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COMMONLY USED TERMS

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

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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power) may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or 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;

the expense and risks associated with capital expenditures for utility infrastructure, and the timing and availability of cost recovery for such expenditures through customer rates, including the potential for the write-down or write-off of expenditures if not deemed prudent by regulators;

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

unseasonable or severe weather conditions, wildfires, drought, and other natural phenomena and natural disasters, including conditions and events associated with climate change, which affect customer demand, hydroelectric generation levels, repair costs, 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 technologies that ~~reduce loads or reduce the need for~~may affect Idaho Power's ~~generation~~sale or ~~sale~~delivery of electric ~~power;~~power or introduce new cyber security risks;

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

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

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

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

accidents, fires (either ataffecting or caused by Idaho Power ~~facilities)~~facilities or infrastructure), explosions, and mechanical breakdowns that may occur while operating and maintaining ~~an electric system,~~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;~~penalties for which the companies 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;

~~administration~~

Table of reliability, security, and other requirements for system infrastructure required by the Federal Energy Regulatory Commission and other regulatory authorities, which could result in penalties and increase costs;Contents

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

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

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

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;

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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 ability to continue to pay dividends based on financial performance and in light of contractual covenants and restrictions and regulatory limitations;

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 the ability to adjust the labor cost structure when necessary;

failure to comply with state and federal laws, ~~policies,~~regulations, and ~~regulations,~~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 resulting operational changes through insurance or rates, or from third parties;

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

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

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

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

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PART I

ITEM 1. BUSINESS

OVERVIEW

Background

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

Idaho Power was incorporated under the laws of the state of Idaho in 1989 as the successor to a Maine corporation that was organized in 1915 and began operations in 1916. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the state regulatory commissions of Idaho and Oregon and by the FERC. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations 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, ~~2015,~~2018, IDACORP had ~~2,002~~1,981 full-time employees, ~~1,993~~1,972 of whom were employed by Idaho Power, and 219 part-time employees, 197 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 hydroelectric 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 ~~Report~~Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC). IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com. The contents of these websites are not part of this Annual Report on Form 10-K. ~~Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from the SEC’s website,~~ ~~www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.~~

UTILITY OPERATIONS

Background

Idaho Power provided electric utility service to ~~approximately~~more than ~~525,000~~558,000 ~~general business~~retail customers in southern Idaho and eastern Oregon as of December 31, ~~2015~~2018. ~~Over 436,000~~Approximately 465,000 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, and winter recreation. 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 ~~one~~1.2 million.

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Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its ~~general business~~retail 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, hydroelectric project relicensing, and system reliability, among other items.

Regulatory Accounting

Idaho Power is subject to accounting principles generally accepted in the United States of America (GAAP), with the impacts of rate regulation reflected in its financial statements. 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.~~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 they~~expects the amounts will be reflected in future prices, based on regulatory orders or other available evidence.

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

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Business Strategy

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. ~~Idaho Power's three-part~~IDACORP's board of directors regularly reviews IDACORP's long-term strategy, ~~can be summarized~~which 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.

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~~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 Power~~date 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.



Focus Areas		Initiatives
Grow to Enhance Financial Strength		- Execute on Business Development Initiatives - Find New Revenue Opportunities - Promote and Engage in Beneficial Electrification
Improve the Core Business		- Implement/Utilize Value-Added Analytics and Machine Learning - Upgrade Infrastructure for Growth, Technology Changes, Renewable Energy Integration, and Flexibility - Evaluate and Control Expenditures and Continue Efficient Operations - Use Technology to Enhance the Grid, System Reliability, and Safety - Implement Rate Structures that are Fair and Reasonable to All Customers - Leverage Technology and Turn Disruptive Threats into Opportunities
Enhance Idaho Power's Brand		- Enhance Idaho Power's Customers' Experience and Interactions - Continue Environmental Stewardship and Emission Reductions - Continue Constructive Regulatory Relationships and a Regulatory Compliance Mindset - Communicate Idaho Power's Story
Focus on Safety & Employee Engagement		- Continue Idaho Power's Strong Focus on Safety and Reducing Injuries - Execute on Employee Engagement and Leadership Development Initiatives

~~Idaho Power’s business strategy~~In 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’s financial stability and flexibility.~~stakeholders. Idaho Power ~~has further refined~~is working to continue to provide safe, fair-priced, reliable service to its ~~three-part business strategy~~customers from diversified generation resources, with a continued commitment to ~~include three core focuses for 2016—improving its core business, growing revenues,~~strong, sustainable financial results and ~~enhancing the brand and positioning the company for the future. IDACORP continues to focus on its core business and its goal of generating returns for its shareholders and long-term shareholder value.~~strong credit ratings.

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 a critical ~~factor~~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 ~~periodically~~to earn a reasonable return on investment as authorized by regulators. Idaho Power regularly evaluates the need to request changes to its retail electricity price structure to cover its operating costs and to ~~seek to~~ earn a fair return on its investments. Idaho Power uses general rate cases, power cost adjustment ~~(PCA)~~ 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 request rate changes does not, however, ensure that Idaho Power will recover all of its costs or earn a specified rate of return, or that its costs will be recovered in advance of or at the same time as the costs are incurred.

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In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of amounts recorded under specific authorization from the IPUC or OPUC but deferred for recovery or accrued for refund. 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 ~~PCA~~power cost adjustment mechanisms, FCA mechanism, and energy efficiency ~~rider.~~riders. Idaho Power collects most of its energy efficiency program costs through energy efficiency riders on customer bills. The Idaho and Oregon ~~PCA~~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 overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power ~~collects most~~to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of ~~its energy efficiency program costs through an energy efficiency rider on customer bills.~~base revenue annually, with any excess deferred for collection in a subsequent year.

Wholesale Markets: As a public utility subject to the provisions of Part II of 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. 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.

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Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run hydroelectric 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-system~~wholesale energy sales ~~revenues~~ depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as ~~adequate~~ market power prices at the time when those resources are available. ~~When~~A reduction in either factor leads to lower wholesale energy sales.

Idaho Power’s OATT rate is ~~low, off-system sales revenue is reduced.~~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 ~~moderate~~mild 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 presents~~Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho ~~Power’s revenues~~Power sales to existing customers. Also, development of new technologies and ~~sales volumes~~services 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 business~~retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.”

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

Year Ended December 31,
2015 2014 2013
General business revenues (thousands of dollars)

Residential $ 512,068
$ 500,195
$ 513,914
Commercial 306,178
299,462
281,009
Industrial 182,254
182,675
165,941
Irrigation 164,403
158,654
159,242
Provision for rate refund for sharing mechanism (3,159 ) (7,999 ) (7,602 )
Deferred revenue related to Hells Canyon Complex relicensing AFUDC (10,706 ) (10,706 ) (10,776 )
Total general business revenues 1,151,038
1,122,281
1,101,728
Off-system sales 30,887
77,165
54,473
Other 85,580
79,205
86,897
Total revenues $ 1,267,505
$ 1,278,651
$ 1,243,098
Energy sales (thousands of MWh)

Residential 4,977
4,965
5,365
Commercial 4,045
3,944
3,975
Industrial 3,196
3,217
3,182
Irrigation 2,047
1,966
2,097
Total general business 14,265
14,092
14,619
Off-system sales 1,254
2,220
1,683
Total 15,519
16,312
16,302



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


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

(2)

As part of its January 30, 2009, general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the 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, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new

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~~ways that 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.

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, have recently taken steps toward the adoption of a separate utility code applicable to electric utilities operating within the Shoshone-Bannock Tribal Reservation (Reservation). The proposed 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 MW.

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Power Supply

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

Weather, load demand, supply constraints, economic conditions, and availability of generation resources impact power supply costs. Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric 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 ~~PCA~~power cost adjustment mechanisms mitigate in large part the ~~potentially adverse~~ financial ~~statement~~ impacts of volatile fuel and power costs.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. ~~The~~Idaho Power reached its highest all-time system peak demand ~~was 3,407 Megawatts~~of 3,422 megawatts (MW)~~, set~~ on July ~~2, 2013, at which time~~7, 2017. Idaho ~~Power had deployed 30 MW of demand response programs to mitigate the load demand. The~~Power's highest all-time winter peak demand ~~was~~of 2,527 MW ~~set~~was last achieved on ~~December 10, 2009. Idaho Power's peak demand during 2015 was 3,402 MW, the magnitude of which was diminished by the deployment of 60 MW of demand response programs during the peak load period.~~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.

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	MWh			Percent of Total Generation						Power Supply			Percent of Total Generation
	2015	2014	2013	2015		2014		2013		2018	2017	2016	2018		2017		2016
	(thousands of MWh)									(thousands of MWh)
Hydroelectric plants	5,910	6,170	5,656	47	%	47	%	42	%	8,682	8,900	6,408	65	%	65	%	53	%
Coal-fired plants	4,676	5,851	6,327	37	%	44	%	47	%	3,274	3,284	4,045	24	%	24	%	33	%
Natural gas fired plants	2,076	1,175	1,576	16	%	9	%	11	%
Natural gas-fired plants										1,408	1,504	1,722	11	%	11	%	14	%
Total system generation	12,662	13,196	13,559	100	%	100	%	100	%	13,364	13,688	12,175	100	%	100	%	100	%

Purchased power - cogeneration and small power production	2,008	2,286	2,127							3,045	2,800	2,314
Purchased power - other	1,784	1,867	1,775							2,386	1,442	2,023
Total purchased power	3,792	4,153	3,902							5,431	4,242	4,337
Total power supply	16,454	17,349	17,461							18,795	17,930	16,512

Hydroelectric Generation: Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of ~~1,709~~1,775 MW and annual generation of approximately ~~8.5~~8.7 million ~~Megawatt-hours (MWh)~~MWh under median water conditions. The amount of water available for hydroelectric power generation depends on several factors—the amount of ~~snow pack~~snowpack in the mountains upstream of Idaho Power’s hydroelectric facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summer time irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River.

In 2018, reservoir storage carryover from the previous year coupled with near-normal winter snowpack resulted in 8.7 million MWh of hydroelectric generation. In 2017, above normal winter and spring precipitation resulted in 8.9 million MWh of hydroelectric generation. In 2016, low upstream reservoir carryover (primarily in the upper Snake River basin) resulted in reduced downstream flow releases. Additionally, although snowpack accumulation was near-normal on April 1, 2016, the snowpack melted earlier than usual. The combined effect was lower than median hydro production of 6.4 million MWh in 2016. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is ~~reduced. The result is~~reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. In 2014, significantly low upstream carryover water storage hindered the impact of the runoff of near-normal snow accumulation, resulting in generation of 6.2 million MWh. 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 2015 April through July inflow volume into Brownlee Reservoir (the uppermost reservoir of Idaho Power's Hells Canyon Complex) was only 46 percent of normal. By comparison, April through July Brownlee Reservoir inflow was 63 percent of normal in 2014. For ~~2016,~~2019, Idaho Power estimates annual generation from its hydroelectric facilities ofto be between ~~6.0~~6.5 million MWh and ~~8.0~~8.5 million MWh.

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Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric 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 project,~~HCC, its largest hydroelectric generation source. Idaho Power also has three Oregon licenses under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities. For further information on relicensing activities, see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of Hydroelectric Projects.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydroelectric operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectric 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.

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~~Bridger Coal Company (BCC)~~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 ~~over a 51-year period ending in~~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 ~~2017~~2021 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 ~~operate~~fuel the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

NV Energy is the operator of the North Valmy power ~~plant. NV Energy and~~plant (Valmy Plant). Idaho Power ~~have contracts with a coal supplier through 2016. Idaho Power's share of these contracts, together with the existing coal inventory at the North Valmy plant, are expected~~expects to meet ~~Idaho Power's projected~~2019 fuel requirements through existing inventory and coal ~~requirements at the plant through 2017. Idaho Power~~contracts and expects to be able to ~~obtain~~meet future coal requirements through ~~similar~~new or existing coal supply contracts. In 2017 and 2018, Idaho Power established a process approved by the IPUC and OPUC for recovery of costs related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant units 1 and 2 in 2019 and 2025, respectively. In 2018, the Valmy Plant provided 5 percent of Idaho Power's total generation, compared with 2 percent of Idaho Power's total generation in both 2017 and 2016.

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 ~~2016 and has 25 percent of projected fuel needs for 2017.~~2019. The Boardman plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Idaho Power expects to meet future coal needs through similar contracts. In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant no later than December 31, 2020.

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

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

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As of December 31, ~~2015,~~2018, approximately ~~9.8~~6.4 million ~~MMBtu's~~MMBtu of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through January ~~2017.~~2020. 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.

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 ~~limitations,~~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 ~~2015~~2018 and ~~2014~~,2017, Idaho Power purchased ~~1.8~~1.4 million MWh and ~~1.9~~0.9 million MWh of power through wholesale market purchases at an average cost of ~~$49.57~~$31.55 per MWh and ~~$49.31~~$26.32 per MWh, respectively. During ~~2015~~2018 and ~~2014~~,2017, Idaho Power sold ~~1.3~~2.2 million MWh and ~~2.2~~1.9 million MWh of power in wholesale market sales, with an average price of ~~$24.63~~$23.53 per MWh and ~~$34.76~~$12.82 per MWh, respectively.

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

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

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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 through~~ends in 2037.

Clatskanie People's Utility - for ~~the exchange of~~ up to 18 MW of ~~energy~~generation from the Arrowrock hydroelectric project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The ~~initial~~contract term ~~of the agreement was through December 31, 2015, but the term of the agreement has been extended through December 31,~~ends in 2020. Idaho Power has the right to renew the agreement for ~~one~~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 ~~is through~~ends in 2033.

PURPA ~~Power Purchase Contracts~~Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA ~~projects~~qualifying facilities as mandated by federal law. As of ~~February 5, 2016,~~December 31, 2018, Idaho Power had contracts with on-line ~~PURPA-related projects~~PURPA qualifying facilities with a total of ~~784~~1,119 MW of nameplate generation capacity, with an additional ~~423~~29 MW nameplate capacity of projects projected to be on-line ~~by June 1, 2017.~~in 2019. The ~~power purchase contracts~~energy sales agreements for these ~~projects~~qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA ~~project power purchases~~qualifying facilities during the last three years is included in the following table:


	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2018		2017		2016
PURPA contract expense (in thousands)	$	131,340	$	144,617	$	131,338
PURPA contracts expense (in thousands)							$	189,722	$	169,788	$	153,665
MWh purchased under PURPA contracts (in thousands)	2,008		2,286		2,127		3,045		2,800		2,314
Average cost per MWh from PURPA contracts	$	65.41	$	63.26	$	61.75	$	62.31	$	60.64	$	66.41

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 purchase~~energy sales agreements:

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

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

The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the ~~PCA,~~Idaho-jurisdiction power cost adjustment (PCA) mechanism, and the OPUC jurisdictional portion is recovered through ~~general rate case filings~~base rates and an Oregon ~~PCA~~power cost recovery 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.~~

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OPUC jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years. ~~Various ongoing cases are being processed at the OPUC in which the contract term and other PURPA regulations are being reviewed.~~

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 facilities that exceed these size limitations, Idaho Power is required to negotiate an applicable price (premised 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 ~~all~~solar PURPA qualifying facilities with a nameplate rating of 103 MW or less and ~~that~~all other types of projects with a nameplate rating of 10 MW or less. Idaho Power is required to negotiate an applicable price (premised on avoided costs) for all other qualifying facilities based upon OPUC regulations. ~~As part of the ongoing cases at the OPUC, the OPUC has temporarily reduced this nameplate rating for solar and wind projects to 3 MW.~~

~~Idaho Power, as well as other affected electric utilities, have engaged~~Participation in proceedings at the IPUC and OPUC relating to PURPA contracts. Final rulings were issued in the IPUC proceedings in 2015, and the OPUC proceedings are ongoing. These proceedings have related to, among other things, appropriate contract term lengths and the prices paid for energy purchased from PURPA projects. Refer to Part II - Item 7 - MD&A - "Regulatory Matters - ~~Renewable Energy Contracts and PURPA" for a summary of those proceedings.~~

~~Consideration of Participation in~~Western Energy Imbalance Market: ~~Utilities in the western United States outside~~In 2014, the California Independent System Operator ~~(California ISO) have traditionally relied upon a combination of automated~~ and ~~manual dispatch~~

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~~within the hour to balance generation and load to maintain reliable supply. These utilities have limited capability to transact within the hour outside their own borders. In contrast,~~PacifiCorp implemented an energy imbalance ~~markets use~~market (Western EIM) under which the participating parties enabled their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. ~~The 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. ~~Since 2015,~~ Idaho Power ~~has been evaluating the potential power supply cost savings and other advantages, system upgrade requirements, capital and ongoing operating costs, and other aspects of Idaho Power's potential~~commenced participation in the Western ~~EIM.~~EIM in April 2018. For information on regulatory proceedings related to costs associated with joining the Western EIM, see Part II, Item 7 – MD&A - "Regulatory Matters - Western Energy Imbalance Market Costs."

