidated Statements of Income
7476
Consolidated Statements of Comprehensive Income
7577
Consolidated Balance Sheets
7678
Consolidated Statements of Cash Flows
7880
Consolidated Statements of Equity
7981
  
Idaho Power Company: 
Consolidated Statements of Income
8082
Consolidated Statements of Comprehensive Income
8183
Consolidated Balance Sheets
8284
Consolidated Statements of Cash Flows
8486
Consolidated Statements of Retained Earnings
8587
  
Notes to the Consolidated Financial Statements
8688
Reports of Independent Registered Public Accounting Firm
125128
  
Supplemental Financial Information and Financial Statement Schedules 
  
Supplemental Financial Information (unaudited)
127131
Financial Statement SchedulesSchedules: 
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant
141145
IDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying Accounts
143
Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts
144147


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

Table of contentsContents






IDACORP, Inc.
Consolidated Statements of Income

 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars except for per share amounts) (thousands of dollars except for per share amounts)
Operating Revenues:            
Electric utility:      
General business $1,145,993
 $1,151,038
 $1,122,281
Off-system sales 25,205
 30,887
 77,165
Other revenues 88,155
 85,580
 79,205
Total electric utility revenues 1,259,353
 1,267,505
 1,278,651
Electric utility revenues $1,342,940
 $1,366,582
 $1,344,893
Other 2,667
 2,784
 3,873
 3,443
 4,170
 4,593
Total operating revenues 1,262,020
 1,270,289
 1,282,524
 1,346,383
 1,370,752
 1,349,486
            
Operating Expenses:            
Electric utility:            
Purchased power 245,764
 226,470
 244,628
 285,266
 293,814
 248,950
Fuel expense 179,491
 186,231
 201,241
 156,872
 133,198
 145,829
Power cost adjustment (5,330) 16,766
 22,235
 2,047
 42,106
 52,024
Other operations and maintenance 351,893
 342,146
 354,567
 355,770
 364,456
 346,695
Energy efficiency programs 33,754
 30,532
 27,154
 40,128
 35,703
 39,241
Depreciation 143,661
 138,110
 132,987
 169,210
 165,190
 162,091
Taxes other than income taxes 32,823
 32,808
 31,748
 34,044
 34,792
 34,089
Total electric utility expenses 982,056
 973,063
 1,014,560
 1,043,337
 1,069,259
 1,028,919
Other 8,188
 15,129
 14,268
 4,720
 4,571
 5,022
Total operating expenses 990,244
 988,192
 1,028,828
 1,048,057
 1,073,830
 1,033,941
Operating Income 271,776
 282,097
 253,696
 298,326
 296,922
 315,545
Allowance for Equity Funds Used During Construction 22,031
 21,785
 17,931
 27,112
 24,353
 20,784
Earnings of Unconsolidated Equity-Method Investments 12,871
 11,128
 12,372
 12,370
 12,449
 11,374
Other Income, Net 9,874
 7,159
 6,328
Other Income (Expense), Net 6,502
 (2,867) (2,109)
Interest Expense:     
     
Interest on long-term debt 81,956
 83,056
 80,562
 82,457
 84,408
 81,198
Other interest 10,273
 8,922
 7,703
 14,721
 11,691
 11,242
Allowance for borrowed funds used during construction (10,194) (10,044) (8,464) (10,703) (10,151) (8,694)
Total interest expense, net 82,035
 81,934
 79,801
 86,475
 85,948
 83,746
Income Before Income Taxes 234,517
 240,235
 210,526
 257,835
 244,909
 261,848
Income Tax Expense 36,429
 45,760
 16,772
 24,507
 17,386
 48,660
Net Income 198,088
 194,475
 193,754
 233,328
 227,523
 213,188
Adjustment for loss (income) attributable to noncontrolling interests 200
 204
 (274)
Adjustment for income attributable to noncontrolling interests (474) (722) (769)
Net Income Attributable to IDACORP, Inc. $198,288
 $194,679
 $193,480
 $232,854
 $226,801
 $212,419
Weighted Average Common Shares Outstanding - Basic (000’s) 50,298
 50,220
 50,131
 50,502
 50,432
 50,361
Weighted Average Common Shares Outstanding - Diluted (000’s) 50,373
 50,292
 50,199
 50,537
 50,510
 50,424
Earnings Per Share of Common Stock:            
Earnings Attributable to IDACORP, Inc. - Basic $3.94
 $3.88
 $3.86
 $4.61
 $4.50
 $4.22
Earnings Attributable to IDACORP, Inc. - Diluted $3.94
 $3.87
 $3.85
 $4.61
 $4.49
 $4.21


The accompanying notes are an integral part of these statements.
Table of contentsContents


IDACORP, Inc.
Consolidated Statements of Comprehensive Income
 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
            
Net Income $198,088
 $194,475
 $193,754
 $233,328
 $227,523
 $213,188
Other Comprehensive Income:            
Unfunded pension liability adjustment, net of tax
of $253, $1,851, and $(4,881)
 394
 2,882
 (7,605)
Unfunded pension liability adjustment, net of tax
of $(4,658), $2,815, and $(1,555)
 (13,440) 8,120
 (5,990)
Total Comprehensive Income 198,482
 197,357
 186,149
 219,888
 235,643
 207,198
Comprehensive loss (income) attributable to noncontrolling interests 200
 204
 (274)
Comprehensive income attributable to noncontrolling interests (474) (722) (769)
Comprehensive Income Attributable to IDACORP, Inc. $198,682
 $197,561
 $185,875
 $219,414
 $234,921
 $206,429


The accompanying notes are an integral part of these statements.
 
 


Table of contentsContents


IDACORP, Inc.
Consolidated Balance Sheets
 
 December 31, December 31,
 2016 2015 2019 2018
 (thousands of dollars) (in thousands)
Assets        
        
Current Assets:        
Cash and cash equivalents $61,480
 $114,802
 $217,254
 $267,492
Receivables:        
Customer (net of allowance of $968 and $1,196, respectively) 71,557
 73,505
Other (net of allowance of $164 and $159, respectively) 15,280
 8,642
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 12,781
 13,058
 3,106
 4,356
Accrued unbilled revenues 80,738
 65,805
 64,545
 69,318
Materials and supplies (at average cost) 57,858
 56,924
 56,660
 54,987
Fuel stock (at average cost) 53,698
 61,818
 57,448
 47,979
Prepayments 18,389
 17,979
 17,638
 16,492
Current regulatory assets 62,570
 49,215
 56,626
 48,707
Other 5,961
 288
 405
 3,655
Total current assets 440,312
 462,036
 565,146
 597,640
        
Investments 125,164
 140,743
 98,218
 101,178
        
Property, Plant and Equipment:        
Utility plant in service 5,732,044
 5,485,464
 6,113,567
 6,103,856
Accumulated provision for depreciation (1,988,477) (1,913,927) (2,155,783) (2,210,781)
Utility plant in service - net 3,743,567
 3,571,537
 3,957,784
 3,893,075
Construction work in progress 405,069
 396,931
 552,499
 480,259
Utility plant held for future use 7,441
 7,090
 3,872
 4,751
Other property, net of accumulated depreciation 15,922
 16,855
 17,299
 17,650
Property, plant and equipment - net 4,171,999
 3,992,413
 4,531,454
 4,395,735
        
Other Assets:        
American Falls and Milner water rights 9,487
 11,592
Company-owned life insurance 57,553
 48,566
 58,922
 59,852
Regulatory assets 1,409,329
 1,305,210
 1,326,433
 1,165,467
Long-term receivables (net of allowance of $402 and $552, respectively) 23,482
 22,538
Other 52,571
 40,216
 61,028
 62,882
Total other assets 1,552,422
 1,428,122
 1,446,383
 1,288,201
        
Total $6,289,897
 $6,023,314
 $6,641,201
 $6,382,754


The accompanying notes are an integral part of these statements.
Table of contentsContents


IDACORP, Inc.
Consolidated Balance Sheets


 
 December 31, December 31,
 2016 2015 2019 2018
 (thousands of dollars) (in thousands)
Liabilities and Equity        
        
Current Liabilities:        
Current maturities of long-term debt $1,064
 $1,064
 $100,000
 $—
Notes payable 21,800
 20,000
Accounts payable 106,194
 95,526
 110,745
 110,824
Taxes accrued 11,348
 10,762
 11,501
 12,009
Interest accrued 22,377
 22,292
 20,999
 23,622
Accrued compensation 45,787
 42,961
 52,550
 55,121
Current regulatory liabilities 9,944
 2,217
 33,987
 25,883
Advances from customers 21,438
 31,214
 28,452
 20,037
Other 9,763
 16,270
 16,625
 11,096
Total current liabilities 249,715
 242,306
 374,859
 258,592
        
Other Liabilities:        
Deferred income taxes 1,244,250
 1,137,375
 746,231
 699,878
Regulatory liabilities 436,845
 416,282
 748,198
 738,994
Pension and other postretirement benefits 411,523
 394,030
 519,570
 431,475
Other 45,084
 45,867
 45,131
 43,216
Total other liabilities 2,137,702
 1,993,554
 2,059,130
 1,913,563
        
Long-Term Debt 1,744,614
 1,725,410
 1,736,659
 1,834,788
        
Commitments and Contingencies 
 
 

 

        
Equity:        
IDACORP, Inc. shareholders’ equity:        
Common stock, no par value (shares authorized 120,000,000;
50,420,017 and 50,352,051 shares issued, respectively)
 851,833
 849,112
Common stock, no par value (120,000 shares authorized; shares issued 50,420) 868,307
 863,593
Retained earnings 1,323,198
 1,230,105
 1,634,525
 1,531,543
Accumulated other comprehensive loss (20,882) (21,276) (36,284) (22,844)
Treasury stock (23,244 and 11,221 shares at cost, respectively) (243) (57)
Treasury stock (22 and 27 shares at cost, respectively) (1,920) (1,932)
Total IDACORP, Inc. shareholders’ equity 2,153,906
 2,057,884
 2,464,628
 2,370,360
Noncontrolling interests 3,960
 4,160
 5,925
 5,451
Total equity 2,157,866
 2,062,044
 2,470,553
 2,375,811
        
Total $6,289,897
 $6,023,314
 $6,641,201
 $6,382,754
        
The accompanying notes are an integral part of these statements.


Table of contentsContents


IDACORP, Inc.
Consolidated Statements of Cash Flows

 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
Operating Activities:            
Net income $198,088
 $194,475
 $193,754
 $233,328
 $227,523
 $213,188
Adjustments to reconcile net income to net cash provided by operating activities:  
  
    
  
  
Depreciation and amortization 147,294
 142,581
 137,088
 173,800
 169,120
 165,933
Deferred income taxes and investment tax credits 35,732
 38,645
 19,163
 22,389
 11,292
 33,245
Changes in regulatory assets and liabilities (5,650) 13,699
 32,135
 (4,310) 48,392
 57,131
Pension and postretirement benefit plan expense 29,581
 30,207
 44,627
 27,804
 32,256
 28,911
Contributions to pension and postretirement benefit plans (45,301) (42,843) (33,720) (48,525) (45,899) (46,589)
Earnings of unconsolidated equity-method investments (12,871) (11,128) (12,372)
Distributions from unconsolidated equity-method investments 25,641
 12,458
 5,261
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 (22,031) (21,785) (17,931) (27,112) (24,353) (20,784)
Gain on sale of investments and assets (103) (97) (193) (285) (155) (131)
Other non-cash adjustments to net income, net 5,108
 2,788
 5,085
 8,325
 9,152
 8,454
Change in:  
  
    
  
  
Accounts receivable (2,671) 4,740
 20,433
 (5,996) 729
 1,045
Accounts payable and other accrued liabilities 13,300
 2,440
 6,359
 (9,526) 29,666
 (17,208)
Taxes accrued/receivable 662
 818
 (13,631) 742
 4,725
 4,361
Other current assets (10,887) (14,861) (13,124) (8,820) 12,707
 2,814
Other current liabilities (3,283) 403
 1,771
 (799) 6,848
 1,017
Other assets (3,897) 3,021
 (3,655) (4,375) (7,488) (8,734)
Other liabilities (1,006) (2,367) (6,707) 555
 (1,555) (1,093)
Net cash provided by operating activities 347,706
 353,194
 364,343
 366,625
 491,626
 435,161
Investing Activities:  
  
  
  
  
  
Additions to property, plant and equipment (296,950) (294,021) (274,094) (278,705) (277,853) (285,488)
Payments received from transmission project joint funding partners 7,586
 11,377
 —
 2,442
 21,587
 6,074
Purchase of available-for-sale securities (14,917) (14,106) (8,000)
Proceeds from sale of available-for-sale securities 15,693
 34,243
 —
Purchase of life insurance investment (10,000) (30,000) —
Purchase of equity securities (10,896) (11,390) (11,356)
Proceeds from sale of equity securities 5,080
 5,007
 4,989
Other 1,144
 801
 9,674
 1,587
 4,472
 5,340
Net cash used in investing activities (297,444) (291,706) (272,420) (280,492) (258,177) (280,441)
Financing Activities:  
  
  
  
  
  
Issuance of long-term debt 120,000
 250,000
 —
 166,100
 220,000
 —
Retirement of long-term debt (101,064) (121,064) (1,064) (166,100) (130,000) (1,064)
Dividends on common stock (104,984) (96,810) (88,489) (129,677) (121,421) (113,127)
Net change in short-term borrowings 1,800
 (11,300) (23,450) —
 —
 (21,800)
Acquisition of treasury stock (3,329) (3,277) (2,737) (4,160) (3,614) (3,212)
Make-whole premium on retirement of long-term debt (13,895) (17,872) —
 —
 (4,607) —
Other (2,112) (3,171) 2,463
Debt issuance costs and other (2,534) (2,964) (348)
Net cash used in financing activities (103,584) (3,494) (113,277) (136,371) (42,606) (139,551)
Net (decrease) increase in cash and cash equivalents (53,322) 57,994
 (21,354) (50,238) 190,843
 15,169
Cash and cash equivalents at beginning of the year 114,802
 56,808
 78,162
 267,492
 76,649
 61,480
Cash and cash equivalents at end of the year $61,480
 $114,802
 $56,808
 $217,254
 $267,492
 $76,649
Supplemental Disclosure of Cash Flow Information:  
  
  
  
  
  
Cash paid during the year for:            
Income taxes $3,302
 $8,857
 $11,364
 $14,055
 $5,272
 $14,742
Interest (net of amount capitalized) $78,334
 $79,442
 $77,295
 $85,260
 $80,951
 $80,004
Non-cash investing activities:            
Additions to property, plant and equipment in accounts payable $34,603
 $23,840
 $28,438
 $38,815
 $29,528
 $33,220


The accompanying notes are an integral part of these statements.
Table of contentsContents


IDACORP, Inc.
Consolidated Statements of Equity
 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
Common Stock:            
Balance at beginning of year $849,112
 $845,402
 $839,750
 $863,593
 $857,207
 $851,833
Cumulative effect of change in accounting principle 234
 —
 —
Issued —
 —
 195
Share-based compensation expense 8,788
 9,362
 7,384
Treasury shares issued (4,172) (3,068) (2,069)
Other 2,487
 3,710
 5,457
 98
 92
 59
Balance at end of year 851,833
 849,112
 845,402
 868,307
 863,593
 857,207
            
Retained Earnings:            
Balance at beginning of year 1,230,105
 1,132,237
 1,027,461
 1,531,543
 1,426,528
 1,323,198
Cumulative effect of change in accounting principle (234) —
 —
 —
 —
 4,092
Net income attributable to IDACORP, Inc. 198,288
 194,679
 193,480
 232,854
 226,801
 212,419
Common stock dividends ($2.08, $1.92, and $1.76 per share, respectively) (104,961) (96,811) (88,704)
Common stock dividends ($2.56, $2.40, and $2.24 per share, respectively) (129,872) (121,786) (113,181)
Balance at end of year 1,323,198
 1,230,105
 1,132,237
 1,634,525
 1,531,543
 1,426,528
            
