Idacorp
Annual Report 2018

Plain-text annual report

2018 Annual Report 6 .7% Earnings Growth 2 .3% Customer Growth 6 .8% Dividend Growth 2018 Contents I. Welcome Letter II. Overview III. Board of Directors IV. Generation Facilities V. Form 10-K 1 2 11 12 13 REVIEW Highlights Dollar Amounts in Thousands, Except Per Share Amounts 2018 Total Operating Revenues $1,370,752 Net Income $226,801 Earnings Per Diluted Common Share Dividends Declared Per Common Share $4.49 $2.40 Total Assets $6,382,754 Number of Employees (full-time) 1,981 2017 %CHANGE 1.58 $1,349,486 $212,419 $4.21 $2.24 $6,045,405 1,972 6.77 6.65 7.14 5.58 0.46 P A G E 1 Darrel T. Anderson Robert A. Tinstman IDACORP enjoyed another incredible year of accomplishment in 2018, punctuated by our eleventh consecutive year of earnings growth — a feat that is unprecedented for our company and unique among investor-owned utilities during that period. Idaho Power, IDACORP’s primary operating subsidiary, ended the year with record highs in customer satisfaction, as well as electrical grid reliability metrics that were the best ever measured for the company. 2018 saw Idaho Power successfully join the Western Energy Imbalance Market, which has improved our eff orts to integrate renewables onto the grid and to more effi ciently dispatch our diverse energy mix to power markets throughout the western United States. We reached signifi cant settlements related to federal and state income tax reform in Idaho and Oregon that also addressed the evergreen extension of the earnings support and revenue sharing mechanism in Idaho. We also fi nished the year having reached a settlement agreement with the states of Oregon and Idaho that now paves the way for the relicensing of the Hells Canyon Hydroelectric Complex, the crown jewel of one of the cleanest generation fl eets in the country. Other notable 2018 accomplishments and milestones include the seventh straight year of meaningful dividend increases, key milestones reached on the Boardman-to- Hemingway and Gateway West 500-kV transmission line projects, and the continued achievement of Idaho Power’s carbon dioxide emissions-intensity reduction goal. While each of these achievements is worthy of celebration, we believe the best years are ahead for our company. We are focused on the future, and the future looks bright. While we recognize additional challenges on the horizon, we will continue to use those as opportunities. We are focused on fi nancial success for shareholders, and we are committed to developing a nimble workforce to meet our customers’ changing needs. We are determined to adapt to these changes by balancing the interests of shareowners, customers, employees and other stakeholders. At Idaho Power, our commitment to serving customers and communities with clean, reliable, fair-priced energy has been the hallmark of our 100-year history. Our diversifi ed energy mix is well-positioned to adapt to changes in our region’s climate and our customers’ desires. We are clean today, and we are determined to be cleaner tomorrow. Our glide path away from coal, which already includes plans to end our participation in two of three coal-fi red power plants, will continue to gain clarity. Our strong hydropower backbone — together with solar, wind and other clean resources — have us on the path toward an even cleaner energy future, while balancing fair prices for all customers. Chairperson of the Board President and Chief Executive Offi cer P A G E 2 new business and residential customers to our service area. Idaho remains the fastest-growing state in the nation, while its capital city, Boise, moved up 14 spots to No. 12 on the Milken Institute’s 2018 list of “Best Performing Cities” thanks to its low business costs and aff ordable cost of living. We again preserved tax credits under our Idaho regulatory stipulation for potential use in future years and, more important, extended the earnings support and sharing mechanism indefi nitely. Th e full $45 million of credits remain available for earnings support in future years. IDACORP also received the Edison Electric Institute Electric Utilities Index award for the best total shareholder return performance over the past fi ve years among small-cap utilities (market capitalization of less than $5 billion). IDACORP has received this award twice in the past three years. Overview As the energy industry evolves, IDACORP continues to adapt and thrive. In 2018, IDACORP’s primary subsidiary, Idaho Power, set new records for energy sales, earnings, customer satisfaction and reliability. As our service area grows and prospers, we continue to innovate and adapt while producing clean, reliable, fair-priced energy for more customers than ever. Last year marked IDACORP’s eleventh consecutive year of earnings growth. Net income increased $14 million from 2017, while Idaho Power was able to reduce customer rates by successfully navigating a federal tax reform giveback to customers, and share $5 million with customers because return on year-end equity exceeded 10 percent. It was another year of growth across southern Idaho and eastern Oregon. Idaho Power experienced 2.3 percent customer growth as clean energy and competitive prices continued to attract Diluted Earnings Per Share 2018 2017 2016 2015 2014 $4.49 $4.21 $3.94 $3.87 $3.85 Earnings Guidance We ended 2018 with earnings of $4.49 per diluted share, and we initiated earnings guidance for the full year 2019 in the range of $4.30 to $4.45 per diluted share. Dividend Growth In 2018, IDACORP's quarterly common stock dividend increased from $0.59 per share to $0.63 per share, an increase of 6.8 percent. Management currently expects to recommend to the Board of Directors future annual increases of 5 percent or more to remain near the upper end of the target payout range of between 50 and 60 percent of sustainable IDACORP earnings. Annualized Year-End Dividend Per Share 2 0 1 8 $2.52 2 0 2 0 1 7 $2.36 1 6 $2.20 2 0 1 5 $2.04 2 0 1 4 $1.88 7 2 0 0 1 1 6 2 Return on Year-End Equity 2018 2017 2016 2015 2014 P A G E 3 Book Value Per Share 9.6% 9.4% 9.2% 9.5% 9.9% 2018 2017 2016 2015 2014 $47.04 $44.68 $42.74 $40.88 $38.85 Capital Expenditures Idaho Power continues to adapt and respond to changes in the energy industry, in part by updating its infrastructure. Ongoing capital projects include upgrading generation plants, replacing underground conductors and continuing to advance the Boardman to Hemingway and Gateway West 500-kilovolt transmission projects. Idaho Power estimates total capital expenditures of nearly $1.5 billion over the next fi ve years. Th ese infrastructure investments help Idaho Power ensure an adequate supply of electricity, provide service to new customers and maintain system reliability. We expect capital expenditures in the estimated range of $280 million to $290 million for 2019, which remains consistent with recent years. Operations & Maintenance Expenses in millions $349.6 $340.0 $349.3 $346.7 $364.5 2014 2015 2016 2017 2018 2018 ENERGY MIX P A G E 4 Adaptable Energy Mix Hydroelectricity remains the backbone of Idaho Power's clean, reliable energy mix. Hydro once again accounted for nearly half of our generation in 2018. Customers continue to be served by a series of 17 hydroelectric projects on the Snake River and its tributaries, as well as three natural gas-fi red power plants and portions of three coal-fi red plants in which Idaho Power is part owner. Compared with 2017, hydro, coal and natural gas saw minor reductions in generation, while purchased power increased. 500-kilovolt Transmission Projects Th e Boardman to Hemingway Transmission Line Project continues to press forward. Idaho Power anticipates the in-service date for this line to be no earlier than 2026, but we expect the Oregon Department of Energy to issue a draft proposed order in 2019, followed by geotechnical investigation in early 2020. Once complete, we expect this line to bring additional clean, aff ordable energy to our service area. Th e Gateway West project is also progressing. Th is 500-kV line is on schedule to be completed in phases between 2019 and 2024. We project enhanced reliability with the addition of Gateway West. P A G E 5 Hells Canyon Idaho Power continues to work toward renewing a long-term federal license for the three-dam Hells Canyon Complex, the company’s largest generation resource. In April 2018, state regulators approved a settlement agreement allowing approximately $216.5 million in expenditures related to relicensing the Hells Canyon Complex to be designated as prudently incurred and eligible for recovery through customer rates at a later date. Later in 2018, the states of Idaho and Oregon agreed to a proposed settlement on reintroduction of steelhead and spring Chinook salmon into the Snake River above Oxbow Dam. As part of the settlement, Idaho Power committed to spend an additional $12 million over the fi rst 20 years of the renewed license for research, water quality and stream improvements — key components of meeting our obligations under the federal Clean Water Act— and increase hatchery production. Niagara Springs Hatchery Western Energy Imbalance Market On April 1, Idaho Power became a full participant in the Western Energy Imbalance Market (EIM). Th e Western EIM is designed to reduce the power supply cost to serve customers through more effi cient dispatch of larger, more diverse resources; to integrate intermittent power from renewable generation resources more eff ectively; and to enhance reliability. From April through December 2018, Idaho Power recorded $2.2 million as a regulatory asset within the Idaho Power Cost Adjustment (PCA) STEELHEAD SPRING CHINOOK & SALMON balance per the stipulation in the order to match the costs with the benefi ts of the Western EIM. Participation in the Western EIM was also a factor in Idaho Power increasing its wholesale energy volumes by $28.1 million in 2018 compared to 2017. P A G E 6 Renewables and PURPA Idaho Power has signifi cant contracts to purchase power from Public Utility Regulatory Policies Act of 1978 (PURPA) Qualifying Facilities (QF) that include renewable generation sources, such as biomass, wind, solar and small hydroelectric. In addition, Idaho Power has non-PURPA power purchase agreements to buy energy from wind and geothermal renewable generation projects, the largest being the Elkhorn Valley wind project with a 101 megawatt (MW) nameplate capacity. As of December 31, 2018, Idaho Power had contracts to purchase generation from 127 PURPA QFs as well as three non-PURPA projects. We also have one new hydroelectric and fi ve solar PURPA QFs expected to come on-line in 2019. Social and Environmental Responsibility A clean, adaptable energy mix is helping Idaho Power continue to achieve and exceed its carbon reduction goals. In 2018, the company’s carbon dioxide (CO) emissions intensity was 647 pounds per megawatt of generation — 46 percent below our baseline year of 2005. Idaho Power’s abundance of clean hydroelectricity and long-term resource planning point toward continued CO emissions reductions in the future. Idaho Power also continued to show environmental stewardship across its service area in 2018. Th e company is working on habitat improvement projects at Daly Creek in Hells Canyon and Bayha Island in the Mid-Snake River, while eff orts are ongoing to protect birds of prey and boost populations of anadromous steelhead and Chinook salmon through hatchery programs. Idaho Power also continues to off er energy effi ciency incentives and educate its customers about the benefi ts of energy effi ciency and the wise use of resources. Lower Salmon Hydroelectric Plant P A G E 7 BOARDMAN HEMINGWAY Integrated Resource Plan Idaho Power plans for infrastructure that will support anticipated growth and allow us to continue to produce clean, reliable, fair-priced energy for our customers. Every two years, Idaho Power updates its Integrated Resource Plan (IRP), with the participation of the many stakeholders who participate on the IRP Advisory Council (IRPAC). Th e 2017 IRP was fi led with state regulators in June 2017. Key action items identifi ed in the IRP include continued planning for participation in the Western Energy Imbalance Market, planning and coordinating with our operating partners for early retirement of certain coal-fi red units, and pre-construction activities for the Boardman-to-Hemingway 500-kilovolt transmission line. Idaho Power is currently preparing its 2019 IRP, which will be submitted to public utility commissions in Idaho and Oregon in June 2019. 300 MILE 500-kV TRANSMISSION LINE Coal-fi red Operations In February 2019, Pacifi Corp fi led an alternate regional haze compliance plan with the Wyoming Department of Environmental Quality (DEQ) that would place operational restrictions on the Jim Bridger Power Plant. If approved by the DEQ and the federal Environmental Protection Agency (EPA), this plan would reduce the amount of time the Jim Bridger Plant could operate. Th e impact would be to reduce emissions to levels at or below what would be achieved by installing additional environmental controls, without incurring the expense of new equipment. Th is proposal was made in consultation with Idaho Power. Th e proposal would allow us to comply with the regional haze guidelines while maintaining operational fl exibility and system reliability. At the North Valmy plant in Nevada, Idaho Power fi nalized negotiations to cease its participation in Unit 1 by the end of 2019. We remain on track to end participation in Unit 2 by the end of 2025. Idaho Power’s other coal resource, the Boardman, Oregon, plant in which we are a 10 percent owner, is projected to cease coal-fi red operations by the end of 2020. 46% CO2 Emissions Intensity reduction FROM 2005 1,015 944 858 632 647 2014 2015 2016 2017 2018 Pounds CO2 per MWh Generation P A G E 8 Competitive Prices Idaho Power customers continued to enjoy some of the lowest energy rates in the nation in 2018. Th anks to our clean, low-cost hydroelectric power, diverse energy mix and purposeful regulatory strategy, our company continues to earn a fair return for shareholders while keeping customer prices low. Residential customers enjoyed prices 20 percent lower than the national average in 2018, while business prices were 30 percent lower than average. Idaho Power has not fi led a general rate case since 2011 and does not anticipate fi ling one in 2019. 20% LOWER $ THAN THE NATIONAL AVERAGE ADITC Extension Idaho Power did not record any additional Accumulated Deferred Investment Tax Credits (ADITC) amortization during 2018. Th is preserves the full $45 million of credits available in the regulatory stipulation for future years. Even more importantly, the company reached an agreement on an indefi nite extension of this earnings support and sharing mechanism, providing future earnings stability. Increased stability is a win for the company, its customers and its shareowners. Idaho Power expects to continue to practice diligence in managing costs and growing revenues with the goal of preserving credits for future years. Rate Decreases Idaho Power, with Idaho Public Utilities Commission (IPUC) approval, decreased rates that saved the average Idaho residential customer 7.06 percent on their monthly bill. Th e decreases went into eff ect June 1, 2018. Two of the proposals came from annual mechanisms — the Fixed Cost Adjustment (FCA) and Power Cost Adjustment (PCA) — and the third stemmed from federal and Idaho state income tax-rate changes. Th e FCA decreased rates approximately $19.4 million for residential and small general service customers. Residential customers experienced a 3.61-percent decrease. Th e PCA decreased rates by $22.6 million for all Idaho Power customers. Residential customers saw a 1.29-percent decrease. Tax reform changes resulted in a total customer benefi t of $33.9 million, provided through a base rate reduction of approximately $18.7 million, an additional $7.8 million decrease provided through the 2018 PCA, and a non-cash annual benefi t of $7.4 million in the form of an off set to other deferred costs. Th is decreased residential rates by 2.15 percent. All Idaho customer classes experienced a rate decrease of at least 4.25 percent in 2018. P A G E 8 P A G E 9 Customer Growth Idaho Power continues to see substantial growth within its service area — its customer base grew by 2.3 percent in 2018 and employment grew by approximately 2.2 percent. Our total customer base has grown to nearly 560,000. Customer growth in Idaho Power's service area continues to positively impact revenues. Boise, ID NEARLY 560,000 CUSTOMERS 2.3% Economic Development Idaho’s economy continued to thrive in 2018. Customer growth brought new business customers to Idaho Power’s service area, and Moody’s gross domestic product (GDP) forecast calls for continued economic growth going forward. Employment in our region has grown to a record of nearly 525,000 people. Economic development brings opportunities for large commercial and industrial growth. Idaho Power’s energy sales for this customer segment increased nearly 1 percent over the record-breaking numbers we saw in 2017. Large load growth primarily came from expansion projects of existing customers, along with several new customers investing in our service area. Idaho Power also experienced a balanced mix of growth within our core industry focus, including major additions and expansions in food processing, manufacturing and data centers and technology. Customer Satisfaction & Reliability Adaptability extends beyond Idaho Power’s balanced energy mix and business strategy. Our company also works hard to focus on and meet our customers’ ever-changing needs. Idaho Power undertook several projects to improve customer touchpoints in 2018, including improving our website, redesigning our monthly bill and off ering new online services. Customer response was outstanding — the company earned the highest customer satisfaction scores in its history, fi nishing at or near the top of our western, mid-sized investor-owned utility peers in every category. Reliability also enjoyed a benchmark year in 2018. On average, our customers only experienced about one outage longer than fi ve minutes. P A G E P A G E 1 1 1 1 Looking Forward IDACORP had a momentous year of growth and success in 2018. From achieving an eleventh consecutive year of earnings growth to earning the best customer satisfaction scores in company history, Idaho Power continued to thrive thanks to the hard work and dedication of our nearly 2,000 employees. As we look forward, Idaho Power is well positioned to meet the challenges ahead. Our company’s clean energy mix, purposeful regulatory strategy and dedicated employees will continue to adapt to a changing energy industry, ensuring future success for our company and shareowners and a positive experience for our customers. By embracing growth, adjusting to technological changes and keeping our customers’ needs at the forefront, we expect Idaho Power to continue to grow its fi nancial strength, improve its core business and enhance its brand. Th ank you for your continued investment in IDACORP. We appreciate your support, and we look forward to another great year in 2019. P A G E 1 1 P A G E 15 P A G E 11 BOARD OF DIRECTORS IDACORP & IDAHO POWER (as of Feb. 23, 2017) Robert A. Tinstman* (1999) Boise, Idaho Former Executive Chairman of James Construction Group; former President and Chief Executive Offi cer and Director of Morrison–Knudsen Corp.; Director of Primoris Services Corp.; Director of Westmoreland Coal Company; former Director of CNA Surety and Home Federal Bancorp, Inc. Judith A. Johansen (2007) Scottsdale, Arizona Former President of Marylhurst University; former President and Chief Executive Offi cer of Pacifi Corp; former Chief Executive Offi cer and Administrator of the Bonneville Power Administration; Director of Schnitzer Steel and Roseburg Forest Products; former Director of Pacifi c Continental Corporation. Darrel T. Anderson (2013) Boise, Idaho President and Chief Executive Offi cer of IDACORP, Inc. and Idaho Power. Thomas E. Carlile (2014) Boise, Idaho Former Chief Executive Offi cer of Boise Cascade Company; Director of Boise Cascade Company. Richard J. Dahl (2008) Kailua, Hawaii Chairman of the Board and former President and Chief Executive Offi cer of James Campbell Company, LLC; Director, Dine Brands Global, Inc.; Director, Hawaiian Electric Industries, Inc. and Hawaii Electric Company; former President and Chief Operating Offi cer of Dole Food Company. Annette G. Elg (2017) Boise, Idaho Former Senior Vice President and Chief Financial Offi cer of J.R. Simplot Company; former Vice President and Controller of J.R. Simplot Company; former Director of Cascade Bancorp Ronald W. Jibson (2013) North Salt Lake City, Utah Former President and Chief Executive Offi cer and Director and Chairman of the Board of Questar Corporation; former President and Chief Executive Offi cer of Wexpro Corporation and Questar Gas Company; former Chairman of the Board of Directors of Questar Pipeline Company; Director of Dominion Energy, Inc. Dennis L. Johnson (2013) Eagle, Idaho President, Chief Executive Offi cer and Director of United Heritage Mutual Holding Company, United Heritage Financial Group, and United Heritage Life Insurance Company; Director of First Interstate Bancorp; former Director of Cascade Bancorp. Christine King (2006) Scottsdale, Arizona Former President and Chief Executive Offi cer of Standard Microsystems Corporation; former Chief Executive Offi cer and Director of AMI Semiconductor; Director of Skyworks Solutions, Inc.; former Director and Executive Chair of QLogic Corp., former Director of Cirrus Logic, Inc. Richard J. Navarro (2015) Boise, Idaho Former Chief Financial Offi cer of Albertson’s, LLC; former Chief Administrative Offi cer at Albertson’s, LLC.; former Director of Home Federal Bancorp, Inc. Average Tenure 7.5 years Average Age 66 years Independent 90 percent Gender Diversity 30 percent ( ) year appointed or elected to the board * Chairperson of the Board P A G E 1 2 GENERATION FACILITIES AND NAMEPLATE CAPACITIES Boardman 1 2 3 4 Salmon Diesel Langley Gulch Evander Andrews 9 7 8 Bennett Mountain 17 12 16 10 13 11 14 15 SERVICE AREA 24,000 SQUARE MILES 5 6 North Valmy 17HYDROELECTRIC PROJECTS Jim Bridger Hydroelectric Facilities Thermal Facilities 1 Hells Canyon 391,500 kW 10 Lower Salmon 60,000 kW 2 Oxbow 3 Brownlee 4 Cascade 5 Swan Falls 6 C.J. Strike 7 Bliss 190,000 kW 654,100 kW 12,420 kW 27,170 kW 82,800 kW 75,000 kW 11 Upper Salmon 34,500 kW 12 Th ousand Springs 6,800 kW 13 Clear Lake 2,500 kW Jim Bridger North Valmy Boardman 770,501 kW1 283,500 kW1 64,200 kW1 14 Shoshone Falls 11,500 kW Evander Andrews 270,900 kW2 15 Twin Falls 16 Milner 52,897 kW 59,448 kW Bennett Mountain 172,800 kW Salmon Diesel 5,000 kW 8 Lower Malad 13,500 kW 17 American Falls 92,340 kW Langley Gulch 318,452 kW 9 Upper Malad 8,270 kW 1 Idaho Power share 2 Danskin UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ................... to ................................................................. Exact name of registrants as specified in their charters, address of principal executive IRS Employer Commission File Number 1-14465 1-3198 offices, zip code and telephone number IDACORP, Inc. Idaho Power Company 1221 W. Idaho Street Boise, ID 83702-5627 (208) 388-2200 State of incorporation: Idaho SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: IDACORP, Inc.: Common Stock, without par value SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Idaho Power Company: Preferred Stock Identification Number 82-0505802 82-0130980 Name of exchange on which registered New York Stock Exchange Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act. IDACORP, Inc. Yes (X) No ( ) Idaho Power Company Yes ( ) No (X) Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. IDACORP, Inc. Yes ( ) No (X) Idaho Power Company Yes ( ) No (X) Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X) No ( ) 1 Indicate by check mark whether the registrants have submitted electronically Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). IDACORP, Inc. Yes (X) No ( ) Idaho Power Company Yes (X) No ( ) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. IDACORP, Inc.: Large accelerated filer X Accelerated filer __ Non-accelerated filer __ Smaller reporting company __ Emerging growth company __ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. __ Idaho Power Company: Large accelerated filer __ Accelerated filer __ Non-accelerated filer X Smaller reporting company __ Emerging growth company __ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. __ Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act). IDACORP, Inc. Yes ( ) No (X) Idaho Power Company Yes ( ) No (X) Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2018): IDACORP, Inc.: $ 4,611,144,658 Idaho Power Company: None Number of shares of common stock outstanding as of February 15, 2019: 50,383,366 IDACORP, Inc.: 39,150,812, all held by IDACORP, Inc. Idaho Power Company: Documents Incorporated by Reference: Part III, Items 10 - 14 Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders. This combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representation as to the information relating to IDACORP, Inc.’s other operations. Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format. 2 TABLE OF CONTENTS Commonly Used Terms Cautionary Note Regarding Forward-Looking Statements Part I Item 1 Item 1A Item 1B Item 2 Item 3 Item 4 Part II Business Executive Officers of the Registrants Risk Factors Unresolved Staff Comments Properties Legal Proceedings Mine Safety Disclosures Item 5 Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities Selected Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures About Market Risk Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information Directors, Executive Officers and Corporate Governance* Executive Compensation* Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters* Certain Relationships and Related Transactions, and Director Independence* Principal Accountant Fees and Services* Exhibits and Financial Statement Schedules Form 10-K Summary Item 6 Item 7 Item 7A Item 8 Item 9 Item 9A Item 9B Part III Item 10 Item 11 Item 12 Item 13 Item 14 Part IV Item 15 Item 16 Signatures Page 4 5 7 18 19 30 30 32 32 33 34 35 74 76 133 133 137 137 137 137 138 138 139 150 150 * 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 2019 annual meeting of shareholders. 3 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 LTICP - IDACORP 2000 Long-Term Incentive and Credits Compensation Plan AFUDC - Allowance for Funds Used During MATS - Mercury and Air Toxics Standards Construction AOCI - Accumulated Other Comprehensive Income MD&A - Management’s Discussion and Analysis of Financial Condition and Results of Operations APCU - Annual Power Cost Update MMBtu - Million British Thermal Units ASU BCC BLM CAA CO2 CWA EIS EPA ESA FASB FCA FERC FPA GAAP GHG HCC - Accounting Standards Update - Bridger Coal Company, a joint venture of MW MWh - Megawatt - Megawatt-hour IERCo - U.S. Bureau of Land Management NAAQS - National Ambient Air Quality Standards - Clean Air Act - Carbon Dioxide - Clean Water Act - Environmental Impact Statement - U.S. Environmental Protection Agency - Endangered Species Act - Financial Accounting Standards Board - Idaho Fixed Cost Adjustment - Federal Energy Regulatory Commission - Federal Power Act - Generally Accepted Accounting Principles NEPA NMFS NOAA Fisheries NO2 NOx O&M OATT OPUC PCA PCAM PEIS - National Environmental Policy Act - National Marine Fisheries Service - National Oceanic and Atmospheric Administration's National Marine Fisheries Service - Nitrogen Dioxide - Nitrogen Oxide - Operations and Maintenance - Open Access Transmission Tariff - Public Utility Commission of Oregon - Idaho-jurisdiction Power Cost Adjustment - Oregon Power Cost Adjustment Mechanism - Programmatic Environmental Impact Statement - Greenhouse Gas - Hells Canyon Complex PURPA - Public Utility Regulatory Policies Act of 1978 REC - Renewable Energy Certificate IDACORP - IDACORP, Inc., an Idaho Corporation RH BART - Regional haze - best available retrofit technology Idaho Power - Idaho Power Company, an Idaho Corporation RPS - Renewable Portfolio Standard Idaho ROE - Idaho-jurisdiction return on year-end equity Ida-West - Ida-West Energy Company, a subsidiary of SEC SCR - U.S. Securities and Exchange Commission - Selective catalytic reduction equipment IDACORP, Inc. IERCo - Idaho Energy Resources Co., a subsidiary of SMSP - Security Plan for Senior Management IFS IPUC IRP IRS kW kWh Idaho Power Company - IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. Employees SO2 - Sulfur Dioxide - Idaho Public Utilities Commission USFWS - U.S. Fish and Wildlife Service - Integrated Resource Plan - U.S. Internal Revenue Service - Kilowatt - Kilowatt-hour Valmy Plant - North Valmy coal-fired power plant Western EIM WPSC WDEQ - Energy imbalance market implemented in the western United States - Wyoming Public Service Commission - Wyoming Department of Environmental Quality 4 CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power) may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, future events, or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "continues," "could," "estimates," "expects," "guidance," "intends," "potential," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, as well as in subsequent reports filed by IDACORP and Idaho Power with the U.S. Securities and Exchange Commission, and the following important factors: • • • • • • • • • • • • the effect of decisions by the Idaho and Oregon public utilities commissions and the Federal Energy Regulatory Commission that impact Idaho Power's ability to recover costs and earn a return on investment; 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, the loss or change in the business of significant customers, or the addition of new customers, and their associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery through customer rates in the event of those changes; the impacts of economic conditions, including inflation, interest rates, regulatory authorized returns on equity, supply costs, population growth or decline in Idaho Power's service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers, and the collection of receivables; unseasonable 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 may affect Idaho Power's sale or delivery of electric 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 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 affecting or caused by Idaho Power facilities or infrastructure), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power assets, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, and regulatory fines and penalties for which the companies may have inadequate insurance coverage; the increased purchased power costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio; 5 • • • • • • • • • • • • • disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission systems may constrain resources or cause Idaho Power to incur repair costs and purchase replacement power at increased costs; the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance; reductions in credit ratings, which could adversely impact access to debt and equity markets, increase borrowing costs, and require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements; the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended; changes in actuarial assumptions, changes in interest rates, and the return on plan assets for pension and other post- retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies' cash flows; the 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, regulations, and orders, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation; the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities; the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of resulting operational changes through insurance or rates, or from third parties; the companies' failure to secure data or to comply with privacy laws or regulations, security breaches, or the disruption or damage to the companies' business, operations, or reputation resulting from cyber-attacks and related litigation or penalties, terrorist incidents or the threat of terrorist incidents, or other malicious acts, and acts of war; unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new technology solutions; and adoption of or changes in accounting policies and principles, changes in accounting estimates, and new U.S. Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements. Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law. 6 PART I ITEM 1. BUSINESS OVERVIEW Background IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho. Its principal operating subsidiary is Idaho Power Company (Idaho Power). IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions with access to books and records and imposes record retention and reporting requirements on IDACORP. Idaho Power was incorporated under the laws of the state of Idaho in 1989 as the successor to a Maine corporation that was organized in 1915 and began operations in 1916. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the state regulatory commissions of Idaho and Oregon and by the FERC. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations. As of December 31, 2018, IDACORP had 1,981 full-time employees, 1,972 of whom were employed by Idaho Power, and 9 part-time employees, 7 of whom were employed by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200. Available Information IDACORP and Idaho Power make available free of charge on their websites their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC). IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com. The contents of these websites are not part of this Annual Report on Form 10-K. UTILITY OPERATIONS Background Idaho Power provided electric utility service to more than 558,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2018. 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 72 cities in Idaho and 7 cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and 3 counties in Oregon. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of 1.2 million. 7 Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Wyoming Public Service Commission (WPSC) as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (FPA), Idaho Power has authority to charge market- based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydroelectric 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 or when otherwise directed to begin amortization by a regulator. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. Idaho Power records regulatory assets or liabilities if it expects the amounts will be reflected in future prices, based on regulatory orders or other available evidence. Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective 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. 8 Business Strategy IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. IDACORP's board of directors regularly reviews IDACORP's long-term strategy, which as of the date of this report is focused on the following areas and initiatives: Focus Areas 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 In executing the focus areas above, IDACORP seeks to balance the interests of shareholders, Idaho Power customers, employees, and other stakeholders. Idaho Power is working to continue to provide safe, fair-priced, reliable service to its customers from diversified generation resources, with a continued commitment to strong, sustainable financial results and 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 electric power and services are critical factors in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report. Retail Rates: Idaho Power's rates for retail electric services are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses including depreciation on capital investments, an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators. Idaho Power regularly evaluates the need to request changes to its retail electricity price structure to cover its operating costs and to earn a fair return on its investments. Idaho Power uses general rate cases, power cost adjustment mechanisms in Idaho and Oregon, a fixed cost adjustment (FCA) mechanism in Idaho, balancing accounts and tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order. Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties. The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment. The ability to 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. 9 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 and accrued amounts are generally refunded to retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. Idaho Power collects most of its energy efficiency program costs through energy efficiency riders on customer bills. The Idaho and Oregon power cost adjustment mechanisms are intended to address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers by allowing partial recovery or refund of the difference between net power supply costs included in base rates and actual net power supply costs incurred by Idaho Power. The FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year. Wholesale Markets: Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 hydroelectric 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 wholesale energy sales depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as market power prices at the time when those resources are available. A reduction in either factor leads to lower wholesale energy sales. Idaho Power’s OATT rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1. The FERC oversees mandatory transmission and network reliability standards, as well as power and transmission markets, including protection against market manipulation. These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, which have responsibility for compliance and enforcement of transmission and reliability standards. Retail Energy Sales: Weather, seasonal customer demand, energy efficiency, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned, and associated expenses are not incurred, evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak during the winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and mild temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could continue to alter demand for Idaho Power's electric energy. Approximately 95 percent of Idaho Power’s retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.” 10 The table that follows presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type. Retail revenues (thousands of dollars): Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA(1)) Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA(1)) Industrial Irrigation Provision for sharing Deferred revenue related to HCC relicensing AFUDC(2) Total retail revenues Wholesale energy sales Transmission wheeling revenues Energy efficiency program revenues Other revenues Total electric utility operating revenues Energy sales (thousands of Megawatt-hour (MWh)): $ Residential Commercial Industrial Irrigation Total retail energy sales Wholesale energy sales Bundled energy sales Total energy Year Ended December 31, 2017 2018 2016 $ 530,527 $ 552,333 $ 514,954 310,299 190,130 158,001 (5,025) (8,780) 1,175,152 52,845 59,094 35,703 43,788 1,366,582 $ 319,195 195,124 150,030 — (10,706) 1,205,976 24,790 43,970 39,241 30,916 1,344,893 $ 302,650 182,590 156,505 — (10,706) 1,145,993 11,900 32,496 33,754 35,210 1,259,353 5,135 4,105 3,371 1,976 14,587 2,246 617 17,450 5,355 4,099 3,346 1,771 14,571 1,934 202 16,707 5,004 3,999 3,243 1,950 14,196 742 444 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 (2) in Note 4 – “Revenues” to the consolidated financial statements included in this report. 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 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. 11 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 power cost adjustment mechanisms mitigate in large part the financial impacts of volatile fuel and power costs. Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. Idaho Power reached its highest all-time system peak demand of 3,422 megawatts (MW) on July 7, 2017. Idaho Power's highest all-time winter peak demand of 2,527 MW was last achieved on January 6, 2017. During these and other similarly heavy load periods, Idaho Power’s system is fully committed to serve load and meet required operating reserves. The table that follows shows Idaho Power’s total power supply for the last three years. 2018 Power Supply 2017 (thousands of MWh) 2016 Percent of Total Generation 2017 2016 2018 Hydroelectric plants Coal-fired plants Natural gas-fired plants Total system generation Purchased power - cogeneration and small power production Purchased power - other Total purchased power Total power supply 8,682 3,274 1,408 13,364 3,045 2,386 5,431 18,795 8,900 3,284 1,504 13,688 2,800 1,442 4,242 17,930 6,408 4,045 1,722 12,175 2,314 2,023 4,337 16,512 65% 24% 11% 100% 65% 24% 11% 100% 53% 33% 14% 100% 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 1,775 MW and annual generation of approximately 8.7 million MWh under median water conditions. The amount of water available for hydroelectric power generation depends on several factors—the amount of 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, resulting in a greater reliance on other generation resources and wholesale power purchases. For 2019, Idaho Power estimates annual generation from its hydroelectric facilities to be between 6.5 million MWh and 8.5 million MWh. 12 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 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. BCC supplies coal to the Jim Bridger power plant. IERCo, a wholly-owned subsidiary of Idaho Power, owns a one-third interest in BCC and PacifiCorp owns a two-third interest in BCC and is the operator of the Bridger Coal Mine. The mine operates under a long-term sales agreement that provides for delivery of coal through 2024 from surface and underground sources. Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at least the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2021 from the Black Butte mine located near the Jim Bridger plant. This contract supplements the BCC deliveries and provides another coal supply to fuel the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums. NV Energy is the operator of the North Valmy power plant (Valmy Plant). Idaho Power expects to meet 2019 fuel requirements through existing inventory and coal contracts and expects to be able to meet future coal requirements through new or existing coal supply contracts. In 2017 and 2018, Idaho Power 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 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. 13 As of December 31, 2018, approximately 6.4 million MMBtu of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through January 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 requirements, and unit availability. Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets. During 2018 and 2017, Idaho Power purchased 1.4 million MWh and 0.9 million MWh of power through wholesale market purchases at an average cost of $31.55 per MWh and $26.32 per MWh, respectively. During 2018 and 2017, Idaho Power sold 2.2 million MWh and 1.9 million MWh of power in wholesale market sales, with an average price of $23.53 per MWh and $12.82 per MWh, respectively. Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has the following notable long-term power purchase contracts and energy exchange agreements: • Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from the Elkhorn Valley wind project located in eastern Oregon. The contract term ends in 2027. • USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs Unit #1 geothermal power plant located near Vale, Oregon. The contract term ends in 2037. • Clatskanie People's Utility - for up to 18 MW of generation from the Arrowrock hydroelectric project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The contract term ends in 2020. Idaho Power has the right to renew the agreement for an additional five-year term. • Raft River Energy I, LLC - for up to 13 MW (estimated average annual output) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term ends in 2033. PURPA Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA qualifying facilities as mandated by federal law. As of December 31, 2018, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of 1,119 MW of nameplate generation capacity, with an additional 29 MW nameplate capacity of projects projected to be on-line in 2019. The energy sales agreements for these qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA qualifying facilities during the last three years is included in the following table: PURPA contracts expense (in thousands) MWh purchased under PURPA contracts (in thousands) Average cost per MWh from PURPA contracts $ $ Year Ended December 31, 2017 169,788 $ 2018 189,722 $ 2016 153,665 3,045 2,800 62.31 $ 60.64 $ 2,314 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 that meet the requirements of PURPA. A key component of the PURPA contracts is the energy price contained within the agreements. PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The IPUC and OPUC have established specific rules and regulations to calculate the avoided cost that Idaho Power is required to include in PURPA energy sales agreements under each state's jurisdiction. For PURPA energy sales agreements: • • Idaho Power is required to purchase all of the output delivered from the contracted qualifying facilities located inside its service area, subject to some exceptions such as adverse impacts on system reliability. Idaho Power is required to purchase the output of projects located outside its service area if it has the ability to receive power at the qualifying facility’s requested point of delivery on Idaho Power's system. • The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho-jurisdiction power cost adjustment (PCA) mechanism, and the OPUC jurisdictional portion is recovered through base rates and an Oregon power cost recovery mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates. 14 • OPUC jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years. • The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 kilowatts (kW) and all other types of projects that are smaller than 10 average MWs. For PURPA qualifying 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 solar PURPA qualifying facilities with a nameplate rating of 3 MW or less and all other types of projects with a nameplate rating of 10 MW or less. Idaho Power is required to negotiate an applicable price (premised on avoided costs) for all other qualifying facilities based upon OPUC regulations. Participation in Western Energy Imbalance Market: In 2014, the California Independent System Operator and PacifiCorp implemented an energy imbalance 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 Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. Idaho Power commenced participation in the Western EIM in April 2018. For information on regulatory proceedings related to costs associated with joining the Western EIM, see Part II, Item 7 – MD&A - "Regulatory Matters - Western Energy Imbalance Market Costs." Transmission Services Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located hundreds of miles away from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy. These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection, the transmission grid covering much of western North America. Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the Western Electricity Coordinating Council, the Northwest PowerPool, the Northern Tier Transmission Group, and the North American Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the Western Interconnection. Transmission to serve Idaho Power's retail customers is subject to the jurisdiction of the IPUC and OPUC for retail rate making purposes. Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approved OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system. As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function. Idaho Power is jointly working on the permitting of two significant transmission projects. The Boardman-to-Hemingway line 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 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: 15 • • • • 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 expects to use in its 2019 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads. 5-Year Forecast 20-Year Forecast Annual Growth Rate: Retail Sales (Billed MWh) 1.3% Annual Growth Rate: Annual Peak (Peak Demand) 1.4% Annual Growth Rate: Retail Sales (Billed MWh) 1.0% Annual Growth Rate: Annual Peak (Peak Demand) 1.2% 1.1% 1.1% 1.6% 1.5% 0.9% 1.1% 1.4% 1.4% 2019 IRP (preliminary) 2017 IRP 2015 IRP Idaho Power's 2017 IRP identifies its preferred resource portfolio and action plan. The IRP includes the completion of the Boardman-to-Hemingway 500-kV transmission line by 2026, the end of Idaho Power's participation in coal-fired operations at the North Valmy power 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, 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. Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 23 programs. These energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer at times of peak loads. The programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimize or delay the need for new generation and transmission infrastructure. Idaho Power’s programs include: • • • • financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems; energy efficiency for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, air duct sealing, and energy efficient lighting; incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes; demand response programs to reduce peak summer demand through the voluntary cycling of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through actions taken by business owners and operators; and • membership in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region. In 2018, Idaho Power’s energy efficiency programs reduced energy usage by approximately 173,000 MWh. For 2018, Idaho Power had a demand response available capacity of approximately 382 MW. In 2018, 2017, and 2016, Idaho Power expended approximately $44 million, $48 million, and $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 power cost adjustment mechanisms. Energy efficiency program expenditures funded through the 16 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 Annual Average Emissions Intensity 869 647 Environmental Regulation and Costs 896 934 944 945 929 867 864 1,066 632 858 944 1,015 1,129 874 681 1,066 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 17 requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Item 7 - MD&A - "Environmental Matters" in this report. Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, particularly given the volume of existing and proposed regulations at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars): Capital expenditures: License compliance and relicensing efforts at hydroelectric facilities Investments in equipment and facilities at thermal plants Total capital expenditures Operating expenses: Operating costs for environmental facilities - hydroelectric Operating costs for environmental facilities - thermal Total operations and maintenance 2019 2020-2021 $ $ $ $ 12 4 16 21 12 33 $ $ $ $ 35 22 57 42 23 65 Idaho Power anticipates that finalization, implementation, or modification of a number of federal and state rulemakings and other proceedings addressing, among other things, greenhouse gases and endangered species could result in substantial changes in operating and compliance costs, but Idaho Power is unable to estimate those changes in costs given the uncertainty associated with existing and potential future regulations. Idaho Power expects that it would seek to recover increases in costs through the ratemaking process. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and potential early plant retirements cannot be fully recovered in rates on a timely basis. IDACORP FINANCIAL SERVICES, INC. IFS invests in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk with most of IFS’s investments having been made through syndicated funds. While IFS has not actively pursued new investment opportunities for some time, IFS does evaluate new investment opportunities. At December 31, 2018, the unamortized amount of IFS’s portfolio was approximately $3 million ($146 million in gross tax credit investments, net of $143 million of accumulated amortization). IFS generated tax credits of $2.6 million in each year in 2018, 2017, and 2016. In 2018, 2017, and 2016, IFS received distributions related to fully- amortized affordable housing investments that reduced IDACORP's income tax expense by $0.3 million, $1.1 million, and $1.7 million, respectively. IDA-WEST ENERGY COMPANY Ida-West operates and has a 50 percent ownership interest in nine hydroelectric projects that have a total generating capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of approximately $10 million in both 2018 and 2017 and $8 million in 2016. EXECUTIVE OFFICERS OF THE REGISTRANTS The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), along with their business experience during at least the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed. DARREL T. ANDERSON, 60 • • • President and Chief Executive Officer of IDACORP, Inc., May 2014 - present President and Chief Executive Officer of Idaho Power Company, January 2014 - present President and Chief Financial Officer of Idaho Power Company, January 2012 - December 2013 18 • Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 2009 - April 2014 • Member of the Boards of Directors of IDACORP, Inc. and Idaho Power Company since September 2013 BRIAN R. BUCKHAM, 40 Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - present • • Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - February 2017 • In-house legal counsel of IDACORP, Inc. and Idaho Power Company, April 2010 - March 2016 JEFFREY S. GLENN, 51 • Vice President of Corporate Services and Chief Information Officer of Idaho Power Company, June 2018 - present • Vice President of Information Technology and Chief Information Officer of Idaho Power Company, January 2016 - June 2018 • Vice President of Technology Operations of Verizon Digital Media Services, Inc. (a digital media content delivery network company), January 2014 - January 2016 • Vice President of Technology Operations of Edgecast Networks, Inc. (acquired by Verizon Digital Media Services, Inc. in 2014), January 2012 - January 2014 LISA A. GROW, 53 • • • Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - present Senior Vice President of Operations of Idaho Power Company, January 2016 - March 2016 Senior Vice President - Power Supply of Idaho Power Company, October 2009 - December 2015 STEVEN R. KEEN, 58 Senior Vice President - Chief Financial Officer, and Treasurer of IDACORP, Inc., May 2014 - present Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 2014 - present Senior Vice President - Finance and Treasurer of Idaho Power Company, January 2012 - December 2013 • • • • Vice President - Finance and Treasurer of IDACORP, Inc., June 2010 - April 2014 JEFFREY L. MALMEN, 51 • Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present • Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, October 2008 - March 2016 TESSIA PARK, 57 • Vice President of Power Supply of Idaho Power Company, January 2016 - present • Director of Load Serving Operations of Idaho Power Company, September 2012 - December 2015 KEN W. PETERSEN, 55 • Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - present • Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 2010 - December 2013 N. VERN PORTER, 59 • Vice President of Transmission & Distribution Engineering and Construction and Chief Safety Officer, April 2016 - present Senior Vice President of Customer Operations of Idaho Power Company, April 2015 - December 2015 • Vice President of Customer Operations of Idaho Power Company, January 2016 - March 2016 • • Vice President of Idaho Power Company, January 2014 - April 2015 • Vice President of Delivery Engineering and Construction of Idaho Power Company, May 2012 - December 2013 ADAM RICHINS, 40 • Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - present • General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017 • In-house legal counsel of Idaho Power Company, November 2010 - January 2014 ITEM 1A. RISK FACTORS 19 IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Matters Impacting Future Results" in this report, and information in other reports the companies file with the SEC, should be considered carefully when making any investment decisions relating to IDACORP or Idaho Power. State or federal regulators may not approve customer rates that provide timely or sufficient recovery of Idaho Power's costs or allow Idaho Power to earn a reasonable rate of return, which could cause IDACORP's and Idaho Power's financial condition and results of operations to be adversely affected. The prices that the IPUC and OPUC authorize Idaho Power to charge customers for its retail services, and the tariff rate that the FERC permits Idaho Power to charge for its transmission services, are generally the most significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, liquidity, and financial condition. Idaho Power's ability to recover its costs and earn a reasonable rate of return can be affected by many regulatory factors, including the timing difference between when Idaho Power incurs costs and when Idaho Power recovers those costs in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs included in rates and the amount of actual costs incurred. Idaho Power is often required to incur costs before the IPUC, OPUC, or FERC approves the recovery of those costs, such as construction costs for new facilities or power lines, the costs of compliance with legislative and regulatory requirements, increased funding levels of a defined benefit pension plan, and the costs of damage from fires, weather-related events, and natural disasters. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basis that they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. Ratemaking has generally been premised on estimates of historic costs based on a test year, so if a given year’s actual costs are higher than historic costs, rates may not be sufficient to cover actual costs. While rate regulation is also premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard. Decisions are subject to judicial appeal, which could lead to further uncertainty in regulatory proceedings. Economic, political, legislative, public policy, or regulatory pressures may lead stakeholders to seek rate reductions or refunds, limits on rate increases, or lower allowed rates of return on investments for Idaho Power. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates. The IPUC and OPUC may adopt different methods of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings or significant regulatory lag may cause Idaho Power to record an impairment of its assets or otherwise adversely affect cash flows and earnings and result in lower credit ratings, reduced access to capital and higher financing costs, and reductions or delays in planned capital expenditures. For additional information relating to Idaho Power's state and federal regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, and Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters" in this report. Idaho Power's cost recovery mechanisms may not function as intended and are subject to change or elimination, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustment mechanism in Idaho. The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differences between these two amounts is deferred for future recovery from, or refund to, customers through rates. Volatility in power supply costs continues to be significant, in large part due to fluctuations in hydroelectric generation conditions and high costs for the purchase of renewable energy under mandatory long-term contracts. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. The fixed cost adjustment mechanism is a decoupling mechanism designed to remove a portion of Idaho Power's disincentive to invest in and support 20 energy efficiency activities. This mechanism allows Idaho Power to charge Idaho residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case. The power cost and fixed cost adjustment mechanisms are generally subject to change at the discretion of applicable state regulators, who could decide to modify or eliminate either mechanism in a manner that adversely impacts IDACORP's and Idaho Power's financial condition, cash flows, and results of operations. IDACORP's and Idaho Power's business, financial condition, and results of operations may be negatively affected by changes in customer growth or customer usage. Changes in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, expansion or loss of service area, changes in customer needs and expectations, adoption rates of energy efficiency measures, customer-generated power such as from solar panels and gas-fired generators, demand-side management requirements, regulation or deregulation, and adverse economic conditions. An economic downturn or recession could also negatively impact customer use and reduce revenues and cash flows, thus adversely affecting results of operations. Many electric utilities, including Idaho Power, have experienced a decline in usage per customer, in part attributable to energy efficiency activities. State or federal regulations may be enacted to encourage or require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, legislation to deregulate electric service, and customers seeking alternative sources of energy and electric service. If customers choose to generate their own energy, discontinue a portion or all service from Idaho Power, or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of its services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho residential customers has declined from 1,063 kWh in 2009 to 945 kWh in 2018. Rate mechanisms, such as the Idaho fixed cost adjustment, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's volume- based energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in IDACORP and Idaho Power modifying or eliminating large generation or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows. Conversely, if Idaho Power were to experience an unanticipated increase in the demand for energy through, for example, the rapid addition of new industrial and commercial customers or population growth in the service area, Idaho Power may be required to rely on higher-cost purchased power to meet peak system demand and may need to accelerate investment in additional generation or transmission resources. If the incremental costs associated with the unanticipated changes in loads exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows. IDACORP's and Idaho Power's operating results fluctuate seasonally and can be adversely affected by changes in weather conditions, severe weather, and climate change. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year. Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, droughts, heat waves, fires, floods, snow loading, and other extreme weather events, and impact Idaho Power’s ability to import power on transmission lines from other geographic areas. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and 21 extended outages, increasing costs and other operating and maintenance expenses, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to higher temperatures are likely to decrease power generation from hydroelectric plants. Variations in hydroelectric generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus hydroelectric power in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs. The costs of repair and replacing infrastructure or liability for personal injury, loss of life, or property damage from utility equipment that fails as a result of significant weather and weather-related events, including fires, may not be covered in full by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators. In addition, state and federal legislation and regulations have been proposed in recent years to limit the severity and impact of climate change, such as imposing mandatory reductions in greenhouse gas emissions, which could increase Idaho Power’s compliance costs. For additional information relating to legislation, regulations, and legal proceedings related to environmental matters, see Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. New advances in power generation, energy efficiency, or other technologies that impact the power utility industry could cause decreased customer energy demand and decreased revenues. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, power storage, and energy efficiency. In particular, in recent years the net cost of solar generation has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar generation. There is potential that customer-owned power generation systems, particularly if coupled with power storage devices, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way Idaho Power manages its distribution systems, and reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency would result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations. Acts or threats of terrorism, cyber attacks, data or physical security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid could require significant expenditures, or result in claims against the companies, and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. Federal regulators have stated that a number of organizations continue to seek opportunities to exploit potential vulnerabilities in the U.S. energy infrastructure and that those attacks have become increasingly frequent and sophisticated. Some of Idaho Power's facilities are deemed "critical infrastructure," in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk electric power system, national economic security, and public health and safety. The possibility that infrastructure facilities, such as generation facilities and electric transmission or distribution facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack, including by nation states or nation state-sponsored groups (whether originating internally or externally) may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Cyber threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power, such as process breakdowns, human error, security architecture or design vulnerabilities, or by third parties, such as computer hackings, cyber attacks, computer viruses, or other destructive or disruptive software, denial of service attacks, social engineering or other malicious activities, or any combination of the foregoing, could result in a degradation or disruption in the energy grid and the services of the companies. Physical or cyber attacks against key suppliers or service providers could have a similar effect on IDACORP and Idaho Power. Political, economic, social, or financial market instability or damage to or interference with Idaho Power’s operating assets, customers, or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair, or other costs, any of which may materially adversely affect Idaho Power in ways that cannot be predicted as of the date of this report. Any of these risks could materially affect the companies’ consolidated financial results. 