Transmission Services

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

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

Idaho Power is jointly working on the permitting of two significant transmission projects. The Boardman-to-Hemingway line is a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West line is a proposed 1,000-mile, 500-kV transmission 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 in June ~~2015.~~2017. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side and demand-side resource options, and identifies potential near-term and long-term actions. The four primary goals of the IRP are to:

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

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

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

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

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

In 2018, Idaho Power began preparing its 2019 IRP. The load forecast assumptions Idaho Power ~~used for purposes of~~expects to use in its 2019 IRP are included in the ~~2015 IRP predicts an~~table below, together with the average annual growth rate ~~of 1.2 percent for average loads and 1.5 percent for summer peak loads over~~assumptions used in the ~~20-year planning horizon from 2015 to 2034.~~prior two IRPs. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads. ~~The load forecast Idaho Power used in the 2013 IRP predicted an average annual growth~~

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~~rate of 1.1 percent for average loads and 1.4 percent for summer peak loads over the 20-year planning horizon from 2013 to 2032.~~



	5-Year Forecast		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)
2019 IRP (preliminary)	1.3%	1.4%	1.0%	1.2%
2017 IRP	1.1%	1.6%	0.9%	1.4%
2015 IRP	1.1%	1.5%	1.1%	1.4%

~~The 2015~~Idaho Power's 2017 IRP ~~identified a~~identifies its preferred resource portfolio ~~which~~and action plan. The IRP includes the completion of the Boardman-to-Hemingway 500-kV transmission line ~~and~~by 2026, the ~~potential early retirement~~end of Idaho Power's participation in coal-fired operations at the North Valmy power plant ~~both~~units 1 and 2 in 2019 and 2025, respectively, and the early retirement of Jim Bridger units 1 and 2 in 2032 and 2028, respectively, with no other new resource needs prior to ~~2025.~~2026. However, as noted in the ~~2015~~2017 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, ~~implementation of the EPA's rules under Section 111(d) of the Clean Air Act,~~ the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These and other uncertainties could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.

The 2015 IRP includes 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. The near-term action plan also includes a decrease in the size of the planned Shoshone Falls expansion from 50 MW to a range of 1.7 MW to 4 MW with a scheduled on-line date in 2019, as well as commencement of an economic evaluation of environmental control retrofits for units 1 and 2 at the Jim Bridger power plant.

Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 2223 programs. These energy efficiency ~~and demand response~~ programs target energy savings across the entire year, ~~and~~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 for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, ~~insulation improvement,~~ air duct sealing, and energy efficient lighting;

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

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

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

In ~~2015,~~2018, Idaho Power’s energy efficiency programs reduced energy usage by approximately ~~140,000~~173,000 MWh. For ~~2015,~~2018, Idaho Power had a demand response available capacity of approximately ~~385~~382 MW. In ~~2015~~2018, 2017, and ~~2014,~~2016, Idaho Power expended approximately ~~$39~~$44 million, $48 million, and ~~$37~~$43 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 ~~Idaho PCA mechanism.~~power cost adjustment mechanisms. Energy efficiency program expenditures funded through the

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

Environmental, Social, and Governance Initiatives

IDACORP’s and Idaho Power’s boards of directors are responsible for the oversight of the companies’ environmental, social, and governance (ESG) initiatives and are regularly informed of the goals, measures, and results of their ESG and sustainability programs. IDACORP and Idaho Power publicly released their inaugural sustainability report in May 2012 and have issued sustainability reports annually thereafter. IDACORP’s and Idaho Power’s ESG initiatives include establishing responsible management goals to balance shareholder return and the companies’ impact on the environment (such as the sustainability benefits from the Boardman to Hemingway transmission project, which includes integrating renewable energy generation and deferring the need for development of additional fossil-fueled resources), operational excellence in providing reliable, fair priced, and clean energy, continuing various environmental stewardship programs along the Snake River, engaging and empowering Idaho Power’s workforce (including succession planning at all levels, retirement planning education, and providing competitive pension benefits), promoting a culture of safety and inclusiveness for all employees, and building strong community partnerships for healthy economic development in Idaho Power’s service area, among other things. The most current sustainability report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power. The sustainability reports and related website content are not incorporated by reference into this Annual Report on Form 10-K.

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 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 Valmy Plant in connection with Idaho Power's plan to end its participation in the operation of unit 1 at the Valmy Plant by the end of 2019 and unit 2 by 2025. The plan to end Idaho Power's participation in operations of units 1 and 2 at the 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. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of selective catalytic reduction equipment (SCR) installation, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The table above does not include costs associated with a SCR installation on units 1 and 2 at the Jim Bridger power plant.

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

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



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

Environmental Regulation and Costs

Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with permits and licenses. In addition to generally applicable regulations, Idaho Power's three coal-fired power plants, three natural gas combustion turbine power plants, and 17 hydroelectric generating plants are subject to a broad range of environmental

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

Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, ~~especially~~particularly given the ~~additional~~volume 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):

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	2016		2017 - 2018		2019		2020-2021
Capital expenditures:
License compliance and relicensing efforts at hydroelectric facilities	$	16	$	27	$	12	$	35
Investments in equipment and facilities at thermal plants	29		11		4		22
Total capital expenditures	$	45	$	38	$	16	$	57
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	22	$	44	$	21	$	42
Operating costs for environmental facilities - thermal	14		27		12		23
Total operations and maintenance	$	36	$	71	$	33	$	65

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

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

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

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


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


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


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

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

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

changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho rate mechanisms, ~~decreased~~increased operating cash inflows by ~~$18 million;~~

$63 million. The increase is mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho ~~Power made $39 million~~power cost adjustment and FCA mechanisms, partially offset by revenues accrued in excess of ~~cash contributions to its defined benefit pension plan~~collections from the Valmy Plant settlement stipulation that will be collected in ~~2015, compared with $30 million of cash contributions during 2014.~~future periods;

changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by ~~$34~~$1 million and ~~$50~~decrease cash flows by $23 million at IDACORP and Idaho Power, respectively; ~~and~~

comparative changes in working capital balances due primarily to timing—principally related to a smaller decrease in accounts receivable in 2015 compared to the decrease in accounts receivable in 2014. Changes in accounts receivable balances reduced operating cash flows $16 million and $18 million for IDACORP and Idaho Power, respectively.

IDACORP's and Idaho Power's operating cash inflows in 2014 were $364 million and $343 million, respectively, increases of $59 million and $53 million, respectively, compared with 2013. Significant items that affected the companies' operating cash flows in 2014 relative to 2013 included:

changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating cash inflows by $58 million;

changes in working capital balances due primarily to ~~timing. Decreases~~timing, including fluctuations in accounts receivable, ~~balances from 2013 to 2014 compared with the increase in receivable balances experienced from 2012 to 2013 resulted in an increase to cash flows for 2014~~other current assets, and accounts payable, as follows:


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

Table of ~~approximately $50 million for IDACORP and $52 million for Idaho Power;~~Contents

~~cash outflows related to income taxes increased by approximately $10 million for IDACORP and $16 million for Idaho Power from 2013 to 2014; and~~

Idaho Power's joint venture, BCC, made net distributions to Idaho Power of $4 million in 2014, as compared with $15 million in 2013. A build-up in coal inventories at BCC during 2014 reduced BCC's cash available for distribution.


◦	the changes in other current assets increased cash flows by $14 million, which was primarily due to fluctuations in the balance in accrued unbilled revenues as energy sales near the end of the respective periods were impacted by weather; and


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

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. Idaho Power's construction expenditures, including AFUDC, were ~~$294~~$278 million, ~~$274~~$285 million, and ~~$247~~$297 million in ~~2015, 2014,~~2018, 2017, and ~~2013,~~2016, respectively. These capital expenditures were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. As discussed in "Capital Requirements" below, Idaho Power received ~~$11~~$22 million and $6 million in ~~both 2015~~2018 and ~~2013~~2017 from Boardman-to-Hemingway project joint permitting participants relating to a portion of these construction expenditures. ~~Additionally,~~

Idaho ~~Power's investments in its~~Power has a Rabbi ~~Trust~~trust designated to ~~fund~~provide funding for obligations of its ~~non-qualified pension plan were $10 million, $8 million, and $7~~nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased available-for-sale securities of $11 million in ~~2015, 2014,~~both 2018 and ~~2013, respectively. In 2015,~~2017, and $15 million in 2016. Idaho Power ~~used $30~~received $5 million of ~~Rabbi Trust assets~~proceeds from the sales of available-for-sale securities in both 2018 and 2017, and $16 million in 2016. Idaho Power did not use any of these proceeds to acquire company-owned life ~~insurance.~~insurance in 2018 and 2017 but used $10 million of the proceeds to acquire company-owned life insurance in 2016.

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 ~~2013, 2014,~~2018, 2017, and ~~2015:~~2016:

on ~~April 8, 2013,~~March 16, 2018, Idaho Power issued ~~$75~~$220 million in principal amount of ~~2.50%~~4.20% first mortgage bonds Series K, maturing March 1, 2048;

on April 17, 2018, Idaho Power redeemed, prior to maturity, $130 million of its 4.50% first mortgage bonds, Series H, due ~~2023~~March 1, 2020, and ~~$75~~paid a related make-whole premium of $4.6 million;

on March 10, 2016, Idaho Power issued $120 million in principal amount of ~~4.00% first mortgage bonds due 2043;~~

~~on October 1, 2013 Idaho Power repaid at maturity $70 million of its 4.25% first mortgage bonds;~~

~~on March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65%~~4.05% first mortgage bonds, Series J, maturing on March 1, ~~2045;~~2046;

on April ~~23, 2015,~~11, 2016, Idaho Power redeemed, prior to maturity, ~~its $120~~$100 million in principal amount of ~~6.025%~~6.15% first mortgage bonds, ~~medium-term notes~~Series H, due ~~July 2018;~~April 1, 2019, and paid a related make-whole premium of $14 million;

IDACORP and Idaho Power paid dividends of approximately ~~$97~~$121 million, ~~$88~~$113 million, and ~~$79~~$105 million in ~~2015, 2014,~~2018, 2017, and ~~2013,~~2016, respectively; ~~and~~

IDACORP's net change in commercial paper borrowings ~~were reductions~~used cash of ~~$11~~$22 million and ~~$23 million and $15~~provided cash of $2 million in ~~2015, 2014,~~2017 and ~~2013 respectively .~~2016, respectively; and

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

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Financing Programs and Available Liquidity

~~IDACORP Equity Programs:~~On July 12, 2013, IDACORP entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC (BNYMCM), under which IDACORP may offer and sell up to 3 million shares of its common stock from time to time through BNYMCM as IDACORP's agent. IDACORP has no obligation to sell any minimum number of shares under the Sales Agency Agreement. As of the date of this report, 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM. As of the date of this report, IDACORP does not expect to issue any shares of its common stock under the Sales Agency Agreement prior to its expiration in July 2016.

Effective July 1, 2012, IDACORP discontinued original issuances of common stock and instructed the plan administrators to use market purchases of IDACORP common stock for purposes of acquiring IDACORP common stock for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan. However, IDACORP may determine at any time to resume 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 ~~2013,~~and May 2016, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC ~~was~~is effective through ~~April 9, 2015. However, on April 1, 2015,~~May 31, 2019, subject to extension upon request to the ~~IPUC approved a two-year extension through April 9, 2017, continuing Idaho Power's authorization to issue and sell from time to time debt securities and first mortgage bonds.~~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 interest rate limit of seven percent.

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On ~~July 12, 2013,~~September 27, 2016, Idaho Power entered into a ~~Selling Agency Agreement~~selling agency agreement with ~~eight~~seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, secured medium term notes, Series JK (Series JK Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). ~~Also on July 12, 2013,~~At the same time, Idaho Power entered into the ~~Forty-seventh~~Forty-eighth Supplemental Indenture, dated as of ~~July~~September 1, ~~2013,~~2016, to the ~~Indenture.~~Indenture (Forty-eighth Supplemental Indenture). The ~~Forty-seventh~~Forty-eighth Supplemental Indenture provides for, among other items, (a) the issuance of up to $500 million in aggregate principal amount of Series ~~J Notes.~~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, ~~$250~~Idaho Power has $280 million ~~remained on Idaho Power's Selling Agency Agreement~~available for the issuance of first mortgage bonds, including Series JK Notes, or debt ~~securities.~~securities under the selling agency agreement.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the 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 ~~$2.0~~$2.5 billion, and as a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, ~~2015~~2018, was limited to approximately ~~$279~~$669 million. Idaho Power may increase the ~~$2.0~~$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, ~~2015~~,2018, Idaho Power could issue approximately ~~$1.5~~$1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

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, IDACORP and Idaho Power entered into ~~Credit Agreements~~credit agreements for $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 time and letters of credit not to exceed $50 million at any 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 million at any time. Idaho Power's facility may be increased, subject to

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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 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. 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 November 6, 2020, 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 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, ~~2015~~,2018, the leverage ratios for IDACORP and Idaho Power were 4644 percent and 4846 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, ~~2015~~,2018, 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 ~~2016.~~2019.

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

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

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

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

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.

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Available Short-Term Borrowing Liquidity

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


		December 31, 2015						December 31, 2014							December 31, 2018					December 31, 2017
		IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power				IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power
Revolving credit facility		$	100,000		$	300,000		$	125,000		$	300,000			$	100,000	$	300,000		$	100,000	$	300,000
Commercial paper outstanding		(20,000		)	—			(31,300		)	—				—		—			—		-
Identified for other use⁽¹⁾		—			(24,245		)	—			(24,245		)		—		(24,245		)	—		(24,245		)
Net balance available		$	80,000		$	275,755		$	93,700		$	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.

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The table below presents additional information about short-term commercial paper borrowing during the years ended December 31, 2018 and 2017:



	December 31, 2018						December 31, 2017
	IDACORP⁽¹⁾			Idaho Power			IDACORP⁽¹⁾			Idaho Power
Commercial paper:
Year end:
Amount outstanding	$	—		$	—		$	—		$	—
Weighted average interest rate	—		%	—		%	—		%	—		%
Daily average amount outstanding during the year	$	—		$	—		$	588		$	839
Weighted average interest rate during the year	—		%	—		%	1.42		%	1.12		%
Maximum month-end balance	$	—		$	—		$	2,425		$	—
(1) Holding company only.

At February ~~12, 2016~~,15, 2019, IDACORP had no loans outstanding under its credit facility and ~~$17.5 million of~~no commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. ~~The table below presents additional information about short-term commercial paper borrowing during the years ended~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~:

December 31, 2015 December 31, 2014

IDACORP⁽¹⁾
Idaho Power
IDACORP⁽¹⁾
Idaho Power
Commercial paper:
Year end:
Amount outstanding $ 20,000
$ —
$ 31,300
$ —
Weighted average interest rate 0.88 % — % 0.43 % — %
Daily average amount outstanding during the year $ 22,054
$ —
$ 37,786
$ —
Weighted average interest rate during the year 0.53 % — % 0.32 % — %
Maximum month-end balance $ 43,400
$ —
$ 47,300
$ —
⁽¹⁾Holding company only.

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 ~~and Moody’s Investors Service~~ 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
~~Tax-Exempt Debt~~	~~None~~	~~A3/VMIG-2~~
Standard & Poor's Rating Services:
Corporate Credit Rating	BBB	BBB
Rating Outlook	Stable	Stable
Short-Term Rating	A-2	A-2
Senior Secured Debt	None	A-

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

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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, ~~2015,~~2018, Idaho Power had ~~posted $0.9 million of~~no 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, ~~2015~~,2018, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately ~~$11.6~~$10.5 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

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Capital Requirements

Idaho Power's cash construction expenditures, excluding AFUDC, were ~~$284~~$268 million during the year ended December 31, ~~2015~~.2018. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated ~~cash requirements~~accrual-basis expenditures for construction ~~excluding AFUDC,~~ for ~~2016~~2019 through ~~2020~~2023 (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.

2016 2017 2018-2020
Ongoing capital expenditures (excluding item listed below in this table) $ 280-285 $ 275-285 820-870
Jim Bridger plant selective catalytic reduction equipment (discussed below) 20-25 0 40-50
Total (excluding AFUDC) $ 300-310 275-285 860-920



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

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

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

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

$20-$40 million per year for ongoing improvements and replacements at coal- and natural gas-fired plants;

$50-$70 million per year for hydroelectric plant improvement programs, including relicensing costs; and

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

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

~~Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners are installing selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NO~~_x) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provide for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO_x reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power estimates that the total cost for Idaho Power's share of the upgrades on units 3 and 4 is approximately $105 million, excluding AFUDC. As of December 31, 2015, Idaho Power had expended $83 million, excluding AFUDC, on SCR installation at units 3 and 4. The unit 3 SCR has been installed and was operating as of November 30, 2015. As of the date of this report, the unit 4 project remains on schedule and Idaho Power expects the total project cost to be at or below the originally estimated amount.