Accumulated Other Comprehensive (Loss) Income:            
Balance at beginning of year (21,276) (24,158) (16,553) (22,844) (30,964) (20,882)
Cumulative effect of change in accounting principle —
 —
 (4,092)
Unfunded pension liability adjustment (net of tax) 394
 2,882
 (7,605) (13,440) 8,120
 (5,990)
Balance at end of year (20,882) (21,276) (24,158) (36,284) (22,844) (30,964)
            
Treasury Stock:            
Balance at beginning of year (57) (280) (8) (1,932) (1,386) (243)
Issued 3,143
 3,500
 2,465
 4,172
 3,068
 2,069
Acquired (3,329) (3,277) (2,737) (4,160) (3,614) (3,212)
Balance at end of year (243) (57) (280) (1,920) (1,932) (1,386)
            
Total IDACORP, Inc. shareholders’ equity at end of year 2,153,906
 2,057,884
 1,953,201
 2,464,628
 2,370,360
 2,251,385
            
Noncontrolling Interests:            
Balance at beginning of year 4,160
 4,364
 4,090
 5,451
 4,729
 3,960
Net (loss) income attributable to noncontrolling interests (200) (204) 274
Net income attributable to noncontrolling interests 474
 722
 769
Balance at end of year 3,960
 4,160
 4,364
 5,925
 5,451
 4,729
            
Total equity at end of year $2,157,866
 $2,062,044
 $1,957,565
 $2,470,553
 $2,375,811
 $2,256,114


The accompanying notes are an integral part of these statements.
Table of contentsContents




Idaho Power Company
Consolidated Statements of Income
 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
Operating Revenues:      
General business $1,145,993
 $1,151,038
 $1,122,281
Off-system sales 25,205
 30,887
 77,165
Other revenues 88,155
 85,580
 79,205
Total operating revenues 1,259,353
 1,267,505
 1,278,651
      
Operating Revenues $1,342,940
 $1,366,582
 $1,344,893
            
Operating Expenses:            
Operation:            
Purchased power 245,764
 226,470
 244,628
 285,266
 293,814
 248,950
Fuel expense 179,491
 186,231
 201,241
 156,872
 133,198
 145,829
Power cost adjustment (5,330) 16,766
 22,235
 2,047
 42,106
 52,024
Other operations and maintenance 351,893
 342,146
 354,567
 355,770
 364,456
 346,695
Energy efficiency programs 33,754
 30,532
 27,154
 40,128
 35,703
 39,241
Depreciation 143,661
 138,110
 132,987
 169,210
 165,190
 162,091
Taxes other than income taxes 32,823
 32,808
 31,748
 34,044
 34,792
 34,089
Total operating expenses 982,056
 973,063
 1,014,560
 1,043,337
 1,069,259
 1,028,919
            
Income from Operations 277,297
 294,442
 264,091
 299,603
 297,323
 315,974
            
Other Income (Expense):            
Allowance for equity funds used during construction 22,031
 21,785
 17,931
 27,112
 24,353
 20,784
Earnings of unconsolidated equity-method investments 10,855
 9,773
 10,814
 10,285
 10,712
 9,267
Other expense, net (1,944) (5,071) (4,363)
Other income (expense), net 2,266
 (5,851) (4,756)
Total other income 30,942
 26,487
 24,382
 39,663
 29,214
 25,295
            
Interest Charges:            
Interest on long-term debt 81,956
 83,056
 80,562
 82,457
 84,408
 81,198
Other interest 10,050
 8,706
 7,472
 14,658
 11,634
 11,156
Allowance for borrowed funds used during construction (10,194) (10,044) (8,464) (10,703) (10,151) (8,694)
Total interest charges 81,812
 81,718
 79,570
 86,412
 85,891
 83,660
            
Income Before Income Taxes 226,427
 239,211
 208,903
 252,854
 240,646
 257,609
            
Income Tax Expense 37,185
 48,228
 19,516
 28,417
 18,312
 51,262
            
Net Income $189,242
 $190,983
 $189,387
 $224,437
 $222,334
 $206,347


The accompanying notes are an integral part of these statements.
Table of contentsContents


Idaho Power Company
Consolidated Statements of Comprehensive Income
 
 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
            
Net Income $189,242
 $190,983
 $189,387
 $224,437
 $222,334
 $206,347
Other Comprehensive Income:            
Unfunded pension liability adjustment, net of tax
of $253, $1,851, and $(4,881)		 394
 2,882
 (7,605)
Unfunded pension liability adjustment, net of tax
of $(4,658), $2,815, and $(1,555)		 (13,440) 8,120
 (5,990)
Total Comprehensive Income $189,636
 $193,865
 $181,782
 $210,997
 $230,454
 $200,357


The accompanying notes are an integral part of these statements.
 
 


Table of contentsContents


Idaho Power Company
Consolidated Balance Sheets
 
 December 31, December 31,
 2016 2015 2019 2018
 (thousands of dollars) (in thousands)
Assets        
        
Electric Plant:        
In service (at original cost) $5,732,044
 $5,485,464
 $6,113,567
 $6,103,856
Accumulated provision for depreciation (1,988,477) (1,913,927) (2,155,783) (2,210,781)
In service - net 3,743,567
 3,571,537
 3,957,784
 3,893,075
Construction work in progress 405,069
 396,931
 552,499
 480,259
Held for future use 7,441
 7,090
 3,872
 4,751
Electric plant - net 4,156,077
 3,975,558
 4,514,155
 4,378,085
        
Investments and Other Property 107,379
 121,267
 87,104
 90,019
        
Current Assets:        
Cash and cash equivalents 44,140
 110,756
 98,950
 165,460
Receivables:        
Customer (net of allowance of $968 and $1,196, respectively) 71,557
 73,505
Other (net of allowance of $164 and $159, respectively) 7,555
 8,520
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 23,334
 5,432
 9,279
 11,829
Accrued unbilled revenues 80,738
 65,805
 64,545
 69,318
Materials and supplies (at average cost) 57,858
 56,924
 56,660
 54,987
Fuel stock (at average cost) 53,698
 61,818
 57,448
 47,979
Prepayments 18,270
 17,846
 17,520
 16,374
Current regulatory assets 62,570
 49,215
 56,626
 48,707
Other 5,962
 288
 405
 3,655
Total current assets 425,682
 450,109
 451,215
 502,693
        
Deferred Debits:        
American Falls and Milner water rights 9,487
 11,592
Company-owned life insurance 57,553
 48,566
 58,922
 59,852
Regulatory assets 1,409,329
 1,305,210
 1,326,433
 1,165,467
Other 71,237
 56,533
 56,330
 58,284
Total deferred debits 1,547,606
 1,421,901
 1,441,685
 1,283,603
        
Total $6,236,744
 $5,968,835
 $6,494,159
 $6,254,400




The accompanying notes are an integral part of these statements.
Table of contentsContents


Idaho Power Company
Consolidated Balance Sheets


 
 December 31, December 31,
 2016 2015 2019 2018
 (thousands of dollars) (in thousands)
Capitalization and Liabilities        
        
Capitalization:        
Common stock equity:        
Common stock, $2.50 par value (50,000,000 shares
authorized; 39,150,812 shares outstanding)
 $97,877
 $97,877
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding) $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 1,211,547
 1,127,426
 1,503,805
 1,409,245
Accumulated other comprehensive loss (20,882) (21,276) (36,284) (22,844)
Total common stock equity 1,998,703
 1,914,188
 2,275,559
 2,194,439
Long-term debt 1,744,614
 1,725,410
 1,736,659
 1,834,788
Total capitalization 3,743,317
 3,639,598
 4,012,218
 4,029,227
        
Current Liabilities:        
Current maturities of long-term debt 1,064
 1,064
 100,000
 —
Notes payable 21,800
 —
Accounts payable 105,846
 94,970
 110,581
 110,597
Accounts payable to related parties 1,056
 1,059
Accounts payable to affiliates 2,053
 2,088
Taxes accrued 11,348
 10,745
 11,481
 11,750
Interest accrued 22,377
 22,292
 20,999
 23,622
Accrued compensation 45,622
 42,835
 52,267
 54,910
Current regulatory liabilities 9,944
 2,217
 33,987
 25,883
Advances from customers 21,438
 31,214
 28,452
 20,037
Other 9,103
 15,506
 15,629
 10,198
Total current liabilities 249,598
 221,902
 375,449
 259,085
        
Deferred Credits:        
Deferred income taxes 1,351,415
 1,252,371
 794,402
 753,239
Regulatory liabilities 436,845
 416,282
 748,198
 738,994
Pension and other postretirement benefits 411,523
 394,030
 519,570
 431,475
Other 44,046
 44,652
 44,322
 42,380
Total deferred credits 2,243,829
 2,107,335
 2,106,492
 1,966,088
        
Commitments and Contingencies 
 
    
        
Total $6,236,744
 $5,968,835
 $6,494,159
 $6,254,400
        
The accompanying notes are an integral part of these statements.

Table of contentsContents


Idaho Power Company
Consolidated Statements of Cash Flows

 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
Operating Activities:            
Net income $189,242
 $190,983
 $189,387
 $224,437
 $222,334
 $206,347
Adjustments to reconcile net income to net cash provided by operating activities:   
  
      
  
Depreciation and amortization 146,694
 141,972
 136,496
 173,205
 168,519
 165,337
Deferred income taxes and investment tax credits 25,780
 25,702
 15,454
 14,889
 (2,272) (10,875)
Changes in regulatory assets and liabilities (5,651) 13,699
 32,135
 (4,310) 48,392
 57,131
Pension and postretirement benefit plan expense 29,597
 30,185
 44,579
 27,788
 32,240
 28,894
Contributions to pension and postretirement benefit plans (45,317) (42,821) (33,672) (48,509) (45,883) (46,573)
Earnings of unconsolidated equity-method investments (10,855) (9,773) (10,814)
Distributions from unconsolidated equity-method investments 23,716
 10,833
 3,586
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 (22,031) (21,785) (17,931) (27,112) (24,353) (20,784)
Gain on sale of investments and assets (103) (97) (186) (285) (155) (131)
Other non-cash adjustments to net income, net (454) (687) 2,087
 (463) (210) 1,069
Change in:  
  
    
  
  
Accounts receivable 3,590
 1,998
 20,072
 (4,724) 633
 (5,282)
Accounts payable 13,308
 2,646
 6,183
 (9,463) (25,532) 38,111
Taxes accrued/receivable (17,299) 17,179
 (22,911) 2,281
 15,509
 (3,601)
Other current assets (10,902) (14,849) (13,137) (8,821) 12,707
 2,812
Other current liabilities (3,322) 443
 1,776
 (870) 6,822
 996
Other assets (3,897) 3,021
 (3,655) (4,280) (7,488) (8,734)
Other liabilities (829) (2,222) (6,238) 584
 (1,476) (967)
Net cash provided by operating activities 311,267
 346,427
 343,211
 343,512
 418,475
 417,483
Investing Activities:  
  
    
  
  
Additions to utility plant (296,948) (293,968) (273,911) (278,707) (277,823) (285,471)
Payments received from transmission project joint funding partners 7,586
 11,377
 —
 2,442
 21,587
 6,074
Purchase of available-for-sale securities (14,917) (14,106) (8,000)
Proceeds from the sale of available-for-sale securities 15,693
 34,243
 —
Purchase of life insurance investment (10,000) (30,000) —
Purchase of equity securities (10,896) (11,390) (11,356)
Proceeds from the sale of equity securities 5,080
 5,007
 4,989
Other 1,000
 706
 8,508
 4,117
 4,320
 5,176
Net cash used in investing activities (297,586) (291,748) (273,403) (277,964) (258,299) (280,588)
Financing Activities:  
  
    
  
  
Issuance of long-term debt 120,000
 250,000
 —
 166,100
 220,000
 —
Retirement of long-term debt (101,064) (121,064) (1,064) (166,100) (130,000) (1,064)
Dividends on common stock (105,121) (96,907) (88,584) (129,877) (121,791) (113,284)
Net change in short term borrowings 21,800
 —
 —
 —
 —
 (21,800)
Make-whole premium on retirement of long-term debt (13,895) (17,872) —
 —
 (4,607) —
Other (2,017) (4,775) —
Net cash (used in) provided by financing activities (80,297) 9,382
 (89,648)
Debt issuance costs (2,181) (2,964) (241)
Net cash used in financing activities (132,058) (39,362) (136,389)
Net (decrease) increase in cash and cash equivalents (66,616) 64,061
 (19,840) (66,510) 120,814
 506
Cash and cash equivalents at beginning of the year 110,756
 46,695
 66,535
 165,460
 44,646
 44,140
Cash and cash equivalents at end of the year $44,140
 $110,756
 $46,695
 $98,950
 $165,460
 $44,646
Supplemental Disclosure of Cash Flow Information:  
  
    
  
  
Cash paid during the year for:  
  
  
Income taxes $29,341
 $7,487
 $26,116
Interest (net of amount capitalized) $78,111
 $79,226
 $77,063
Cash paid to IDACORP related to income taxes $19,856
 $63,914
 $12,444
Cash paid for interest (net of amount capitalized) $85,198
 $80,894
 $79,918
Non-cash investing activities:            
Additions to property, plant and equipment in accounts payable $34,603
 $23,840
 $28,438
 $38,815
 $29,528
 $33,220


The accompanying notes are an integral part of these statements.
Table of contentsContents


Idaho Power Company
Consolidated Statements of Retained Earnings


 Year Ended December 31, Year Ended December 31,
 2016 2015 2014 2019 2018 2017
 (thousands of dollars) (thousands of dollars)
            
Retained Earnings, Beginning of Year $1,127,426
 $1,033,350
 $932,547
 $1,409,245
 $1,308,702
 $1,211,547
Net Income 189,242
 190,983
 189,387
 224,437
 222,334
 206,347
Dividends on Common Stock (105,121) (96,907) (88,584) (129,877) (121,791) (113,284)
Cumulative Effect of Change in Accounting Principle —
 —
 4,092
Retained Earnings, End of Year $1,211,547
 $1,127,426
 $1,033,350
 $1,503,805
 $1,409,245
 $1,308,702


The accompanying notes are an integral part of these statements.
Table of contentsContents




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;investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectrichydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co. (IESCo), which is the former limited partner of, and current successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003..
 
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, 2016,2019, Marysville had approximately $18 million of assets, primarily a hydroelectrichydropower plant, and approximately $11$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 $82$40.7 million at December 31, 2016,2019, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $71$58.3 million guarantee for mine reclamation costs, which is discussed further in Note 9.10 - "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 24 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 $8$3.7 million at December 31, 2016.2019.


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 14)15 - "Investments").

Table of contents


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. 

Table of Contents


The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly ownedjointly-owned plants (see Note 12)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 and recorded on the income statement whensheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered or returned in rates.  Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expectedthrough future rates. Regulatory liabilities represent obligations to be refunded.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 3.3 - "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, litigation, 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 one1 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.


Table of Contents

There were no0 impaired receivables without related allowances at December 31, 20162019 and 2015.2018. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.

Table of contents


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 related to Idaho Power’s sale of energy 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. SeeThe effects of applying these regulatory mechanisms are discussed in more detail in Note 3 for additional discussion of certain of the following mechanisms:

energy efficiency riders to fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues;
a fixed cost adjustment mechanism that results in recording additional or reduced revenue based on the allowed and actual fixed costs recovered through current rates;
a sharing mechanism providing for refunds to customers for earnings above stated returns on equity in Idaho;
franchise fees and similar taxes related to energy consumption.  None of these collections are reported on the income statement; and
collection in base rates of a portion of the allowance for funds used during construction (AFUDC) related to its Hells Canyon Complex (HCC) relicensing project.  Cash collected under this ratemaking mechanism is not recorded as revenue but is instead deferred as a regulatory liability.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, AFUDC,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 2.642.9 percent in 2016 and 2.682019, 2.8 percent in both 20152018, and 2014.2.9 percent in 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 2016, 2015,2019, 2018, or 2014.2017.
 