22 These events, and governmental actions in response, could result in a material decrease in revenues and increase costs to protect, repair, and insure Idaho Power's assets and operate its business. Idaho Power's operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. No security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. Any security breaches, such as misappropriation, misuse, leakage, falsification or accidental release or loss of information maintained in IDACORP's and Idaho Power's information technology systems, including customer data, could result in violations of privacy and other laws, financial loss to Idaho Power or to its customers, customer dissatisfaction, damage to Idaho Power’s reputation, and significant litigation and penalty exposure, all of which could materially affect Idaho Power's financial condition and results of operations. Capital expenditures for infrastructure, risks associated with permitting and construction of that infrastructure, and the timing and availability of cost recovery for the expenditures, can significantly affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s business is capital intensive and requires significant investments in energy generation, transmission, and distribution infrastructure. A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, long-term anticipated increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure. For instance, Idaho Power is in the permitting process for two 500-kV transmission line projects, which are intended to help meet future customer energy demands. Construction projects are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples: • • • • • • • • • the ability to timely obtain labor or materials at reasonable costs; defaults by suppliers and contractors; equipment, engineering, and design failures; unexpected environmental and geological problems; the effects of adverse weather conditions; availability of financing; load forecasts; the ability to obtain and comply with permits and land use rights, and environmental constraints; and delays and costs associated with disputes and litigation with third parties. The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable or unwilling to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations. Changes in legislation, regulation, and government policy may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. Changes in, and uncertainty with respect to, federal, state, and local legislation, regulation, and government policy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals and recently enacted legislation that could have a material impact on IDACORP and Idaho Power include, but are not limited to, tax reform, utility regulation, infrastructure renewal programs, environmental regulation, and modifications to accounting and public company reporting requirements. Further, the proposals and new legislation could have an impact on the rate of growth of Idaho Power’s customers and their willingness to expand operations and increase electric service requirements. Laws, regulations, and policies relating to environmental compliance could change and require IDACORP and Idaho Power and their customers to modify their business strategy or affect their returns on 23 investment by restricting activities and projects or subjecting them to increased compliance costs. IDACORP and Idaho Power are monitoring the implementation by federal, state, and local governmental authorities of various executive orders and are unable to predict whether and to what extent such actions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows. Changes in income tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for income taxes. Amounts of income tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. In recent years, state regulatory mechanisms with income tax-related provisions (such as Idaho Power's May 2018 regulatory settlement stipulation with the IPUC), has significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of potential future income tax proceedings, or the state public utility commissions' treatment of those outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances, the treatment from a ratemaking perspective of any net income tax expense or benefit could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. In addition, Idaho Power uses the regulatory flow-through income tax accounting method as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in income tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than most other companies. IDACORP's and Idaho Power’s businesses are subject to an extensive set of environmental laws, rules, and regulations, which could impact their operations and costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. IDACORP's and Idaho Power's operations are subject to a number of federal, state, and local environmental statutes, rules, and regulations relating to air and water quality, natural resources, renewable energy, and health and safety. Many of these laws and regulations are described in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. These laws and regulations generally require IDACORP and Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, and other approvals, including through substantial investment in pollution controls, and may be enforced by both public officials and private individuals. Some of these regulations are pending, changing, or subject to interpretation, and failure to comply may result in penalties, mandatory operational changes, and other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties and complying with new operating requirements. Idaho Power devotes significant resources to environmental monitoring, pollution control equipment, and mitigation projects to comply with existing and anticipated environmental regulations. However, it is possible that federal, state and local authorities could attempt to enforce more stringent standards, stricter regulation, and more expansive application of environmental regulations. Environmental regulations have created the need for Idaho Power to install new pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its owned and co-owned power generation facilities, often at a substantial cost. Compliance with environmental regulations can significantly increase capital spending, operating costs, and plant outages, and can negatively affect the affordability of Idaho Power's services for customers. Idaho Power cannot predict with certainty the amount and timing of all future expenditures necessary to comply with these environmental laws and regulations, although Idaho Power expects the expenditures will be substantial. In some cases, the costs to obtain permits and ensure facilities are in compliance may be prohibitively expensive. If the costs of compliance with new regulations renders the generating facilities uneconomical to maintain or operate, Idaho Power would need to identify alternative resources for power, potentially in the form of new generation and transmission facilities, market power purchases, demand-side management programs, or a combination of these and other methods. Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its existing infrastructure or construction of new infrastructure. The current presidential administration has issued a number of executive orders related to environmental matters designed to ease environmental regulation that the federal agencies are still implementing. However, the outcome of the Environmental Protection Agency's and other federal agencies' review of regulations covered by the executive orders is difficult to predict. Moreover, the executive orders and any resulting federal regulations could be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federal regulations or bolster 24 environmental compliance and enforcement efforts at the local level. Accordingly, Idaho Power may not realize any benefit from changes to federal environmental regulations, if any, resulting from the executive orders and, as of the date of this report, cannot predict whether and to what extent the orders and resulting changes to regulations could affect its operations and environmental-related expenditures. In addition, some environmental regulations are currently subject to litigation and not yet final. As a result of this uncertainty, approaches to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot foresee the potential impacts these regulations would have on Idaho Power's operations or financial condition. Idaho Power is not guaranteed timely or full recovery through customer rates or insurance of costs associated with environmental regulations, environmental compliance, plant closures, or clean-up of contamination. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, or subjected to additional costs. Factors contributing to lower hydroelectric generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power derives a significant portion of its power supply from its hydroelectric facilities. During 2017 and 2018, 65 percent of Idaho Power's electric power generation was from hydroelectric facilities. Due to Idaho Power’s heavy reliance on hydroelectric generation, factors such as precipitation and snowpack, the timing of run-off, and the availability of water in the Snake River basin can significantly affect its operations. The combination of a long-term trend of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights reduce Snake River flows available for hydroelectric generation. When hydroelectric generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and market power purchases; therefore, costs increase and opportunities for wholesale energy sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydroelectric generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity. Obligations imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its largest hydroelectric generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydroelectric projects, which may be reflected in hydroelectric licenses, including for the Hells Canyon Complex. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydroelectric facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power’s generation requirements. One significant issue identified in connection with the Hells Canyon Complex relicensing effort involves water temperature gradients in the Snake River below the Hells Canyon dam. Certain parties in the relicensing proceedings have advocated for the installation of a water temperature management apparatus which, if required to be installed, would involve substantial costs to construct, operate, and maintain. Idaho Power may be unable to recover in full or in a timely manner the costs of such an apparatus through rates, particularly given the magnitude of any potential impact on customer rates. Another significant issue related to the relicensing effort involves a dispute between the states of Idaho and Oregon regarding whether to reintroduce or establish spawning populations of fish species into Idaho waters. In December 2018, the states of Idaho and Oregon, along with Idaho Power, reached a proposed settlement on this matter, requiring Idaho Power to reintroduce certain fish species and fund-related research. Idaho Power cannot predict the outcome of these proceedings, the requirements that might be imposed during the relicensing process, the financial impact of those requirements, whether a new multi-year license will ultimately be issued, and whether the IPUC or OPUC will allow recovery through rates of the substantial costs incurred in connection with the licensing process and subsequent compliance. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydroelectric generation, which could negatively affect results of operations and financial condition. Idaho Power’s use of coal and natural gas to fuel power generation facilities exposes it to commodity availability and price risk, which can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. As part of its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term 25 contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, and changes in technology. Natural gas transportation to Idaho Power's three natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience financial or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power may not be able to fully or timely recover these increased costs through rates, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. If the assumptions underlying coal mine reclamation at Bridger Coal Company and related forecast trust fund growth are materially inaccurate, Idaho Power’s costs could be greater than anticipated or be incurred sooner than anticipated. Bridger Coal Company, a subsidiary of Idaho Power, uses both surface and underground methods to mine coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closure obligations and standards for mining of coal. Bridger Coal Company’s estimate of reclamation liability and bonding obligations is reviewed periodically by Idaho Power’s management committee, audit committee of the board of directors, external and internal auditors, and by government regulators. Idaho Power funds a trust to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected. Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes or attrition, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, wildfires, acts of terrorism or sabotage, the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties, and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area during high-load periods. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third party contractors to perform work on its generation, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders. Accidents, terrorist acts, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, uncontrolled release of water from hydroelectric dams, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could also expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, and property damage, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire and increasing the magnitude of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and 26 commonly hot, dry summer conditions, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs in the event there are fires that are deemed to be separate occurrences covered by self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected. Volatility or disruptions in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing and ability to execute on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The credit facilities represent commitments by the participating banks to make loans and issue letters of credit. However, the ability and obligation of the participating banks to make those loans and issue letters of credit is subject to specified conditions and volatility or disruptions in the financial markets could affect the companies' ability to obtain debt financing or draw upon or renew existing credit facilities. Idaho Power's ability to issue long-term debt is also subject to a number of conditions included in an indenture, and Idaho Power's ability to issue long-term debt and commercial paper is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all. Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper or short-term or long-term debt at reasonable interest rates and terms or at all. Also, while the credit facilities represent a contractual obligation to make loans, one or more of the participating banks may default on their obligations to make loans under, or may withdraw from, the credit facilities. Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities include financial covenants that limit the amount of debt that can be outstanding as a percentage of total capital, and Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. The companies must also make specified representations in connection with request for loans and it is possible that they may be unable to do so at the time of such request, which would limit or eliminate the obligation of the banks to provide loans. Failure to maintain these representations and covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could limit their ability to pursue certain projects and adversely impact IDACORP's and Idaho Power's financial condition, results of operations, and liquidity. A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and rate mechanisms, the effectiveness of management, resource risks and power supply costs, and other factors. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access short- and long-term capital under reasonable terms or at all, reduce the pool of potential lenders, increase borrowing costs under existing credit facilities, limit access to the commercial paper market, require the companies to pay a higher interest rate on their debt, and require the companies to post additional performance assurance collateral with transaction counterparties. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, IDACORP's and Idaho Power's financial condition and results of operations could be adversely affected. Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. The interest rates for any borrowings under IDACORP and Idaho Power’s credit facilities are based on either (1) a floating rate 27 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. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available, or if lenders have increased costs due to changes in LIBOR, IDACORP and Idaho Power may suffer from potential increases in interest rates on any borrowings. Further, IDACORP and Idaho Power may need to renegotiate their credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established. Idaho Power’s risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to buy and sell power, natural gas, and transmission service, enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financial hedge transactions to mitigate in part exposure to variable commodity prices. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments used for hedging might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative instruments, and any such failure to mitigate exposure could result in financial losses. Certain of Idaho Power's purchase or sale, hedging, and derivative agreements may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. Forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions that Idaho Power may not be able to collect in customer rates. The FERC may take action to limit volatility in the energy market by imposing price limits or other market restrictions to control market-based rate sales, which could adversely affect the companies' financial results. As a result, risk management actions, or the failure or inability to manage commodity availability and price and counterparty risk, may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations. Further, the bankruptcy or insolvency of a counterparty to commodity or other transactions could impair Idaho Power’s ability to collect amounts receivable from those counterparties, potentially including the ability to collect or retain collateral posted by a counterparty. In January 2019, Pacific Gas & Electric Company and PG&E Corporation, its parent entity (collectively, PG&E), filed voluntary bankruptcy petitions under Chapter 11 of the U.S. Bankruptcy Code. Idaho Power does not have any direct power, gas, or derivative transactions with PG&E. However, both Idaho Power and PG&E are participants in the Western EIM and engage in indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that PG&E may owe other participants in the Western EIM. Also, PG&E purchases the output of power from small hydroelectric facilities located in California, in which Ida-West is a 50% co-owner. If PG&E is unable to perform on its obligations under its arrangements with Ida-West’s joint venture, IDACORP does not believe the impact would be material to its financial condition nor results of operations. However, a bankruptcy filing of the magnitude of PG&E’s filing in 2019 could have a ripple effect on various Idaho Power counterparties in the power, gas, and derivative markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of Idaho Power’s counterparties to perform on their obligations. Idaho Power could be subject to penalties and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability, security, and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC regulations may be substantial, and in some circumstances monetary penalties may exceed $1 million per day per violation. The imposition of penalties on Idaho Power for its actual or alleged failure to comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition. Federally mandated purchases of power from renewable energy projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's 28 and IDACORP's results of operations and financial condition. An abundance of intermittent, non-dispatchable generation from renewable energy projects interconnected with Idaho Power's system has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel- fired generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in additional generation. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and shifts in customer costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. If Idaho Power is unable to timely recover those costs through its power cost adjustment mechanisms or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows. The performance of pension and postretirement benefit plan investments and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. As benefit costs continue to rise, there is no assurance that the state public utility commissions will continue to allow recovery. The key actuarial assumptions that affect funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 12 - "Benefit Plans" to the consolidated financial statements included in this report. As a holding company, IDACORP does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other means. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiary's actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, tax obligations, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which may reduce or cease payment of dividends at any time. See Note 7 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends. IDACORP's and Idaho Power's activities are concentrated in one industry and in one region, which exposes it to risks from lack of diversification, regional economic conditions, and regional legislation and regulation. IDACORP and Idaho Power do not have diversified operations or sources of revenue. Idaho Power comprises the bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and Idaho Power's future performance will be affected by economic conditions, regulatory and legislative activity, weather conditions, and other events and conditions in its service area and in the electric power industry. The impacts of a retiring workforce with specialized utility-specific functions could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and 29 design personnel, and generation plant operators, require extensive, specialized training. Idaho Power has experienced in recent years an above-average number of employee retirements and expects the increased level of retirement of its skilled workforce and persons in key positions will continue in 2019 and in the near-term. At December 31, 2018, approximately 22 percent of Idaho Power's employees were eligible for regular or early retirement under Idaho Power's defined benefit pension plan. This will require Idaho Power to attract, train, and retain new employees to help prevent a loss of institutional knowledge and avoid a skills gap. The loss of skills and institutional knowledge of experienced employees and the failure to hire and the costs associated with attracting, training, and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations. IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have reputational impact and a short- or long-term negative effect on their financial condition and results of operations. Similarly, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations. Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board (FASB) and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of operations nor the timing of such changes. Idaho Power meets conditions under GAAP to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations. None. ITEM 1B. UNRESOLVED STAFF COMMENTS ITEM 2. PROPERTIES Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants. In addition to these physical assets, Idaho Power has rights-of-way and water rights that enable it to use its facilities. Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. As of December 31, 2018, the system also includes approximately 4,816 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 21 transmission substations, 9 switching stations, 32 mixed-use transmission and distribution substations, 183 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,569 pole-miles of distribution lines. Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for all of its hydroelectric projects that are subject to federal licensing. Relicensing of Idaho Power’s hydroelectric projects is discussed in Part II - Item 7 - MD&A – "Regulatory Matters – Relicensing of Hydroelectric Projects” in this report. 30 Idaho Power's hydroelectric projects and other owned and co-owned generating facilities and their nameplate capacities are included in the table below. Project Hydroelectric Projects: Properties Subject to Federal Licenses: Lower Salmon Bliss Upper Salmon Shoshone Falls CJ Strike Upper Malad - Lower Malad Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex) Swan Falls American Falls Cascade Milner Twin Falls Other Hydroelectric: Clear Lakes - Thousand Springs Total Hydroelectric Steam and Other Generating Plants: Jim Bridger (coal-fired)(3) North Valmy (coal-fired)(3) Boardman (coal-fired)(3)(4) Danskin (gas-fired) Langley Gulch (gas-fired) Bennett Mountain (gas-fired) Salmon (diesel-internal combustion) Total Steam and Other Total Generation Nameplate Capacity (kW)(1) License Expiration 2034 2034 2034 2034 2034 2035 (2) 2005 2042 2025 2031 2038 2040 60,000 75,000 34,500 11,500 82,800 21,770 1,235,600 27,170 92,340 12,420 59,448 52,897 9,300 1,774,745 770,501 283,500 64,200 270,900 318,452 172,800 5,000 1,885,353 3,660,098 (1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity. (2) Licensed on an annual basis while the application for a new multi-year license is pending. (3) Idaho Power’s ownership interests are one-third for Jim Bridger, 50 percent for North Valmy, and 10 percent for Boardman. Amounts shown represent Idaho Power’s share. (4) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020. IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus is comprised of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,113,631 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon. Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act (FPA) and reservoirs and other easements. Substantially all of Idaho Power’s property is subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. Idaho Power’s property is subject to minor defects common to properties of such size and character that it believes do not materially impair the value to, or the use by, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition. Through Idaho Energy Resources Co., Idaho Power owns a one-third interest in Bridger Coal Company (BCC) and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West holds 50- percent interests in nine hydroelectric plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California. 31 ITEM 3. LEGAL PROCEEDINGS Refer to Note 11 – “Contingencies” to the consolidated financial statements included in this report. ITEM 4. MINE SAFETY DISCLOSURES Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report. 32 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE) under the trading symbol "IDA". On February 15, 2019, there were 9,006 holders of record of IDACORP common stock. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998. For information regarding IDACORP's dividend policy, see Part II - Item 7 - MD&A - "Liquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends see, Note 7 - "Common Stock" to the consolidated financial statements included in this report. IDACORP did not repurchase any shares of its common stock during the fourth quarter of 2018. Performance Graph The graph below shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the Edison Electric Institute (EEI) Electric Utilities Index. The data assumes that $100 was invested on December 31, 2013, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns. Source: Bloomberg and EEI 2013 2014 2015 2016 2017 2018 IDACORP S&P 500 EEI Electric Utilities Index $ 100.00 $ 131.78 $ 139.49 $ 169.92 $ 197.83 $ 100.00 100.00 113.68 128.91 115.25 123.88 129.02 145.48 157.17 162.53 206.86 150.27 168.49 The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and shall not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing. 33 ITEM 6. SELECTED FINANCIAL DATA IDACORP, Inc. SUMMARY OF OPERATIONS (thousands of dollars, except per share amounts and statistics) Operating revenues Operating income(1) Net income attributable to IDACORP, Inc. Diluted earnings per share Dividends declared per share Financial Condition: Total assets(2) Long-term debt (including current portion)(2) Financial Statistics: Times interest charges earned: Before tax(3) After tax(4) Book value per share(5) Market-to-book ratio(6) Payout ratio(7) Return on year-end common equity(8) 2018 $1,370,752 296,922 226,801 4.49 2.40 2017 $1,349,486 315,545 212,419 4.21 2.24 2016 $1,262,020 283,582 198,288 3.94 2.08 2015 $1,270,289 297,048 194,679 3.87 1.92 2014 $1,282,524 267,194 193,480 3.85 1.76 $6,382,754 $6,045,405 $6,289,897 $6,023,314 $5,701,037 $1,834,788 $1,746,123 $1,745,678 $1,726,474 $1,599,686 3.55 3.36 47.04 $ 3.82 3.30 44.68 $ 3.54 3.15 42.74 $ 3.61 3.12 40.88 $ 3.38 3.19 38.85 $ 198% 53% 9.6% 204% 53% 9.4% 188% 53% 9.2% 166% 50% 9.5% 170% 46% 9.9% (1) Operating income in 2018-2014 reflects IDACORP's 2018 adoption of Accounting Standards Update (ASU) 2017-07. IDACORP retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit cost. The non-service cost components of net periodic benefit cost were reclassified from "Other operations and maintenance" and "Other" operating expenses to "Other Expense, Net" on the consolidated statements of income to conform to current period presentation. (2) Amounts in 2014 were adjusted to reflect IDACORP's 2015 adoption of ASU 2015-03, which required debt issuance costs be reported as reductions of long-term debt rather than as long-term assets on the consolidated balance sheets. The financial statistics listed above are calculated in the following manner: (3) The sum of "Interest on long-term debt," "Other interest" expense, and "Income before income taxes" divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income. (4) The sum of "Interest on long-term debt," "Other interest" expense, and "Net income attributable to IDACORP, Inc." divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income. (5) "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year divided by shares outstanding at the end of the year. (6) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (5) above. (7) Dividends paid per common share divided by diluted earnings per share. (8) "Net income attributable to IDACORP, Inc." on the consolidated income statements divided by "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year. 34 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. INTRODUCTION IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; and Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). EXECUTIVE OVERVIEW IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements and recognitions during 2018 include: • • • • • • • • • IDACORP achieved net income growth for an eleventh consecutive year; IDACORP provided a 14 percent cumulative annual total shareholder return over the past three years, including share price appreciation and dividends paid, ranking in the 63rd percentile among peer companies in the Edison Electric Institute (EEI) Electric Utilities Index; IDACORP received its second EEI Electric Utilities Index award in the past three years, for the best total shareholder return performance among small cap utilities (market capitalization of less than $5 billion) over the past five years, measured as of September 30, 2018; IDACORP increased its quarterly common stock dividend from $0.59 per share to $0.63 per share, as a part of a 110 percent increase in quarterly dividends approved over the last seven years under the company's objective to pay dividends at the upper end of the range of 50 percent to 60 percent of sustainable earnings; Idaho Power's customer count grew 2.3 percent in 2018; Idaho Power ranked second in J.D. Power's Electric Utility Residential Customer Satisfaction Study in its West Region Midsize segment for the second year in a row; Idaho Power reached milestones on key transmission projects as the U.S. Forest Service issued a record of decision on the siting of the Boardman-to-Hemingway 500-kV project and the U.S. Bureau of Land Management (BLM) issued a record of decision for the remaining transmission line segments of the Gateway West 500-kV transmission project; Idaho Power achieved its carbon dioxide (CO2) emissions intensity reduction goal; and Idaho Power reached several constructive regulatory settlements that were approved by the IPUC and OPUC related to recent income tax reform, the indefinite extension, with modifications, of the current earnings support and revenue sharing mechanism, the prudence of certain Hells Canyon Complex (HCC) relicensing costs, and the treatment of costs incurred to join the energy imbalance market implemented in the western United States (Western EIM). 35 Summary of 2018 Financial Results The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2018, 2017, and 2016 (in thousands, except earnings per share amounts): Idaho Power net income Net income attributable to IDACORP, Inc. Average outstanding shares – diluted (000’s) IDACORP, Inc. earnings per diluted share $ $ $ Year Ended December 31, 2017 206,347 212,419 50,424 4.21 2018 222,334 226,801 50,510 4.49 $ $ $ $ $ $ 2016 189,242 198,288 50,373 3.94 The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2018, from the year ended December 31, 2017 (items are in millions and are before tax unless otherwise noted): 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 Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms Idaho fixed cost adjustment (FCA) revenues Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms Transmission wheeling and other revenues Non-cash amortization of regulatory deferrals (related to tax reform) Other operations and maintenance (O&M) expenses (excluding non-cash amortization of regulatory deferrals) Other changes in operating revenues and expenses, net Decrease in Idaho Power operating income prior to sharing mechanism Decrease in revenues as a result of sharing mechanism Decrease in Idaho Power operating income Earnings of unconsolidated equity-method investments Non-operating income and expenses, net Decrease in income tax expense from remeasurement of deferred taxes and make-whole premium for early bond redemption Income tax expense (excluding remeasurement of deferred taxes and make-whole premium for early bond redemption) 10.3 (9.4) 17.7 (26.9) 16.1 (4.0) (13.8) (3.6) (13.6) (5.0) (18.6) 1.4 0.3 9.0 23.9 Total increase in Idaho Power net income Other IDACORP changes (net of tax) Net income attributable to IDACORP, Inc. - December 31, 2018 16.0 (1.6) $ 226.8 IDACORP's net income increased $14.4 million for 2018 compared with 2017, primarily due to higher net income at Idaho Power. Customer growth added $10.3 million to Idaho Power's operating income compared with 2017. Sales volumes on a per- customer basis decreased operating income by $9.4 million in 2018 compared with 2017. A decrease in sales volumes to residential customers was partially offset by an increase in usage per irrigation customer. Milder temperatures in 2018 compared with 2017 caused residential customers to use 6 percent less electricity per customer, mostly for cooling and heating purposes, while decreased precipitation led agricultural irrigation customers to use 9 percent more electricity per customer to operate irrigation pumps. However, due mostly to the lower usage by Idaho residential customers, the FCA mechanism added $17.7 million to operating income during 2018 compared with 2017. The net decrease in retail revenues per MWh reduced operating income by $26.9 million in 2018 compared with 2017. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to recent income tax reform reduced revenues by approximately $22 million in 2018. The timing of the revenue reductions may not align with decreases in income tax expense in any given period due to the method and timing of customer rate reductions provided for in the settlement 36 stipulations, the nature and timing of income tax accruals, discrete items, and other items discussed in more detail in the "Income Tax Reform" section below. Also, a change in customer sales mix reduced the retail revenues per MWh as volumes sold to residential customers made up a smaller portion of the customer sales mix. During 2018, Idaho Power benefited from a $16.1 million increase in transmission wheeling and other revenues, compared with 2017. This change was largely due to a 37 percent increase in the Open Access Transmission Tariff (OATT) rate in October 2017, partially offset by a 10 percent decrease in the OATT rate in October 2018 and, to a lesser extent, an increase in wheeling volumes. Other O&M expenses included $4.0 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers, as provided by the settlement stipulation approved by the IPUC related to income tax reform. Excluding the non-cash amortization of regulatory deferrals, other O&M expenses were $13.8 million higher in 2018 compared with 2017. In 2018, compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses. In 2018, Idaho Power recorded $5.0 million as a provision against current revenues to be refunded to customers through a future rate reduction, through the Idaho-jurisdiction power cost adjustment (PCA) mechanism pursuant to a settlement stipulation with the IPUC as described in "Regulation of Rates and Cost Recovery" below. Idaho Power's $5.7 million remeasurement of deferred taxes resulting from the federal and Idaho income tax rate change (discussed in further detail below) on the adjustment of temporary differences as a result of IDACORP’s 2017 consolidated income tax return filings and the $1.3 million 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 April 2018 decreased Idaho Power's income tax expense by $7.0 million in 2018. Idaho Power recorded $2.0 million of income tax expense in 2017 for the initial remeasurement of deferred taxes resulting from the federal and Idaho income tax rate change. Excluding these items, Idaho Power income tax expense was $23.9 million lower during 2018 compared with 2017, due mostly to the lower federal and state statutory income tax rates resulting from income tax reform. 2018 Initiatives and Strategy IDACORP’s strategy is focused on four areas: growing to enhance financial strength, improving Idaho Power's core business, enhancing Idaho Power’s brand, and focusing on safety and employee engagement. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic focus areas, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is working to continue to provide safe, fair-priced, reliable service to its customers from a diversified source of generation resources, with a continued commitment to strong, sustainable financial results. For more information on the business strategy of the companies, see Part I, Item 1 – “Business - Business Strategy” in this report. Overview of General Factors and Trends Affecting Results of Operations and Financial Condition IDACORP's and Idaho Power's results of operations and financial condition are affected by a number of factors, and the impact of those factors is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following: • Regulation of Rates and Cost Recovery: The price that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has regulatory settlement stipulations in Idaho that include provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent (9.4 percent after 2019) return on year-end equity in the Idaho jurisdiction (Idaho ROE). The settlement stipulations also provide for the potential sharing between Idaho Power and customers of Idaho- jurisdictional earnings in excess of specified levels of Idaho ROE. The settlement stipulations provide for modifications of certain terms and the indefinite extension of the mechanism beyond the original termination date of December 31, 2019. The specific terms of these settlement stipulations are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. During 37 2019, Idaho Power will continue to assess the need to file a general rate case to reset base rates, but does not anticipate filing a rate case in the next twelve months. • Income Tax Reform: In December 2017, the Tax Cuts and Jobs Act was signed into law, which lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations (Tax Cuts and Jobs Act). The majority of the changes, including the rate reduction, became effective on January 1, 2018. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation related to these changes in income taxes (May 2018 Idaho Tax Reform Settlement Stipulation). Beginning June 1, 2018, the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million for the amortization of regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the PCA mechanism during the period from June 2018 through May 2019, for the income tax reform benefits accrued from January 2018 to May 2018 and for amounts included in Idaho Power's transmission revenues. The May 2018 Idaho Tax Reform Settlement Stipulation was designed to return to Idaho customers their share of the estimated annual pro forma tax expense reductions resulting from income tax reform, based on the full- year 2017 as required by the IPUC. Idaho Power's financial results from 2018 forward will be affected by any differences between annual income tax expense and the pro forma 2017 income tax expense used in the settlement until incorporated into a future rate proceeding or rate case. Refer to "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings. • Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen growth in the number of customers in its service area. In 2018, Idaho Power's customer count grew by 2.3 percent, and employment in Idaho Power's service area grew by approximately 2.2 percent based on Idaho Department of Labor preliminary December 2018 data. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power has in recent years supported State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area. In August 2018, Idaho Power began preparing its 2019 Integrated Resource Plan (IRP), Idaho Power's long-term forecast of loads and resources. For more information on the 2019 IRP, including the preliminary load forecast assumptions Idaho Power expects to use in its 2019 IRP, refer to "Resource Planning" in Item 1 - "Business" in this Form 10-K. • Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year, when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to Idaho residential and small commercial customers is mitigated through the FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements in this report. Further, as Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales of its excess power. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms. • Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho 38 Power has been pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the HCC, its largest hydroelectric generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding. • Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies heavily on natural gas and coal to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power. • Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Recently, energy industry regulators have issued substantial penalties for utilities alleged to have violated reliability and critical infrastructure protection requirements. Moreover, environmental laws and regulations, in particular, may increase the cost of operating generation plants, including Idaho Power's coal-fired plants, and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade, and due to economic factors in part associated with the costs of compliance with environmental regulation, has accelerated the retirement dates of certain of its coal-fired power plants. • Water Management and Relicensing of the Hells Canyon Hydroelectric Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydroelectric projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydroelectric generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license. 39 RESULTS OF OPERATIONS This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for 2018 are compared with 2017 and the results for 2017 are compared with 2016. The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last three years. Retail energy sales Wholesale energy sales Bundled energy sales Total energy sales Hydroelectric generation Coal generation Natural gas and other generation Total system generation Purchased power Line losses Total energy supply Year Ended December 31, 2017 2016 2018 14,587 2,246 617 17,450 8,682 3,274 1,408 13,364 5,431 (1,345) 17,450 14,571 1,934 202 16,707 8,900 3,284 1,504 13,688 4,242 (1,223) 16,707 14,196 742 444 15,382 6,408 4,045 1,722 12,175 4,337 (1,130) 15,382 For purposes of illustration, Boise, Idaho, weather-related information for the last three years is presented in the table that follows. Heating degree-days(1) Cooling degree-days(1) Precipitation (inches) Year Ended December 31, 2018 2017 2016 4,984 1,116 10.6 5,655 1,341 15.4 4,807 1,001 8.7 Normal(2) 5,514 942 11.3 (1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree above 65 degrees is counted as one cooling degree-day, and each degree below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers. (2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration. Sales Volume and Generation: In 2018, retail sales volumes were relatively flat compared with those of the prior year. Customer growth increased sales volumes during 2018 compared with 2017, with the number of Idaho Power's customers growing by 2.3 percent. During 2018, usage per irrigation customer was approximately 9 percent higher compared with 2017. Precipitation in the Idaho Power service area during 2018 was significantly less than in 2017, which increased usage by irrigation customers in 2018. Usage per residential customer was approximately 6 percent lower in 2018 compared with 2017. The decrease in residential usage was primarily due to milder weather during 2018 compared with 2017, which decreased the use of electricity for heating and cooling purposes. Cooling degree-days in Boise, Idaho were 17 percent lower during 2018 compared with 2017, but 18 percent above normal. Heating degree-days in Boise, Idaho were 12 percent lower during 2018 compared with 2017, and 10 percent below normal. Also, bundled energy sales (electric power combined with renewable energy certificates) volumes increased during 2018 compared with 2017. The solar generation projects under PURPA contracts that were initiated in 2017 generated an increased number of renewable energy credits to sell bundled with electricity. Total system generation decreased 2 percent during 2018 compared with 2017. Hydroelectric generation decreased 2 percent during 2018 compared with 2017, but comprised 65 percent of Idaho Power's total system generation during both 2018 and 2017. In 2018, purchased power increased 28 percent compared with 2017 due to an increase in power purchased from generation projects under mandatory PURPA contracts and an increase in other purchased power resulting from favorable wholesale gas and electricity market conditions and, to a lesser extent, transactions in the Western EIM, which commenced in 40 April 2018. The availability of hydroelectric generation and an increase in purchased power during 2018 reduced thermal generation compared with 2017. Wholesale energy sales volumes increased 312 thousand MWh, or 16 percent, during 2018 compared with 2017, due primarily to an increase in purchased power, both in market purchases and in purchases under PURPA contracts, resulting in increased energy available for wholesale energy sales. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power in the wholesale energy markets. The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms." Operating Revenues Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of customers for the last three years. Retail revenues: Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA(1)) Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA(1)) Industrial Irrigation Provision for sharing Deferred revenue related to HCC relicensing AFUDC(2) Total retail revenues Volume of Sales (MWh) Residential Commercial Industrial Irrigation Total retail MWh sales Number of retail customers at year-end Residential Commercial Industrial Irrigation Total customers Year Ended December 31, 2017 2018 2016 $ 530,527 $ 552,333 $ 514,954 310,299 319,195 302,650 190,130 158,001 (5,025) (8,780) 1,175,152 $ 195,124 150,030 — (10,706) 1,205,976 $ 182,590 156,505 — (10,706) 1,145,993 $ 5,135 4,105 3,371 1,976 14,587 464,670 71,680 120 21,175 557,645 5,355 4,099 3,346 1,771 14,571 453,605 70,411 119 20,932 545,067 5,004 3,999 3,243 1,950 14,196 444,431 69,344 121 20,638 534,534 (1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers. (2) As part of its January 30, 2009, general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in "Regulatory Matters" in this MD&A, Idaho Power was collecting $10.7 million annually. Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last three years. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates 41 based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. Retail Revenues - 2018 Compared with 2017: Retail revenues decreased $30.8 million in 2018 compared with 2017. The primary factors affecting retail revenues during the period were the following: • Rates: Rate changes decreased retail revenues by $39.0 million in 2018 compared with 2017. As a direct result of settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to income tax reform described further in "Regulatory Matters" in this MD&A, Idaho Power's revenues decreased approximately $22 million in 2018 compared with 2017. The timing of the revenue reductions may not align with decreases in income tax expense in any given period due to the method and timing of customer rate reductions provided for in the settlement stipulations, the nature and timing of income tax accruals, discrete items, and other items discussed in this MD&A. The rates include collection of amounts related to the PCA mechanism, which decreased revenues by $15.4 million in 2018 compared with 2017. The collection of amounts related to the PCA mechanism in rates has no effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates. • Customers: Customer growth of 2.3 percent increased retail revenues by $13.5 million in 2018 compared with 2017. • Usage: Lower usage (on a per customer basis), primarily by residential customers, decreased retail revenues by $18.0 million during 2018 compared with 2017. Decreased usage was primarily the result of more mild temperatures in Idaho Power's service area during 2018 compared with 2017, which led to decreased usage by residential customers for heating and cooling. For 2018, a 6 percent decrease in usage per residential customer compared with 2017 was partially offset by a 9 percent increase in usage per irrigation customer. Precipitation in Idaho Power's service area during 2018 was significantly less than 2017, which led to increased usage by irrigation customers. • • Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small general service customers during 2018 increased the amount of FCA revenue accrued by $17.7 million compared with 2017. Sharing: During 2018, Idaho Power recorded $5.0 million as a provision against current revenues to be refunded to customers through a future rate reduction. If approved, the rate reduction would be included in PCA rates beginning in June 2019. Idaho Power did not record any provision for sharing in 2017. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. Retail Revenues - 2017 Compared with 2016: Retail revenues increased $60.0 million in 2017 compared with 2016. The factors affecting retail revenues during the period are discussed below: • Rates: Rate changes, including the revenue accruals provided for in the Valmy settlement stipulation, increased retail revenues by $39.8 million for 2017 compared with 2016. In the second quarter of 2017, the IPUC and OPUC each approved settlement stipulations related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025, which increased retail revenues collections and retail revenues accruals for 2017 compared with 2016. Colder winter temperatures in early 2017 and warmer summer temperatures during the third quarter of 2017 resulted in residential sales making up a larger portion of the sales mix and led to a greater proportion of residential sales in higher rate categories in Idaho Power's tiered rate structure in 2017 compared with 2016. • Customers: Customer growth of 2.0 percent increased retail revenues by $12.1 million in 2017 compared with 2016. • Usage: Higher usage (on a per customer basis), primarily by residential, industrial, and commercial customers increased retail revenues by $20.1 million in 2017 compared with 2016. Increased usage was primarily the result of warmer summer temperatures and colder winter temperatures in Idaho Power's service area, which increased usage by residential customers for cooling and heating. Cooling degree days and heating degree days were significantly higher in 2017 compared with 2016. These increases in usage were partially offset by an 11 percent decrease in usage per irrigation customer due to increased precipitation in Idaho Power's service area during 2017 compared with 2016, 42 particularly in the first six months of 2017. Greater customer participation in energy efficiency programs, resulting in decreased usage, partially offset the increase in total usage during 2017 compared with 2016. • Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Higher usage (on a per customer basis) by residential and small general service customers during 2017 decreased the amount of FCA revenue accrued by $12.1 million compared with 2016. Idaho Power accrued $18.2 million of FCA revenue in 2017 compared with $30.3 million of FCA revenue in 2016. Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the Western EIM, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last three years (in thousands, except for MWh amounts). Year Ended December 31, 2017 2018 2016 Wholesale energy revenues Wholesale MWh sold Wholesale energy revenues per MWh $ $ 52,845 2,246 23.53 $ $ 24,790 1,934 12.82 $ $ 11,900 742 16.04 Wholesale Energy Sales - 2018 Compared with 2017: In 2018, wholesale energy revenue increased by $28.1 million, or 113 percent, compared with 2017. Wholesale energy sales volumes increased 16 percent in 2018 compared with 2017, and the average price of wholesale energy sales was 84 percent higher for 2018 compared with 2017. During the fourth quarter of 2018, a natural gas pipeline ruptured in British Columbia, Canada, disrupting natural gas flows to the Pacific Northwest and Western Canada, driving up energy and natural gas prices in the region, including in Idaho Power's service area. An increase in purchased power, both in market purchases and in purchases under PURPA contracts, resulted in additional energy available for wholesale energy sales in 2018 compared with 2017. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power in the wholesale energy markets. The increase in wholesale energy sales volumes and sales prices during 2018 compared with 2017 was also due to transactions in the Western EIM, which commenced in April 2018. Under the Western EIM, participating parties enable their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. Wholesale Energy Sales - 2017 Compared with 2016: For 2017, wholesale energy sales revenue increased by $12.9 million, or 108 percent compared with 2016 as generation from Idaho Power's hydroelectric plants increased due to significantly greater precipitation in 2017 compared with 2016. The increase in hydroelectric generation resulted in more energy available for wholesale energy sales in 2017 compared with 2016. The average price of wholesale energy sales was 20 percent lower for 2017 compared with 2016, as an increase in output from hydroelectric resources in the northwest United States region due to increased precipitation during the period, as well as additional output from new wind and solar projects throughout the region, increased surplus power available for sale and decreased wholesale power market prices. Transmission Wheeling Revenues: Revenue from transmission wheeling increased $15.1 million, or 34 percent, in 2018 compared with 2017, largely due to Idaho Power's OATT rate that increased in October 2017 and, to a lesser extent, an increase in wheeling volumes. In October 2017, Idaho Power's OATT rate increased from $25.52 per kW-year to $34.90 per kW-year. In October 2018, the rate decreased to $31.25 per kW-year. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate. Revenue from transmission wheeling increased $11.5 million, or 35 percent, in 2017 compared with 2016, largely due to an increase in wheeling volumes, an increase in Idaho Power's OATT rate, and a new long-term wheeling agreement that became effective in July 2016. Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. The cumulative variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2018, Idaho Power's energy efficiency rider balances were a $5.3 million regulatory liability in the Idaho jurisdiction and a $1.4 million regulatory asset in the Oregon jurisdiction. 43 Operating Expenses Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last three years (in thousands, except for MWh amounts). Expense PURPA contracts Other purchased power (including wheeling) Total purchased power expense MWh purchased PURPA contracts Other purchased power Total MWh purchased Cost per MWh from PURPA contracts Cost per MWh from other sources Weighted average - all sources Year Ended December 31, 2017 2016 2018 $ $ 189,722 104,092 293,814 $ $ 169,788 79,162 248,950 $ $ 153,665 92,099 245,764 3,045 2,386 5,431 62.31 $ 43.63 $ 54.10 $ 2,800 1,442 4,242 60.64 $ 54.90 $ 58.69 $ 2,314 2,023 4,337 66.41 45.53 56.67 $ $ $ Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. The other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms. Purchased Power - 2018 Compared with 2017: Purchased power expense increased $44.9 million, or 18 percent, in 2018 compared with 2017, primarily due to a 65 percent increase in the volume of other non-PURPA power purchases and a 9 percent increase in the volume of power purchases from generation projects under PURPA contracts. Other purchased power volumes increased during 2018 compared with 2017 due to wholesale gas and electricity market conditions and due to transactions in the Western EIM, which commenced in April 2018. These volume increases were partially offset by decreases in cost per MWh of power purchased from sources other than PURPA contracts. Purchased Power - 2017 Compared with 2016: Purchased power expense increased $3.2 million, or 1 percent, in 2017 compared with 2016, primarily due to an increase in generation provided by PURPA solar contracts. The increase in PURPA volumes was partially offset by decreases in costs per MWh. Other purchased power expense decreased $12.9 million, or 14 percent, as abundant hydroelectric generation in 2017 compared with 2016 reduced the need for market purchases to meet load requirements. 44 Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last three years (in thousands, except per MWh amounts). Year Ended December 31, 2017 2018 2016 Expense Coal Natural gas(1) Total fuel expense MWh generated Coal Natural gas(1) Total MWh generated Cost per MWh - Coal Cost per MWh - Natural gas Weighted average, all sources $ $ $ $ $ 115,524 17,674 133,198 3,274 1,408 4,682 35.29 12.55 28.45 $ $ $ $ $ 107,894 37,935 145,829 3,284 1,504 4,788 32.85 25.22 30.46 $ $ $ $ $ 137,689 41,802 179,491 4,045 1,722 5,767 34.04 24.28 31.12 (1) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant. The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirds of the coal used by the Jim Bridger plant. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods. Fuel Expense - 2018 Compared with 2017: Fuel expense decreased $12.6 million, or 9 percent, in 2018 compared with 2017. In October 2018, a natural gas pipeline ruptured in British Columbia, Canada, which disrupted natural gas distribution to the Pacific Northwest region and Western Canada, and drove up energy prices in the region. In accordance with its ongoing risk management policies, Idaho Power held a number of financial gas hedges at the time of the rupture. Fuel expense in the fourth quarter of 2018 included $23.3 million in gains on financial gas hedges, which reduced natural gas fuel expense. Idaho Power was able to meet natural gas needs by purchasing physical gas from sources unaffected by the rupture. Most of these realized hedging gains will be a benefit to customers through the power cost adjustment mechanisms described below. Fuel Expense - 2017 Compared with 2016: Fuel expense decreased $33.7 million, or 19 percent, in 2017 compared with 2016, due primarily to increased output from Idaho Power's hydroelectric plants, which reduced utilization of gas and coal generation. Generation from the hydroelectric plants increased 39 percent during 2017 compared with 2016. Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year. 45 The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last three years (in thousands). Year Ended December 31, 2017 2018 2016 Power supply cost accrual (deferral) Amortization of prior year authorized balances Total power cost adjustment expense $ $ 41,535 571 42,106 $ $ 14,658 37,366 52,024 $ $ (43,841) 38,511 (5,330) The power supply accruals represent the portion of the power supply cost fluctuations accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, which was the case for 2018 and 2017, most of the difference is accrued. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, which was the case for 2016, most of the difference is deferred. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism). Power Cost Adjustment Mechanisms - 2018 Compared with 2017: Actual net power supply costs decreased in 2018 relative to forecasted costs, resulting in a change of $26.9 million—from accruals of $14.7 million to accruals of $41.5 million. The increase in accruals is due in part to lower natural gas fuel costs and purchased power, as explained above, combined with more surplus sales than forecasted. In addition, Idaho Power recorded $0.6 million of amortization of the prior-year authorized balances in 2018, compared with $37.4 million of amortization in 2017. Power Cost Adjustment Mechanisms - 2017 Compared with 2016: Actual net power supply costs decreased in 2017 relative to forecasted costs, resulting in a change of $58.5 million—from deferrals of $43.8 million to accruals of $14.7 million. The change from deferrals in 2016 to accruals in 2017 is due in part to the lower fuel costs and purchased power, combined with more surplus sales than forecasted. The $37.4 million of amortization of prior year authorized balances in 2017 offsets the collection from customers of prior years' deferrals. Other Operations and Maintenance Expenses: The changes in other O&M expenses for the periods presented are discussed below. O&M - 2018 Compared with 2017: Other O&M expenses increased $17.8 million, or 5 percent, in 2018 compared with 2017. As provided by the settlement stipulation approved by the IPUC related to recent income tax reform, other O&M expenses in 2018 also included $4.0 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers. In 2018, compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses. O&M - 2017 Compared with 2016: Other O&M expense decreased by $2.2 million in 2017 compared with 2016, primarily due to a $2.4 million decrease related to previously expensed energy efficiency rider-funded costs deemed to be prudently incurred and a $2.7 million decrease in thermal O&M expenses due to lower generation at thermal plants. These decreases in O&M were partially offset by a $2.5 million increase in O&M related to a settlement stipulation in Idaho that established the reasonableness of the HCC relicensing costs incurred through December 2015 as further discussed in "Regulatory Matters" in this MD&A. Income 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 46 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, 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: Debt Equity IDACORP Idaho Power 46% 54% 44% 56% 47 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; 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, 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; 48 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 Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non- utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2018, 2017, and 2016: • • • • • • • 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 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. 49 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 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 $2.5 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. 50 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. 