Boardman-to-Hemingway Transmission Line: The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon, and the Hemingway station 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 ~~(BPA)~~ 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 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 $40 million, including Idaho Power's AFUDC. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including ~~AFUDC for~~ Idaho Power's ~~share of the project.~~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. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table ~~above. In December 2015,~~above, in addition to approximately $50 million of Idaho ~~Power received an~~Power's share of costs related to early ~~payment of $11.4 million from a joint permitting participant. Construction costs beyond the permitting phase~~construction efforts, which are ~~not~~primarily included in the ~~table above.~~period 2021-2023. 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 and estimates.

~~Idaho Power~~Approximately $100 million, including AFUDC, has been expended ~~approximately $73 million~~ on the Boardman-to-Hemingway project through December 31, ~~2015.~~2018. Pursuant to the terms of the joint funding arrangements, ~~approximately $35 million of that amount has been received by~~ Idaho Power ~~as reimbursement from the project participants~~has received $70 million as of December 31, ~~2015. Approximately $15 million more must be reimbursed to Idaho Power in the future by the~~2018, due from project participants for ~~expenses~~their share of costs. As of the date of this report, no material participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power ~~incurred,~~ for ~~a total amount reimbursable by joint permitting participants of $49 million. In addition to the $49 million amount, $5 million is subject to~~

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~~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. Idaho Power plans to seek recovery of its~~ share of any future project ~~costs through the regulatory process.~~permitting expenditures incurred by Idaho Power.

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) as the lead federal agency on behalf of other federal agencies,~~BLM, the U.S. Forest Service, ~~and~~ the ~~Oregon~~ Department of ~~Energy.~~the Navy, and certain other federal agencies. The BLM issued ~~a draft environmental impact statement (EIS)~~its record of decision for the project in ~~December 2014, and as~~November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the ~~date~~project to cross approximately seven miles of ~~this report~~National Forest lands. Idaho Power expects the ~~BLM~~U.S. Forest Service to issue ~~a final EIS during 2016 and a record~~its right-of-way easement in 2019. Idaho Power expects the Department of the Navy to issue its decision on whether to approve the project to cross approximately seven miles of Department of the Navy lands in ~~late 2016 or early 2017.~~ the first quarter of 2019.

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In the separate Oregon state permitting process, in September 2018, Idaho ~~Power submitted a preliminary~~Power's application for site certificate was deemed complete by the Oregon Department of Energy (ODOE). The ODOE is expected to issue a draft proposed order on the application in the first half of 2019 providing the ODOE's recommendation on whether to issue a site certificate for construction in ~~February 2013 and intends to finalize the amended preliminary application in 2016. Idaho Power is unable to determine an in-service date for the line but, given~~Oregon. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date ~~would~~for the transmission line to be in ~~2022~~2026 or beyond.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway ~~station.~~station 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 $64 million, including AFUDC. Idaho~~ Power has expended approximately ~~$29~~$38 million, onincluding AFUDC, for its share of the permitting phase of the project through December 31, ~~2015.~~2018. 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, including AFUDC. Idaho Power's estimated share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. ~~Construction~~Idaho Power's share of potential early construction costs ~~beyond~~are excluded from the ~~permitting phase are not included in~~capital requirements table above because the ~~table above.~~timing of construction of Idaho Power's portion of the project 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 ~~under the National Environmental Policy Act~~ in November ~~2013.~~2013 for eight of the ten transmission line segments. In May 2017, a federal bill was signed into law that issued a right-of-way for certain portions of the remaining Gateway West segments. In April 2018, the BLM published its record of decision for the ~~BLM identified its final decision on the routing~~outstanding portions of the ~~project, issued right-of-way grants on public land for some segments, and deferred a decision on two segments (in both of which~~remaining segments. Idaho Power ~~has an interest)~~and PacifiCorp continue to ~~resolve routing concerns in those areas. Several interested parties have appealed~~coordinate the ~~BLM's record~~timing of ~~decision,~~next steps to best meet customer and Idaho Power has intervened in the proceedings. The BLM has initiated the supplemental EIS process for the two deferred segments. As of the date of this report, the BLM's schedule provides for the issuance of a record of decision on the two deferred segments in 2016.system needs.

~~Shoshone Falls Plant Expansion: The Shoshone Falls plant expansion project was included in~~ In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's ~~2013 IRP and, as originally planned, was to consist~~expenditures of ~~constructing a new powerhouse, intake structure, penstock, and substation and installing a new turbine to increase the nameplate generation capacity~~$220.8 million through year-end 2015 on relicensing of the ~~plant from 12.5 MW to 61.5 MW. However, following additional analysis of the costs~~HCC were prudently incurred, and ~~potential benefits of the expansion, Idaho Power's 2015 IRP includes~~thus eligible for future inclusion in ~~the near-term action plan a modified project that would result~~retail rates in a ~~significantly smaller increase in nameplate generation capacity at the facility, in a range of 1.7 MW to 4 MW, with a potential on-line date as early as 2019.~~future rate proceeding. In December 2017, Idaho Power is performing additional engineering and cost studies to determine the most suitable project that will optimize and improve the reliability of the facility. Following consultation with FERC staff, Idaho Power has concluded it can proceedfiled with the ~~modified expansion under the terms and conditions of the current operating license.~~

~~Completed Transmission System Transaction: To enhance the abilities of Idaho Power and PacifiCorp to serve their respective customers, in October 2014, Idaho Power and PacifiCorp executed~~IPUC a ~~Joint Ownership and Operating Agreement (Joint Operating Agreement) applicable to certain transmission-related equipment to be exchanged~~settlement stipulation signed by Idaho Power, the IPUC staff, and ~~PacifiCorp. The asset exchange was finalized on October 30, 2015, under the terms~~a third party intervenor recognizing that a total of a Joint Purchase and Sale Agreement dated October 24, 2014, between Idaho Power and PacifiCorp. Under the terms of the Joint Purchase and Sale Agreement each party agreed to transfer to the other transmission-related equipment with an estimated year-end 2014 net book value of approximately $43 million, subject to true-up as of the closing date. Additionally, the Joint Purchase and Sale Agreement terminated or amended a

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number of legacy long-term agreements related to the ownership and operation of transmission-related equipment and transmission services between Idaho Power and PacifiCorp. In 2014, Idaho Power collected approximately $8$216.5 million in ~~transmission revenues under legacy long-term transmission agreements that~~expenditures were ~~terminated~~reasonably incurred, and therefore should be eligible for inclusion in ~~connection with the Joint Purchase and Sale Agreement.~~customer rates at a later date. As a result of filing the ~~transaction~~settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for costs incurred through 2015 as well as $0.7 million related to associated costs incurred in 2016 and ~~termination of those long-term transmission agreements,~~2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an ~~increase~~order approving the settlement stipulation as filed with IPUC and determined the associated costs to ~~Idaho Power's OATT rate will~~ be ~~phased-in over a two-year period, as discussed in "Regulatory Matters" in the MD&A.~~reasonably and prudently incurred.

~~Other Infrastructure Projects:~~ Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen dioxide (NO₂) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provided for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO₂ reductions on unit 2 by 2021 and unit 1 by 2022.The unit 3 SCR was operating as of November 2015, and the unit 4 SCR was operating as of November 2016. In light of the substantial estimated cost of SCR installation, as of the date of this report, Idaho Power continues to ~~add~~assess whether to ~~its system to accommodate for growth~~move forward with the installation of SCR on units 1 and ~~to reinvest for reliability and general system improvement. These system enhancement projects involve significant~~2 at the Jim Bridger power plant. The expected capital ~~expenditures. Examples of system enhancements over~~expenditures in the ~~period 2016 through 2020, and their~~table above do not include any estimated ~~costs, include the following:~~

~~$50-$85 million per year for transmission-related projects other than the Boardman-to-Hemingway and Gateway West projects;~~

~~$30-$35 million per year for reconstruction of distribution lines;~~

~~$15-$20 million per year for replacement of underground distribution cables;~~

~~$25-$40 million per year for ongoing thermal plant improvement programs other than SCR equipment;~~

~~$25-$40 million per year for hydroelectric plant improvement programs;~~

~~$5-$10 million per year for reliability-related construction projects, such as wood pole crossarm replacements and feeder system improvement; and~~

~~$30-$45 million per year for general plant improvements, such as information technology, facilities, and fleet vehicles.~~

~~Approval of Long-Term Service Agreement for Natural Gas Plants:~~During 2015, Idaho Power executed a long-term service agreement for maintenance services at three of Idaho Power's natural gas plants, with a total estimated obligation of $82 million over the term of the agreement. In additionexpenditures relating to the ~~provision~~installation of maintenance services to Idaho Power, the agreement provided for Idaho Power's sale of approximately $22 million of capitalized spare parts to the service provider. Idaho Power expects that the arrangement will decrease the long-term costs of operating Idaho Power's natural gas plants. The agreement became effective in the fourth quarter of 2015, following receipt of an orderSCR on ~~reconsideration from the IPUC approving accounting treatment acceptable to Idaho Power.~~units 1 and 2.

Environmental Regulation Costs: Idaho Power anticipates that it will incur significant expenditures for the installation of environmental controls at its coal-fired plants and for its hydroelectric relicensing efforts. 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

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

Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an ~~Integrated Resource Plan (IRP). Idaho Power filed its most recent IRP in June 2015.~~IRP. 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 resource~~transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2017. The ~~2015~~2017 IRP identified a preferred resource portfolio and action plan, which includes ~~as near-term action items~~ the ~~continued permitting and planning for~~completion of the Boardman-to-Hemingway transmission line by 2026, the end to Idaho Power's participation in coal-fired operations at the Valmy Plant units 1 and ~~further investigation of~~2 in 2019 and 2025, respectively, and the early retirement of the North Valmy power plant in collaboration with the plant's co-owner. The near-term action plan also includes a decrease in the size of the planned Shoshone Falls expansion described above, as well as commencement of an economic evaluation of environmental control retrofits forJim Bridger units 1 and 2 atin 2032 and 2028, respectively, with no other new resource needs prior to 2026. However, as noted in the ~~Jim Bridger power plant.~~2017 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, environmental requirements, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant operation and retirements. These uncertainties, as well as others, could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. Additional information on Idaho Power's 2017 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed ~~$39 million, $30 million, and $30~~$40 million to its defined benefit pension plan in ~~2015, 2014,~~each year in 2018, 2017, and ~~2013, respectively.~~2016. Idaho Power estimates that it has no minimum contribution requirement for ~~2016, though it plans~~2019. Depending on market conditions and cash flow considerations in 2019, Idaho Power could contribute up to ~~contribute at least $20~~$40 million to the pension plan during ~~2016. Idaho Power may elect to contribute more than that amount based on long-term projections.~~2019. 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 2016 and beyond,~~Beyond 2019, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 1112 - "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.

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Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. ~~As of~~ At December 31, ~~2015~~,2018 and 2017, Idaho Power's deferral balance associated with the Idaho jurisdiction was ~~$82.5 million.~~$148 million and $128 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 ~~$17.1~~$17 million of deferred pension costs annually, and has applied ~~$68.1~~$68 million against the deferred amount under its Idaho sharing ~~mechanisms.~~mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions.

Income Tax Reform

In December 2017, the Tax Cuts and Jobs Act was signed into law, which among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. The majority of the law changes, including the rate reductions, became effective on January 1, 2018. See "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings and financial impacts.

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Contractual Obligations

The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, ~~2015,~~2018, for the respective periods in which they are due:

Payments Due by Period
Total 2016 2017-2018 2019-2020 Thereafter
(millions of dollars)
Long-term debt⁽¹⁾
$ 1,747
$ 1
$ 1
$ 330
$ 1,415
Future interest payments⁽²⁾
1,417
83
165
153
1,016
Operating leases⁽³⁾
17
—
2
2
13
Purchase obligations:

Cogeneration and small power production⁽⁴⁾
4,736
199
475
469
3,593
Fuel supply agreements 251
60
59
18
114
Other⁽⁵⁾
263
62
52
36
113
Pension and postretirement benefit plans⁽⁶⁾
264
8
75
138
43
Other long-term liabilities 1
—
1
—
—
Total $ 8,696
$ 413
$ 830
$ 1,146
$ 6,307
⁽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, 2015.
⁽³⁾The operating leases include right-of-way easements. Approximately $1 million of the obligations included have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
⁽⁴⁾ Subsequent to the end of 2015, as of February 5, 2016, three power purchase contracts with solar projects not yet online with a combined nameplate capacity of 25 MW had terminated. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $74 million over the 20-year lives of the terminated contracts.
⁽⁵⁾Approximately $84 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, 10 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.
⁽⁶⁾Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2020 with any level of precision, and amounts through 2020 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		2019		2020-2021		2022-2023		Thereafter
	(millions of dollars)
Long-term debt⁽¹⁾	$	1,855	$	—	$	100	$	150	$	1,605
Future interest payments⁽²⁾	1,565		85		166		159		1,155
Purchase obligations:
Maintenance and service agreements⁽³⁾	131		34		26		16		55
FERC and other industry-related fees⁽³⁾	128		14		25		25		64
Cogeneration and small power production	4,042		239		490		508		2,805
Fuel supply agreements	201		43		57		17		84
Other⁽³⁾⁽⁴⁾	51		3		8		8		32
Pension and postretirement benefit plans⁽⁵⁾	326		11		110		153		52
Other long-term liabilities - IDACORP only⁽³⁾	2		—		—		—		2
Total	$	8,301	$	429	$	982	$	1,036	$	5,854
(1) For additional information, see Note 5 – “Long-Term Debt” to the consolidated financial statements included in this report.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2018.
(3) Approximately $20 million of the amounts in maintenance and service agreements, $71 million of the amounts in FERC and other industry-related fees, $29 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(4) Other purchase obligations include right-of-way easements and the joint-operating agreement payments.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2023 with any level of precision, and amounts through 2023 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.

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.

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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 ~~2013, 2014,~~2018, 2017, and ~~2015,~~2016, IDACORP's board of directors voted to increase the quarterly dividend to ~~$0.43~~$0.63 per share, ~~$0.47~~$0.59 per share, and ~~$0.51~~$0.55 per share of IDACORP common stock, respectively. IDACORP's ~~2015 calendar year payout ratio was 50 percent.~~dividends during 2018 were 53.5 percent of actual 2018 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.

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Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. Certain legal or administrative proceedings to which IDACORP or Idaho Power are parties or are otherwise involved, and certain actual or potential legal claims pertaining to Idaho Power, are described in Note 10 - "Contingencies" to the consolidated financial statements included in this report. Except where noted in Note 10, inIn 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 ~~$73~~$58.4 million at December 31, ~~2015,~~2018, representing IERCo's one-third share of BCC's total reclamation obligation of ~~$218~~$175.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, ~~2015~~,2018, the value of the reclamation trust fund totaled ~~$70~~$101.9 million. During ~~2015,~~2018, the reclamation trust fund ~~distributed approximately $6~~made $6.7 million in 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. Starting in 2010, BCC began applying a nominal surcharge~~sales, all of which are made to ~~coal sales in order to maintain adequate reserves in~~ the ~~reclamation trust fund.~~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.

REGULATORY MATTERS

Introduction

Idaho Power's ~~development of rate case plans~~regulatory strategy takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of rate filings. These factors include, among others, in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and Idaho Power filed a large single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates. Between general rate cases, Idaho Power relies upon customer growth, power cost adjustment mechanisms, tariff riders, and other mechanisms to reduce the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return.

Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. ~~During 2016,~~ Idaho Power ~~plans to continue~~continues to assess ~~its~~the 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, ~~among others.~~ but does not anticipate filing a general rate case in 2019.

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Notable Retail Rate Changes in Idaho and Oregon

Included in the table that follows are notable regulatory developments during ~~2013, 2014,~~2018, 2017, and ~~2015~~2016 that affected Idaho Power's results for the periods. Also refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report for a description of regulatory mechanism and associated orders of the IPUC and OPUC, which should be read in conjunction with the discussion of regulatory matters in this MD&A.