Allowance for Funds Used During Construction


AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, as discussed above for the HCCHells 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
Table of contents

interest expense. Idaho Power’s weighted-average monthly AFUDC rate was 7.6 percent for 20162019, 2018 and 2015 and 7.7 percent for 2014.2017.


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
Table of Contents

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 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 providerecord 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 recognizeIdaho 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 providesrecords 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 providedrecorded 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 2.2 - "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.

Supplemental Cash Flows Information

In 2015, Idaho Power executed an agreement to exchange property with another electric utility. Under the terms of the agreement, each party transferred to the other transmission-related equipment with a book value of approximately $44 million. Idaho Power received an immaterial amount of cash, representing the difference in the book value of the assets exchanged. Also in 2015, Idaho Power executed a long-term service agreement and transferred to the service provider approximately $22 million of spare parts in partial exchange for future services. No cash was exchanged in the 2015 transfer transaction.

Reclassifications

In these consolidated financial statements, certain immaterial amounts in prior periods' consolidated financial statements and footnotes have been reclassified to conform with the current period presentation.

Table of contents


New and Recently Adopted Accounting Pronouncements


Recently Adopted Accounting Pronouncements


In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-09, Compensation--Stock Compensation (Topic 718) - Improvements to Employer Share-Based Payment Accounting, simplifying several aspects of the accounting for stock compensation paid to employees. As allowed, IDACORP and Idaho Power elected to early adopt the provisions of the new standard in the first quarter of 2016 under the modified retrospective method, with the cumulative effect of adoption recorded as an adjustment to 2016 beginning retained earnings. The principal changes under the new accounting standard include the following:

Excess or deficit income tax benefits on share-based transactions are recorded as income tax expense rather than in additional-paid-in-capital.
Previously recorded forfeiture estimates of approximately $0.2 million are reported as a decrease to beginning retained earnings. IDACORP made an accounting policy election to account for share-based award forfeitures as they occur, rather than making an estimate of future forfeitures.
In the statement of cash flows, excess tax benefits on share-based payments are presented in operating activities in the same manner as other cash flows related to income taxes. Previously, these cash flows were presented in financing activities. Prior periods were not restated for this change.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. As required, IDACORP and Idaho Power have adopted the provisions of this ASU at December 31, 2016, and accordingly, have retrospectively adjusted prior periods.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis, which revises the consolidation model that reporting entities use when determining what entities are to be consolidated. The amendments focus on limited partnerships and similar legal entities. The adoption of ASU 2015-02 in the first quarter of 2016 did not have a material impact on IDACORP's or Idaho Power's financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. The companies continue to assess the impacts of ASU 2014-09 on their financial statements, including disclosure requirements, but the companies do not expect the new guidance to significantly affect revenue recognition for tariff-based sales, which represent a significant majority of the companies' general business revenue. Accordingly, the companies do not expect the adoption of ASU 2014-09 to have a material effect on their financial statements; however, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could affect the companies' accounting for contributions in aid of construction, sales of renewable energy credits, alternative revenue programs, and recognition of revenue when collectability is in question. The guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full retrospective approach) and one requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach). IDACORP and Idaho Power plan to adopt ASU 2014-09 on January 1, 2018, using the modified-retrospective approach.

Table of contents

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting abouton leasing transactions. The ASU significantly changes the accounting model used byrequires lessees to account for leases, requiring that all material leases be presented on the balance sheet. Under the current model, some leases are classified as capital leasesrecognize a right-of-use asset and recordedlease liability on the balance sheet while other leases classified as operating leases arefor most leases. In addition, the ASU revises the definition of a lease in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement. IDACORP and Idaho Power adopted ASU 2016-02 on January 1, 2019. The adoption did not recognizedhave a material impact on their respective financial statements. Neither IDACORP nor Idaho Power has material agreements that meet the balance sheet.definition of a lease under ASU 2016-02.

Recent Accounting Pronouncements Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, to provide financial statement users with more information about expected credit losses on financial instruments. The ASU revises the incurred loss impairment methodology to reflect current expected credit losses and requires consideration of a broader range of information to estimate credit losses. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, including interim periods,2019, with early adoption permitted. The standard must be adopted using a modified-retrospective approach. IDACORP and Idaho Power are evaluatingfinalizing the impactassessment of the financial impacts of adoption, but do not believe that the adoption of ASU 2016-022016-13 will have a material impact on their respective financial statements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact

Table of the adoption. Specifically, the companies are considering whether the new guidance will affect their accounting for purchase power agreements, easements and rights-of-way, utility pole attachments, and other utility industry-related areas.Contents


In August 2016,2018, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230)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, which amends ASC 230 to clarifyprovide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the classificationrecognition of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASUsuch implementation costs with the intentaccounting for costs incurred to implement an internal-use software solution. However, the balance sheet line item for presentation of reducing diversitycapitalized implementation costs for a cloud arrangement that is a service contract should be the same as that for the prepayment of fees related to the same arrangement, while capitalized implementation costs for internal-use software solutions are often included in practice with respect to eight types of cash flows.property, plant, and equipment as an intangible asset. The companies expect the ASU to affect the classification of proceeds from the settlement of corporate-owned life insurance policies and related costs, which will be classified as investing activities under the new guidance. The companies already present 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 in accordance with the new guidance. ASU 2016-15standard is effective for interim and annual reporting periods beginning after December 15, 2017, including interim periods,2019, with early adoption permitted one year earlier.permitted. IDACORP and Idaho Power do not plan to early adoptare finalizing the standard. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. IDACORP and Idaho Powerassessment of the financial impacts of adoption, but do not believe the adoption of ASU 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
  2016 2015 2014 2016 2015 2014
  (thousands of dollars)
Federal income tax expense at 35% statutory rate $82,151
 $84,154
 $73,588
 $79,250
 $83,724
 $73,116
Change in taxes resulting from:  
  
  
    
  
AFUDC (11,278) (11,140) (9,238) (11,278) (11,140) (9,238)
Capitalized interest 2,000
 2,693
 2,278
 2,000
 2,693
 2,278
Investment tax credits (2,922) (2,963) (3,002) (2,922) (2,963) (3,002)
Removal costs (5,559) (4,807) (3,656) (5,559) (4,807) (3,656)
Capitalized overhead costs (10,500) (8,750) (8,750) (10,500) (8,750) (8,750)
Capitalized repair costs (28,000) (28,700) (26,250) (28,000) (28,700) (26,250)
Bond redemption costs (4,997) (6,459) —
 (4,997) (6,459) —
Tax method change – capitalized repairs(1)
 —
 —
 (24,516) —
 —
 (24,516)
State income taxes, net of federal benefit 5,071
 7,343
 4,680
 4,880
 7,503
 5,334
Depreciation 18,673
 17,149
 16,040
 18,673
 17,149
 16,040
Share-based compensation (1,614) —
 —
 (1,583) —
 —
Affordable housing tax credits (2,579) (3,258) (5,189) —
 —
 —
Affordable housing investment distributions (1,717) —
 —
 —
 —
 —
Affordable housing investment amortization 1,380
 1,519
 2,757
 —
 —
 —
Other, net (3,680) (1,021) (1,970) (2,779) (22) (1,840)
Total income tax expense $36,429
 $45,760
 $16,772
 $37,185
 $48,228
 $19,516
Effective tax rate 15.5% 19.0% 8.0% 16.4% 20.2% 9.3%
(1) In 2014, Idaho Power finalized an income tax accounting method change for the electric generation property portion of its capitalized repairs tax method and the final tangible property regulations. The cumulative impact of the method changes resulted in a net flow-through income tax benefit for 2014. The IRS approved the method changes as part of IDACORP's Compliance Assurance Process (CAP) examinations.
Table of contentsContents


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
  2016 2015 2014 2016 2015 2014
  (thousands of dollars)
Income taxes current:            
Federal $1,181
 $4,831
 $(4,926) $7,639
 $16,470
 $(2,805)
State 2,158
 2,704
 3,516
 3,766
 6,056
 6,867
Total 3,339
 7,535
 (1,410) 11,405
 22,526
 4,062
Income taxes deferred:  
  
  
  
  
  
Federal 33,205
 34,770
 17,159
 27,506
 27,696
 21,833
State 100
 626
 (3,260) (2,031) (2,486) (6,421)
Total 33,305
 35,396
 13,899
 25,475
 25,210
 15,412
Investment tax credits:  
  
  
�� 
  
  
Deferred 3,227
 3,455
 3,044
 3,227
 3,455
 3,044
Restored (2,922) (2,963) (3,002) (2,922) (2,963) (3,002)
Total 305
 492
 42
 305
 492
 42
Affordable housing investments (520) 2,337
 4,241
 —
 —
 —
Total income tax expense $36,429
 $45,760
 $16,772
 $37,185
 $48,228
 $19,516


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
  2016 2015 2016 2015
  (thousands of dollars)
Deferred tax assets:  
  
  
  
Regulatory liabilities $51,326
 $51,131
 $51,326
 $51,131
Deferred compensation 29,490
 27,573
 29,424
 27,489
Deferred revenue 40,354
 34,282
 40,354
 34,282
Tax credits 142,627
 147,299
 33,589
 30,307
Partnership investments 6,543
 7,220
 —
 —
Retirement benefits 132,362
 126,885
 132,362
 126,885
Other 11,401
 11,245
 11,069
 10,745
Total 414,103
 405,635
 298,124
 280,839
Deferred tax liabilities:    
    
Property, plant and equipment 500,987
 474,879
 500,987
 474,879
Regulatory assets 948,540
 875,028
 948,540
 875,028
Power cost adjustments 21,077
 18,489
 21,077
 18,489
Fixed cost adjustment 17,376
 14,395
 17,376
 14,395
Partnership investments 12,371
 16,925
 5,554
 9,829
Retirement benefits 140,083
 126,090
 140,083
 126,090
Other 17,919
 17,205
 15,922
 14,500
Total 1,658,353
 1,543,011
 1,649,539
 1,533,210
Net deferred tax liabilities $1,244,250
 $1,137,376
 $1,351,415
 $1,252,371


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.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, 2016,2019, IDACORP had $103.5$36.7 million of general business credit carryforwards for federal income tax purposes and $39.1$39.4 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 20252032 to 2036,2039, and the Idaho investment tax credit expires from 20212024 to 2030.2033.  


Table of contentsContents


Uncertain Tax Positions


IDACORP and Idaho Power believe that they have no0 material income tax uncertainties for 20162019 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 20162019 for federal and 2012-20162016-2019 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 2016,2019, the IRS completed its examination of IDACORP's 20152018 tax year with no unresolved income tax issues.


Income Tax Reform

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law, which significantly 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 suchthose 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.


Table of contentsContents


The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
   As of December 31, 2016       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 2016 2015 2019 2018
Regulatory Assets:    
          
      
Income taxes(2)   $—
 $948,540
 $948,540
 $875,027
   $—
 $646,886
 $646,886
 $614,144
Unfunded postretirement benefits(2)(3)
   —
 263,779
 263,779
 251,762
   —
 347,935
 347,935
 278,674
Pension expense deferrals(4) 
 83,057
 22,295
 105,352
 85,790
 
 150,350
 22,287
 172,637
 147,836
Energy efficiency program costs(3)(5)
 5,552
 —
 5,552
 4,482
 1,465
 —
 1,465
 1,398
Power supply costs(4)
 2017-2018 53,870
 —
 53,870
 47,220
Fixed cost adjustment(4)
 2017-2018 44,445
 —
 44,445
 36,820
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(5)(7)
   —
 14,154
 14,154
 14,410
   —
 18,835
 18,835
 17,655
Mark-to-market liabilities(6)
   —
 —
 —
 4,973
Long-term service agreement(7)
 2043 17,879
 11,202
 29,081
 30,225
Long-term service agreement 2020-2043 15,412
 10,178
 25,590
 26,748
Other 2017-2054 2,541
 4,585
 7,126
 3,716
 2020-2055 2,804
 5,366
 8,170
 7,704
Total   $207,344
 $1,264,555
 $1,471,899
 $1,354,425
   $312,764
 $1,070,295
 $1,383,059
 $1,214,174
Regulatory Liabilities:    
  
  
  
    
  
  
  
Income taxes   $—
 $51,326
 $51,326
 $51,131
Income taxes(8)
   $—
 $96,599
 $96,599
 $98,042
Depreciation-related excess deferred income taxes(9)
 183,881
 —
 183,881
 190,062
Removal costs(5)(7)
   —
 186,609
 186,609
 183,505
   —
 185,685
 185,685
 183,798
Investment tax credits   —
 79,960
 79,960
 79,655
   —
 94,806
 94,806
 92,790
Deferred revenue-AFUDC(8)
   70,178
 33,041
 103,219
 87,690
Deferred revenue-AFUDC(10)
   109,921
 41,747
 151,668
 135,146
Energy efficiency program costs(3)(5)
 10,730
 —
 10,730
 6,554
 —
 —
 —
 5,259
Settlement agreement sharing mechanism(4)
 
 —
 —
 —
 3,159
Mark-to-market assets(6)
   —
 7,831
 7,831
 405
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 
 5,598
 1,516
 7,114
 6,399
 
 6,636
 5,279
 11,915
 12,433
Total   $86,506
 $360,283
 $446,789
 $418,498
   $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 11.12 - "Benefit Plans."
(3) The energy efficiency(4) 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 balancedifference between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the liability represents theamounts 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.
(4) These items are(6) This item is discussed in more detail in this Note 3.3 - "Regulatory Matters."
(5)(7) Asset retirement obligations and removal costs are discussed in Note 13.14 - "Asset Retirement Obligations (ARO)."
(6) Mark-to-market(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."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities are discussed in Note 16.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.
(7) A portion not earning a return as of December 31, 2016, will be eligible to earn a return as of January 1, 2018.
(8) (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.

(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.


Table of contentsContents


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 mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-systemwholesale 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 PCAIdaho-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 shareholdersIdaho 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, 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 reduction due to the transfer of Idaho energy efficiency rider funds.
June 1, 2015 $(11.6) The net decrease in PCA rates included the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of the December 2011 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds.
June 1, 2014 $(88.2) 2014 PCA rates are net of (a) $20.0 million of surplus Idaho energy efficiency rider funds, and (b) $7.6 million of customer revenue sharing under a regulatory settlement stipulation. In addition, on June 1, 2014, there was an increase in base net power supply costs that shifted $99.3 million in power supply expenses from recovery via the PCA mechanism to recovery via base rates. The shifting of base net power supply costs is discussed in more detail below.

 
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.

In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties further evaluated Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment was appropriate. While the IPUC's docket was closed in August 2014 with no adjustment to the PCA true-up revenue amount, Idaho Power subsequently met with the IPUC Staff to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism. In May 2015, the IPUC approved a settlement stipulation that resulted in the replacement of the existing load-based adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The sales-based adjustment functions in the same manner as the previous load-based adjustment but measures deviations between Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved settlement stipulation implemented the new methodology as of January 1, 2015.

Table of contents

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 no greater than 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 no less than 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 2016, 2015,2019, 2018, and 2014 are summarized in2017 did not have a material impact on the table that follows:
Year and MechanismAPCU or PCAM Adjustment
2016 PCAMActual net power supply costs were within the deadband, resulting in no deferral.
2016 APCUA rate increase of $0.2 million annually took effect June 1, 2016.
2015 PCAMActual net power supply costs were within the deadband, resulting in no deferral.
2015 APCUA rate decrease of $0.7 million annually took effect June 1, 2015.
2014 PCAMActual net power supply costs were within the deadband, resulting in no deferral.
2014 APCUA rate increase of $0.4 million annually took effect June 1, 2014.
companies' financial statements.
 
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. 2014, 2017, 2018, and 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
Table of Contents

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, theThe IPUC also 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.


December 2011 Idaho Settlement Stipulation: In December 2011, the IPUC issued an order, separate from the then-pending general rate case proceeding, approving a settlement stipulation that provided as follows:
If Idaho Power's actual Idaho-jurisdiction return on year-end equity (Idaho ROE) for 2012, 2013, or 2014 was less than 9.5 percent, then Idaho Power could amortize up to a total of $45 million of additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho ROE in the applicable year.
If Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeded 10.0 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA mechanism adjustment.
If Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeded 10.5 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.