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 Revolving credit facility Commercial paper outstanding Identified for other use(1) Net balance available (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 $ $ Idaho Power 300,000 $ — (24,245) 275,755 IDACORP(2) 100,000 $ — — 100,000 IDACORP(2) 100,000 $ — — 100,000 $ Idaho Power 300,000 $ - (24,245) 275,755 $ provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties. (2) Holding company only. 51 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 Weighted average interest rate during the year Maximum month-end balance (1) Holding company only. $ $ $ — $ —% — $ —% — $ — $ —% — $ —% — $ — $ —% 588 1.42% 2,425 $ $ — —% 839 1.12% — 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’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors Service and Standard & Poor’s Ratings Services as of the date of this report: Moody's Investors Service: Rating Outlook Long-Term Issuer Rating First Mortgage Bonds Senior Secured Debt Commercial Paper Standard & Poor's Rating Services: Corporate Credit Rating Rating Outlook Short-Term Rating Senior Secured Debt IDACORP Idaho Power Stable Baa1 None None P-2 BBB Stable A-2 None Stable A3 A1 A1 P-2 BBB Stable A-2 A- These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2018, 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. 52 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. Expected capital expenditures (excluding AFUDC) 2019 280-290 2020 $ 285-300 2021-2023 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. 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. 53 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 54 possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants. Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2017. 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 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. 55 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: Total 2019 2022-2023 Thereafter Payments Due by Period 2020-2021 (millions of dollars) Long-term debt(1) Future interest payments(2) Purchase obligations: Maintenance and service agreements(3) FERC and other industry-related fees(3) Cogeneration and small power production Fuel supply agreements Other(3)(4) Pension and postretirement benefit plans(5) Other long-term liabilities - IDACORP only(3) Total $ $ 1,855 1,565 — $ 85 131 128 4,042 201 51 326 2 8,301 $ $ 34 14 239 43 3 11 — 429 $ 100 166 26 25 490 57 8 110 — 982 $ $ $ 150 159 16 25 508 17 8 153 — 1,036 $ 1,605 1,155 55 64 2,805 84 32 52 2 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. 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. 56 Contingencies and Proceedings IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows. Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant. Off-Balance Sheet Arrangements Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $58.4 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. 57 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 May 2018 Idaho Tax Reform Settlement Stipulation - Idaho base rates May 2018 Idaho Tax Reform Settlement Stipulation - Idaho PCA(2) 2018 Idaho PCA 2018 Idaho FCA Oregon Tax Reform Settlement Stipulation Oregon Valmy Plant Accelerated Depreciation Settlement Stipulation Oregon Valmy Plant Settlement Stipulation Idaho Valmy Plant Settlement Stipulation 2017 Idaho PCA(3) 2017 Idaho FCA 2016 Idaho PCA(4) 2016 Idaho FCA Effective Date Estimated Annualized Rate Impact (millions)(1) 6/1/2018 6/1/2018 6/1/2018 6/1/2018 6/1/2018 6/1/2018 7/1/2017 6/1/2017 6/1/2017 6/1/2017 6/1/2016 6/1/2016 $ (19) (8) (23) (19) (1) 2 1 13 11 7 17 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 Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011. In the general rate case, the IPUC issued an order approving a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity. Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho- jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. In September 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates. In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the PCA mechanism and instead results in collecting that portion through base rates. 58 Valmy Base Rate Adjustment Settlement Stipulations In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the Valmy Plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017 in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 Oregon Income Tax Reform Settlement Stipulation described below, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. Other Notable Regulatory Matters December 2011 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 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. Under the December 2011 Idaho 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. 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. 59 Idaho Power recorded the following for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations (in millions): Recorded as Refunds to Customers 5.0 — — 3.2 8.0 7.6 7.2 Year 2018 2017 2016 2015 2014 2013 2012 2011(1) Total $ $ 27.1 58.1 $ Total Recorded as a Pre-tax Charge to Pension Expense $ — $ — — — 16.7 16.5 14.6 20.3 68.1 $ 5.0 — — 3.2 24.7 24.1 21.8 47.4 126.2 (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 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. 60 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 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. 61 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 Current period net power supply costs accrued Energy efficiency rider funds transferred to Idaho PCA mechanism Prior amounts recovered through rates Sulfur Dioxide (SO2) allowance and renewable energy certificate (REC) sales Interest and other Balance at December 31, 2017 Current period net power supply costs accrued Tax reform revenue accrual to be refunded through Idaho PCA, net of amounts refunded Western EIM cost recovery to be collected through Idaho PCA Prior amounts refunded through rates SO2 allowance and REC sales Interest and other Balance at December 31, 2018 $ $ $ 53.5 (14.7) (13.0) (26.1) (2.1) 0.2 (2.2) (41.5) (1.9) 2.2 4.2 (2.6) (0.3) (42.1) $ $ 0.4 — — (0.5) (0.1) 0.1 (0.1) — — — — (0.1) — (0.2) $ 53.9 (14.7) (13.0) (26.6) (2.2) 0.3 (2.3) (41.5) (1.9) 2.2 4.2 (2.7) (0.3) (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. 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 62 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 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. 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 63 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. 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. 64 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 PURPA: Wind Solar Hydroelectric Other Total PURPA Non-PURPA: Wind Geothermal Total non-PURPA Total On-line (MW) Under Contract but not yet On-line (MW) Total Projects under Contract (MW) 627 290 146 56 1,119 101 35 136 — 27 2 — 29 — — — 627 317 148 56 1,148 101 35 136 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. 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 65 (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 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. 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. 66 Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statements across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction. In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests. In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In December 2018, the BLM issued draft resource management plan amendments and a final environmental impact statements to modify the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits. ESA Issues Related to Specific Projects: Hells Canyon Relicensing Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has yet to be initiated and the NMFS and the USFWS continue to gather and consider information relative to the effects of relicensing on relevant ESA listed species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during 2019 is unlikely. Boardman-to-Hemingway and Gateway West Transmission Projects: In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass. Most of the species are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed routes for the Boardman-to-Hemingway and Gateway West transmission line projects to continue to impact the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation. The USFWS has also indicated it intends to designate critical habitat for the species. If critical habitat is designated within the vicinity of the transmission line projects, Idaho Power expects that the designation could increase the cost of obtaining permits for the projects and could further delay the in-service date of the projects. 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 67 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 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 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 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, 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 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 68 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. State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO2 equivalent annually. The Boardman coal-fired power plant located in Oregon, in which Idaho Power is a 10-percent owner, is subject to and in compliance with Oregon's GHG reporting requirements but is scheduled to cease coal-fired operations in 2020. In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, and requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base. The State of Idaho has not passed legislation specifically regulating GHGs. Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry, a national, voluntary GHG emission 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 results. National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, NO2, and SO2. States are then required to develop emission 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 69 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. 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. As of the date of this report and based on the EPA designations described above, Idaho Power does not expect these standards to significantly impact its operations or materially increase Idaho Power’s capital and operating costs. Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units at the Jim Bridger and the Boardman coal-fired plants. The RH BART rules would have required installation of a suite of emissions controls at the Boardman plant; however, in December 2010, the Oregon Environmental Quality Commission approved a plan to install a less costly suite of environmental controls and cease coal-fired operations at the Boardman power plant no later than December 31, 2020. In December 2009, the WDEQ issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install SCR equipment for nitrogen oxide (NOx) control at Jim Bridger units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017 to install add-on NOx controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, 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 NOx 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 70 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. Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate- making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.2 billion of regulatory assets and $0.8 billion of regulatory liabilities at December 31, 2018. 71 Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations. Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters. Income Taxes IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax- related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities. Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are recorded for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting. Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes. Pension and Other Postretirement Benefits Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, and two unfunded nonqualified deferred compensation plan for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits). The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates. The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2018, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2019 pension expense will be increased to 4.55 percent from the 3.95 percent used in 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 2019 pension expense will be 7.5 percent, the same assumption as was used for 2018. 72 Gross net periodic pension and other postretirement benefit cost for these plans totaled $51.2 million, $50.4 million, and $51.8 million for the years ended December 31, 2018, 2017, and 2016, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2019, gross pension and other postretirement benefit costs are expected to total approximately $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 2019 2018 2019 (millions of dollars) 2018 Effect of 0.5% rate increase on net periodic benefit cost Effect of 0.5% rate decrease on net periodic benefit cost $ (7.0) $ 7.8 (7.9) $ 8.8 (3.5) $ 3.4 (3.7) 3.6 Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $76.2 million decrease in the combined benefit obligations of the plans as of December 31, 2018. A 0.5 percent decrease in the plans' discount rates would have resulted in an $85.7 million increase in the combined benefit obligations of the plans as of December 31, 2018. The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2018, a total of $148 million of expense was deferred as a regulatory asset. Approximately $23 million is expected to be deferred in 2019. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million in 2018, 2017, and 2016. Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS For a listing of new and recently adopted accounting standards, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the consolidated financial statements included in this report. 73 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, 2018. IDACORP and Idaho Power have not entered into any of these market-risk-sensitive instruments for trading purposes. Interest Rate Risk IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination. Variable Rate Debt: As of December 31, 2018, IDACORP and Idaho Power had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt. Fixed Rate Debt: As of December 31, 2018, both IDACORP and Idaho Power had $1.8 billion in fixed rate debt, with a fair market value of approximately $1.9 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $276.8 million if market interest rates were to decline by one percentage point from their December 31, 2018, levels. Commodity Price Risk IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These effects of changes in commodity prices on Idaho Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk. A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy (Policy) and associated standards implementing the Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprises selected Idaho Power officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho Power Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non- retail purposes. The Policy and associated standards require monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The power supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, and orders 74 risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by the power supply unit for consistency and compliance with the Policy and associated standards. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval. Credit Risk IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits. The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2018, Idaho Power had no performance assurance collateral posted related to these contracts. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, 2018, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $10.5 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis. Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly. Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations. Equity Price Risk IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 12 - "Benefit Plans" to the consolidated financial statements included in this report. 75 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Financial Statements and Financial Statement Schedules Consolidated Financial Statements IDACORP, Inc.: Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Equity Idaho Power Company: Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Notes to the Consolidated Financial Statements Reports of Independent Registered Public Accounting Firm Supplemental Financial Information and Financial Statement Schedules Supplemental Financial Information (unaudited) Financial Statement Schedules: IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant IDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying Accounts Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts Page 77 78 79 81 82 83 84 85 87 88 89 130 132 146 148 149 All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included. 76 IDACORP, Inc. Consolidated Statements of Income Year Ended December 31, 2017 (thousands of dollars except for per share amounts) 2016 2018 Operating Revenues: Electric utility revenues Other Total operating revenues Operating Expenses: Electric utility: Purchased power Fuel expense Power cost adjustment Other operations and maintenance Energy efficiency programs Depreciation Taxes other than income taxes Total electric utility expenses Other Total operating expenses Operating Income Allowance for Equity Funds Used During Construction Earnings of Unconsolidated Equity-Method Investments Other Expense, Net Interest Expense: Interest on long-term debt Other interest Allowance for borrowed funds used during construction Total interest expense, net Income Before Income Taxes Income Tax Expense Net Income Adjustment for (income) loss attributable to noncontrolling interests Net Income Attributable to IDACORP, Inc. Weighted Average Common Shares Outstanding - Basic (000’s) Weighted Average Common Shares Outstanding - Diluted (000’s) Earnings Per Share of Common Stock: Earnings Attributable to IDACORP, Inc. - Basic Earnings Attributable to IDACORP, Inc. - Diluted $ $ 1,366,582 4,170 1,370,752 $ 1,344,893 4,593 1,349,486 1,259,353 2,667 1,262,020 293,814 133,198 42,106 364,456 35,703 165,190 34,792 1,069,259 4,571 1,073,830 296,922 24,353 12,449 (2,867) 84,408 11,691 (10,151) 85,948 244,909 17,386 227,523 (722) 248,950 145,829 52,024 346,695 39,241 162,091 34,089 1,028,919 5,022 1,033,941 315,545 20,784 11,374 (2,109) 81,198 11,242 (8,694) 83,746 261,848 48,660 213,188 (769) $ $ $ 226,801 $ 212,419 $ 50,432 50,510 50,361 50,424 4.50 4.49 $ $ 4.22 4.21 $ $ 245,764 179,491 (5,330) 349,290 33,754 143,661 32,823 979,453 (1,015) 978,438 283,582 22,031 12,871 (1,932) 81,956 10,273 (10,194) 82,035 234,517 36,429 198,088 200 198,288 50,298 50,373 3.94 3.94 The accompanying notes are an integral part of these statements. 77 IDACORP, Inc. Consolidated Statements of Comprehensive Income Year Ended December 31, 2017 2016 2018 Net Income Other Comprehensive Income: Unfunded pension liability adjustment, net of tax of $2,815, $(1,555), and $253 Total Comprehensive Income Comprehensive (income) loss attributable to noncontrolling interests Comprehensive Income Attributable to IDACORP, Inc. (thousands of dollars) $ 227,523 $ 213,188 $ 198,088 8,120 235,643 (722) 234,921 $ (5,990) 207,198 (769) 206,429 394 198,482 200 $ 198,682 $ The accompanying notes are an integral part of these statements. 78 IDACORP, Inc. Consolidated Balance Sheets Assets Current Assets: Cash and cash equivalents Receivables: Customer (net of allowance of $1,725 and $2,013, respectively) Other (net of allowance of $264 and $180, respectively) Income taxes receivable Accrued unbilled revenues Materials and supplies (at average cost) Fuel stock (at average cost) Prepayments Current regulatory assets Other Total current assets December 31, 2018 2017 (in thousands) $ 267,492 $ 76,649 77,178 7,476 4,356 69,318 54,987 47,979 16,492 48,707 3,655 597,640 75,249 30,438 8,147 75,120 55,745 56,638 16,984 48,613 18 443,601 Investments 101,178 115,698 Property, Plant and Equipment: Utility plant in service Accumulated provision for depreciation Utility plant in service - net Construction work in progress Utility plant held for future use Other property, net of accumulated depreciation Property, plant and equipment - net Other Assets: Company-owned life insurance Regulatory assets Other Total other assets Total 6,103,856 (2,210,781) 3,893,075 480,259 4,751 17,650 4,395,735 5,906,162 (2,098,274) 3,807,888 452,424 8,075 15,488 4,283,875 59,852 1,165,467 62,882 1,288,201 59,323 1,083,483 59,425 1,202,231 $ 6,382,754 $ 6,045,405 The accompanying notes are an integral part of these statements. 79 IDACORP, Inc. Consolidated Balance Sheets Liabilities and Equity Current Liabilities: Accounts payable Taxes accrued Interest accrued Accrued compensation Current regulatory liabilities Advances from customers Other Total current liabilities Other Liabilities: Deferred income taxes Regulatory liabilities Pension and other postretirement benefits Other Total other liabilities December 31, 2018 2017 (in thousands) $ $ 110,824 12,009 23,622 55,121 25,883 20,037 11,096 258,592 699,878 738,994 431,475 43,216 1,913,563 90,277 11,075 22,379 47,018 1,404 18,414 10,182 200,749 660,940 698,044 438,869 44,566 1,842,419 Long-Term Debt 1,834,788 1,746,123 Commitments and Contingencies Equity: IDACORP, Inc. shareholders’ equity: Common stock, no par value (120,000 shares authorized; shares issued 50,420) Retained earnings Accumulated other comprehensive loss Treasury stock (27 and 28 shares at cost, respectively) Total IDACORP, Inc. shareholders’ equity Noncontrolling interests Total equity Total 863,593 1,531,543 (22,844) (1,932) 2,370,360 5,451 2,375,811 857,207 1,426,528 (30,964) (1,386) 2,251,385 4,729 2,256,114 $ 6,382,754 $ 6,045,405 The accompanying notes are an integral part of these statements. 