~~Description~~	~~Effective Date~~	~~Estimated Annualized Revenue Impact (millions)~~⁽¹⁾
~~2013 Idaho FCA~~⁽²⁾	~~6/1/2013~~		(1	)
~~2013 Idaho PCA~~⁽²⁾⁽³⁾	~~6/1/2013~~		~~140~~
~~2013 Oregon APCU~~⁽²⁾	~~6/1/2013~~		3
~~2014 Idaho FCA~~⁽²⁾	~~6/1/2014~~		6
~~2014 Idaho PCA~~⁽²⁾⁽⁴⁾	~~6/1/2014~~		~~(88~~	)
~~Transfer of power supply costs from the Idaho PCA mechanism to Idaho base rates~~⁽⁵⁾	~~6/1/2014~~		99
~~2015 Idaho FCA~~⁽²⁾	~~6/1/2015~~		2
~~2015 Idaho PCA~~⁽²⁾⁽⁶⁾	~~6/1/2015~~		~~(12~~	)

⁽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⁾ 2013 PCA rates reflect $7 million of Idaho revenue-sharing related to 2012 financial results pursuant to an IPUC order issued in 2013 under regulatory settlement agreements approved in January 2010 and December 2011. The $140 million increase in PCA rates includes the reduction in the PCA mechanism component of the revenue sharing amount from $27 million for the 2012 PCA to $7 million for the 2013 PCA.
⁽⁴⁾ 2014 PCA rates reflect (a) the application of $20 million of surplus Idaho energy efficiency rider funds, (b) $8 million of customer revenue sharing for the year 2013 under a regulatory settlement agreement approved in December 2011, and (c) a $99 million shift in base net power supply expenses from recovery via the PCA mechanism to recovery through base rates.
⁽⁵⁾ ~~See footnote (4) 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.~~
⁽⁶⁾ 2015 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.



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

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

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 ~~Idaho~~ PCA mechanism and instead results in collecting that portion through base rates.

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~~Non-Base~~Valmy Base Rate ~~Idaho Regulatory~~Adjustment Settlement Stipulations

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

In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 Oregon Income Tax Reform Settlement Stipulation ~~for 2012~~described below, the OPUC also deemed prudent Idaho Power's decision to ~~2014~~pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement.

Other Notable Regulatory Matters

December 2011 Idaho Earnings Support and Sharing Settlement Stipulation: 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~~accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year. ~~The more specific terms and conditions of~~Under 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,~~Earnings Support and Sharing 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. As Idaho Power's 2012, 2013, and 2014 Idaho ROE exceeded 10.0 percent, Idaho Power did not amortize additional ADITC for those years, but instead shared earnings with customers. The amounts Idaho Power recorded for sharing for those years were as follows (in millions of dollars):

2014 2013 2012
Additional pension expense funded through sharing $ 16.7
$ 16.5
$ 14.6
Provision against current revenue as a result of sharing 8.0
7.6
7.2
Total $ 24.7
$ 24.1
$ 21.8

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation ~~for 2015 to 2019~~: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 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 more specific terms and conditions of the October 2014 settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 ~~settlement stipulation~~Idaho Earnings Support and Sharing Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory Treatment" below.

In 2018, Idaho Power recorded ~~no additional ADITC amortization and~~ a ~~$3.2~~$5.0 million provision against current revenue for sharing with customers, as its full-year Idaho ROE for ~~2015,~~2018 was above 10.0 percent. In both 2017 and 2016, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE ~~for 2015~~in both years was ~~above~~between 9.5 percent and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under the terms of the ~~settlement stipulation.~~October 2014 Idaho Earnings Support and Sharing Settlement Stipulation.

~~Modifications~~

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Idaho Power recorded 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		Total
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.

Income Tax Reform - Regulatory Treatment: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to (1) record a regulatory liability for the estimated Idaho-jurisdictional share of financial benefits after January 1, 2018, from the changes in federal income tax law under the Tax Cuts and Jobs Act, and (2) file a report with the IPUC by March 30, 2018, identifying and quantifying the financial impact of the income tax changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates and corresponding revenues to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full-year 2017.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho ~~Annual Rate Adjustment Mechanisms~~
customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease 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.

~~PCA Mechanism:~~ ~~In July~~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 ~~IPUC opened~~initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism to become effective beginning January 1, 2020. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a ~~docket pursuant~~moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their respective terms.

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking income tax reform benefits beginning January 1, 2020, at which time Idaho Power, the ~~IPUC Staff,~~OPUC staff, and other interested parties ~~evaluated~~ will discuss the methodology to quantify potential future income tax reform benefits.

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

Customer-Owned Generation Filing:In July 2017, Idaho Power filed an application with the IPUC related to residential and small general service customers who install their own on-site generation, seeking to create two new customer classes, with no request to change pricing or compensation. In May 2018, the IPUC issued an order authorizing the creation of the new customer classes. In October 2018, Idaho Power filed petitions requesting the IPUC open two new proceedings to study the fixed-costs of providing electric service to customers, and to study the costs, benefits, and compensation of net excess energy supplied by customer on-site generation, respectively. In November 2018, the IPUC opened the proceedings. As of the date of this report, Idaho Power and the parties in both proceedings are continuing to determine the procedural and substantive scope for each proceeding.

Western Energy Imbalance Market Costs:Idaho Power's ~~application~~participation in the Western EIM commenced on April 4, 2018. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Financial benefits or costs resulting from participation in the ~~true-up component of the PCA mechanism. The July 2014 docket arose from a prior order of the IPUC, which noted that the IPUC Staff believed that~~Western EIM are subject to 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 approved a settlement stipulation that modified the calculation of the true-up component of the PCA mechanism. The mechanics of the PCA mechanism ~~and the terms of the PCA settlement stipulation are~~as described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

~~FCA Mechanism:Also in July 2014,~~ In January 2017, the IPUC ~~opened a docket to allow~~issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. In November 2017, Idaho Power filed an application with the IPUC ~~Staff, and other interested parties~~requesting authorization to ~~further evaluate~~establish an interim method of recovery for Western EIM-related costs. In July 2018, the IPUC Staff's concerns regarding the application of the FCA. Concerns cited included the application of weather-normalization, the 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 toissued an order approving a set amount per customer. Stated generally, under the FCA Idaho Power charges residential and small commercial customers when it recovers less "actual fixed costs per customer" than the base level of fixed costssettlement stipulation that ~~the IPUC authorized~~provides for recovery through ~~rates~~Idaho Power's PCA mechanism. For more information on the order and its impact on financial results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in the last general rate case, and Idaho Power credits those customers when its "actual fixed costs per customer" recovered exceed that base level 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.

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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. Implementation of the new methodology was retroactive to January 1, 2015, as contemplated by the settlement stipulation. For 2015, application of the new FCA methodology resulted in Idaho Power recording greater FCA revenues than would have been recorded for the year under the prior mechanism.

this report.

Deferred (Accrued) Net Power Supply Costs

Deferred (accrued) power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred (accrued) power supply costs are recorded on the balance sheets for future recovery ~~or refund~~(refund) through customer rates. Idaho Power's ~~PCA~~power cost adjustment mechanisms in its Idaho and Oregon jurisdictions provide for annual adjustments to the rates charged to retail customers. The ~~PCA mechanism~~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 ~~significant PCA~~power cost adjustment rate changes in recent years include year-to-year volatility in hydroelectric generation conditions, market energy prices and the volume of ~~off-system~~wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, ~~the~~these factors ~~that influence power supply costs~~ can vary significantly, which can result in significant accruals and deferrals under the ~~PCA mechanism.~~power cost adjustment mechanisms. The ~~PCA~~power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" are illustrative of the volatility of net power supply costs and the impact on ~~PCA~~power cost adjustment rates.

~~As noted above under the heading "Idaho and Oregon General Rate Cases and Base Rate Adjustments," in light~~

Table 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 Idaho PCA mechanism.Contents

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

Idaho
Oregon⁽¹⁾
Total
Balance at December 31, 2013 $ 84,843
$ 6,611
$ 91,454
Current period net power supply costs deferred 48,104
—
48,104
Revenue sharing applied to deferred power supply costs (7,624 ) —
(7,624 )
Energy efficiency rider funds applied to deferred power supply costs (20,000 ) —
(20,000 )
Prior deferred costs amortized and recovered through rates (48,489 ) (2,210 ) (50,699 )
SO₂ allowance and renewable energy certificate (REC) sales
(2,895 ) (127 ) (3,022 )
Interest and other 573
403
976
Balance at December 31, 2014 54,512
4,677
59,189
Current period net power supply costs deferred 35,802
—
35,802
Revenue sharing applied to deferred power supply costs (7,999 ) —
(7,999 )
Energy efficiency rider funds applied to deferred power supply costs (4,000 ) —
(4,000 )
Prior deferred costs amortized and 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
⁽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, 2016	$	53.5		$	0.4		$	53.9
Current period net power supply costs accrued	(14.7		)	—			(14.7		)
Energy efficiency rider funds transferred to Idaho PCA mechanism	(13.0		)	—			(13.0		)
Prior amounts recovered through rates	(26.1		)	(0.5		)	(26.6		)
Sulfur Dioxide (SO₂) allowance and renewable energy certificate (REC) sales	(2.1		)	(0.1		)	(2.2		)
Interest and other	0.2			0.1			0.3
Balance at December 31, 2017	(2.2		)	(0.1		)	(2.3		)
Current period net power supply costs accrued	(41.5		)	—			(41.5		)
Tax reform revenue accrual to be refunded through Idaho PCA, net of amounts refunded	(1.9		)	—			(1.9		)
Western EIM cost recovery to be collected through Idaho PCA	2.2			—			2.2
Prior amounts refunded through rates	4.2			—			4.2
SO₂ allowance and REC sales	(2.6		)	(0.1		)	(2.7		)
Interest and other	(0.3		)	—			(0.3		)
Balance at December 31, 2018	$	(42.1	)	$	(0.2	)	$	(42.3	)

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Open Access Transmission Tariff Rate Proceedings

Idaho Power uses a formula rate for transmission service provided under its ~~OATT. The~~OATT, which allows transmission rates ~~are~~to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. In August ~~2015,~~2018, Idaho Power filed its 2018 final transmission rate with the FERC, ~~and publicly posted its final informational filing for its 2015 transmission rate,~~ reflecting a transmission rate of ~~$23.43~~$31.25 per kW-year, to be effective for the period from October 1, ~~2015~~2018, to September 30, ~~2016.~~2019. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $123.1 million. The OATT rate in effect from October 1, 2017, to September 30, 2018, was $34.90 per kW-year based on a net annual transmission revenue requirement of $130.4 million. The decrease in the OATT rate is largely attributable to an increase in short-term transmission revenues in 2017, which serves 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.

Leading up to the final informational filing, in a draft transmission rate posting Idaho Power made in June 2015, Idaho Power included in its draft OATT rate calculations the expected changes in demand associated with the then-pending transmission system transaction with PacifiCorp (described in "Liquidity and Capital Resources" in this MD&A), resulting in a draft rate of $33.23 per kW-year. The transmission system transaction terminated certain legacy transmission agreements and provided for new long-term point-to-point transmission service for PacifiCorp. In response to concerns from transmission customers, Idaho Power subsequently shifted its procedural approach for incorporating the impacts of the transmission system transaction on its OATT rate. Idaho Power's 2015 transmission rate of $23.43 per kW-year for the period from October 1, 2015 to September 30, 2016 does not include the impact of the transmission system transaction. In a July 2015 filing, Idaho Power requested clarification from the FERC as to when Idaho Power may fully incorporate the effects of the pending transmission system transaction in the formula used to determine its OATT rate. On November 19, 2015, the FERC issued an order requiring Idaho Power to reflect historic loads in the load denominator used in the transmission formula rate, resulting in an OATT rate increase that is phased-in over a two-year period rather than on an accelerated basis.

Relicensing of Hydroelectric Projects

Overview: Idaho Power, like other utilities that operate ~~nonfederal~~non-federal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. ~~Relicensing~~Idaho Power expects to seek recovery of relicensing costs and costs related to a new ~~licenses will be submitted to regulators for recovery~~long-term license through the ~~ratemaking process.~~regulatory process and, in December 2016, submitted a request for a determination of prudence of HCC relicensing costs, which is described below. Relicensing costs of ~~$221~~$297 million (including AFUDC) for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at December 31, ~~2015.~~2018. 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 ~~now~~currently will reduce ~~the amount collected in the~~ future ~~once~~collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, ~~2015,~~2018, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was ~~$88~~$135 million. In addition to the discussion below, ~~see~~refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydroelectric generating plants.

Hells Canyon Complex: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into

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

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

In April 2017, the governors of Oregon and Idaho jointly requested that Idaho Power withdraw and resubmit its Section 401 certification applications in both states to allow the states additional time to negotiate a potential resolution of the disputed issues. As of June 2018, the states had not resolved their differences, requiring Idaho Power to again withdraw and resubmit its Section 401 certification applications in both states. In December 2018, the states of Idaho and Oregon, along with Idaho Power, reached a proposed settlement that 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 401 certification for at least the first 20 years after final license issuance. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million over the term of the new license. Idaho and Oregon draft 401 certifications were released for public comment in December 2018. After the public comment period closes in February 2019, Idaho Power anticipates the states will evaluate the comments and draft final 401 certifications, which must be completed by June 2019 for the current cycle.

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 pending before the Oregon and Idaho Departments of Environmental Quality.~~process. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.

Idaho Power continues to work with Idaho and Oregon in the development of measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water quality certifications can be issued for the project, and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns. Idaho Power has begun ~~the process for~~ construction of new aerated runners at the Brownlee project (part of the HCC) at an estimated cost of ~~$50~~$59 million. Three of four units were installed by the end of 2018 and Idaho Power plans to install the final unit in 2019. Other measures that have been proposed or considered have included modification of spillways at ~~Brownlee and Hells Canyon~~the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements or the installation of a temperature

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control structure to address water temperatures during a small portion of the year. If Idaho Power is required to take these or other additional measures to satisfy relicensing requirements, it could add substantially to 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 ~~$20~~$30 million to ~~$30~~$40 million until issuance of the ~~license.~~license, which Idaho Power estimates will occur no earlier than 2022. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for cost incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.

Renewable Energy Standards and Contracts

Renewable Portfolio Standards: ~~Numerous proponents~~Many states have ~~introduced~~enacted 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 ~~power~~energy from the Elkhorn Valley wind project.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared ~~95%~~95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, ~~2015~~2018, 2017, and ~~2014,~~2016, Idaho Power's REC sales totaled ~~$1.8~~$2.9 million, $2.3 million, and ~~$3.2~~$1.0 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 ~~PCA~~power cost adjustment mechanisms.

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Renewable and Other Energy ~~Contracts and PURPA:~~Contracts: Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydroelectric and geothermal. The majority of these contracts are entered into as mandatory purchases wind power from both cogeneration and small power production (CSPP) and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity.under PURPA. As of ~~February 5, 2016,~~December 31, 2018, Idaho Power had contracts to purchase energy from 127 on-line ~~CSPP~~PURPA projects. An additional three contracts are with non-PURPA projects, including the Elkhorn Valley wind ~~power projects~~project with a ~~combined~~101-MW nameplate rating of 577 MW and an additional 50 MW of CSPP wind power projects not on-line and scheduled to come on-line by year-end 2016. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other CSPP and non-CSPP renewable generation

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sources, such as biomass, solar, small hydroelectric projects, and two geothermal projects. As of February 5, 2016, Idaho Power had contracts to purchase 364 MW of energy from solar projects not yet on-line and 9 MW of energy from hydroelectric projects not yet on-line. All of the solar projects have estimated on-line dates no later than year-end 2016, though with the extension of federal solar tax credit availability, it is likely the on-line date for some of the projects will extend into 2017.capacity. The following ~~tables~~table sets forth, as of ~~February 5, 2016,~~December 31, 2018, the ~~number~~resource type and nameplate capacity of Idaho Power's signed ~~CSPP-related agreements.~~agreements for energy purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.

Status Number of CSPP Contracts Nameplate Capacity (MW)
On-line as of February 5, 2016 109 784
Contracted and projected to come on-line by June 1, 2017 28 423



Resource Type	Total On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:
Wind	627	—	627
Solar	290	27	317
Hydroelectric	146	2	148
Other	56	—	56
Total PURPA	1,119	29	1,148
Non-PURPA:
Wind	101	—	101
Geothermal	35	—	35
Total non-PURPA	136	—	136

~~Pursuant~~The projects not yet on-line include one hydroelectric project and five solar projects that are scheduled to the requirements of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from CSPP facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory-mandated execution of PURPA agreements can resultbe on-line in Idaho Power acquiring energy that it does not need to serve customer loads at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. Integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of nameplate capacity (including non-PURPA wind) were contributing only 57 MW of power due to lack of wind. As the volume of CSPP purchases increases under PURPA, the magnitude of the costs and integration issues also increases. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms, and thus the primary impact of PURPA agreements is on customer rates.

In light of the volume of intermittent generation Idaho Power is required to purchase pursuant to existing PURPA power purchase agreements and the substantial increase in volume of proposed new solar generation facilities seeking power purchase agreements with Idaho Power, in January 2015 Idaho Power filed an application with the IPUC requesting that the IPUC issue an order directing that the maximum required term for prospective PURPA power purchase agreements be reduced from 20 years to two years. In its application, Idaho Power stated that the requested modification to terms of PURPA energy purchases is necessary to prevent harm to Idaho Power's customers that may result from entering into additional long-term, fixed-rate purchase agreements when Idaho Power predicts that there is no need for new generation capacity through 2021. In February 2015, the IPUC issued an order reducing the maximum contract term of certain future PURPA power purchase agreements from 20 years to five years during the pendency of the proceedings. In August 2015, the IPUC issued an order reducing the length of PURPA contracts that involve avoided-cost-based pricing to two years.