As Idaho Power's Idaho ROE exceeded 10.5 percent in 2014, Idaho Power did not amortize additional ADITC, but instead shared $24.7 million of its Idaho-jurisdiction earnings with Idaho customers. Of the amount shared in 2014, $8.0 million was
Table of contents

returned as a rate reduction as part of the 2015 PCA mechanism adjustment and $16.7 million was recorded as a pre-tax charge to pension expense.

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 thea 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 ADITC contemplated by the settlement stipulation has been amortized. The provisions of the new settlement stipulation are as follows:

If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of additional ADITC over the 2015 through 2019 period.
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 10.5 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 expense deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.
If the full $45 million of additional ADITCaccumulated 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 sharing provisions would terminate.October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table included under "Income Tax Reform - Idaho Regulatory Treatment" below.

In 2019 and 2017, Idaho Power recorded 0 provision against current revenue for sharing with customers, as its full-year return on year-end equity in the eventIdaho jurisdiction (Idaho ROE) for 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, 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 described in "Income Tax Reform - Idaho Regulatory Treatment" below.

May 2018 Idaho Tax Reform 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 May 2018, the IPUC approvesissued an order approving a changesettlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. 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 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 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 Idaho-jurisdictional allowed returnOATT rate. The amount provided via the PCA mechanism decreased to $2.7 million on equity as partJune 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 general rate case proceeding seeking a rate change effective prior tofull year of reduced OATT third-party transmission revenues.

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.

Table of Contents

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 became applicable 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 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.

The May 2018 Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be adjusted prospectively.

Neither the settlement stipulation nor the associated IPUC orderTax 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 its respective term.

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 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 term ofcost recovery period specified in the settlement stipulation.

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 2015,February 2019, Idaho Power recorded a $3.2 million provision against current revenue for sharingreached an agreement with customers, asNV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its Idaho ROE for 2015 was above 10.0 percent.jointly-owned North
Table of Contents

Valmy coal-fired power plant in 2019 and 2025, respectively. In 2016,May 2019, the IPUC issued an order approving the North Valmy plant agreement and allowing Idaho Power recorded no additional ADITC amortizationto recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and no provision for sharing with customers, as its 2016 Idaho ROE was between 9.5 percent and 10.0 percent. Accordingly, atother exit costs, effective June 1, 2019, through December 31, 2016, the full $45 million of additional ADITC remains available for future use under the terms of the settlement stipulation.

2028. In 2016, 2015, and 2014,December 2019, as planned, Idaho Power recorded the following for sharing with customers under the December 2011 and October 2014ended its participation in coal-fired operations of North Valmy plant unit 1.

Other Notable Idaho settlement stipulations (in millions):Regulatory Matters


Year Recorded as Refunds to Customers Recorded as a Pre-tax Charge to Pension Expense
2016 $— $—
2015 $3.2 $—
2014 $8.0 $16.7

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. TheUnder 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 over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism is adjusted each yearallows Idaho Power to collect,accrue, or refund,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. The IPUC has discretion to cap the annual changeincrease in the FCA recovery is capped at no more than 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

Table of contents


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)
2015 June 1, 2016-May 31, 2017 $28.1
2014 June 1, 2015-May 31, 2016 $16.9
2013 June 1, 2014-May 31, 2015 $14.9


Hells Canyon Complex Relicensing Costs Settlement Stipulation:In July 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA mechanism (including weather-normalization, customer count methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs. In May 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA charges effective June 1, 2016.

Depreciation Rate Requests
In 2016, Idaho Power conducted a depreciation study of all electric plant-in-service that provided updates to net salvage percentages and service life estimates for all Idaho Power plant assets. Based on the study, in October and November 2016, Idaho Power filed applications with the IPUC and OPUC, respectively, requesting approval to institute revised depreciation rates for Idaho Power's electric plant-in-service and adjust base rates by an aggregate of $7.4 million to reflect the revised depreciation rates applied to electric plant in service balances subject to the most recent general rate cases. The proposed adjustments in these applications are an overall rate increase of 0.6 percent in Idaho and 1.3 percent in Oregon.
At the same time, Idaho Power also filed applications with the IPUC and the OPUC requesting authorization to (a) accelerate depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31, 2025, (b) establish a balancing account to track the incremental costs and benefits associated with the accelerated depreciation date, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $29.6 million. The proposed adjustment in these applications are an overall rate increase of 2.5 percent in Idaho and 1.9 percent in Oregon.
Idaho Power expects the IPUC and the OPUC to enter final orders in both matters prior to June 2017 in Idaho and November 2017 in Oregon.

Western Energy Imbalance Market Costs
Idaho Power plans to participate in a new energy imbalance market implemented in the western United States (Western EIM).  In August 2016, Idaho Power filed an application with the IPUC requesting specifieda 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 accounting treatment associatedproceeding. In December 2017, Idaho Power filed with its participationthe 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 Western EIM.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 January 2017,April 2018, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment forapproving the settlement stipulation as filed with the IPUC and determined the $216.5 million of associated costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of the coststo be reasonably and the deferral balance or the end of 2018. Recovery of deferred costs will be addressed in a future IPUC proceeding.  Idaho Power anticipates that its participation in the Western EIM will commence in the spring of 2018.prudently incurred.


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 OPUCPublic 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 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. 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 Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the
Table of contentsContents


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. 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


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. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
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, 2016 to September 30, 2017 $25.52
October 1, 2015 to September 30, 2016 $23.43
October 1, 2014 to September 30, 2015 $22.48
October 1, 2013 to September 30, 2014 $22.80


Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.4$107.0 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.


4. REVENUES
IDACORP and Idaho Power adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), using the modified retrospective 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 0 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


Table of contentsContents


4.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,
  2019 2018 2017
Revenues from contracts with customers:      
Retail revenues:      
 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 181,372
 190,130
 195,124
Irrigation 135,850
 158,001
 150,030
Provision for sharing —
 (5,025) —
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (8,780) (10,706)
Total retail revenues 1,130,611
 1,175,152
 1,205,976
Less: FCA mechanism revenues(1)
 (36,923) (35,924) (18,196)
Wholesale energy sales 71,198
 52,845
 24,790
Transmission wheeling-related revenues 53,828
 59,094
 43,970
Energy efficiency program revenues 40,128
 35,703
 39,241
Other revenues from contracts with customers 26,444
 25,242
 24,223
Total revenues from contracts with customers $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) The IPUC 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 2017, respectively.

Table of Contents

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 2019 Idaho ROE, Idaho Power recorded 0 provision against current revenues for sharing of earnings with customers for 2019. Idaho Power recorded $5.0 million of sharing of earnings with 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-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-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-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, 2019, Idaho Power's energy efficiency rider balances were a $0.3 million regulatory asset in the Idaho jurisdiction and a $1.2 million regulatory asset in the Oregon jurisdiction.

Table of Contents

Alternative Revenue Programs and 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 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


IDACORP's Other Revenues

IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydropower generation projects that satisfy the requirements of PURPA.

Table of Contents

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
     

  2016 2015
First mortgage bonds:    
6.15% Series due 2019 $—
 $100,000
4.50% Series due 2020 130,000
 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
 —
Total first mortgage bonds 1,575,000
 1,555,000
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
Milner Dam note guarantee 1,064
 2,127
Unamortized issuance costs and discounts (20,731) (20,998)
Total IDACORP and Idaho Power outstanding debt(2)
 1,745,678
 1,726,474
Current maturities of long-term debt (1,064) (1,064)
Total long-term debt $1,744,614
 $1,725,410
     
(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, 2016,2019, to $1.741$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, 20162019 and 2015,2018, the overall effective cost rate of Idaho Power's outstanding debt was 4.874.50 percent and 4.964.83 percent, respectively.


At December 31, 2016,2019, 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
 2017 2018 2019 2020 2021 Thereafter
 $1,064
 $—
 $—
 $230,000
 $—
 $1,535,345

 
Long-Term Debt Issuances, Maturities, and AvailabilityRedemptions


OnIn March 10, 2016,2018, Idaho Power issued $120$220.0 million in principal amount of 4.05%4.20% first mortgage bonds, secured medium-term notes, Series J,K, maturing on March 1, 2046. On2048. In April 11, 2016,2018, Idaho Power redeemed, prior to maturity, $100$130.0 million in principal amount of 6.15%4.50% first mortgage bonds, secured medium-term notes, Series H, due April 2019.March 2020. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holdersof $4.6
Table of contentsContents


of the redeemed notes in the aggregate amount of approximately $14.0 million. Idaho Power used a portion of the net proceeds from the March 20162018 sale of first mortgage bonds, medium-term notes to effect the redemption.

On March 6, 2015,In August 2019, Idaho Power issued $250 millionpurchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of 3.65% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2045. On April 23, 2015, Idaho Power redeemed, prior to maturity, $120$49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of 6.025% 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 July 2018. In accordancewere remarketed with substantially the redemption provisionssame 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 term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent.

Idaho Power First Mortgage Bonds

Idaho Power's paymentissuance of a make-whole premiumlong-term indebtedness is subject to the holdersapproval of the redeemed notes in the aggregate amount of approximately $17.9 million. Idaho Power used a portion of the net proceeds from the March 2015 sale of first mortgage bonds, medium-term notes to effect the redemption.

IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2016,2019, Idaho Power received orders from the IPUC, OPUC, and Wyoming Public Service Commission (WPSC)WPSC authorizing Idaho Powerthe 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. The orderAuthority from the IPUC approved the issuance of the securitiesis 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.


OnIn May 20, 2016, IDACORP and2019, Idaho Power filed a joint shelf registration statement with the U.S. Securities and Exchange Commission (SEC),SEC, which became effective upon filing, for the offer and sale of in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities. On September 27, 2016, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potentialbonds. The issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds secured medium term notes, Series K (Series K Notes), underrequires that Idaho Power’sPower 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). At the same time, Idaho Power 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, 2016, $500 million in principal amount of Series K Notes remained available for issuance under the Indenture.

Mortgage: As of December 31, 2016, Idaho Power could issue under its Indenture approximately $1.7 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 amountFuture issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture.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 a selling agency agreement under the 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. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. 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, 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, 2019 was limited to approximately $669 million under the Indenture.

5.
Table of Contents

6. NOTES PAYABLE
 
Table of contents

Credit Facilities
 
On NovemberDecember 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, towhich 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 0.0 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 NovemberDecember 6, 2020,2024, the credit agreements grant IDACORP and Idaho Power the right to request up to two2 one-year extensions, subject to certain conditions. On November 7, 2016, IDACORP and Idaho Power executed the first extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 5, 2021. 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, 2016,2019, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2016,2019, 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 followszero at December 31, 2016,2019, and December 31, 2015:
  IDACORP Idaho Power Total
  2016 2015 2016 2015 2016 2015
Commercial paper balances:            
At the end of year $—
 $20,000
 $21,800
 $—
 $21,800
 $20,000
Average during the year $15,692
 $22,054
 $438
 $—
 $16,130
 $22,054
Weighted-average interest rate            
At the end of the year —% 0.88% 1.13% —% 1.13% 0.88%
2018.
  
Table of contents

6.7. COMMON STOCK
 
IDACORP Common Stock


The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 20162019:
  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
  2016 2015 2014 December 31, 2016
Balance at beginning of year 50,352,051
 50,308,702
 50,233,463
  
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 67,966
 43,349
 75,239
 1,311,147
Restricted stock plan(1)
 —
 —
 —
 256,154
Balance at end of year 50,420,017
 50,352,051
 50,308,702
  
(1) The Restricted Stock Plan was terminated on February 9, 2017.

In recent years,During 2019, 2018, and 2017, IDACORP has entered into sales agency agreements under which IDACORP could offergranted 70,419, 75,761, and sell72,397 restricted stock unit awards, respectively, to employees and 9,594, 12,950, and 12,050 shares of its common stock, from timerespectively, to time through an agent. The most recent sales agency agreement expired in May 2016,directors but IDACORP may choose to enter into a new sales agency agreement in the future. On May 20, 2016, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the potential offer and sale of an unspecified amountmade 0 original issuances of shares of common stock.stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan.


Table of Contents

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, 2016,2019, the leverage ratios for IDACORP and Idaho Power were 4543 percent and 4745 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.2$1.5 billion and $1.0$1.3 billion, respectively, at December 31, 2016.2019. 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 the companyIDACORP and Idaho Power from any material subsidiary. At December 31, 2016,2019, 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, 2016,2019, Idaho Power's common equity capital was 5355 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 Federal Power Act (FPA)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.
 
Table of contents

7.  STOCK-BASED8. SHARE-BASED COMPENSATION
 
IDACORP has twoone share-based compensation plans --plan — the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP).  The RSP was terminated effective February 9, 2017. 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 performanceand performance-based units (together, Performance-Based Shares), and several other types of stock-basedshare-based awards. At December 31, 2016,2019, the maximum number of shares available under the LTICP and RSP were 934,781 and 15,796, respectively, excluding (i) issued but unvested performance-based restricted shares and (ii) issued but unvested time-based restricted shares.was 613,394.
 
Restricted Stock Awards:and Performance-Based Shares Awards

Restricted stockStock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights.rights, except that holders of restricted stock units do not have voting rights until the units are vested and settled in shares. Unvested sharesawards 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, based onreduced for any forfeitures during the number of shares expected to vest.vesting period.
 
Performance-based restricted stockPerformance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights.rights, except that holders of performance-based units do not have voting rights until the units are vested and settled in shares. Unvested sharesawards 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 to 150 percent of the target award for awards granted prior to 2015 and from zero0 to 200 percent of the target award for awards granted in 2015 and 2016.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 numberestimated achievement of shares expected to vest.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
Table of Contents

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 stockRestricted Stock and performance sharePerformance-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		 Weighted-Average
Grant Date
Fair Value		 Number of
Shares		 Weighted-Average
Grant Date
Fair Value
Nonvested shares at January 1, 2016 230,820
 $52.41
 228,790
 $52.44
Shares granted 114,486
 64.13
 113,708
 64.18
Shares forfeited (24,699) 65.75
 (24,699) 65.75
Shares vested (119,542) 44.30
 (118,273) 44.32
Nonvested shares at December 31, 2016 201,065
 $61.49
 199,526
 $61.51

 
The total fair value of shares vested was $9.4 million in 2019, $8.3 million in 2016, $8.32018, and $7.5 million in 2015, and $6.6 million in 2014.2017. At December 31, 2016,2019, IDACORP had $5.0$7.9 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest.compensation. Idaho Power’sPower's share of this amount was $4.9$7.8 million. These costs are expected to be recognized over a weighted-average period of 1.731.7 years. IDACORP uses original issue and/or treasury shares for these awards.
 
In 2016,2019, a total of 12,6819,594 shares were awarded to directors at a grant date fair value of $70.96$98.41 per share. Directors elected to defer receipt of 4,9313,198 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 these plans,the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars): 
Table of contents
  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
             


(1) Due to 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."

  IDACORP Idaho Power
  2016 2015 2014 2016 2015 2014
Compensation cost $5,561
 $5,299
 $5,609
 $5,494
 $5,221
 $5,458
Income tax benefit 2,174
 2,072
 2,193
 2,148
 2,042
 2,134

NoNaN equity compensation costs have been capitalized. These costs are primarily reported within other"Other operations and maintenancemaintenance" expense inon the consolidated statements of income.


8.9. EARNINGS PER SHARE
 
The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2016, 2015,2019, 2018, and 20142017 (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,
  2016 2015 2014
Numerator:  
  
  
Net income attributable to IDACORP, Inc. $198,288
 $194,679
 $193,480
Denominator:  
  
  
Weighted-average common shares outstanding - basic 50,298
 50,220
 50,131
Effect of dilutive securities 75
 72
 68
Weighted-average common shares outstanding - diluted 50,373
 50,292
 50,199
Basic earnings per share $3.94
 $3.88
 $3.86
Diluted earnings per share $3.94
 $3.87
 $3.85
       


9.
Table of Contents

10. COMMITMENTS
 
Purchase Obligations


At December 31, 2016,2019, 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

  2017 2018 2019 2020 2021 Thereafter
Cogeneration and power production $228,545
 $235,366
 $229,450
 $229,473
 $235,922
 $3,150,212
Fuel 56,534
 22,070
 8,948
 8,433
 8,399
 100,978

As of December 31, 2016,2019, Idaho Power had 9451,136 MW nameplate capacity of PURPA-related projects on-line, with an additional 17811 MW nameplate capacity of projects projected to be on-line in 2017 and an additional 9 MW expected to be added 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 $154$187 million in 2016, $1312019, $190 million in 2015,2018, and $145$170 million in 2014.2017.

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 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.

Idaho Power also has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry related fees (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
             

  2017 2018 2019 2020 2021 Thereafter
Operating leases $3,339
 $4,171
 $4,237
 $4,076
 $4,038
 $29,218
Equipment, maintenance, and service agreements 26,884
 12,435
 6,185
 6,871
 3,421
 51,085
FERC and other industry-related fees 12,508
 12,444
 8,434
 5,744
 5,744
 28,720
(1) Approximately $27 million, $48 million, and $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 approximately $4.9 million in 2016, $4.4 million in 2015,not material for the years ended 2019, 2018, and $5.9 million in 2014.2017.
 
Table of contents

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 $71$58.3 million at December 31, 2016,2019, representing IERCo's one-third share of BCC's total reclamation obligation.obligation of $175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2016,2019, the value of the reclamation trust fund was $78$139.5 million. During 2016,2019, the reclamation trust fund distributed approximately $6 millionmade 0 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.
 
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
Table of Contents

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, 2016,2019, 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.
 
10.11. 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, including the items described below. Somesome of these claims, controversies, disputes, and other contingent matterswhich 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. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, and adjust the amount as appropriate. 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.

Western Energy Proceedings
High prices for electricity, energy shortages, and blackouts in California and in the western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings to consider requiring refunds and other forms of disgorgement from energy sellers. For matters that affect Idaho Power's operations, Idaho Power and IESCo (as successorintends to IDACORP Energy L.P.) believe that the current state of the FERC's orders and the settlement releases they have obtained, including a settlement Idaho Power and IESCo executed in December 2016 and approved by the FERC relatingseek, to the California energy market proceedings, will eliminate or restrict potential future claimsextent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that might result from the remaining proceedings. As IDACORP and Idaho Power believe that their participation in the California and western wholesale market proceedings has effectively concluded, IDACORP and Idaho Power expect that these matters will not have a material adverse effect on their respective results of operations or financial condition in future periods.such recovery would be granted.

Hoku Corporation Bankruptcy Claims

On June 26, 2015, the trustee in the Hoku Corporation chapter 7 bankruptcy case (In Re: Hoku Corporation, United States Bankruptcy Court, District of Idaho, Case No. 13-40838 JDP) filed a complaint against Idaho Power, alleging that specified
Table of contents

payments made by Hoku Corporation to Idaho Power in the six years prior to Hoku Corporation's bankruptcy filing in July 2013 should be recoverable by the trustee as constructive fraudulent transfers. Hoku Corporation was the parent entity of Hoku Materials, Inc., with which Idaho Power had an electric service agreement approved by the IPUC in March 2009. Under the electric service agreement, Idaho Power agreed to provide electric service to a polysilicon production facility under construction by Hoku Materials in the state of Idaho. Idaho Power also had agreements with Hoku Materials pertaining to the design and construction of apparatus for the provision of electric service to the polysilicon plant. The trustee's complaint against Idaho Power requested recovery from Idaho Power in amounts up to approximately $36 million. The complaint alleged that the payments made by Hoku Corporation to Idaho Power were subject to recovery by the trustee on the basis that Hoku Corporation was insolvent at the time of the payments and did not have any legal or equitable title in the polysilicon plant or liability for Hoku Materials' debts, and thus did not receive reasonably equivalent value for the payments it made for or on behalf of Hoku Materials. In September 2016, the bankruptcy judge issued an oral opinion granting Idaho Power’s and other parties’ motion for substantive consolidation of Hoku Corporation and Hoku Materials, which consolidated the bankruptcies of Hoku Corporation and Hoku Materials.  On December 20, 2016, the bankruptcy judge entered an order of dismissal, with prejudice, of the complaint against Idaho Power, which effectively ended Idaho Power’s participation in the adversary proceedings. 

Other Proceedings


IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business that are in addition to those discussed above 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 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 those mattersexisting 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. However, Idaho Power does believe that future capital investment for infrastructure and modifications to its electric system facilities could be significant to comply with these regulations.

11.12. 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 of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes.  In 2016, 2015, and 2014 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. 
Table of contentsContents


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
  2016 2015 2016 2015
   
Change in projected benefit obligation:  
  
  
  
Benefit obligation at January 1 $835,523
 $844,812
 $95,389
 $94,410
Service cost 32,019
 33,164
 1,228
 1,689
Interest cost 37,813
 35,171
 4,275
 3,868
Actuarial loss (gain) 22,640
 (47,952) 2,933
 (352)
Plan amendment 81
 —
 120
 —
Benefits paid (33,016) (29,672) (4,375) (4,226)
Projected benefit obligation at December 31 895,060
 835,523
 99,570
 95,389
Change in plan assets:  
  
  
  
Fair value at January 1 559,616
 559,719
 —
 —
Actual return on plan assets 40,968
 (9,431) —
 —
Employer contributions 40,000
 39,000
 —
 —
Benefits paid (33,016) (29,672) —
 —
Fair value at December 31 607,568
 559,616
 —
 —
Funded status at end of year $(287,492) $(275,907) $(99,570) $(95,389)
Amounts recognized in the statement of financial position consist of:  
  
  
  
Other current liabilities $—
 $—
 $(4,733) $(4,423)
Noncurrent liabilities (287,492) (275,907) (94,837) (90,966)
Net amount recognized $(287,492) $(275,907) $(99,570) $(95,389)
Amounts recognized in accumulated other comprehensive income consist of:  
  
  
  
Net loss $263,634
 $253,212
 $33,660
 $34,260
Prior service cost 96
 74
 625
 673
Subtotal 263,730
 253,286
 34,285
 34,933
Less amount recorded as regulatory asset (263,730) (253,286) —
 —
Net amount recognized in accumulated other comprehensive income $—
 $—
 $34,285
 $34,933
Accumulated benefit obligation $766,367
 $714,994
 $91,146
 $86,838
(1) Changes in the funded status of 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 $78$97.6 million and $69$92.5 million at December 31, 20162019 and 2015,2018, respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.


Table of contentsContents


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
 2016 2015 2014 2016 2015 2014 2019 2018 2017 2019 2018 2017
Service cost $32,019
 $33,164
 $25,292
 $1,228
 $1,689
 $1,645
 $34,061
 $37,836
 $33,742
 $(181) $(316) $759
Interest cost 37,813
 35,171
 35,415
 4,275
 3,868
 3,856
 42,312
 38,833
 38,957
 4,575
 4,248
 4,315
Expected return on assets (42,081) (42,310) (42,289) —
 —
 —
 (48,623) (52,302) (45,138) —
 —
 —
Amortization of net loss 13,331
 13,927
 3,911
 3,532
 4,195
 2,618
 13,564
 13,558
 13,190
 2,533
 3,788
 2,963
Amortization of prior service cost 59
 221
 347
 168
 185
 220
 6
 6
 28
 96
 98
 127
Net periodic pension cost 41,141
 40,173
 22,676
 9,203
 9,937
 8,339
 41,320
 37,931
 40,779
 7,023
 7,818
 8,164
Adjustments due to the effects of regulation(1)
 (22,181) (21,173) 12,124
 —
 —
 —
Net periodic benefit cost recognized for financial reporting $18,960
 $19,000
 $34,800
 $9,203
 $9,937
 $8,339
Regulatory deferral of net periodic benefit cost(1)
 (39,379) (36,153) (38,699) —
 —
 —
Previously deferred pension cost recognized(1)
 17,154
 17,154
 17,154
 —
 —
 —
Net periodic benefit cost recognized for financial reporting(1)(2)
 $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 recognition of pension plan costs is deferred untilas those costs are recovered through rates.
(2)  Of total net periodic benefit cost recognized for financial reporting $15.1 million,$15.2 million, and $16.2 million respectively, was recognized in "Other operations and maintenance" and $11.0 million, and $11.6 million, and $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, and 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
  2016 2015 2014 2016 2015 2014
Actuarial (loss) gain during the year $(23,753) $(3,790) $(146,674) $(2,933) $353
 $(15,324)
Reclassification adjustments for:            
Amortization of net loss 13,331
 13,927
 3,911
 3,532
 4,195
 2,618
Plan amendment service cost (81) —
 —
 (120) —
 —
Amortization of prior service cost 59
 221
 347
 168
 185
 220
Adjustment for deferred tax effects 4,083
 (4,050) 55,678
 (253) (1,851) 4,881
Adjustment due to the effects of regulation 6,361
 (6,308) 86,738
 —
 —
 —
Other comprehensive income recognized related to pension benefit plans $—
 $—
 $—
 $394
 $2,882
 $(7,605)

In 2017, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $16.6 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2016, relating to the pension plan and SMSP.  This amount consists of $13.5 million of amortization of net loss for the pension plan and $3.0 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
  2017 2018 2019 2020 2021 2022-2026
Pension Plan $32,592
 $34,957
 $37,375
 $39,938
 $42,477
 $248,151
SMSP 4,829
 4,630
 4,594
 5,199
 4,843
 26,976

 
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, 2016,the date of this report, IDACORP's and Idaho Power's minimum required contributionscontribution to the pension plan areis estimated to be zero$14 million during 2020. Depending on market conditions and cash flow considerations in 2017, though2020, Idaho Power planscould contribute up to contribute between $20 million and $40 million to the pension plan during 20172020 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.


Table of Contents

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.
 
Table of contents

The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
 2016 2015 2019 2018
Change in accumulated benefit obligation:  
  
  
  
Benefit obligation at January 1 $62,393
 $65,999
 $66,453
 $70,051
Service cost 1,116
 1,235
 853
 1,051
Interest cost 2,766
 2,678
 2,989
 2,643
Actuarial loss (gain) 1,550
 (5,008) 5,298
 (2,688)
Benefits paid(1)
 (3,949) (2,511) (4,564) (4,604)
Plan amendments 


 —
Benefit obligation at December 31 63,876
 62,393
 71,029
 66,453
Change in plan assets:  
  
  
  
Fair value of plan assets at January 1 35,566
 38,375
 33,391
 38,294
Actual return on plan assets 2,425
 85
Actual return (loss) on plan assets 7,269
 (1,330)
Employer contributions(1)
 957
 (383) 3,529
 1,031
Benefits paid(1)
 (3,949) (2,511) (4,564) (4,604)
Fair value of plan assets at December 31 34,999
 35,566
 39,625
 33,391
Funded status at end of year (included in noncurrent liabilities) $(28,877) $(26,827) $(31,404) $(33,062)
        
(1) Contributions and benefits paid are each net of $3.7$3.3 million and $3.5$3.1 million of plan participant contributions for 2019 and $0.3 million and $0.3 million of Medicare Part D subsidy receipts for 2016 and 2015,2018, 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 $—
 $—
  2016 2015
Net gain $(55) $(1,654)
Prior service cost 104
 130
Subtotal 49
 (1,524)
Less amount recognized in regulatory assets (49) 1,524
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
       

(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.


Table of Contents
  2016 2015 2014
Service cost 1,116
 $1,235
 $1,011
Interest cost 2,766
 2,678
 2,841
Expected return on plan assets (2,474) (2,680) (2,595)
Amortization of prior service cost 26
 15
 183
Net periodic postretirement benefit cost $1,434
 $1,248
 $1,440


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 $—
 $—
 $—
       

  2016 2015 2014
Actuarial (loss) gain during the year $(1,600) $2,413
 $(5,733)
Reclassification adjustments for amortization of prior service cost 26
 15
 183
Adjustment for deferred tax effects 615
 (949) 2,170
Adjustment due to the effects of regulation 959
 (1,479) 3,380
Other comprehensive income related to postretirement benefit plans $—
 $—
 $—
(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.
 
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003 and established a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage.
Table of contents

The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (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
  2017 2018 2019 2020 2021 2022-2026
Expected benefit payments $3,980
 $4,040
 $4,070
 $4,100
 $4,120
 $20,620
Expected Medicare Part D subsidy receipts 370
 410
 450
 480
 520
 3,240

 
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
 2016 2015 2016 2015 2016 2015 2019 2018 2019 2018 2019 2018
Discount rate 4.45% 4.60% 4.45% 4.60% 4.45% 4.60% 3.60% 4.55% 3.65% 4.60% 3.60% 4.60%
Rate of compensation increase(1)
 4.11% 4.11% 4.75% 4.50% —
 —
 4.37% 4.25% 4.75% 4.75% —
 —
Medical trend rate —
 —
 —
 —
 8.3% 9.7% —
 —
 —
 —
 6.7% 6.3%
Dental trend rate —
 —
 —
 —
 5.0% 5.0% —
 —
 —
 —
 4.0% 4.0%
Measurement date 12/31/2016
 12/31/2015
 12/31/2016
 12/31/2015
 12/31/2016
 12/31/2015
 12/31/2019
 12/31/2018
 12/31/2019
 12/31/2018
 12/31/2019
 12/31/2018
                        
(1) The 20162019 rate of compensation increase assumption for the pension plan includes an inflation component of 2.50%2.40% plus a 1.61%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%

Table of Contents
  Pension Plan SMSP 
Postretirement
Benefits
  2016 2015 2014 2016 2015 2014 2016 2015 2014
Discount rate 4.60% 4.25% 5.20% 4.60% 4.20% 5.10% 4.60% 4.20% 5.15%
Expected long-term rate of return on assets 7.50% 7.50% 7.75% —
 —
 —
 7.25% 7.25% 7.25%
Rate of compensation increase 4.11% 4.11% 4.30% 4.50% 4.50% 4.50% —
 —
 —
Medical trend rate —
 —
 —
 —
 —
 —
 8.3% 9.7% 6.4%
Dental trend rate —
 —
 —
 —
 —
 —
 5.0% 5.0% 5.0%

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 8.36.7 percent in 20162019 and is assumed to decrease to 6.85.9 percent in 2017, 5.3 percent in 2018,2020, 5.2 percent in 20192021, 5.1 percent in 2022 and to gradually decrease to 4.53.9 percent by 2096.2091. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 5.04.0 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, 2016 (in thousands of dollars):
  One-Percentage-Point
  Increase Decrease
Effect on total of cost components $382
 $(280)
Effect on accumulated postretirement benefit obligation 3,687
 (2,841)

Table of contents


Plan Assets


Pension Asset Allocation Policy:The target allocation and actual allocations at December 31, 2016,2019, 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, 2016
Debt securities 24% 22%
Equity securities 54% 56%
Real estate 6% 7%
Other plan assets 16% 15%
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 pensioners.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 at leastapproximately 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, core 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.