For the Oregon jurisdiction, on April 24, 2015, Idaho Power made filings with the OPUC requesting, among other things, a reduction in the term of standard PURPA power purchase agreements from 20 years to two years for projects above 100 kW, and a temporary suspension of Idaho Power's obligation to enter into new fixed-price standard PURPA agreements during the pendency of the proceedings. On June 23, 2015, the OPUC issued an order denying Idaho Power’s request for a temporary suspension but reduced the eligibility cap for standard contracts from 10 MW to 3 MW on a temporary basis during the pendency of the proceedings. The current phases in these proceedings have been fully submitted and are awaiting a ruling by the OPUC.2019.

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ENVIRONMENTAL MATTERS

Overview

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

Compliance with current and future environmental laws and regulations may:

increase the operating costs of generating plants;

increase the construction costs and lead time for new facilities;

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

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

reduce the output from current generating facilities.

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

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

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from ~~2016~~2018 to ~~2018.~~2020. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond ~~2018,~~2020, though they could be substantial. Furthermore, several executive orders issued in 2017 and 2018 concerning environmental regulations, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. For example, in August 2017, an executive order was issued to accelerate federal agencies' environmental review and permitting for major infrastructure projects. The outcome of federal agencies' review of regulations covered by executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or reduction or elimination of permitting requirements. Executive orders resulting in modifications to federal regulations could, on the other hand, be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federal regulations or bolster environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations and environmental-related expenditures. Idaho Power plans to continue to monitor actions associated with or resulting from executive orders.

Endangered Species Act Matters

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

In July 2018, the USFWS and the NMFS issued three proposals to revise ESA regulations (2018 ESA Proposals) related to the process and standards for listing species and designating critical habitat, the process for consultations with federal agencies under Section 7 of the ESA (including the definition of "destructive or adverse modification" of designated critical habitat), and the scope of protection of threatened species. Idaho Power believes that if the 2018 ESA Proposals are promulgated, the regulations could reduce Idaho Power’s obligations for mitigation under the ESA related to various construction and relicensing projects. Furthermore, in November 2018, the U.S. Supreme Court held that an area is eligible for designation as a critical habitat under the ESA only if it is also "habitat" for the species as defined in the statute, which generally means the area can support the species without modification, and as part of the designation, the USFWS must also consider the costs compared to the benefits of such designation. Idaho Power believes this ruling may limit the number of areas designated as critical habit and could also reduce Idaho Power’s obligations for mitigation under the ESA.

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~~the Washington ground squirrel.~~peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydroelectric facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydroelectric facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydroelectric dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

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~~Non-Listing~~Developments in Regulation of ~~Greater~~ Sage ~~Grouse:~~Grouse Habitat: In ~~2010,~~February 2016, a lawsuit was filed in the U.S. ~~Fish and Wildlife Service announced that listing~~District Court of Idaho challenging the ~~greater~~BLM's sage grouse ~~as threatened or endangered~~resource management and land use plan revisions that became effective in 2015 under the ~~Endangered Species Act was warranted but precluded by higher priority listing actions. Due to~~Federal Land Policy and Management Act. The lawsuit challenges the ~~presence of~~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 ~~vicinity of~~best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West ~~500-kV~~ transmission ~~lines, siting~~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 ~~these projects has required more extensive, costly,~~North Dakota, challenging the BLM's sage grouse resource management and ~~time consuming evaluation, permitting,~~land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and ~~engineering. Listing~~Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.

In June 2017, the Secretary of the ~~greater~~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 ~~threatened or endangered would~~the parties and the courts have ~~resulted~~agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for ~~a Section 7 consultation under~~ the Endangered Species Act, increasing the cost and time requirements for the permitting of these transmission projects. After evaluating scientific and other information regarding the greater sage-grouse, the U.S. Fish and Wildlife Service determined in September 2015 that protection for the greater sage-grouse under the Endangered Species Act is no longer warranted and withdrew the species from the candidate species list. This determination does not reduce the scope or magnitude of the consideration of sage grouse issues, or possible mitigation requirements associated with sage grouse, in Idaho Power's separate permitting processes for the transmission lines. It does, however, eliminate the requirement for a Section 7 consultation with the U.S. Fish and Wildlife Service under the ESA.lawsuits.

ESA Issues Related to Specific Projects:

Hells Canyon Relicensing 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 ~~2016~~2019 is unlikely.

Boardman-to-Hemingway and Gateway West Transmission Projects: ~~Slickspot peppergrass was listed as threatened by~~In August 2016, the USFWS ~~in 2009. In May 2011,~~re-instated the ~~USFWS issued a proposed rule to designate critical habitat for~~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 proposed to designate approximately 58,000 acres of critical habitat in four southeast Idaho counties. Most of the species is located on federal land. Additionally, the Washington ground squirrel is considered a “candidate species” under the ESA. Theits existence ~~of slickspot peppergrass and Washington ground squirrel~~ within or near the proposed routes for the Boardman-to-Hemingway and Gateway West transmission line projects ~~is impacting, and Idaho Power expects it~~ to continue to impact the cost and timing of permitting and construction of the ~~projects. The listing of either species would result in the need for a~~projects, as it requires an ESA Section 7 ~~consultation under~~consultation. The USFWS has also indicated it intends to designate critical habitat for the ~~ESA, which would~~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 ~~project~~projects and could further delay the in-service date of the ~~project.~~projects.

Endangered Species Act and National Environmental Policy Act Developments: In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydroelectric 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 National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the National Environmental Policy Act (NEPA) by failing to prepare a comprehensive environmental impact statement on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could

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result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement process to examine hydroelectric dams on the lower Snake River, which Idaho Power expects will take place over a five-year period. None of Idaho Power’s hydroelectric facilities are included in the studies.

Climate Change and the Regulation of Greenhouse Gas ~~(GHG)~~ Emissions

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

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

extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, 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 hydroelectric 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

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consumer preference for, and resource planning decisions requiring, renewable or low 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, ~~specifically~~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 ~~relatively~~continued low natural gas prices that decrease the cost to operate natural gas-fired power plants. As a result, Idaho Power plans to end its participation in coal-fired operations at the Valmy Plant units 1 and 2 in 2019 and 2025, respectively, and 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: The ~~EPA~~U.S. Environmental Protection Agency (EPA) has ~~become increasingly~~been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

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 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 are~~rule is complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.

In June 2014, the EPA released, under Section 111(d) of the CAA, a proposed rule for addressing ~~greenhouse gas emissions~~GHG from existing fossil fuel-fired electric generating units (EGUs). ~~According to the EPA, the~~The proposed rule was ~~designed~~intended to achieve a 30 percent reduction in CO₂ emissions from the power ~~sector. The EPA's proposal required that states meet their respective goals~~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. The final rule contains several changes from the proposed rule. The final rule requires~~Plan (CPP), which required states to adopt plans to collectively reduce 2005 levels of power sector CO₂ emissions by ~~32%~~32 percent by the year 2030. The final rule ~~provides~~provided states until September 2018 to submit implementation plans, phasing in several compliance periods beginning in 2022 and ~~until 2022 (rather than 2020 under the proposed rule) to begin~~ achieving ~~emissions reductions.~~

In the final ~~rule,~~emissions goals by 2030. In August 2018, the EPA ~~used a procedure~~proposed the Affordable Clean Energy (ACE) rule to ~~determine~~replace the ~~"best system~~CPP under Section 111(d) of ~~emission reduction" that was different than under~~ the ~~proposed rule, establishing two sets of uniform emissions rates (one~~CAA for coal-fired EGUs and one for natural gas-fired EGUs) and developing state limits based on the number and type of affected EGUs in each state. For the final rule, the EPA analyzed emissions reductions that affected EGUs could achieve by applying three “building blocks,” that the EPA concluded met the statutory standard “best system of emission reduction”:

~~Building Block 1: Improving heat rate at~~ existing ~~coal-fired steam EGUs;~~electric

~~Building Block 2: Shifting electricity generation from higher-emitting coal-fired steam EGUs to lower-emitting existing natural gas combined cycle generation; and~~

~~Building Block 3: Shifting generation from affected fossil fuel-fired EGUs to new zero-emitting renewable energy generation.~~

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~~The EPA also changed its approach to calculating the emissions targets. In the final rule, the EPA specified nationwide “sub-category” CO~~₂ emission performance standards applicable to affected steam coal-fired EGUs (1,305 lbs/MWh) and stationary natural gas combustion turbines (771 lbs/MWh). There are a number of methods states may use to achieve compliance. States may simply require affected EGUs to meet these emission rate standards. As in the proposed rule, the EPA also calculated statewide target emission rates, though the method used to calculate the state targets was different in the final rule. The EPA also included equivalent mass-based limits (in short tons) for each state, with the intent of making it easier for states to adopt intrastate or interstate allowance-based emissions trading programs. Other modifications to the proposed rule included an allowance for increased use of thermal generation due to hydroelectric plant variability, and adjustments for plants like the Langley Gulch natural gas power plant that commenced commercial operations during 2012.

~~Idaho Power's owned~~utility generating units. The new proposed rule is limited to reduction and ~~co-owned generation facilities are in~~compliance measures that occur at the ~~states~~physical location of ~~Idaho, Nevada, Oregon, and Wyoming. Idaho Power is evaluating~~each plant, removing the ~~impact that~~proposal to require reductions outside the ~~final~~boundaries of plants. The ACE rule ~~will have on its operations in those states. Idaho Power is working with state representatives, neighboring utilities, and others as it analyzes~~also provides for more state-specific control over implementation of the rule to address greenhouse gas emissions from existing coal-fired power plants, with a focus on state evaluation of improvement potential, technical feasibility, applicability, and ~~prepares for compliance. However, because~~remaining useful life of each unit. Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the existing and potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the presidential administration's executive orders and the EPA's proposal to repeal and replace the CPP discussed above, as of the date of this report and in light of these executive actions, Idaho Power is ~~unable~~uncertain whether and to ~~determine~~what extent the financial or operational impacts of the final rule. Further, on February 9, 2016, the U.S. Supreme Court issued an order staying the implementation of the rule pending the completion of certain legal challenges, which has an uncertainreplacement CPP may impact ~~on the ultimate timeline for implementation of the rule. In~~ its ~~2015 IRP, Idaho Power included a number of scenarios for the potential outcome of the then-pending 111(d) rulemaking process, and~~operations in the ~~future will continue to make operational decisions based on the implementation of the final rule and any compliance deadlines ultimately imposed.~~near term.

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

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

The State of Idaho has not passed legislation specifically regulating GHGs, 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 emission reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emission 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), ~~NSR/PSD~~New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.

MATS Implementation: The final ~~Mercury and Air Toxics Standards (MATS)~~MATS rule under the CAA, previously referred to as the Utility ~~MACT~~Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in compliance 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. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, and does not expect the EPA’s review of the MATS rule to have a significant impact on Idaho Power’s operations or financial results.

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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 emission 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:

•

NO_x2.: In 2010, the EPA adopted a new NAAQS for NO_x2 at a level of 100 parts per billion averaged over a 1-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 NO_x. The EPA indicated it will 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 NO_x. 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. As the designations have not yet been finalized, as of the date of this report Idaho Power is unable to predict the impact of the NAAQS for NO_x ~~on its operations. However, the costs of installation and implementation of any additional pollution reduction technology could be substantial.~~

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

•

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 actions~~has finalized designations of “unclassifiable/attainment” for ~~those states, and is likely to proceed with designation actions once additional data are gathered.~~SO₂ for all areas in which Idaho Power ~~expects that designations for Nevada and Wyoming will also be addressed~~owns or has an interest in a ~~separate future action.~~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. OnIn 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 majority of U.S. counties will meet the standards by 2025 with federal 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. IfSince January 2018, the EPA ~~were to make non-attainment determinations~~has finalized designations for all of the counties in ~~areas where~~which Idaho Power owns or ~~co-owns~~has an interest in a natural gas or coal-fired power ~~plants, or proposes to construct power plants,~~plant and determined that they meet 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. However, as the EPA has not yet made attainment and non-attainment designations, Idaho Power is unable to predict the potential impact of the standard on its operations. 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.standard.

~~Because~~As of the date of this report and based on the EPA ~~has not yet completed the designation of areas as attaining or not attaining the NAAQS for NO~~_x~~, SO~~₂~~, and ozone,~~designations described above, Idaho Power ~~is unable to predict what impact the adoption and implementation of~~does not expect these standards ~~may have on~~to significantly impact its operations ~~though it does expect at least some increases in~~or 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.

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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 ~~requires~~required that PacifiCorp install SCR equipment for NOnitrogen oxide (NO_x) control at Jim Bridger units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017 to install add-on NO_x controls at Jim Bridger unit 2 by 2021 and unit 1 by ~~2022.~~2022, which was submitted in December 2017. Idaho Power is assessing whether to move forward with installation of SCR equipment at units 1 and 2. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming ~~Regional Haze~~regional haze SIP that are consistent with the terms of the settlement agreement. OnIn January ~~10,~~ 2014, the EPA approved Wyoming's ~~Regional Haze~~regional haze SIP as to the Jim Bridger plant, with the NO_x control compliance dates set forth in the settlement agreement. Several interested parties have appealed the EPA's decisions on Wyoming's RHregional haze SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent the Jim Bridger plant could be affected.

~~New Source Review / Prevention of Significant Deterioration:~~ ~~NSR/PSD is a~~ pre-construction permitting program that requires a stationary source of air pollution to obtain a permit before beginning construction. The purpose of the program is to ensure that air quality is not significantly degraded by the addition of new and modified facilities, industrial boilers, and power plants. Under current NSR provisions of the CAA, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory equivalent before beginning the construction of a stationary source that will emit regulated pollutants, or before modifying an existing stationary source that will increase its emission levels. Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the NSR permitting requirements and NSPS under the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. As part of an industry-wide assessment of compliance with NSR and NSPS, EPA has sought information from a number of utilities regarding their coal-fired generating facilities. In 2003, the EPA sent information requests pursuant to the CAA to the Jim Bridger plant, seeking information relevant to NSR and NSPS compliance. Additional requests were received by the Boardman plant in 2008, with a follow up request for information in 2009 and by the Valmy plant in 2009. In September 2010, the EPA issued a Notice of Violation to Portland General Electric Company, the operator of the Boardman plant, alleging that Portland General Electric Company violated the NSPS under Section 111 of the CAA and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of certain modifications made to the plant in 1998 and 2004. To date, the EPA has not taken action on the Notice of Violation, and a related private lawsuit under the CAA was settled in 2011.

~~Regulation of Coal Combustion Residuals~~

The Resource Conservation and Recovery Act (RCRA) is a federal statute regulating the generation, treatment, storage, and disposal of solid and hazardous wastes. In December 2014, the EPA signed a final rule for the disposal of coal combustion residuals (CCRs), which are regulated under the RCRA. The rule established structural integrity design criteria and requires that owners and operators of coal-fired power plants periodically conduct a number of structural integrity related assessments and install monitoring apparatus. The final rule also imposes location restrictions on impoundments, requires the closure of impoundments that cannot meet the location restrictions, imposes liner design criteria and operating requirements, and imposes certain record keeping and notification requirements. Additionally, the EPA's rule imposed obligations associated with the closure of CCR impoundments. Idaho Power and its co-owners of coal-fired units performed engineering and cost studies to determine the impacts of the rule, and during 2015 Idaho Power recorded an increase of approximately $5 million in its asset retirement obligation for the Jim Bridger coal-fired plant. The amounts recorded for asset retirement obligations for Idaho Power's other jointly-owned coal-fired plants were not impacted by the EPA's new rule.

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~~Clean Water~~Income Taxes

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

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

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

compared with 2016. The increase was primarily due to higher pre-tax earnings at Idaho Power in 2017, and the $5.6 million

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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. There were no early redemptions of long-term debt in 2017. These increases in income tax expense

were partially offset by greater net flow-through income tax items at Idaho Power.

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power continues to pursue significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power's cash expenditures for property, plant, and equipment, excluding AFUDC, were $268 million in 2018, $277 million in 2017, and $287 million in 2016. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of approximately $1.5 billion expected over the period from 2019 through 2023.