Table of contentsContents


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 16.17 - "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, 2016        
Assets at December 31, 2019        
Cash and cash equivalents $28,632
 $—
 $—
 $28,632
 $10,878
 $—
 $—
 $10,878
Short-term bonds 11,198
 —
 —
 11,198
 21,628
 —
 —
 21,628
Intermediate bonds 11,904
 88,734
 —
 100,638
 22,369
 134,931
 —
 157,300
Long-term bonds —
 20,573
 —
 20,573
 —
 —
 —
 —
Equity Securities: Large-Cap 80,582
 —
 —
 80,582
 92,852
 —
 —
 92,852
Equity Securities: Mid-Cap 68,634
 —
 —
 68,634
 81,663
 —
 —
 81,663
Equity Securities: Small-Cap 53,766
 —
 —
 53,766
 67,075
 —
 —
 67,075
Equity Securities: Micro-Cap 29,671
 —
 —
 29,671
 31,469
 —
 —
 31,469
Equity Securities: International 7,782
 —
 —
 7,782
 13,817
 —
 —
 13,817
Equity Securities: Emerging Markets 9,204
 —
 —
 9,204
 8,245
 —
 —
 8,245
Plan assets measured at NAV (not subject to hierarchy disclosure)                
Equity Securities: International —
 —
 —
 64,930
Equity Securities: Emerging Markets —
 —
 —
 24,443
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 —
 —
 —
 41,907
 

 

 

 47,570
Private market investments —
 —
 —
 33,713
 

 

 

 40,795
Commodities fund —
 —
 —
 31,895
Total $301,373
 $109,307
 $—
 $607,568
 $349,996
 $134,931
 $—
 $763,119
Postretirement plan assets(1)
 $28
 $34,971
 $—
 $34,999
 $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
         

Assets at December 31, 2015  
  
  
  
Cash and cash equivalents $10,519
 $—
 $—
 $10,519
Short-term bonds 11,023
 —
 —
 11,023
Intermediate bonds 11,499
 92,742
 —
 104,241
Long-term bonds —
 21,747
 —
 21,747
Equity Securities: Large-Cap 73,489
 —
 —
 73,489
Equity Securities: Mid-Cap 64,397
 —
 —
 64,397
Equity Securities: Small-Cap 47,777
 —
 —
 47,777
Equity Securities: Micro-Cap 22,186
 —
 —
 22,186
Equity Securities: International 7,698
 —
 —
 7,698
Equity Securities: Emerging Markets 9,679
 —
 —
 9,679
Plan assets measured at NAV (not subject to hierarchy disclosure)        
Equity Securities: International —
 —
 —
 59,787
Equity Securities: Emerging Markets —
 —
 —
 23,167
Real estate —
 —
 —
 39,035
Private market investments —
 —
 —
 37,316
Commodities fund —
 —
 —
 27,555
Total $258,267
 $114,489
 $—
 $559,616
Postretirement plan assets(1)
 $16
 $35,550
 $—
 $35,566
         
(1) The postretirement benefits assets are primarily life insurance contracts.


For the yearyears ended December 31, 20162019 and December 31, 2015,2018, there were no0 material transfers into or out of Levels 1, 2, or 3 other than the adoption of ASU 2015-07, Fair Value Measurement (Topic 820) -Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, certain investments were3.

Table of contentsContents

measured using NAV as a practical expedient for fair value, and these amounts were included as level 2 and 3 items in the fair value hierarchy. The requirements of this ASU were adopted retrospectively; therefore, the 2015 amounts have been reclassified to conform to the 2016 presentation. Because these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote.


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 international and emerging markets equity securities and commoditescommodities fund measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The valuevalues 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-endedopen-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 open-ended 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.


Table of contents

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 $8approximately $7.7 million, $7$7.7 million, and $7$7.4 million in 2016, 2015,2019, 2018, and 2014,2017, respectively.
Table of Contents

 
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 benefit amountspost-employment benefits included in other deferred credits on both IDACORP’s and Idaho Power’s consolidated balance sheets at both December 31, 20162019, and 2015,2018, were approximately $2 million.


12.13. 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, 20162019 and 20152018 (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
  
  2016 2015
  Balance Avg Rate Balance Avg Rate
Production $2,551,823
 2.40% $2,422,175
 2.46%
Transmission 1,120,903
 2.02% 1,077,065
 2.01%
Distribution 1,637,131
 2.72% 1,578,445
 2.72%
General and Other 422,187
 5.49% 407,779
 5.62%
Total in service 5,732,044
 2.64% 5,485,464
 2.68%
Accumulated provision for depreciation (1,988,477)  
 (1,913,927)  
In service - net $3,743,567
  
 $3,571,537
  

 
At December 31, 2016,2019, Idaho Power's construction work in progress balance of $405$552.5 million included relicensing costs of $249$326.0 million for the Hells Canyon Complex (HCC),HCC, Idaho Power's largest hydroelectrichydropower complex. TheIn 2019, 2018, and 2017, Idaho Power had IPUC authorizes Idaho Powerauthorization to include in its Idaho jurisdiction rates approximately $6.5 million annually ($10.78.8 million when grossed-up for the effect of income taxes)taxes in 2019 and 2018 and $10.7 million when grossed-up for the effect of income taxes in 2017 prior to income tax reform described in Note 2 - "Income Taxes") of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2016,2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $103$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, 20162019 (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 $710,910
 $5,972
 $302,291
 33 771
Boardman Boardman, OR 82,419
 34
 67,568
 10 64
Valmy Units 1 and 2 Winnemucca, NV 410,390
 1,373
 189,557
 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 $93$73.6 million in 2016, $932019, $81.8 million in 2015,2018, and $79$86.4 million in 2014.2017.
 
Table of contents

Idaho Power has contracts to purchase the energy from four PURPA qualifiedqualifying facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8$8.6 million in 2016, $82019, $9.7 million in 2015,2018, and $9$9.8 million in 2014.2017.
 
Table of Contents

IDACORP's consolidated VIE, Marysville, owns a hydroelectrichydropower plant with a net book value of approximately $16$14.7 million and $19$15.2 million at December 31, 20162019 and 2015,2018, respectively.


13.14. 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. Beginning June 1, 2012, accretion,Accretion, depreciation, and gains or losses related to the Boardman generating facility have beenare 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.  In 2016, changes in estimates at the coal-fired generation facilities resulted in a net increase of $1.8 million in the recorded AROs.


Idaho Power also has additional AROs associated with its transmission system, hydroelectrichydropower 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.
 
The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to redesignateclassify these removal costs as regulatory liabilities.  Seeliabilities, 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, 20162019 and 2015.2018.
 
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

  2016 2015
Balance at beginning of year $26,153
 $21,930
Accretion expense 1,031
 993
Revisions in estimated cash flows 1,759
 5,043
Liability settled (2,686) (1,813)
Balance at end of year $26,257
 $26,153


14.15. 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
  2016 2015
Idaho Power investments:  
  
Bridger Coal Company (equity method investment) $82,299
 $95,159
Exchange traded short-term bond funds and cash equivalents 23,908
 24,459
Executive deferred compensation plan investments 111
 102
Total Idaho Power investments 106,318
 119,720
Investments in affordable housing (IDACORP Financial Services) 7,643
 9,909
Ida-West joint ventures (equity method investments) 11,213
 11,123
Total IDACORP investments $125,174
 $140,752

 
Table of contentsContents


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 (loss) 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
  2016 2015 2014
Bridger Coal Company (Idaho Power) $10,855
 $9,773
 $10,814
Ida-West joint ventures 2,016
 1,355
 1,614
Other —
 —
 (56)
Total $12,871
 $11,128
 $12,372

 
Investments in Equity Securities


Investments in securities classified as available-for-saleequity securities are reported at fair value. Any unrealized gains or losses on available-for-saleequity securities are included in income, as the fair value option has been elected for these instruments.income. Unrealized gains and losses on available-for-saleequity securities were immaterial at December 31, 20162019 and December 31, 2015.2018. The following table summarizes sales of available-for-saleequity securities (in thousands of dollars):
  2019 2018 2017
Proceeds from sales $5,080
 $5,007
 $4,989
Gross realized gains from sales —
 —
 —

  2016 2015 2014
Proceeds from sales $15,693
 $34,243
 $—
Gross realized gains from sales 54
 —
 —
Gross realized losses from sales —
 —
 —

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary.  At December 31, 2016 and December 31, 2015, there were no indicators of other-than-temporary impairment related to IDACORP's and Idaho Power's investments.


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.


15.16. 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
Table of contents

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.


Table of Contents

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2016, 2015,2019, 2018, and 20142017 (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)
 2016 2015 2014 2019 2018 2017
Financial swaps Off-system sales $1,405
 $2,882
 $(4,119) Operating revenues $904
 $1,316
 $902
Financial swaps Purchased power 586
 748
 (1,416) Purchased power (2,183) 7,828
 166
Financial swaps Fuel expense (1,947) (6,045) 3,862
 Fuel expense 13,811
 22,563
 701
Financial swaps Other operations and maintenance (161) (50) (158) Other operations and maintenance —
 118
 (84)
Forward contracts Off-system sales —
 —
 277
 Operating revenues 285
 41
 55
Forward contracts Purchased power 31
 (6) (279) Purchased power (270) (54) (69)
Forward contracts Fuel expense 139
 54
 94
 Fuel expense 565
 (186) 4
      
(1)(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 off-system salesrevenues 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 1617 - "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, 20162019 and 20152018 (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
    
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, 2016              
Current:    
      
    
Financial swaps Other current assets $8,134
 $(2,183)
(1) 
$5,951
 $302
 $(302) $—
Total   $8,134
 $(2,183) $5,951
 $302
 $(302) $—
               
December 31, 2015              
Current:    
      
    
Financial swaps Other current assets $999
 $(785) $214
 $785
 $(785) $—
Financial swaps Other current liabilities 177
 (177) —
 5,146
 (177) 4,969
Forward contracts Other current assets 64
 —
 64
 —
 —
 —
Forward contracts Other current liabilities —
 —
 —
 3
 —
 3
Long-term:    
      
    
Financial swaps Other assets 148
 (22) 126
 22
 (22) —
Total   $1,388
 $(984) $404
 $5,956
 $(984) $4,972
               
(1) Current asset derivative amounts offset include $1.9 million$45 thousandof collateral payable for the period endingat December 31, 2016.2018.



Table of contentsContents


The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 20162019 and 20152018 (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 2016 2015
Electricity purchases MWh 217
 357
Electricity sales MWh 135
 120
Natural gas purchases MMBtu 6,604
 11,597
Natural gas sales MMBtu 70
 78
Diesel purchases Gallons 1,188
 1,068

 
Credit Risk
 
At December 31, 2016,2019, 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 Western Systems Power PoolWSPP, 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, 2016,2019, was $0.3$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, 2016,2019, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $2.7$6.7 million to cover open liability positions as well as completed transactions that have not yet been paid.


16.17. 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.
 
Table of contents

IDACORP and Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.
Table of Contents

 
•      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, 20162019 and 2015.2018.


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, 20162019 and 20152018 (in thousands of dollars): 
 December 31, 2016 December 31, 2015 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                
Money market funds and commercial paper                
IDACORP(1) $15,000
 $—
 $—
 $15,000
 $1,000
 $—
 $—
 $1,000
 $64,173
 $—
 $—
 $64,173
 $97,833
 $—
 $—
 $97,833
Idaho Power 29,967
 —
 —
 29,967
 10,000
 —
 —
 10,000
 26,510
 —
 —
 26,510
 79,228
 —
 —
 79,228
Derivatives 5,951
 —
 —
 5,951
 340
 64
 —
 404
 392
 13
 —
 405
 3,655
 —
 —
 3,655
Trading securities: Equity securities 111
 —
 —
 111
 102
 —
 —
 102
Available-for-sale securities: Equity securities 23,908
 —
 —
 23,908
 24,459
 —
 —
 24,459
Equity securities 42,738
 —
 —
 42,738
 36,488
 —
 —
 36,488
Liabilities:                                
Derivatives $—
 $—
 $—
 $—
 $286
 $4,686
 $—
 $4,972
 $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 (ICE) with quoted prices in an active market. Natural gas and diesel derivative valuationsderivatives are performedvalued using New York Mercantile Exchange (NYMEX) and ICEIntercontinental Exchange pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. TradingEquity securities consist of employee-directed investments held in a Rabbi trust and are related to an executive deferred compensation plan.  Available-for-sale securities areplan and actively traded money market and exchange traded funds related to the SMSP,SMSP. The investments are measured using quoted prices in active markets and are held in a Rabbi trust, and are actively traded money market and exchange-traded funds with quoted prices in active markets.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, 20162019 and 2015,2018, using available market information and appropriate valuation methodologies (in thousands of dollars):thousands).
 December 31, 2016 December 31, 2015 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)
 1,745,678
 1,858,666
 1,726,474
 1,813,243
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)
 $1,745,678
 $1,858,666
 $1,726,474
 $1,813,243
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 16.17 - "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 hydroelectrichydropower conditions. Long-term debt is not traded on an exchange and is valued using
Table of contentsContents


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.


17.18. 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 hydroelectrichydropower generation projects, the remaining activities of IESCo, the successor to which wound down its energy marketing operations in 2003, 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 of dollars)thousands):
 
Utility
Operations
 
All
Other
 Eliminations 
Consolidated
Total
 
Utility
Operations
 
All
Other
 Eliminations 
Consolidated
Total
2016        
2019        
Revenues $1,259,353
 $2,667
 $—
 $1,262,020
 $1,342,940
 $3,443
 $—
 $1,346,383
Operating income 265,491
 6,285
 —
 271,776
 297,652
 674
 —
 298,326
Other income 27,658
 6
 —
 27,664
Other income, net 20,362
 1
 —
 20,363
Interest income 4,235
 127
 (121) 4,241
 10,968
 3,052
 (769) 13,251
Equity-method income 10,855
 2,016
 —
 12,871
 10,285
 2,085
 —
 12,370
Interest expense 81,812
 344
 (121) 82,035
 86,412
 832
 (769) 86,475
Income before income taxes 226,427
 8,090
 —
 234,517
 252,854
 4,981
 —
 257,835
Income tax expense (benefit) 37,185
 (756) —
 36,429
 28,417
 (3,910) —
 24,507
Income attributable to IDACORP, Inc. 189,242
 9,046
 —
 198,288
 224,437
 8,417
 —
 232,854
Total assets 6,236,744
 73,137
 (19,984) 6,289,897
 6,494,159
 220,620
 (73,578) 6,641,201
Expenditures for long-lived assets 296,948
 2
 —
 296,950
 278,707
 (2) —
 278,705
Table of contentsContents


  
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

2015        
Revenues $1,267,505
 $2,784
 $—
 $1,270,289
Operating income 282,252
 (155) —
 282,097
Other income 25,868
 37
 —
 25,905
Interest income 3,037
 64
 (62) 3,039
Equity-method income 9,773
 1,355
 —
 11,128
Interest expense 81,718
 278
 (62) 81,934
Income before income taxes 239,211
 1,024
 —
 240,235
Income tax expense (benefit) 48,228
 (2,468) —
 45,760
Income attributable to IDACORP, Inc. 190,983
 3,696
 —
 194,679
Total assets 5,968,835
 71,704
 (17,225) 6,023,314
Expenditures for long-lived assets 293,969
 52
 —
 294,021
         
2014        
Revenues $1,278,651
 $3,873
 $—
 $1,282,524
Operating income 253,437
 259
 —
 253,696
Other income 21,517
 37
 —
 21,554
Interest income 2,705
 34
 (34) 2,705
Equity-method income 10,814
 1,558
 —
 12,372
Interest expense 79,570
 265
 (34) 79,801
Income before income taxes 208,903
 1,623
 —
 210,526
Income tax expense (benefit) 19,516
 (2,744) —
 16,772
Income attributable to IDACORP, Inc. 189,387
 4,093
 —
 193,480
Total assets 5,604,506
 109,044
 (12,513) 5,701,037
Expenditures for long-lived assets 273,911
 183
 —
 274,094


Table of contentsContents


18.19. OTHER INCOME AND EXPENSE
 
The following table presents the components of IDACORP’s Otherother income (expense), net and Idaho Power's Otherother income (expense) income,, 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 - Other income, net 2016 2015 2014
Investment income, net $4,466
 $2,890
 $2,655
Carrying charges on regulatory assets 2,082
 1,774
 1,949
Other income 767
 777
 588
Life insurance proceeds, net of premiums 2,588
 1,739
 1,164
Other expense (29) (21) (28)
Total $9,874
 $7,159
 $6,328
Idaho Power - Other expense, net      
Investment income, net $4,460
 $2,889
 $2,655
Carrying charges on regulatory assets 2,082
 1,774
 1,949
Other income 761
 739
 551
SMSP expense (9,203) (9,937) (8,339)
Life insurance proceeds, net of premiums 2,588
 1,739
 1,164
Other expense (2,632) (2,275) (2,343)
Total $(1,944) $(5,071) $(4,363)
       
(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."


19.20. 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, 2016, 2015,2019, 2018, and 20142017 (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)
       

(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).
Table of Contents
  Year Ended December 31,
  2016 2015 2014
Defined benefit pension items      
Balance at beginning of period $(21,276) $(24,158) $(16,553)
Other comprehensive income before reclassifications (1,859) 214
 (9,333)
Amounts reclassified out of AOCI 2,253
 2,668
 1,728
Net current-period other comprehensive income 394
 2,882
 (7,605)
Balance at end of period $(20,882) $(21,276) $(24,158)
       


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, 2016, 2015,2019, 2018, and 20142017 (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,
 2016 2015 2014 2019 2018 2017
Amortization of defined benefit pension items(1)
            
Prior service cost $168
 $185
 $220
 $96
 $98
 $127
Net loss 3,532
 4,195
 2,618
 2,533
 3,788
 2,963
Total before tax 3,700
 4,380
 2,838
 2,629
 3,886
 3,090
Tax benefit(2)
 (1,447) (1,712) (1,110) (677) (1,000) (1,208)
Net of tax 2,253
 2,668
 1,728
 1,952
 2,886
 1,882
Total reclassification for the period $2,253
 $2,668
 $1,728
 $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.


Table of contents

20.21. 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 2016, $0.92019 and $0.7 million in 2015,both 2018 and $1.42017.

At December 31, 2019 and 2018, Idaho Power had a $1.9 million payable to IDACORP, which was included in 2014.its accounts payable to affiliates balance on its consolidated balance sheets. In 2019, Idaho Power paid IDACORP certain estimated income taxes that had been accrued at December 31, 2018.
 
Ida-West:Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectrichydropower projects located in Idaho. Idaho Power paid Ida-West $8$8.6 million in 2016 and 2015 and $92019, $9.7 million in 2014.2018, and $9.8 million in 2017 for that power.
Table of contents




Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholders and the Board of Directors and Shareholders of
IDACORP, Inc.
Boise, Idaho
Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 20162019 and 2015, and2018, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2016.  Our audits also included2019, and the financial statementrelated notes and the schedules listed in the Index at Item 8.  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

These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements and financial statement schedules 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 Public Company Accounting Oversight Board (United States).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.  An audit includesmisstatement, 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 supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.

InCritical 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 such consolidatedon the financial statements, present fairly, in all material respects,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 positionstatements

Critical Audit Matter Description

Idaho Power Company ("Idaho Power"), the principal operating subsidiary of IDACORP, Inc. and subsidiaries at December 31, 2016 and 2015,the Company, is subject to rate regulation by the Federal Energy Regulatory Commission and the resultsIdaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of their operationselectric distribution companies in Idaho and their cash flows for each ofOregon. Management has determined it meets the three years in the period ended December 31, 2016, in conformity withrequirements under accounting principles generally accepted in the United States of America.  Also, in our opinion, suchAmerica 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 schedules, when consideredline 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.

Table of Contents

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 relationthe 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 basic consolidatedsignificant 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 takenstatements. 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 whole, present fairly,refund or a future reduction in all material respects,rates that should be reported as regulatory liabilities.

We evaluated the information set forth therein.Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.


We have also audited,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 standardsassistance of income tax specialists, we evaluated whether management had appropriately identified the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reportingincome tax timing differences eligible for flow-through accounting and recorded such differences as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commissionadjustments to income tax expense and our report dated February 23, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.regulatory assets.

/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 23, 201720, 2020


We have served as the Company's auditor since 1932.
Table of contentsContents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholder and the Board of Directors and Shareholder of
Idaho Power Company
Boise, Idaho
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, 20162019 and 2015, and2018, 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, 2016.  Our audits also included2019, and the financial statementrelated notes and the schedule listed in the Index at Item 8.  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

These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements and financial statement schedule 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 Public Company Accounting Oversight Board (United States).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.  An audit includesmisstatement, 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 supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiary at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 23, 201720, 2020


 We have served as the Company's auditor since 1932.
 
Table of contentsContents




SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
 
QUARTERLY FINANCIAL DATA
 
The following unaudited information is presented for each quarter of 20162019 and 20152018 (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.  
  
  
  
  
  
  
  
2016        
2019        
Revenues $280,956
 $315,436
 $372,045
 $293,583
 $350,319
 $316,895
 $386,320
 $292,849
Operating income 43,818
 76,953
 97,928
 53,077
 58,119
 71,780
 114,156
 54,271
Net income 25,530
 56,386
 83,017
 33,155
 42,637
 53,400
 90,218
 47,073
Net income attributable to IDACORP, Inc. 25,729
 56,246
 83,100
 33,213
 42,686
 53,156
 89,876
 47,136
Basic earnings per share $0.51
 $1.12
 $1.65
 $0.66
 $0.85
 $1.05
 $1.78
 $0.93
Diluted earnings per share $0.51
 $1.12
 $1.65
 $0.66
 $0.84
 $1.05
 $1.78
 $0.93
2015  
  
  
  
2018  
  
  
  
Revenues $279,395
 $336,328
 $369,165
 $285,401
 $310,107
 $339,952
 $408,801
 $311,892
Operating income 42,904
 85,976
 104,664
 48,552
 50,589
 82,835
 115,233
 48,265
Net income 23,344
 66,190
 73,267
 31,673
 36,111
 62,593
 102,591
 26,228
Net income attributable to IDACORP, Inc. 23,430
 66,080
 73,336
 31,832
 36,142
 62,288
 102,231
 26,140
Basic earnings per share $0.47
 $1.32
 $1.46
 $0.63
 $0.72
 $1.24
 $2.03
 $0.52
Diluted earnings per share $0.47
 $1.31
 $1.46
 $0.63
 $0.72
 $1.23
 $2.02
 $0.52
Idaho Power Company                
2016        
2019        
Revenues $280,566
 $314,411
 $371,474
 $292,902
 $349,771
 $315,774
 $385,028
 $292,367
Income from operations 47,124
 79,409
 100,928
 49,836
 58,734
 71,749
 113,924
 55,196
Net income 25,534
 54,807
 80,029
 28,872
 41,584
 51,176
 87,979
 43,698
2015  
  
  
  
2018  
  
  
  
Revenues $278,774
 $335,321
 $368,517
 $284,893
 $309,461
 $338,699
 $407,355
 $311,067
Income from operations 46,159
 88,836
 107,614
 51,833
 51,120
 82,659
 114,963
 48,581
Net income 23,462
 64,340
 71,727
 31,455
 35,857
 60,637
 100,194
 25,646


Table of contentsContents


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, 2016,2019, 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, 2016.2019. 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, 2016,2019, 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, 20162019 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, 2016.2019.
 
February 23, 201720, 2020


Table of contentsContents


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholders and the Board of Directors and Shareholders of
IDACORP, Inc.
Boise, Idaho
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, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 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 as of and for the year ended December 31, 2019, of the Company and our report dated February 20, 2020, expressed an unqualified opinion on those financial 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 overOver Financial Reporting.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 Public Company Accounting Oversight Board (United States).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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, 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 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 theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2016 of the Company and our report dated February 23, 2017 expressed an unqualified opinion on those financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 23, 201720, 2020


Table of contentsContents


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, 2016,2019, 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;
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.
 
Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016.2019. 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, 2016,2019, 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, 20162019 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, 2016.2019.
 
February 23, 201720, 2020


Table of contentsContents


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholder and the Board of Directors and Shareholder of
Idaho Power Company
Boise, Idaho
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, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 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 as of and for the year ended December 31, 2019, of the Company and our report dated February 20, 2020, expressed an unqualified opinion on those financial 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.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 Public Company Accounting Oversight Board (United States).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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, 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 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 theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2016 of the Company and our report dated February 23, 2017 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 23, 201720, 2020


Table of contentsContents


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, 20162019 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 20172020 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 20172020 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 20172020 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2016,2019, with respect to equity compensation plans where equity securities of IDACORP may be issued.  These plans are the 1994 Restricted Stock Plan (RSP), which was terminated on February 9, 2017, and the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP). pursuant to which equity securities of IDACORP may be issued.


Table of Contents

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))
Equity compensation plans approved by shareholders(1)
—
$—
950,577
(2)
Equity compensation plans not approved by shareholders—
$—
—
Total—
$—
950,577
(1) Consists of the RSP (terminated as of February 9, 2017) and the LTICP.
(2) 934,781 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 as of December 31, 2016.  As of December 31, 2016, 15,796 shares remained available for future issuance under the RSP prior to termination of the plan. 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 issued pursuant to the LTICP and unvested as of December 31, 2016.
Table of contents


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))
 
Equity compensation plans approved by shareholders 232,550
(1) 
$—
(2) 
613,394
(3) 
Equity compensation plans not approved by shareholders —
 $—
 —
 
Total 232,550
 $—
 613,394
 
 
(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) 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.
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 20172020 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 20172020 annual meeting of shareholders is hereby incorporated by reference.
 
Idaho Power:The table below presents the aggregate fees ourof 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, 20162019 and 2015:2018:
 2016 2015 2019 2018
Audit fees $1,344,108
 $1,280,500
 $1,515,701
 $1,437,100
Audit-related fees(1)
 25,000
 6,732
 3,927
 29,550
Tax fees(2)
 4,117
 37,655
 3,993
 26,125
All other fees(3)
 2,000
 2,000
 1,895
 1,895
Total $1,375,225
 $1,326,887
 $1,525,516
 $1,494,670
        
(1) Includes agreed-upon procedures in connection with Bonneville Power Administration's evaluation of Idaho Power's compliance with its Residential Exchange Program.
(2) Includes fees for benefit plan tax returns and consultation related to tax planning.
(1) Includes accounting-related consultation services.
(1) Includes accounting-related consultation services.
(2) Includes fees for consultation related to tax planning and accounting.(2) Includes fees for consultation related to tax planning and accounting.
(3) Accounting research tool subscription.
(3) Accounting research tool subscription.
(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 20162019 and 2015,2018, 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
Table of Contents

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.

Table of contents


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) Please referRefer 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 thisIDACORP'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 DescriptionFormFile No.Exhibit No.DateIncluded Herewith
2Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998S-4333-48031A3/16/1998 
3.1Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989S-3 Post-Effective Amend. No. 233-004404(a)(xiii)6/30/1989 
3.2Statement 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, 1991S-333-657204(a)(ii)7/7/1993 
3.3Statement 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, 1993S-333-657204(a)(iii)7/7/1993 
3.4Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998S-8 Post-Effective Amend. No. 133-56071-993(d)10/1/1998 
3.5Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 200010-Q1-31983(a)(iii)8/4/2000 
3.6Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 20058-K1-31983.31/26/2005 
3.7Articles 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, 20078-K1-31983.311/19/2007 
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
2
Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998
S-4333-48031A3/16/1998
Table of contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
3.8Articles 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, 20128-K1-31983.145/21/2012 
3.9Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect8-K1-31983.211/19/2007 
3.10Articles of Incorporation of IDACORP, Inc.S-3333-647373.111/4/1998 
3.11Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998S-3 Amend. No. 1333-647373.211/4/1998 
3.12Articles 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, 1998S-3 Post-Effective Amend. No. 1333-00139-993(b)9/22/1998 
3.13Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 20128-K1-144653.135/21/2012 
3.14Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect10-Q1-144653.1510/30/2014 
4.1Mortgage 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 2-3413B-2  
4.2Idaho 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 DescriptionFormFile No.Exhibit No.DateIncluded Herewith
3.1Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989S-3 Post-Effective Amend. No. 233-00440*4(a)(xiii)6/30/1989 
3.2Statement 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, 1991S-333-65720*4(a)(ii)7/7/1993 
3.3Statement 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, 1993S-333-65720*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. 133-56071-993(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-Q1-31983(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-K1-31983.31/26/2005 
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-K1-31983.311/19/2007 
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-K1-31983.145/21/2012 
3.9
Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect
8-K1-31983.211/19/2007 
3.10
Articles of Incorporation of IDACORP, Inc.
S-3333-647373.111/4/1998 
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. 1333-647373.211/4/1998 
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. 1333-00139-993(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-K1-144653.135/21/2012 
3.14
Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect
10-Q1-144653.1510/30/2014 
4.1Mortgage 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  
4.2Idaho 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 contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded 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
4.3Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.24)10-Q1-31984(b)8/4/2000 
4.4Agreement of Idaho Power Company to furnish certain debt instrumentsS-333-657204(f)7/7/1993 
4.5Agreement of IDACORP, Inc. to furnish certain debt instruments10-Q1-144654(c)(ii)11/6/2003 
4.6Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating CorporationS-3 Post-Effective Amend. No. 233-004402(a)(iii)6/30/1989 
4.7Indenture 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 trustee8-K1-144654.12/28/2001 
4.8First 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 trustee8-K1-144654.22/28/2001 
4.9Indenture 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 trusteeS-3333-677484.138/16/2001 
4.10Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 201010-Q1-31984.128/5/2010 
10.1Agreement, dated as of October 11, 1973, between Idaho Power Company and Pacific Power & Light Company 2-495845(c)  
10.2Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp10-K1-14465, 1-319810.42/19/2015 
10.3Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp10-K1-14465, 1-319810.52/19/2015 
10.4Letter Agreement, dated January 23, 1976, between Idaho Power Company and Portland General Electric Company 2-565135(i)  
10.5Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and Idaho Power CompanyS-72-620345(s)6/30/1978 
  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded 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-Q1-31984(b)8/4/2000 
4.4Agreement of Idaho Power Company to furnish certain debt instrumentsS-333-65720*4(f)7/7/1993 
4.5Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating CorporationS-3 Post-Effective Amend. No. 233-00440*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-K1-144654.12/28/2001 
Table of contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.6Amendment, dated September 30, 1977, relating to the agreement filed as Exhibit 10.4S-72-620345(t)6/30/1978 
10.7Amendment, dated October 31, 1977, relating to the agreement filed as Exhibit 10.4S-72-620345(u)6/30/1978 
10.8Amendment, dated January 23, 1978, relating to the agreement filed as Exhibit 10.4S-72-620345(v)6/30/1978 
10.9Amendment, dated February 15, 1978, relating to the agreement filed as Exhibit 10.4S-72-620345(w)6/30/1978 
10.10Amendment, dated September 1, 1979, relating to the agreement filed as Exhibit 10.4S-72-685745(x)7/23/1980 
10.11Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty ReservoirS-72-685745(z)7/23/1980 
10.12Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and Idaho Power CompanyS-72-649105(y)6/29/1979 
10.13Framework 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 rightsS-333-6572010(h)7/7/1993 
10.14Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.13S-333-6572010(h)(i)7/7/1993 
10.15Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.13S-333-6572010(h)(ii)7/7/1993 
10.16Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.13 10-Q1-1446510.585/7/2009 
10.17Agreement 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 LimitedS-333-6572010(m)7/7/1993 
10.18Credit 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 therein8-K1-14465, 1-319810.111/9/2015 
10.19Credit 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 therein8-K1-14465, 1-319810.211/9/2015 
10.20Letter 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    X
  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded 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-K1-144654.22/28/2001 
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-3333-677484.138/16/2001 
4.9
Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010
10-Q1-31984.128/5/2010 
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-K1-14465, 1-319810.42/19/2015 
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-K1-14465, 1-319810.52/19/2015 
10.3Framework 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 rightsS-333-65720*10(h)7/7/1993 
10.4Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*10(h)(i)7/7/1993 
10.5Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*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-Q1-14465*10.585/7/2009 
10.7Agreement 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 LimitedS-333-65720*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-K1-14465, 1-319810.111/9/2015 
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-K1-14465, 1-319810.211/9/2015 
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-K1-14465, 1-319810.112/10/2019 
Table of contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.21Letter 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    X
10.22Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company8-K1-319810.110/10/2006 
10.23Guaranty 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-333-6572010(m)(i)7/7/1993 
10.24Guaranty 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, Idaho10-Q1-319810(c)8/4/2000 
10.25Guaranty Agreement, dated as of August 30, 1974, between Idaho Power Company and Pacific Power & Light CompanyS-72-620345(r)6/30/1978 
10.261
Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 200810-K1-14465, 1-319810.152/26/2009 
10.271
Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I10-Q1-14465, 1-319810.6211/1/2012 
10.281
Idaho Power Company Security Plan for Senior Management Employees II, effective January 1, 2005, as amended and restated November 30, 2011 (superseded by Exhibit 10.31 effective February 9, 2017)10-K1-14465, 1-319810.212/22/2012 
10.291
Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees II (superseded by Exhibit 10.31 effective February 9, 2017)10-Q1-14465, 1-319810.6311/1/2012 
10.301
Amendment, dated January 16, 2014, to the Idaho Power Company Security Plan for Senior Management Employees II (superseded by Exhibit 10.31 effective February 9, 2017)10-K1-14465, 1-319810.262/20/2014 
10.311
Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 9, 2017    X
10.321
IDACORP, Inc. Restricted Stock Plan, as amended and restated September 20, 2007 (terminated February 9, 2017)10-Q1-14465, 1-319810(h)(iii)10/31/2007 
10.331
Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 200610-Q1-14465, 1-319810(h)(viii)11/2/2006 
10.341
IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 19, 201510-K1-14465, 1-319810.342/18/2016 
10.351
Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 200610-Q1-14465, 1-319810(h)(xix)11/2/2006 
10.361
Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 200610-Q1-14465, 1-319810(h)(xx)11/2/2006 
10.371
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, 200810-K1-14465, 1-319810.242/26/2009 
10.381
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, 200810-K1-14465, 1-319810.252/26/2009 
10.391
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 20108-K1-14465, 1-319810.13/24/2010 
  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded 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-K1-14465, 1-319810.212/10/2019 
10.12
Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company
8-K1-319810.110/10/2006 
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-Q1-319810(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-K1-14465, 1-319810.152/26/2009 
10.151
Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I
10-Q1-14465, 1-319810.6211/1/2012 
10.161
Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017
10-K1-14465, 1-319810.312/23/2017 
10.171
Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017
10-Q1-14465, 1-319810.18/3/2017 
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-Q1-14465, 1-319810(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-Q1-14465, 1-319810(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-Q1-14465, 1-319810(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-K1-14465, 1-319810.242/26/2009 
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-K1-14465, 1-319810.252/26/2009 
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-K1-14465, 1-319810.13/24/2010 
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-K1-14465, 1-319810.412/23/2017 
10.271
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)
10-K1-14465, 1-319810.302/21/2019 
10.281
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)
10-K1-14465, 1-319810.312/21/2019 
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-K1-14465, 1-319810.322/21/2019 
Table of contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.4010.301
IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 8, 2017X
10.411
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017X
10.421
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting) (For 2017 and 2018 Outstanding Awards)10-K1-14465, 1-319810.422/23/2017 X
10.4310.311
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-K1-14465, 1-319810.432/23/2017 X
10.4410.321
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)
X
10.451
IDACORP, Inc. 2000 Long-Term Incentive (For 2017 and Compensation Plan - Form of Restricted Stock Award Agreement (Time Vesting) (For 2015 and 20162018 Outstanding Awards)10-K1-14465, 1-319810.432/19/2015
10.461
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (Performance with Two Goals) (For 2015 and 2016 Outstanding Awards)10-K1-14465, 1-319810.442/19/201523/2017 
10.4710.331
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award Agreement (Time Vesting) (For 2014 and Prior Outstanding Awards)10-Q1-14465, 1-319810(h)(xvii)11/2/2006
10.481
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (Performance with Two Goals) (For 2014 and Prior Outstanding Awards)10-Q1-14465, 1-319810.695/5/2011
10.491
IDACORP, Inc. Executive Incentive Plan, as amended and restated February 11, 2016November 14, 201810-K1-14465, 1-319810.4710.362/18/201621/2019 
10.5010.341
Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008
10-K1-14465, 1-319810.322/26/2009 
10.5110.351
IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 20172020
    X
10.5210.361
Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.462/26/2009 
10.5310.371
Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement (November 16, 2008)
10-K1-14465, 1-319810.472/26/2009 
10.5410.381
Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.482/26/2009 
10.5510.391
Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.492/26/2009 
10.5610.401
Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.502/26/2009 
10.5710.411
Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred Compensation Agreement (November 16, 2008)
10-K1-14465, 1-319810.512/26/2009 
10.5810.421
Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.522/26/2009 
10.5910.431
Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008
10-K1-14465, 1-319810.532/26/2009 
10.6010.441
Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016
10-K1-14465, 1-319810.592/18/2016 
10.6110.451
Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016
10-K1-14465, 1-319810.612/23/2017
10.461
Second Amendment to the Idaho Power Company Employee Savings Plan, as amended January 1, 2018
10-Q1-14465, 1-319810.111/2/2017
10.471
Third Amendment to the Idaho Power Company Employee Savings Plan, as amended April 26, 2018
10-Q1-14465, 1-319810.45/3/2018
10.481
Fourth Amendment to the Idaho Power Company Employee Savings Plan, executed October 24, 2019 and effective January 1, 2020
10-Q1-14465, 1-319810.110/31/2019
21.1
Subsidiaries of IDACORP, Inc.
    X
12.123.1
Consent of Registered Independent Accounting Firm
X
23.2
Consent of Registered Independent Accounting Firm
X
31.1
IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed ChargesRule 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 contentsContents