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

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

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

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

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

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

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



	IDACORP	Idaho Power
Debt	44%	46%
Equity	56%	54%

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

Operating Cash Flows

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

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

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

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

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

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


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


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


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

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

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

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

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


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

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◦	the changes in other current assets increased cash flows by $14 million, which was primarily due to fluctuations in the balance in accrued unbilled revenues as energy sales near the end of the respective periods were impacted by weather; and


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

Investing Cash Flows

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

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

Financing Cash Flows

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

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

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

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

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

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

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

Financing Programs and Available Liquidity

~~Definition~~Idaho Power First Mortgage Bonds: Idaho Power's issuance of ~~“Waters~~long-term indebtedness is subject to the approval of the ~~United States” Under the CWA: On August 28, 2015, the EPA's~~IPUC, OPUC, and ~~U.S. Army Corps of Engineers' final rule defining the phrase "waters of the United States" under the CWA became effective.~~Wyoming Public Service Commission (WPSC). In April and May 2016, Idaho Power ~~believes that~~received orders from the ~~final rule potentially expands federal jurisdiction under~~IPUC, OPUC, and WPSC authorizing Idaho Power 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 ~~CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries,~~orders. Authority from the IPUC is effective through May 31, 2019, subject to extension upon request to the IPUC. The OPUC's and ~~adjacent wetlands, to~~WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other ~~waters,~~conditions, including ~~waters~~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 interest rate limit of seven percent.

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On September 27, 2016, Idaho Power entered into a selling agency agreement with ~~a "significant nexus"~~seven banks named in the agreement in connection with the potential issuance and sale from time to ~~those traditional waters. As a result~~time of up to $500 million in aggregate principal amount of first mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture (Forty-eighth Supplemental Indenture). The Forty-eighth Supplemental Indenture provides for, among other items, (a) the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture and (b) the increase of the ~~potential expansion,~~maximum amount of obligations to be secured by the ~~final rule~~Indenture to $2.5 billion (which maximum amount may ~~result in additional permitting and regulatory requirements under multiple provisions~~be further increased or decreased by Idaho Power without the consent of the ~~CWA.~~holders of first mortgage bonds). As of the date of this report, Idaho Power has ~~analyzed~~$280 million available for the ~~final rule~~issuance of first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and ~~expects that while it~~security provisions set forth in the Indenture. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

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

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

IDACORP and Idaho Power Credit Facilities: In November 2015, IDACORP and Idaho Power entered into credit agreements for $100 million and $300 million credit facilities, respectively. These facilities replaced IDACORP's and Idaho Power's ~~operations or financial condition, in part due~~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 time and letters of credit not to exceed $50 million at any 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 million at any time. 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 ~~relatively arid climate~~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. The applicable margin is based on IDACORP's or Idaho Power's, ~~service area and~~as applicable, senior unsecured long-term indebtedness credit rating, as set forth on a schedule to the ~~existing application of~~credit agreements. The companies also pay a facility fee based on the ~~CWA to most of Idaho Power's facilities, including its hydroelectric plants.~~respective company's credit rating for senior unsecured long-term debt securities.

~~On October 9, 2015, the United States Court~~Each facility contains a covenant requiring each company to maintain a leverage ratio of ~~Appeals for the Sixth Circuit issued a nationwide stay~~consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the ~~final waters~~end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the ~~United States rule from becoming effective. In response to~~respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the ~~Sixth Circuit's decision,~~credit agreement). “Consolidated total capitalization” is calculated as the ~~EPA resumed nationwide use~~sum of all consolidated indebtedness, consolidated stockholders' equity of the ~~agency's prior regulations defining~~borrower and its subsidiaries, and the ~~term “waters~~aggregate value of outstanding hybrid securities. At December 31, 2018, the ~~United States.” The EPA stated~~leverage ratios for IDACORP and Idaho Power were 44 percent and 46 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 ~~those regulations will be implemented as~~prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2018, IDACORP and Idaho Power believe 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 Clean Water Act.~~

~~Regulation of Cooling Water Intake Structures:~~The CWA generally prohibits the discharge of any "pollutant" from a point source into waters of the United States without a permit. Pollutants are broadly defined to include changes in temperature. Section 316(b) of the CWA requires that National Pollutant Discharge Elimination System permits for facilitiescompliance with cooling water intake structures ensure that the location, design, construction, and capacity of the structures employ the best technology available (BTA) to minimize harmful impacts on the environment, such as the removal of fish, fish larvae, marine mammals, and other aquatic organisms from waters of the U.S.In May 2014, the EPA issued final rules that establish requirements under Section 316(b) of the CWA for existing power generation facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. Given the nature of its co-owned coal-fired plants, Idaho Power expects that its cost to comply with the new rules will be nominal at the Jim Bridger power plant and that it will incur no costs related to the rule at the North Valmy and Boardman plants.

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

~~Effluent Limitation Guidelines and Standards:~~ In June 2013, the EPA issued proposed rulemaking to revise the technology-based effluent limitation guidelines and standards under the CWA for water discharged from steam electric power plants, which includes coal-fired plants. On September 30, 2015, the EPA issued the final rule, which established limits on the levels of specified metals in wastewater that can be discharged from steam electric power plants. The EPA stated that it estimates that approximately 12 percent of steam electric power plants will incur some costs associated with the final rule. Idaho Power has analyzed the final rule and, given the nature of its co-owned coal-fired plants,all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2019.

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Available Short-Term Borrowing Liquidity

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



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

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The table below presents additional information about short-term commercial paper borrowing during the years ended December 31, 2018 and 2017:



	December 31, 2018						December 31, 2017
	IDACORP⁽¹⁾			Idaho Power			IDACORP⁽¹⁾			Idaho Power
Commercial paper:
Year end:
Amount outstanding	$	—		$	—		$	—		$	—
Weighted average interest rate	—		%	—		%	—		%	—		%
Daily average amount outstanding during the year	$	—		$	—		$	588		$	839
Weighted average interest rate during the year	—		%	—		%	1.42		%	1.12		%
Maximum month-end balance	$	—		$	—		$	2,425		$	—
(1) Holding company only.

At February 15, 2019, IDACORP had no loans outstanding under its credit facility and no commercial paper outstanding, 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	Idaho Power
Moody's Investors Service:
Rating Outlook	Stable	Stable
Long-Term Issuer Rating	Baa1	A3
First Mortgage Bonds	None	A1
Senior Secured Debt	None	A1
Commercial Paper	P-2	P-2
Standard & Poor's Rating Services:
Corporate Credit Rating	BBB	BBB
Rating Outlook	Stable	Stable
Short-Term Rating	A-2	A-2
Senior Secured Debt	None	A-

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

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Capital Requirements

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



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

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

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

$20-$40 million per year for ongoing improvements and replacements at coal- and natural gas-fired plants;

$50-$70 million per year for hydroelectric plant improvement programs, including relicensing costs; and

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

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon, and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line, Idaho Power would seek to retain that percentage interest in the completed project. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, in addition to approximately $50 million of Idaho Power's share of costs related to early construction efforts, which are primarily included in the period 2021-2023. 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 and estimates.

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

The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the BLM, the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. Idaho Power expects the U.S. Forest Service to issue its right-of-way easement in 2019. Idaho Power expects the Department of the Navy to issue its decision on whether to approve the project to cross approximately seven miles of Department of the Navy lands in the first quarter of 2019.

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In the separate Oregon state permitting process, in September 2018, Idaho Power's application for site certificate was deemed complete by the Oregon Department of Energy (ODOE). The ODOE is expected to issue a draft proposed order on the application in the first half of 2019 providing the ODOE's recommendation on whether to issue a site certificate for construction in Oregon. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date for the transmission line to be in 2026 or beyond.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $38 million, including AFUDC, for its share of the permitting phase of the project through December 31, 2018. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $250 million and $450 million, including AFUDC. Idaho Power's estimated share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.

The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. In May 2017, a federal bill was signed into law that issued a right-of-way for certain portions of the remaining Gateway West segments. In April 2018, the BLM published its record of decision for the outstanding portions of the remaining segments. 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 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022. Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial, but the company is currently unable to estimate those costs in light of the uncertainty surrounding the ultimate terms and conditions that may be included in the license. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and a third party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for costs incurred through 2015 as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with IPUC and determined the associated costs to be reasonably and prudently incurred.

Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen dioxide (NO₂) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provided for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO₂ reductions on unit 2 by 2021 and unit 1 by 2022.The unit 3 SCR was operating as of November 2015, and the unit 4 SCR was operating as of November 2016. In light of the substantial estimated cost of SCR installation, as of the date of this report, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The expected capital expenditures in the table above do not include any estimated expenditures relating to the installation of SCR on units 1 and 2.

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

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Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2017. The 2017 IRP identified a preferred resource portfolio and action plan, which includes the completion of the Boardman-to-Hemingway transmission line by 2026, the end to Idaho Power's participation in coal-fired operations at the Valmy Plant units 1 and 2 in 2019 and 2025, respectively, and the early retirement of Jim Bridger units 1 and 2 in 2032 and 2028, respectively, with no other new resource needs prior to 2026. However, as noted in the 2017 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, environmental requirements, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant operation and retirements. These uncertainties, as well as others, could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. Additional information on Idaho Power's 2017 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Defined Benefit Pension Plan Contributions and Recovery

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

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

Income Tax Reform

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Contractual Obligations

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



	Payments Due by Period
	Total		2019		2020-2021		2022-2023		Thereafter
	(millions of dollars)
Long-term debt⁽¹⁾	$	1,855	$	—	$	100	$	150	$	1,605
Future interest payments⁽²⁾	1,565		85		166		159		1,155
Purchase obligations:
Maintenance and service agreements⁽³⁾	131		34		26		16		55
FERC and other industry-related fees⁽³⁾	128		14		25		25		64
Cogeneration and small power production	4,042		239		490		508		2,805
Fuel supply agreements	201		43		57		17		84
Other⁽³⁾⁽⁴⁾	51		3		8		8		32
Pension and postretirement benefit plans⁽⁵⁾	326		11		110		153		52
Other long-term liabilities - IDACORP only⁽³⁾	2		—		—		—		2
Total	$	8,301	$	429	$	982	$	1,036	$	5,854
(1) For additional information, see Note 5 – “Long-Term Debt” to the consolidated financial statements included in this report.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2018.
(3) Approximately $20 million of the amounts in maintenance and service agreements, $71 million of the amounts in FERC and other industry-related fees, $29 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(4) Other purchase obligations include right-of-way easements and the joint-operating agreement payments.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2023 with any level of precision, and amounts through 2023 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.

Dividends

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

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

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Contingencies and Proceedings

Off-Balance Sheet Arrangements

Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $58.4 million at December 31, 2018, representing IERCo's one-third share of BCC's total reclamation obligation of $175.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2018, the value of the reclamation trust fund totaled $101.9 million. During 2018, the reclamation trust fund made $6.7 million in 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.

REGULATORY MATTERS

Introduction

Idaho Power's regulatory strategy takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of rate filings. These factors include, among others, in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and Idaho Power filed a large single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates. Between general rate cases, Idaho Power relies upon customer growth, power cost adjustment mechanisms, tariff riders, and other mechanisms to reduce the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. Idaho Power continues to assess the need and timing of filing a general rate case in its two retail jurisdictions, based on its consideration of the factors described above, but does not anticipate filing a general rate case in 2019.

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Notable Retail Rate Changes in Idaho and Oregon

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



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

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

Idaho and Oregon General Rate Cases

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

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

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Valmy Base Rate Adjustment Settlement Stipulations

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

Other Notable Regulatory Matters

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 settlement stipulation 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 more specific terms and conditions of the October 2014 settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory Treatment" below.

In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its full-year Idaho ROE for 2018 was above 10.0 percent. In both 2017 and 2016, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation.

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Idaho Power recorded 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		Total
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.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism to become effective beginning January 1, 2020. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their respective terms.

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking income tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.

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

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

Deferred (Accrued) Net Power Supply Costs

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

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

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



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

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 financial and operational data Idaho Power files with the FERC. In August 2018, Idaho Power filed its 2018 final transmission rate with the FERC, reflecting a transmission rate of $31.25 per kW-year, to be effective for the period from October 1, 2018, to September 30, 2019. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $123.1 million. The OATT rate in effect from October 1, 2017, to September 30, 2018, was $34.90 per kW-year based on a net annual transmission revenue requirement of $130.4 million. The decrease in the OATT rate is largely attributable to an increase in short-term transmission revenues in 2017, which serves as an offset to the transmission revenue requirement. Historic OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Relicensing of Hydroelectric Projects

Overview: Idaho Power, like other utilities that operate non-federal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process and, in December 2016, submitted a request for a determination of prudence of HCC relicensing costs, which is described below. Relicensing costs of $297 million (including AFUDC) for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at December 31, 2018. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Prior to the May 2018 Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2018, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $135 million. In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydroelectric generating plants.

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

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

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

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

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As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, as of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for cost incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.

Renewable Energy Standards and Contracts

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

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

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

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Renewable and Other Energy Contracts: Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydroelectric and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of December 31, 2018, Idaho Power had contracts to purchase energy from 127 on-line PURPA projects. An additional three contracts are with non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity. The following table sets forth, as of December 31, 2018, the resource type and nameplate capacity of Idaho Power's signed agreements for energy purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.



Resource Type	Total On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:
Wind	627	—	627
Solar	290	27	317
Hydroelectric	146	2	148
Other	56	—	56
Total PURPA	1,119	29	1,148
Non-PURPA:
Wind	101	—	101
Geothermal	35	—	35
Total non-PURPA	136	—	136

The projects not yet on-line include one hydroelectric project and five solar projects that are scheduled to be on-line in 2019.

ENVIRONMENTAL MATTERS

Overview

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

Compliance with current and future environmental laws and regulations may:

increase the operating costs of generating plants;

increase the construction costs and lead time for new facilities;

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

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

reduce the output from current generating facilities.

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

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

Endangered Species Act Matters

The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's hydroelectric projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydroelectric facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydroelectric facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydroelectric dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

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

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

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

ESA Issues Related to Specific Projects:

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.

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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;

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

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

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

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

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

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

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utility generating units. The new proposed rule is limited to reduction and compliance measures that occur at the physical location of each plant, removing the proposal to require reductions outside the boundaries of plants. The ACE rule also provides for more state-specific control over implementation of the rule to address greenhouse gas emissions from existing coal-fired power plants, with a focus on state evaluation of improvement potential, technical feasibility, applicability, and remaining useful life of each unit. Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the existing and potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the presidential administration's executive orders and the EPA's proposal to repeal and replace the CPP discussed above, as of the date of this report and in light of these executive actions, Idaho Power is uncertain whether and to what extent the replacement CPP may impact its operations in the near term.

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

Clean Air Act Matters

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

MATS Implementation: The final MATS rule under the CAA, previously referred to as the Utility Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in compliance 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. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, and does not expect the EPA’s review of the MATS rule to have a significant impact on Idaho Power’s operations or financial ~~condition.~~results.

~~November 2015 Presidential Memorandum~~

~~On November 3, 2015, President Obama issued a Presidential Memorandum directing~~National Ambient Air Quality Standards: The CAA requires the ~~Departments of Defense, Interior~~EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and ~~Agriculture,~~ the ~~Environmental Protection Agency,~~environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, NO₂, and ~~all bureaus or agencies within them to avoid and~~SO₂. States are then minimize harmful effects to land, water, wildlife, and other ecological resources caused by land- or water-disturbing activities, and to ensure that any remaining harmful effects are effectively addressed, consistent with existing mission and legal authorities. The Presidential Memorandum requires agencies to adopt clear and consistent approaches for avoiding, minimizing, or compensating for impacts of agency activities and activities agencies approve under their jurisdiction. The agencies also are required to develop ~~institutionalized steps for implementing~~emission 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 ~~Presidential Memorandum’s policy objectives.~~following:

For mitigation, agencies are advised to adopt a "net benefit goal" for natural resource use, along with at least a "no net loss" policy of natural resources affected by federal actions, including permitting. The PM prescribes the application of a mitigation hierarchy consisting of first avoiding, then minimizing, and finally compensating for impacts of applicable activities with a federal nexus. Idaho Power expects that the relevant agencies will issue policies and guidelines during the next two years. The policies and guidelines may result in additional costs associated with construction and maintenance activities on federal lands, including transmission projects. To the extent Idaho Power operations affect any natural resources on federal lands, whether


•	NO₂:In 2010, the EPA adopted a new NAAQS for NO₂ at a level of 100 parts per billion averaged over a 1-hour

Table of ~~contents~~Contents

fish, wildlife, or plants, the company could face strict standards of “no net loss,” which could significantly increase costs depending on the type of resource impacted, such as listed species under the Endangered Species Act.

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

•

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

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

~~On January 15, 2016, the U.S. Department~~As of the ~~Interior announced that it would launch a comprehensive review~~date of this report and based on the EPA designations described above, Idaho Power does not expect these standards to ~~identify~~significantly impact its operations or materially increase Idaho Power’s capital and ~~evaluate potential reforms~~operating costs.

Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to ~~the federal coal lease program. The review is intended to address questions such as how, when,~~regional haze - best available retrofit technology (RH BART) if they were built between 1962 and ~~where to lease coal resources, how to account for the environmental~~1977 and public health impacts of federal coal production, and how to ensure taxpayers are earning a fair return for the use of the coal resources. The U.S. Department of the Interior stated that it will not issue new coal leases during the pendency of the review, except under limited circumstances, but mining under existing leases will not be suspended during the review. The Bridger Coal Mine, which mines and supplies coal toaffect 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 ~~currently leases its coal under~~no later than December 31, 2020.

In December 2009, the WDEQ issued a ~~federal coal lease. Any sizable expansion~~RH BART permit to PacifiCorp as the operator of the Jim Bridger ~~Coal Mine beyond its current leases is unlikely to occur during the U.S. Department~~plant. As part of the ~~Interior's coal lease review.~~WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install SCR equipment for nitrogen oxide (NO_x) control at Jim Bridger units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017 to install add-on NO_x controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. Idaho Power ~~believes~~is assessing whether to move forward with installation of SCR equipment at units 1 and 2. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming regional haze SIP that ~~BCC has adequate reserves under existing leases to satisfy its coal delivery obligations~~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, ~~during~~with the ~~term of~~NO_x control compliance dates set forth in the ~~existing coal supply contract through 2024,~~settlement agreement. Several interested parties have appealed the EPA's decisions on Wyoming's 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 ~~that~~to the extent the Jim Bridger plant will otherwise have access to sufficient coal supplies for its operation for the foreseeable future. However, depending on the outcome of the Department of the Interior's review, the availability of coal resources could ~~decline and the cost of leases for coal resources could increase, which could increase the fuel cost for each of Idaho Power's co-owned coal-fired plants.~~be affected.

~~CRITICAL ACCOUNTING POLICIES AND ESTIMATES~~

When preparing financial statements in accordance with generally accepted accounting principles (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. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

~~Accounting for Rate Regulation~~

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

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 ~~$1.4 billion~~ ~~of regulatory assets and~~ ~~$418 million~~ of regulatory liabilities at December 31, 2015. 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 circumstance could have a material effect on Idaho Power’s financial condition or results of operations.

Income Taxes

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

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

compared with 2016. The increase was primarily due to higher pre-tax earnings at Idaho Power in 2017, and the $5.6 million

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were partially offset by greater net flow-through income tax items at Idaho Power.

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

IDACORP's shelf registration statement filed with the SEC on May 20, 2016, which may be used for the issuance of debt securities and common stock;

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.



	IDACORP	Idaho Power
Debt	44%	46%
Equity	56%	54%

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

Operating Cash Flows

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

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

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


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


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


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

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

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

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


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

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◦	the changes in other current assets increased cash flows by $14 million, which was primarily due to fluctuations in the balance in accrued unbilled revenues as energy sales near the end of the respective periods were impacted by weather; and


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

Investing Cash Flows

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

Financing Cash Flows

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

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

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

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

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

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

Financing Programs and Available Liquidity

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, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2019, 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 interest rate limit of seven percent.

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

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

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

IDACORP and Idaho Power Credit Facilities: In November 2015, IDACORP and Idaho Power entered into credit agreements for $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 time and letters of credit not to exceed $50 million at any 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 million at any time. 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 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. 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.

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 capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2018, the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2018, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2019.

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Available Short-Term Borrowing Liquidity

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



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

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The table below presents additional information about short-term commercial paper borrowing during the years ended December 31, 2018 and 2017:



	December 31, 2018						December 31, 2017
	IDACORP⁽¹⁾			Idaho Power			IDACORP⁽¹⁾			Idaho Power
Commercial paper:
Year end:
Amount outstanding	$	—		$	—		$	—		$	—
Weighted average interest rate	—		%	—		%	—		%	—		%
Daily average amount outstanding during the year	$	—		$	—		$	588		$	839
Weighted average interest rate during the year	—		%	—		%	1.42		%	1.12		%
Maximum month-end balance	$	—		$	—		$	2,425		$	—
(1) Holding company only.

Impact of Credit Ratings on Liquidity and Collateral Obligations



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

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

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Capital Requirements



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

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

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

$20-$40 million per year for ongoing improvements and replacements at coal- and natural gas-fired plants;

$50-$70 million per year for hydroelectric plant improvement programs, including relicensing costs; and

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

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon, and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line, Idaho Power would seek to retain that percentage interest in the completed project. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, in addition to approximately $50 million of Idaho Power's share of costs related to early construction efforts, which are primarily included in the period 2021-2023. 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 and estimates.

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Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $38 million, including AFUDC, for its share of the permitting phase of the project through December 31, 2018. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $250 million and $450 million, including AFUDC. Idaho Power's estimated share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.

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

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Defined Benefit Pension Plan Contributions and Recovery

Income Tax Reform

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Contractual Obligations

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



	Payments Due by Period
	Total		2019		2020-2021		2022-2023		Thereafter
	(millions of dollars)
Long-term debt⁽¹⁾	$	1,855	$	—	$	100	$	150	$	1,605
Future interest payments⁽²⁾	1,565		85		166		159		1,155
Purchase obligations:
Maintenance and service agreements⁽³⁾	131		34		26		16		55
FERC and other industry-related fees⁽³⁾	128		14		25		25		64
Cogeneration and small power production	4,042		239		490		508		2,805
Fuel supply agreements	201		43		57		17		84
Other⁽³⁾⁽⁴⁾	51		3		8		8		32
Pension and postretirement benefit plans⁽⁵⁾	326		11		110		153		52
Other long-term liabilities - IDACORP only⁽³⁾	2		—		—		—		2
Total	$	8,301	$	429	$	982	$	1,036	$	5,854
(1) For additional information, see Note 5 – “Long-Term Debt” to the consolidated financial statements included in this report.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2018.
(3) Approximately $20 million of the amounts in maintenance and service agreements, $71 million of the amounts in FERC and other industry-related fees, $29 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(4) Other purchase obligations include right-of-way easements and the joint-operating agreement payments.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2023 with any level of precision, and amounts through 2023 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.

Dividends

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Contingencies and Proceedings

Off-Balance Sheet Arrangements

Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $58.4 million at December 31, 2018, representing IERCo's one-third share of BCC's total reclamation obligation of $175.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2018, the value of the reclamation trust fund totaled $101.9 million. During 2018, the reclamation trust fund made $6.7 million in 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.

REGULATORY MATTERS

Introduction

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Notable Retail Rate Changes in Idaho and Oregon



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

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

Idaho and Oregon General Rate Cases

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

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

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Valmy Base Rate Adjustment Settlement Stipulations

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

Other Notable Regulatory Matters

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Idaho Power recorded 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		Total
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.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease 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.

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking income tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.

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

Deferred (Accrued) Net Power Supply Costs

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

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



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

Open Access Transmission Tariff Rate Proceedings

Relicensing of Hydroelectric Projects

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

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

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

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As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, as of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for cost incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.

Renewable Energy Standards and Contracts

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

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Resource Type	Total On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:
Wind	627	—	627
Solar	290	27	317
Hydroelectric	146	2	148
Other	56	—	56
Total PURPA	1,119	29	1,148
Non-PURPA:
Wind	101	—	101
Geothermal	35	—	35
Total non-PURPA	136	—	136

The projects not yet on-line include one hydroelectric project and five solar projects that are scheduled to be on-line in 2019.

ENVIRONMENTAL MATTERS

Overview

Compliance with current and future environmental laws and regulations may:

increase the operating costs of generating plants;

increase the construction costs and lead time for new facilities;

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

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

reduce the output from current generating facilities.

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

Endangered Species Act Matters

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ESA Issues Related to Specific Projects:

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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;

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

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

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

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Clean Air Act Matters

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

National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, NO₂, and SO₂. States are then required to develop emission 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:


•	NO₂:In 2010, the EPA adopted a new NAAQS for NO₂ at a level of 100 parts per billion averaged over a 1-hour

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•

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

In December 2009, the WDEQ issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install SCR equipment for nitrogen oxide (NO_x) control at Jim Bridger units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017 to install add-on NO_x controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. Idaho Power is assessing whether to move forward with installation of SCR equipment at units 1 and 2. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming regional haze SIP that are consistent with the terms of the settlement agreement. In January 2014, the EPA approved Wyoming's regional haze SIP as to the Jim Bridger plant, with the NO_x control compliance dates set forth in the settlement agreement. Several interested parties have appealed the EPA's decisions on Wyoming's regional haze SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent the Jim Bridger plant could be affected.

Clean Water Act Matters

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

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while the U.S. Army Corps of Engineers considers a replacement rule. In January 2018, the U.S. Supreme Court issued a unanimous ruling that challenges to the WOTUS Rule must begin with the federal district courts, effectively negating a nationwide stay issued by the Sixth Circuit in 2016. However, because the State of Idaho remains a party to the federal court action in North Dakota, that court’s enjoinder remains in effect, meaning the WOTUS Rule currently does not apply to actions brought in Idaho. In July 2018, the EPA and the U.S. Army Corps of Engineers issued a supplemental notice seeking additional comment on their 2017 proposal to repeal the definition of the term WOTUS Rule under the CWA. In August 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction on the EPA’s suspension of the WOTUS Rule, resulting in the WOTUS Rule taking effect in twenty-two states and Washington D.C. The WOTUS Rule does not currently apply in twenty-eight states, including Idaho, and litigation over both the WOTUS Rule and the EPA’s suspension of the WOTUS Rule continues. In December 2018, the EPA and U.S. Army Corps of Engineers proposed a rule to significantly limit the definition of "waters of the United States" under the CWA.

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

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

Review of Federal Coal Leases

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Accounting for Rate Regulation

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

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

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

Income Taxes

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

Idaho Power ~~provides~~records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are ~~provided~~recorded for the temporary

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differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not ~~provided~~recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

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

Pension and Other Postretirement Benefits

Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, anand two unfunded nonqualified deferred compensation plan 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 market~~capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, ~~2015,~~2018, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the ~~2016~~2019 pension expense will be increased to ~~4.60~~4.55 percent from the ~~4.25~~3.95 percent used in ~~2015.~~2018.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. The long-term rate of return used to calculate the ~~2016~~2019 pension expense will be 7.5 percent, the same assumption as was used for ~~2015. The long-term rate~~2018.

Table of ~~return used in 2014 was 7.75 percent~~Contents

Gross net periodic pension and other postretirement benefit cost for these plans totaled ~~$51~~$51.2 million, ~~$32~~$50.4 million, and ~~$55~~$51.8 million for the years ended December 31, ~~2015, 2014,~~2018, 2017, and ~~2013,~~2016, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For ~~2016,~~2019, gross pension and other postretirement benefit costs are expected to total approximately ~~$54~~$51.4 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
	2016			2015			2016			2015			2019			2018			2019			2018
	(millions of dollars)												(millions of dollars)
Effect of 0.5% rate increase on net periodic benefit cost	$	(6.9	)	$	(7.2	)	$	(2.9	)	$	(2.9	)	$	(7.0	)	$	(7.9	)	$	(3.5	)	$	(3.7	)
Effect of 0.5% rate decrease on net periodic benefit cost	7.6			8.0			2.9			3.0			7.8			8.8			3.4			3.6



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

State of incorporation: Idaho

		Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:		which registered
IDACORP, Inc.: Common Stock, without par value		New York
		Stock Exchange

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



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



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



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



~~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~~	~~( )~~



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

	For the fiscal year ended December 31, ~~2015~~2018



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



Number of shares of common stock outstanding as of February ~~12, 2016:~~15, 2019:
IDACORP, Inc.:	~~50,297,581~~50,383,366
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.



Documents Incorporated by Reference:

Part III, Items 10 - 14	Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the ~~2016~~2019 annual meeting of shareholders.



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		Page

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

Part I

Item 1	Business	7
	Executive Officers of the Registrants	18
Item 1A	Risk Factors	19
Item 1B	Unresolved Staff Comments	2730
Item 2	Properties	2730
Item 3	Legal Proceedings	2932
Item 4	Mine Safety Disclosures	2932

Part II

Item 5	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	2933
Item 6	Selected Financial Data	3134
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	3235
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	6974
Item 8	Financial Statements and Supplementary Data	7176
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~125~~133
Item 9A	Controls and Procedures	~~125~~133
Item 9B	Other Information	~~129~~137

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	~~129~~137
Item 11	Executive Compensation*	~~129~~137
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	~~129~~137
Item 13	Certain Relationships and Related Transactions, and Director Independence*	~~130~~138
Item 14	Principal Accountant Fees and Services*	~~130~~138

Part IV

Item 15	Exhibits and Financial Statement Schedules	~~131~~139
Item 16	Form 10-K Summary	150

Signatures		~~142~~150

* 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 ~~2016~~2019 annual meeting of shareholders.


Project		Nameplate Capacity (kW)⁽¹⁾	License Expiration			Nameplate Capacity (kW)⁽¹⁾	License Expiration
Hydroelectric 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	2034
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⁾		1,235,600	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:
Clear Lakes - Thousand Springs		11,300				9,300
Total Hydroelectric		1,709,045				1,774,745
Steam and Other Generating Plants:
Jim Bridger (coal-fired)⁽³⁾		770,501				770,501
North Valmy (coal-fired)⁽³⁾		283,500				283,500
Boardman (coal-fired)⁽³⁾⁽⁴⁾		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				1,885,353
Total Generation		3,594,398				3,660,098
⁽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 33 percent for Jim Bridger, 50 percent for 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 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 Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.



	2015						2014
Quarter	High		Low		Dividends paid per share		High		Low		Dividends paid per share
1st	$	70.48	$	59.21	$	0.47	$	56.65	$	50.21	$	0.43
2nd	64.22		55.40		0.47		57.86		52.91		0.43
3rd	64.94		55.96		0.47		58.79		51.70		0.43
4th	70.33		63.38		0.51		70.05		53.39		0.47

																																IDACORP, Inc.	SUMMARY OF OPERATIONS	(thousands of dollars, except per share amounts and statistics)
	2015			2014			2013			2012			2011				2018			2017			2016			2015			2014
Operating revenues	$	1,270,289		$	1,282,524		$	1,246,214		$	1,080,662		$	1,026,756			$	1,370,752		$	1,349,486		$	1,262,020		$	1,270,289		$	1,282,524
Operating income(1)	282,097			253,696			291,742			242,602			155,352				296,922			315,545			283,582			297,048			267,194
Net income attributable to IDACORP, Inc.	194,679			193,480			182,417			173,014			169,981				226,801			212,419			198,288			194,679			193,480
Diluted earnings per share	3.87			3.85			3.64			3.46			3.43				4.49			4.21			3.94			3.87			3.85
Dividends declared per share	1.92			1.76			1.57			1.37			1.20				2.40			2.24			2.08			1.92			1.76

Financial Condition:
Total assets⁽¹⁾⁽²⁾	$	6,023,314		$	5,701,037		$	5,347,380		$	5,274,147		$	4,908,326			$	6,382,754		$	6,045,405		$	6,289,897		$	6,023,314		$	5,701,037
Long-term debt (including current portion)⁽¹⁾⁽²⁾	$	1,726,474		$	1,599,686		$	1,599,139		$	1,520,553		$	1,471,621			$	1,834,788		$	1,746,123		$	1,745,678		$	1,726,474		$	1,599,686

Financial Statistics:
Times interest charges earned:
Before tax⁽²⁾⁽³⁾	3.61			3.38			3.87			3.41			2.48				3.55			3.82			3.54			3.61			3.38
After tax⁽³⁾⁽⁴⁾	3.12			3.19			3.06			3.02			3.00				3.36			3.30			3.15			3.12			3.19
Book value per share⁽⁴⁾⁽⁵⁾	$	40.88		$	38.85		$	36.84		$	34.73		$	32.76			$	47.04		$	44.68		$	42.74		$	40.88		$	38.85
Market-to-book ratio ⁽⁵⁾⁽⁶⁾	166		%	170		%	141		%	125		%	129		%		198		%	204		%	188		%	166		%	170		%
Payout ratio ⁽⁶⁾⁽⁷⁾	50		%	46		%	43		%	40		%	35		%		53		%	53		%	53		%	50		%	46		%
Return on year-end common equity ⁽⁷⁾⁽⁸⁾	9.5		%	9.9		%	9.9		%	9.9		%	10.4		%		9.6		%	9.4		%	9.2		%	9.5		%	9.9		%

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


•	Idaho Power achieved its ~~goal to reduce average CO~~carbon dioxide (CO₂) emissions intensity ~~by 10 to 15 percent below 2005 emissions for the period from 2010 through 2015;~~reduction goal; and



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


	2010		2011		2012		2013		2014		2015		2013		2014		2015		2016		2017		2018
IDACORP	$	100.00	$	118.25	$	124.96	$	154.34	$	203.17	$	215.24	$	100.00	$	131.78	$	139.49	$	169.92	$	197.83	$	206.86
S&P 500	100.00		102.08		118.39		156.70		178.10		180.56		100.00		113.68		115.25		129.02		157.17		150.27
EEI Electric Utilities Index	100.00		119.99		122.49		138.42		178.44		171.48		100.00		128.91		123.88		145.48		162.53		168.49


	Year Ended December 31,				Year Ended December 31,
	2015	2014	2013	Normal	2018	2017	2016	Normal⁽²⁾
Heating degree-days⁽¹⁾	4,694	4,976	6,032	5,556	4,984	5,655	4,807	5,514
Cooling degree-days⁽¹⁾	1,280	1,129	1,320	942	1,116	1,341	1,001	942
Precipitation (inches)					10.6	15.4	8.7	11.3



Net income attributable to IDACORP, Inc. - December 31, 2014			$	193.5
Change in Idaho Power net income:
Customer growth, net of associated power supply costs	10.3
Usage per customer, net of associated power supply costs	(6.7	)
Change in FCA revenues due to sales volumes and mechanism change	12.7
Depreciation expense and property taxes	(6.2	)
Rent from electric property, wheeling and other revenue	3.0
Other operating and maintenance expenses	(4.2	)
Change in Idaho Power operating income prior to sharing mechanisms	8.9
Change in operating income as a result of sharing mechanisms	21.5
Change in Idaho Power operating income	30.4
Non-operating income and expenses	(0.4	)
Change in income tax benefit related to first mortgage bond redemption costs	7.2
Change in income tax expense due to cumulative impact of tax method change recorded in 2014	(24.5	)
Other change in income tax expense	(11.1	)
Total increase in Idaho Power net income			1.6
Other changes (net of tax)			(0.4		)
Net income attributable to IDACORP, Inc. - December 31, 2015			$	194.7



	2016		2017		2018-2020
Ongoing capital expenditures (excluding item listed below in this table)	$	280-285	$	275-285		820-870
Jim Bridger plant selective catalytic reduction equipment (discussed below)		20-25		0		40-50
Total (excluding AFUDC)	$	300-310		275-285		860-920



	Idaho			Oregon⁽¹⁾			Total
Balance at December 31, 2013	$	84,843		$	6,611		$	91,454
Current period net power supply costs deferred	48,104			—			48,104
Revenue sharing applied to deferred power supply costs	(7,624		)	—			(7,624		)
Energy efficiency rider funds applied to deferred power supply costs	(20,000		)	—			(20,000		)
Prior deferred costs amortized and recovered through rates	(48,489		)	(2,210		)	(50,699		)
SO₂ allowance and renewable energy certificate (REC) sales	(2,895		)	(127		)	(3,022		)
Interest and other	573			403			976
Balance at December 31, 2014	54,512			4,677			59,189
Current period net power supply costs deferred	35,802			—			35,802
Revenue sharing applied to deferred power supply costs	(7,999		)	—			(7,999		)
Energy efficiency rider funds applied to deferred power supply costs	(4,000		)	—			(4,000		)
Prior deferred costs amortized and 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
⁽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.



Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of February 5, 2016	109	784
Contracted and projected to come on-line by June 1, 2017	28	423



Consolidated Financial Statements	Page

IDACORP, Inc.:
Consolidated Statements of Income	7277
Consolidated Statements of Comprehensive Income	7378
Consolidated Balance Sheets	7479
Consolidated Statements of Cash Flows	7681
Consolidated Statements of Equity	7782

Idaho Power Company:
Consolidated Statements of Income	7883
Consolidated Statements of Comprehensive Income	7984
Consolidated Balance Sheets	8085
Consolidated Statements of Cash Flows	8287
Consolidated Statements of Retained Earnings	8388

Notes to the Consolidated Financial Statements	8489
Reports of Independent Registered Public Accounting Firm	~~122~~130

Supplemental Financial Information and Financial Statement Schedules

Supplemental Financial Information (unaudited)	~~124~~132
Financial Statement ~~Schedules~~Schedules:
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant	~~138~~146
IDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying Accounts	~~140~~148
Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts	~~141~~149


	December 31,						December 31,
	2015			2014			2018			2017
	(thousands of dollars)						(in thousands)
Assets

Current Assets:
Cash and cash equivalents	$	114,802		$	56,808		$	267,492		$	76,649
Receivables:
Customer (net of allowance of $1,196 and $1,960, respectively)	73,505			79,083
Other (net of allowance of $159 and $144, respectively)	8,642			16,018
Customer (net of allowance of $1,725 and $2,013, respectively)							77,178			75,249
Other (net of allowance of $264 and $180, respectively)							7,476			30,438
Income taxes receivable	13,058			11,867			4,356			8,147
Accrued unbilled revenues	65,805			56,270			69,318			75,120
Materials and supplies (at average cost)	56,924			55,404			54,987			55,745
Fuel stock (at average cost)	61,818			55,171			47,979			56,638
Prepayments	17,979			18,476			16,492			16,984
Deferred income taxes	—			42,359
Current regulatory assets	49,215			50,042			48,707			48,613
Other	288			603			3,655			18
Total current assets	462,036			442,101			597,640			443,601

Investments	140,743			165,424			101,178			115,698

Property, Plant and Equipment:
Utility plant in service	5,485,464			5,248,212			6,103,856			5,906,162
Accumulated provision for depreciation	(1,913,927		)	(1,841,011		)	(2,210,781		)	(2,098,274		)
Utility plant in service - net	3,571,537			3,407,201			3,893,075			3,807,888
Construction work in progress	396,931			401,930			480,259			452,424
Utility plant held for future use	7,090			7,090			4,751			8,075
Other property, net of accumulated depreciation	16,855			17,256			17,650			15,488
Property, plant and equipment - net	3,992,413			3,833,477			4,395,735			4,283,875

Other Assets:
American Falls and Milner water rights	11,592			13,698
Company-owned life insurance	48,566			23,893			59,852			59,323
Regulatory assets	1,305,210			1,192,345			1,165,467			1,083,483
Long-term receivables (net of allowance of $552 and $552, respectively)	22,538			6,317
Other	40,216			23,782			62,882			59,425
Total other assets	1,428,122			1,260,035			1,288,201			1,202,231

Total	$	6,023,314		$	5,701,037		$	6,382,754		$	6,045,405


		As of December 31, 2015											As of December 31, 2018
	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				2015			2014				2018		Earning a Return⁽¹⁾		Not Earning a Return		2017
Regulatory Assets:	Remaining Amortization Period	Earning a Return⁽¹⁾			Not Earning a Return							Remaining Amortization Period
Income taxes(2)		$	—		$	875,027	$	875,027	$	802,188			$	—	$	614,144		$	614,144	$	584,329
Unfunded postretirement benefits⁽²⁾⁽³⁾		—			251,762		251,762		264,548				—		278,674			278,674		280,166
Pension expense deferrals		62,642			23,148		85,790		63,644				126,811		21,025			147,836		127,721
Energy efficiency program costs⁽³⁾⁽⁴⁾		4,482			—		4,482		4,690				1,398		—			1,398		6,273
Power supply costs⁽⁴⁾⁽⁵⁾	Varies	47,220			—		47,220		59,189				—		—			—		3,137
Fixed cost adjustment⁽⁴⁾⁽⁵⁾	2016-2017	36,820			—		36,820		23,737			2019-2020	34,502		8,001			42,503		30,856
Asset retirement obligations⁽⁵⁾		—			14,410		14,410		17,309
Mark-to-market liabilities⁽⁶⁾		—			4,973		4,973		3,961
Valmy Plant settlements⁽⁵⁾												2019-2028	77,512		—			77,512		44,633
Asset retirement obligations⁽⁶⁾													—		17,655			17,655		15,767
Long-term service agreement⁽⁷⁾	2043	18,592			11,633		30,225		—			2019-2043	16,095		10,653			26,748		27,907
Other	2016-2021	1,096			2,620		3,716		3,121			2019-2055	720		6,984			7,704		11,307
Total		$	170,852		$	1,183,573	$	1,354,425	$	1,242,387			$	257,038	$	957,136		$	1,214,174	$	1,132,096
Regulatory Liabilities:
Income taxes(7)		$	—		$	51,131	$	51,131	$	55,490			$	—	$	98,042		$	98,042	$	98,744
Removal costs⁽⁵⁾		—			183,505		183,505		180,063
Depreciation-related excess deferred income taxes⁽⁸⁾													190,062		—			190,062		193,991
Removal costs⁽⁶⁾													—		183,798			183,798		184,993
Investment tax credits		—			79,655		79,655		79,163				—		92,790			92,790		87,385
Deferred revenue-AFUDC⁽⁸⁾		58,835			28,855		87,690		72,975
Energy efficiency program costs⁽³⁾		6,554			—		6,554		—
Power supply costs⁽⁴⁾		—			—		—		1
Settlement agreement sharing mechanism⁽⁴⁾	2016-2017	3,159			—		3,159		7,999
Mark-to-market assets⁽⁶⁾		—			405		405		1,880
Deferred revenue-AFUDC⁽⁹⁾													95,660		39,486			135,146		119,666
Energy efficiency program costs⁽⁴⁾													5,259		—			5,259		408
Power supply costs⁽⁵⁾												2019-2020	35,815		6,507			42,322		5,443
Settlement agreement sharing mechanism⁽⁵⁾												2019-2020	5,025		—			5,025		—
Mark-to-market assets⁽¹⁰⁾													—		3,700			3,700		22
Other		5,219			1,180		6,399		4,036				2,419		6,314			8,733		8,796
Total		$	73,767		$	344,731	$	418,498	$	401,607			$	334,240	$	430,637		$	764,877	$	699,448



Effective Date	$ Change (millions)			Notes
June 1, 2015	$	(11.6	)	The net decrease in Idaho 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.
June 1, 2013	$	140.4		The 2013 PCA rate increase was net of $7.2 million of customer revenue sharing under regulatory settlement stipulations.



~~Year and Mechanism~~		~~APCU or PCAM Adjustment~~
~~2015 PCAM~~		~~Actual net power supply costs were within the deadband, resulting in no deferral.~~
~~2015 APCU~~		~~A rate decrease of $0.7 million annually took effect June 1, 2015.~~
~~2014 PCAM~~		~~Actual net power supply costs were within the deadband, resulting in no deferral.~~
~~2014 APCU~~		~~A rate increase of $0.4 million annually took effect June 1, 2014.~~
~~2013 PCAM~~		~~Actual net power supply costs were within the deadband, resulting in no deferral.~~
~~2013 APCU~~		~~A rate increase of $2.9 million annually took effect June 1, 2013.~~



October 2014 Idaho Earnings Support and Sharing Settlement Stipulation (Effective through December 31, 2019)		May 2018 Idaho Tax Reform Settlement Stipulation (Effective beginning January 1, 2020, with no defined end date)
If Idaho Power's actual annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million over the 2015 through 2019 period. If the $45 million of ADITC are completely amortized, the revenue sharing provisions below would no longer be applicable.		If Idaho Power's actual annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished.
If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 25 percent to Idaho Power.		If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.		If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.		In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.



FCA Year	Period Rates in Effect	Annual Amount (in millions)
2014	June 1, 2015-May 31, 2016	$16.9
2013	June 1, 2014-May 31, 2015	$14.9
2012	June 1, 2013-May 31, 2014	$8.9



Applicable Period	OATT Rate (per kW-year)
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
October 1, 2012 to September 30, 2013	$	21.29



Applicable Period	OATT Rate (per kW-year)
October 1, 2018 to September 30, 2019	$	31.25
October 1, 2017 to September 30, 2018	$	34.90
October 1, 2016 to September 30, 2017	$	25.52
October 1, 2015 to September 30, 2016	$	23.43



2019		2020		2021		2022		2023		Thereafter
$	—	$	100,000	$	—	$	75,000	$	75,000	$	1,605,345



	Shares issued			Shares reserved
	2015	2014	2013	December 31, 2015
Balance at beginning of year	50,308,702	50,233,463	50,158,486
Continuous equity program	—	—	—	3,000,000
Dividend reinvestment and stock purchase plan	—	—	—	2,576,723
Employee savings plan	—	—	—	3,567,954
Long-term incentive and compensation plan	43,349	75,239	74,977	1,424,695
Restricted stock plan	—	—	—	256,154
Balance at end of year	50,352,051	50,308,702	50,233,463



	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, 2015	255,073		$	43.90	250,396		$	43.91
Shares granted	116,781		54.01		115,863		54.05
Shares forfeited	(10,904	)	55.32		(10,413	)	55.63
Shares vested	(130,130	)	36.91		(127,056	)	36.84
Nonvested shares at December 31, 2015	230,820		$	52.41	228,790		$	52.44



	IDACORP				Idaho Power
	Number of Shares/Units		Weighted-Average Grant Date Fair Value		Number of Shares/Units		Weighted-Average Grant Date Fair Value
Nonvested shares/units at January 1, 2018	201,078		$	72.37	199,652		$	72.39
Shares/units granted	106,992		79.28		106,402		79.29
Shares/units forfeited	(5,179	)	85.07		(5,179	)	85.07
Shares/units vested	(96,856	)	60.30		(96,016	)	60.31
Nonvested shares/units at December 31, 2018	206,035		$	81.31	204,859		$	81.31


	Pension Plan						SMSP						Pension Plan						SMSP
	2015			2014			2015			2014			2018			2017			2018			2017

Change in projected benefit obligation:
Benefit obligation at January 1	$	844,812		$	695,093		$	94,410		$	77,773		$	999,344		$	895,060		$	110,303		$	99,570
Service cost	33,164			25,292			1,689			1,645			37,836			33,742			(316		)	759
Interest cost	35,171			35,415			3,868			3,856			38,833			38,957			4,248			4,315
Actuarial (gain) loss	(47,952		)	114,496			(352		)	15,324			(84,758		)	67,758			(7,050		)	10,635
Benefits paid	(29,672		)	(25,484		)	(4,226		)	(4,188		)	(39,398		)	(36,173		)	(4,867		)	(4,976		)
Projected benefit obligation at December 31	835,523			844,812			95,389			94,410			951,857			999,344			102,318			110,303
Change in plan assets:
Fair value at January 1	559,719			545,092			—			—			697,683			607,568			—			—
Actual return on plan assets	(9,431		)	10,111			—			—
Actual (loss) return on plan assets													(47,681		)	86,288			—			—
Employer contributions	39,000			30,000			—			—			40,000			40,000			—			—
Benefits paid	(29,672		)	(25,484		)	—			—			(39,398		)	(36,173		)	—			—
Fair value at December 31	559,616			559,719			—			—			650,604			697,683			—			—
Funded status at end of year	$	(275,907	)	$	(285,093	)	$	(95,389	)	$	(94,410	)	$	(301,253	)	$	(301,661	)	$	(102,318	)	$	(110,303	)
Amounts recognized in the statement of financial position consist of:
Other current liabilities	$	—		$	—		$	(4,423	)	$	(4,193	)	$	—		$	—		$	(5,158	)	$	(5,010	)
Noncurrent liabilities	(275,907		)	(285,093		)	(90,966		)	(90,217		)	(301,253		)	(301,661		)	(97,160		)	(105,293		)
Net amount recognized	$	(275,907	)	$	(285,093	)	$	(95,389	)	$	(94,410	)	$	(301,253	)	$	(301,661	)	$	(102,318	)	$	(110,303	)
Amounts recognized in accumulated other comprehensive income consist of:
Net loss	$	253,212		$	263,350		$	34,260		$	38,808		$	278,720		$	277,052		$	30,496		$	41,333
Prior service cost	74			295			673			857			62			68			399			498
Subtotal	253,286			263,645			34,933			39,665			278,782			277,120			30,895			41,831
Less amount recorded as regulatory asset	(253,286		)	(263,645		)	—			—			(278,782		)	(277,120		)	—			—
Net amount recognized in accumulated other comprehensive income	$	—		$	—		$	34,933		$	39,665		$	—		$	—		$	30,895		$	41,831
Accumulated benefit obligation	$	714,994		$	719,617		$	86,838		$	84,684		$	814,549		$	850,763		$	94,630		$	100,222


	Pension Plan				SMSP				Postretirement Benefits				Pension Plan				SMSP				Postretirement Benefits
	2015		2014		2015		2014		2015		2014		2018		2017		2018		2017		2018		2017
Discount rate	4.60	%	4.25	%	4.60	%	4.20	%	4.60	%	4.20	%	4.55	%	3.95	%	4.60	%	3.95	%	4.60	%	3.95	%
Rate of compensation increase⁽¹⁾	4.11	%	4.30	%	4.50	%	4.50	%	—		—		4.25	%	4.17	%	4.75	%	4.75	%	—		—
Medical trend rate	—		—		—		—		9.7	%	6.4	%	—		—		—		—		6.3	%	6.8	%
Dental trend rate	—		—		—		—		5.0	%	5.0	%	—		—		—		—		4.0	%	4.0	%
Measurement date	12/31/2015		12/31/2014		12/31/2015		12/31/2014		12/31/2015		12/31/2014		12/31/2018		12/31/2017		12/31/2018		12/31/2017		12/31/2018		12/31/2017


	One-Percentage-Point					One-Percentage-Point
	Increase		Decrease			Increase		Decrease
Effect on total of cost components	$	407	$	(297	)	$	339	$	(247	)
Effect on accumulated postretirement benefit obligation	3,719		(2,838		)	3,222		(2,483		)