  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
12.2Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges    X
21.1Subsidiaries of IDACORP, Inc.10-K1-14465, 1-319821.12/21/2013 
23.1Consent of Registered Independent Accounting Firm    X
23.2Consent of Registered Independent Accounting Firm    X
31.1IDACORP, Inc. Rule 13a-14(a) CEO certification    X
31.2IDACORP, Inc. Rule 13a-14(a) CFO certification    X
31.3Idaho Power Rule 13a-14(a) CEO certification    X
31.4Idaho Power Rule 13a-14(a) CFO certification    X
32.1IDACORP, Inc. Section 1350 CEO certification    X
32.2IDACORP, Inc. Section 1350 CFO certification    X
32.3Idaho Power Section 1350 CEO certification    X
32.4Idaho Power Section 1350 CFO certification    X
95.1Mine Safety Disclosures    X
101.INSXBRL Instance Document    X
101.SCHXBRL Taxonomy Extension Schema Document    X
101.CALXBRL Taxonomy Extension Calculation Linkbase Document    X
101.LABXBRL Taxonomy Extension Label Linkbase Document    X
101.PREXBRL Taxonomy Extension Presentation Linkbase Document    X
101.DEFXBRL Taxonomy Extension Definition Linkbase Document    X
       
1   Management contract or compensatory plan or arrangement
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
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.SCHXBRL Taxonomy Extension Schema DocumentX
101.CALXBRL Taxonomy Extension Calculation Linkbase DocumentX
101.LABXBRL Taxonomy Extension Label Linkbase DocumentX
101.PREXBRL Taxonomy Extension Presentation Linkbase DocumentX
101.DEFXBRL Taxonomy Extension Definition Linkbase DocumentX
104Cover 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 contentsContents


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,
  2016 2015 2014
  (thousands of dollars)
Income:    
  
Equity in income of subsidiaries $198,061
 $194,426
 $193,707
Investment income 3
 1
 —
Total income 198,064
 194,427
 193,707
Expenses:  
  
  
Operating expenses 716
 831
 1,376
Interest expense 333
 276
 261
Other expenses 45
 45
 45
Total expenses 1,094
 1,152
 1,682
Income from Before Income Taxes 196,970
 193,275
 192,025
Income Tax Benefit (1,318) (1,404) (1,455)
Net Income Attributable to IDACORP, Inc. 198,288
 194,679
 193,480
Other comprehensive income (loss) 394
 2,882
 (7,605)
Comprehensive Income Attributable to IDACORP, Inc. $198,682
 $197,561
 $185,875
       
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,
  2016 2015 2014
  (thousands of dollars)
Operating Activities:  
  
  
Net cash provided by operating activities $139,077
 $100,465
 $109,289
Investing Activities:  
  
  
Net cash provided by (used in) investing activities —
 —
 —
Financing Activities:  
  
  
Dividends on common stock (104,985) (96,810) (88,489)
(Decrease) increase in short-term borrowings (20,000) (11,300) (23,450)
Change in intercompany notes payable 2,421
 5,572
 (198)
Other (3,422) (1,675) (274)
Net cash used in financing activities (125,986) (104,213) (112,411)
Net (decrease) increase in cash and cash equivalents 13,091
 (3,748) (3,122)
Cash and cash equivalents at beginning of year 2,028
 5,776
 8,898
Cash and cash equivalents at end of year $15,119
 $2,028
 $5,776
       
The accompanying note is an integral part of these statements.


Table of contentsContents


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,
  2016 2015
Assets (thousands of dollars)
Current Assets:  
  
Cash and cash equivalents $15,119
 $2,028
Receivables 1,065
 946
Income taxes receivable —
 7,241
Other 101
 119
Total current assets 16,285
 10,334
Investment in subsidiaries 2,098,818
 2,007,984
Other Assets:    
Deferred income taxes 66,411
 76,410
Other 385
 402
Total other assets 66,796
 76,812
Total assets $2,181,899
 $2,095,130
Liabilities and Shareholders’ Equity    
Current Liabilities:    
Notes payable $—
 $20,000
Accounts payable 6
 13
Taxes accrued 8,476
 —
Other 660
 765
Total current liabilities 9,142
 20,778
Other Liabilities:    
Intercompany notes payable 17,834
 15,292
Other 1,017
 1,175
Total other liabilities 18,851
 16,467
IDACORP, Inc. Shareholders’ Equity 2,153,906
 2,057,885
Total Liabilities and Shareholders' Equity $2,181,899
 $2,095,130
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 20162019 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 $108$133 million, $99$124 million, and $91$116 million in 2016, 2015,2019, 2018, and 2014,2017, respectively.


Table of contentsContents


IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31,20162019, 2015,2018, and 20142017
 
Column A Column B Column C Column D Column E
    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)
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
2015:        
  
Reserves deducted from applicable assets        
  
Reserve for uncollectible accounts $2,104
 $3,327
 $819
 $4,895
 $1,355
Reserve for uncollectible notes 552
 —
 —
 —
 552
Other Reserves:    
  
  
  
Injuries and damages 1,995
 890
 —
 1,011
 1,874
2014:  
  
  
  
  
Reserves deducted from applicable assets        
  
Reserve for uncollectible accounts $2,502
 $6,756
 $198
 $7,352
 $2,104
Reserve for uncollectible notes 885
 (333) —
 —
 552
Other Reserves:  
  
  
  
  
Rate refunds 398
 (398) —
 —
 —
Injuries and damages 1,671
 461
 —
 137
 1,995
    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, 2016, 2015, and 2014

Column A Column B Column C Column D Column E
    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)
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
2015:        
  
Reserves deducted from applicable assets        
  
Reserve for uncollectible accounts $2,104
 $3,327
 $819
 $4,895
 $1,355
Other Reserves:    
  
  
  
Injuries and damages 1,995
 890
 —
 1,011
 1,874
2014:        
  
Reserves deducted from applicable assets        
  
Reserve for uncollectible accounts $2,502
 $6,756
 $198
 $7,352
 $2,104
Other Reserves:  
  
  
  
  
Rate refunds 398
 (398) —
 —
 —
Injuries and damages 1,671
 461
 —
 137
 1,995
(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 contentsContents


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 23, 201720, 2020 IDACORP, INC.
Date  
  By:/s/ Darrel T. Anderson
    Darrel T. Anderson
    President and Chief Executive Officer

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. TinstmanRichard J. Dahl Chairman of the Board February 23, 201720, 2020
Robert A. TinstmanRichard J. Dahl    
     
/s/ Darrel T. Anderson (Principal Executive Officer) February 23, 201720, 2020
Darrel T. Anderson    
President and Chief Executive Officer and Director    
     
/s/ Steven R. Keen (Principal Financial Officer) February 23, 201720, 2020
Steven R. Keen    
Senior Vice President, Chief Financial    
Officer, and Treasurer    
     
/s/ Kenneth W. Petersen  (Principal Accounting Officer) February 23, 201720, 2020
Kenneth W. Petersen       
Vice President, Controller, and Chief Accounting Officer       
        
/s/ Thomas Carlile Director February 23, 201720, 2020
Thomas Carlile
/s/ Richard J. DahlDirectorFebruary 23, 2017
Richard J. Dahl    
     
/s/ Annette G. Elg Director February 23, 201720, 2020
Annette G. Elg
/s/ Lisa A. GrowDirectorFebruary 20, 2020
Lisa A. Grow    
     
/s/ Ronald W. Jibson Director February 23, 201720, 2020
Ronald W. Jibson    
     
/s/ Judith A. Johansen Director February 23, 201720, 2020
Judith A. Johansen    
     
/s/ Dennis L. Johnson Director February 23, 201720, 2020
Dennis L. Johnson
/s/ J. LaMont KeenDirectorFebruary 23, 2017
J. LaMont Keen    
     
/s/ Christine King Director February 23, 201720, 2020
Christine King    
     
/s/ Richard J. Navarro Director February 23, 201720, 2020
Richard J. Navarro    
Table of contentsContents


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 23, 201720, 2020 Idaho Power Company
Date  
  By:/s/ Darrel T. Anderson
    Darrel T. Anderson
    President and Chief Executive Officer


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. TinstmanRichard J. Dahl Chairman of the Board February 23, 201720, 2020
Robert A. TinstmanRichard J. Dahl    
     
/s/ Darrel T. Anderson (Principal Executive Officer) February 23, 201720, 2020
Darrel T. Anderson    
President and Chief Executive Officer and Director    
     
/s/ Steven R. Keen (Principal Financial Officer) February 23, 201720, 2020
Steven R. Keen    
Senior Vice President, Chief Financial    
Officer, and Treasurer    
     
/s/ Kenneth W. Petersen  (Principal Accounting Officer) February 23, 201720, 2020
Kenneth W. Petersen       
Vice President, Controller, and Chief Accounting Officer       
        
/s/ Thomas Carlile Director February 23, 201720, 2020
Thomas Carlile
/s/ Richard J. DahlDirectorFebruary 23, 2017
Richard J. Dahl    
     
/s/ Annette G. Elg Director February 23, 201720, 2020
Annette G. Elg
/s/ Lisa A. GrowDirectorFebruary 20, 2020
Lisa A. Grow    
     
/s/ Ronald W. Jibson Director February 23, 201720, 2020
Ronald W. Jibson    
     
/s/ Judith A. Johansen Director February 23, 201720, 2020
Judith A. Johansen    
     
/s/ Dennis L. Johnson Director February 23, 201720, 2020
Dennis L. Johnson
/s/ J. LaMont KeenDirectorFebruary 23, 2017
J. LaMont Keen    
     
/s/ Christine King Director February 23, 201720, 2020
Christine King    
     
/s/ Richard J. Navarro Director February 23, 201720, 2020
Richard J. Navarro    
     
Table of contents

EXHIBIT INDEX
149
Exhibit No.Description
10.20Letter 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
10.21Letter 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
10.311
Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 9, 2017
10.401
IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 8, 2017
10.411
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017
10.421
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)
10.431
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)
10.441
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)
10.511
IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 2017
10.611
Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016
12.1IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
23.1Consent of Independent Registered Public Accounting Firm
23.2Consent of Independent Registered Public Accounting Firm
31.1IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3Idaho Power Rule 13a-14(a) CEO certification
31.4Idaho Power Rule 13a-14(a) CFO certification
32.1IDACORP, Inc. Section 1350 CEO certification
32.2IDACORP, Inc. Section 1350 CFO certification
32.3Idaho Power Section 1350 CEO certification
32.4Idaho Power Section 1350 CFO certification
95.1Mine Safety Disclosures
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
(1) Management contract or compensatory plan or arrangement.

147