80 IDACORP, Inc. Consolidated Statements of Cash Flows Operating Activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization Deferred income taxes and investment tax credits Changes in regulatory assets and liabilities Pension and postretirement benefit plan expense Contributions to pension and postretirement benefit plans Earnings of unconsolidated equity-method investments Distributions from unconsolidated equity-method investments Allowance for equity funds used during construction Gain on sale of investments and assets Other non-cash adjustments to net income, net Change in: Accounts receivable Accounts payable and other accrued liabilities Taxes accrued/receivable Other current assets Other current liabilities Other assets Other liabilities Net cash provided by operating activities Investing Activities: Additions to property, plant and equipment Payments received from transmission project joint funding partners Purchase of available-for-sale securities Proceeds from sale of available-for-sale securities Purchase of life insurance investment Other Net cash used in investing activities Financing Activities: Issuance of long-term debt Retirement of long-term debt Dividends on common stock Net change in short-term borrowings Acquisition of treasury stock Make-whole premium on retirement of long-term debt Other Net cash used in financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of the year Cash and cash equivalents at end of the year Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Income taxes Interest (net of amount capitalized) Non-cash investing activities: Additions to property, plant and equipment in accounts payable 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 $ 227,523 $ 213,188 $ 198,088 169,120 11,292 48,392 32,256 (45,899) (12,449) 31,115 (24,353) (155) 9,152 729 29,666 4,725 12,707 6,848 (7,488) (1,555) 491,626 (277,853) 21,587 (11,390) 5,007 — 4,472 (258,177) 220,000 (130,000) (121,421) — (3,614) (4,607) (2,964) (42,606) 190,843 76,649 267,492 5,272 80,951 29,528 $ $ $ $ 165,933 33,245 57,131 28,911 (46,589) (11,374) 24,975 (20,784) (131) 8,454 1,045 (17,208) 4,361 2,814 1,017 (8,734) (1,093) 435,161 (285,488) 6,074 (11,356) 4,989 — 5,340 (280,441) — (1,064) (113,127) (21,800) (3,212) — (348) (139,551) 15,169 61,480 76,649 14,742 80,004 33,220 $ $ $ $ 147,294 35,732 (5,650) 29,581 (45,301) (12,871) 25,641 (22,031) (103) 5,108 (6,315) 13,300 662 (10,887) (3,283) (3,764) (1,006) 344,195 (296,950) 7,586 (14,917) 15,693 (10,000) 4,655 (293,933) 120,000 (101,064) (104,984) 1,800 (3,329) (13,895) (2,112) (103,584) (53,322) 114,802 61,480 3,302 78,334 34,603 $ $ $ $ The accompanying notes are an integral part of these statements. 81 IDACORP, Inc. Consolidated Statements of Equity 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 Common Stock: Balance at beginning of year Cumulative effect of change in accounting principle Share-based compensation expense Treasury shares issued Other Balance at end of year Retained Earnings: Balance at beginning of year Cumulative effect of change in accounting principle Net income attributable to IDACORP, Inc. Common stock dividends ($2.40, $2.24, and $2.08 per share, respectively) Balance at end of year Accumulated Other Comprehensive (Loss) Income: Balance at beginning of year Cumulative effect of change in accounting principle Unfunded pension liability adjustment (net of tax) Balance at end of year Treasury Stock: Balance at beginning of year Issued Acquired Balance at end of year $ $ 857,207 — 9,362 (3,068) 92 863,593 $ 851,833 — 7,384 (2,069) 59 857,207 849,112 234 5,561 (3,143) 69 851,833 1,426,528 — 226,801 (121,786) 1,531,543 1,323,198 4,092 212,419 (113,181) 1,426,528 1,230,105 (234) 198,288 (104,961) 1,323,198 (30,964) — 8,120 (22,844) (1,386) 3,068 (3,614) (1,932) (20,882) (4,092) (5,990) (30,964) (243) 2,069 (3,212) (1,386) (21,276) — 394 (20,882) (57) 3,143 (3,329) (243) Total IDACORP, Inc. shareholders’ equity at end of year 2,370,360 2,251,385 2,153,906 Noncontrolling Interests: Balance at beginning of year Net income (loss) attributable to noncontrolling interests Balance at end of year 4,729 722 5,451 3,960 769 4,729 4,160 (200) 3,960 Total equity at end of year $ 2,375,811 $ 2,256,114 $ 2,157,866 The accompanying notes are an integral part of these statements. 82 Idaho Power Company Consolidated Statements of Income 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 Operating Revenues Operating Expenses: Operation: Purchased power Fuel expense Power cost adjustment Other operations and maintenance Energy efficiency programs Depreciation Taxes other than income taxes Total operating expenses Income from Operations Other Income (Expense): Allowance for equity funds used during construction Earnings of unconsolidated equity-method investments Other expense, net Total other income Interest Charges: Interest on long-term debt Other interest Allowance for borrowed funds used during construction Total interest charges $ 1,366,582 $ 1,344,893 $ 1,259,353 293,814 133,198 42,106 364,456 35,703 165,190 34,792 248,950 145,829 52,024 346,695 39,241 162,091 34,089 1,069,259 1,028,919 245,764 179,491 (5,330) 349,290 33,754 143,661 32,823 979,453 297,323 315,974 279,900 24,353 10,712 (5,851) 29,214 84,408 11,634 (10,151) 85,891 20,784 9,267 (4,756) 25,295 81,198 11,156 (8,694) 83,660 22,031 10,855 (4,547) 28,339 81,956 10,050 (10,194) 81,812 Income Before Income Taxes 240,646 257,609 226,427 Income Tax Expense Net Income 18,312 51,262 37,185 $ 222,334 $ 206,347 $ 189,242 The accompanying notes are an integral part of these statements. 83 Idaho Power Company Consolidated Statements of Comprehensive Income 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 Net Income Other Comprehensive Income: Unfunded pension liability adjustment, net of tax of $2,815, $(1,555), and $253 Total Comprehensive Income $ 222,334 $ 206,347 $ 189,242 8,120 230,454 $ (5,990) 200,357 $ 394 189,636 $ The accompanying notes are an integral part of these statements. 84 Idaho Power Company Consolidated Balance Sheets December 31, 2018 2017 (in thousands) $ $ 6,103,856 (2,210,781) 3,893,075 480,259 4,751 4,378,085 5,906,162 (2,098,274) 3,807,888 452,424 8,075 4,268,387 Assets Electric Plant: In service (at original cost) Accumulated provision for depreciation In service - net Construction work in progress Held for future use Electric plant - net Investments and Other Property 90,019 99,904 Current Assets: Cash and cash equivalents Receivables: Customer (net of allowance of $1,725 and $2,013, respectively) Other (net of allowance of $264 and $180, respectively) Income taxes receivable Accrued unbilled revenues Materials and supplies (at average cost) Fuel stock (at average cost) Prepayments Current regulatory assets Other Total current assets Deferred Debits: Company-owned life insurance Regulatory assets Other Total deferred debits Total 165,460 44,646 77,178 7,206 11,829 69,318 54,987 47,979 16,374 48,707 3,655 502,693 75,249 30,274 26,492 75,120 55,745 56,638 16,866 48,613 18 429,661 59,852 1,165,467 58,284 1,283,603 59,323 1,083,483 54,677 1,197,483 $ 6,254,400 $ 5,995,435 The accompanying notes are an integral part of these statements. 85 Idaho Power Company Consolidated Balance Sheets Capitalization and Liabilities Capitalization: Common stock equity: Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding) $ Premium on capital stock Capital stock expense Retained earnings Accumulated other comprehensive loss Total common stock equity Long-term debt Total capitalization Current Liabilities: Accounts payable Accounts payable to affiliates Taxes accrued Interest accrued Accrued compensation Current regulatory liabilities Advances from customers Other Total current liabilities Deferred Credits: Deferred income taxes Regulatory liabilities Pension and other postretirement benefits Other Total deferred credits Commitments and Contingencies December 31, 2018 2017 (in thousands) $ 97,877 712,258 (2,097) 1,409,245 (22,844) 2,194,439 1,834,788 4,029,227 97,877 712,258 (2,097) 1,308,702 (30,964) 2,085,776 1,746,123 3,831,899 110,597 2,088 11,750 23,622 54,910 25,883 20,037 10,198 259,085 89,978 57,562 10,904 22,379 46,832 1,404 18,414 9,556 257,029 753,239 738,994 431,475 42,380 1,966,088 725,942 698,044 438,869 43,652 1,906,507 Total $ 6,254,400 $ 5,995,435 The accompanying notes are an integral part of these statements. 86 Idaho Power Company Consolidated Statements of Cash Flows Operating Activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization Deferred income taxes and investment tax credits Changes in regulatory assets and liabilities Pension and postretirement benefit plan expense Contributions to pension and postretirement benefit plans Earnings of unconsolidated equity-method investments Distributions from unconsolidated equity-method investments Allowance for equity funds used during construction Gain on sale of investments and assets Other non-cash adjustments to net income, net Change in: Accounts receivable Accounts payable Taxes accrued/receivable Other current assets Other current liabilities Other assets Other liabilities Net cash provided by operating activities Investing Activities: Additions to utility plant Payments received from transmission project joint funding partners Purchase of available-for-sale securities Proceeds from the sale of available-for-sale securities Purchase of life insurance investment Other Net cash used in investing activities Financing Activities: Issuance of long-term debt Retirement of long-term debt Dividends on common stock Net change in short term borrowings Make-whole premium on retirement of long-term debt Other Net cash used in financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of the year Cash and cash equivalents at end of the year Supplemental Disclosure of Cash Flow Information: Cash paid to IDACORP related to income taxes Cash paid for interest (net of amount capitalized) Non-cash investing activities: Additions to property, plant and equipment in accounts payable Year Ended December 31, 2018 2017 2016 (thousands of dollars) $ 222,334 $ 206,347 $ 189,242 168,519 (2,272) 48,392 32,240 (45,883) (10,712) 29,400 (24,353) (155) (210) 633 (25,532) 15,509 12,707 6,822 (7,488) (1,476) 418,475 (277,823) 21,587 (11,390) 5,007 — 4,320 (258,299) 220,000 (130,000) (121,791) — (4,607) (2,964) (39,362) 120,814 44,646 165,460 63,914 80,894 29,528 $ $ $ $ 165,337 (10,875) 57,131 28,894 (46,573) (9,267) 23,000 (20,784) (131) 1,069 (5,282) 38,111 (3,601) 2,812 996 (8,734) (967) 417,483 (285,471) 6,074 (11,356) 4,989 — 5,176 (280,588) — (1,064) (113,284) (21,800) — (241) (136,389) 506 44,140 44,646 12,444 79,918 33,220 $ $ $ $ 146,694 25,780 (5,651) 29,597 (45,317) (10,855) 23,716 (22,031) (103) (454) (54) 13,308 (17,299) (10,902) (3,322) (3,764) (829) 307,756 (296,948) 7,586 (14,917) 15,693 (10,000) 4,511 (294,075) 120,000 (101,064) (105,121) 21,800 (13,895) (2,017) (80,297) (66,616) 110,756 44,140 29,341 78,111 34,603 $ $ $ $ The accompanying notes are an integral part of these statements. 87 Idaho Power Company Consolidated Statements of Retained Earnings 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 Retained Earnings, Beginning of Year Net Income Dividends on Common Stock Cumulative Effect of Change in Accounting Principle Retained Earnings, End of Year $ 1,308,702 $ 1,211,547 $ 1,127,426 222,334 (121,791) — 206,347 (113,284) 4,092 189,242 (105,121) — $ 1,409,245 $ 1,308,702 $ 1,211,547 The accompanying notes are an integral part of these statements. 88 IDACORP, INC. AND IDAHO POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to the Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations. Nature of Business IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other notable wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). Principles of Consolidation IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues and expenses of each company and its wholly-owned subsidiaries listed above, as well as any variable interest entities (VIEs) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting. IDACORP also consolidates one variable interest entity (VIE), Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2018, Marysville had approximately $18 million of assets, primarily a hydroelectric plant, and approximately $8 million of intercompany long- term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses. The BCC joint venture is also a VIE, but because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner, Idaho Power is not the primary beneficiary. The carrying value of BCC was $49.9 million at December 31, 2018, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $58.4 million guarantee for mine reclamation costs, which is discussed further in Note 10 - "Commitments." IFS's affordable housing limited partnership and other real estate investments are also VIEs for which IDACORP is not the primary beneficiary. IFS's limited partnership interests range from 4 to 99 percent and were acquired between 1996 and 2010. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $3.4 million at December 31, 2018. Ida-West's other investments in PURPA facilities, BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 15 - "Investments"). Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation. 89 The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly-owned plants (see Note 13 - "Property, Plant and Equipment and Jointly-Owned Projects"). Regulation of Utility Operations As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power’s operations are discussed in more detail in Note 3 - "Regulatory Matters." Management Estimates Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. Accordingly, actual results could differ from those estimates. System of Accounts The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming. Cash and Cash Equivalents Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition. Receivables and Allowance for Uncollectible Accounts Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent per month may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off. Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income. There were no impaired receivables without related allowances at December 31, 2018 and 2017. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved. 90 Derivative Financial Instruments Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities. Revenues On January 1, 2018, IDACORP and Idaho Power adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power. Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues." Property, Plant and Equipment and Depreciation The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment. All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.8 percent in 2018, 2.9 percent in 2017, and 2.6 percent in 2016. During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek recovery of such costs in customer rates, although there can be no guarantee such recovery would be granted. Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in 2018, 2017, or 2016. Allowance for Funds Used During Construction AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells Canyon Complex (HCC) relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power’s weighted-average monthly AFUDC rate was 7.6 percent for 2018, 2017 and 2016. Income Taxes IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. In general, deferred income tax expense or benefit 91 for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time. Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. IDACORP and Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax- related assets and liabilities. In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless accounted for using flow-through. The state of Idaho allows a three percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned. Income taxes are discussed in more detail in Note 2 - "Income Taxes." Other Accounting Policies Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issues. Losses on reacquired debt and associated costs are amortized over the life of the associated replacement debt, as allowed under regulatory accounting. Reclassifications In these consolidated financial statements, certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with current period presentation. On IDACORP's and Idaho Power's December 31, 2017, consolidated balance sheets, the "Long-term receivables" balances of $4.3 million and $0.5 million, respectively, which had previously been reported separately, were reclassified to "Other" within "Other Assets" and "Deferred Debits," respectively. New and Recently Adopted Accounting Pronouncements Recently Adopted Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. IDACORP and Idaho Power adopted ASU 2014-09 on January 1, 2018, using the modified-retrospective approach as provided for in the standard. The adoption did not change the timing or amounts of revenue currently recognized by the companies, so no cumulative-effect adjustment was required. The adoption did change presentation of revenues on the consolidated statements of income and also added disclosures. To conform with current period presentation, "Electric utility revenues" and "Operating Revenues" on 92 IDACORP's and Idaho Power's consolidated statements of income, respectively, for the year ended December 31, 2018 and 2017, which had previously been reported separately as "General business," "Off-system sales," and "Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of revenue and additional disclosures. In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which revises the accounting related to the classification and measurement of investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal years beginning after December 15, 2017, including interim periods. IDACORP and Idaho Power adopted ASU 2016-01 on January 1, 2018. The adoption did not have a material impact on the companies' financial statements as the companies previously elected the fair value option and reported available-for-sale securities at fair value. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments, to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The companies' classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will be classified as investing activities under the new guidance. The new guidance did not affect the companies' presentation of debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments. IDACORP and Idaho Power adopted ASU 2016-15 on January 1, 2018, using the retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $3.0 million and $3.6 million of company-owned life insurance proceeds received, for the year ended December 31, 2017 and 2016, respectively, from "Change in accounts receivable" and $0.1 million and $0.1 million of prepaid insurance premiums paid, for the year ended December 31, 2017 and 2016, respectively, from "Change in other assets" (net reclassification of $2.9 million and $3.5 million, respectively) within "Operating Activities" to "Other" within "Investing Activities" on the consolidated statement of cash flows. In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power adopted ASU 2017-07 on January 1, 2018, and accordingly, have retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit costs. The adoption did not have a material impact on the companies' financial statements nor did it affect net income for the year ended December 31, 2018. For IDACORP, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, were reclassified out of "Other operations and maintenance" and $8.2 million and $9.2 million, respectively, were reclassified out of "Other" operating expenses for a total of $11.2 million and $11.8 million, respectively, reclassified to "Other Expense, Net" to conform to current period presentation. For Idaho Power, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, was reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation. Recent Accounting Pronouncements Not Yet Adopted In August 2018, the FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. IDACORP and Idaho Power are evaluating the impact of ASU 2018-15 on their respective financial statements. 93 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing transactions. The ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases. In addition, the ASU revises the definition of a lease in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. ASU 2016-02 was effective on January 1, 2019, and IDACORP and Idaho Power will record any effects of the adoption in the first quarter of 2019. While IDACORP and Idaho Power are finalizing the assessment of the financial impacts of the adoption, the adoption of ASU 2016-02 will not have a material impact on their respective financial statements. 2. INCOME TAXES A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows: Federal income tax expense at statutory rate Change in taxes resulting from: AFUDC Capitalized interest Investment tax credits Removal costs Capitalized overhead costs Capitalized repair costs Bond redemption costs Remeasurement of deferred taxes State income taxes, net of federal benefit Depreciation Excess deferred income tax reversal Share-based compensation Income tax return adjustments Affordable housing tax credits Affordable housing investment distributions Affordable housing investment amortization Other, net Total income tax expense Effective tax rate IDACORP Idaho Power 2018 2017 2016 2018 2017 2016 $ 51,279 $ 91,378 (thousands of dollars) $ 50,536 $ 82,151 $ 90,163 $ 79,250 (7,246) 928 (2,929) (3,471) (6,720) (17,850) (1,029) (5,411) 8,512 13,110 (7,289) (894) (5,076) (2,560) (267) 1,519 2,780 $ 17,386 7.1% (10,318) 1,513 (3,081) (6,280) (11,200) (28,700) — 1,690 8,153 18,953 — (1,508) (3,710) (2,559) (1,124) 1,271 (5,818) $ 48,660 18.6% (11,278) 2,000 (2,922) (5,559) (10,500) (28,000) (4,997) — 5,071 18,673 — (1,614) (3,539) (2,579) (1,717) 1,380 (141) $ 36,429 15.5% (7,246) 928 (2,929) (3,471) (6,720) (17,850) (1,029) (5,664) 8,532 13,110 (7,289) (883) (4,968) — — (10,318) 1,513 (3,081) (6,280) (11,200) (28,700) — 1,970 8,108 18,953 — (1,483) (3,601) — — (11,278) 2,000 (2,922) (5,559) (10,500) (28,000) (4,997) — 4,880 18,673 — (1,583) (3,669) — — — 3,255 $ 18,312 7.6% — (4,782) $ 51,262 19.9% — 890 $ 37,185 16.4% 94 The items comprising income tax expense are as follows: Income taxes current: Federal State Total Income taxes deferred: Federal State Total Investment tax credits: Deferred Restored Total Affordable housing investments Total income tax expense IDACORP 2017 2018 2016 2018 (thousands of dollars) Idaho Power 2017 2016 $ 5,390 3,328 8,718 1,649 30 1,679 $ $ 11,726 5,418 17,144 1,181 2,158 3,339 $ 24,919 (2,049) 22,870 $ 51,575 10,562 62,137 $ 7,639 3,766 11,405 24,018 (154) 23,864 33,205 100 33,305 (15,388) 5,425 (9,963) (13,002) (5,298) (18,300) 27,506 (2,031) 25,475 8,334 (2,929) 5,405 1,584 $ 17,386 10,506 (3,081) 7,425 227 $ 48,660 3,227 (2,922) 305 (520) $ 36,429 8,334 (2,929) 5,405 — $ 18,312 10,506 (3,081) 7,425 — $ 51,262 3,227 (2,922) 305 — $ 37,185 The components of the net deferred tax liability are as follows: Deferred tax assets: Regulatory liabilities Deferred compensation Deferred revenue Tax credits Partnership investments Retirement benefits Other Total Deferred tax liabilities: Property, plant and equipment Regulatory assets Fixed cost adjustment Partnership investments Retirement benefits Other Total Net deferred tax liabilities IDACORP 2018 2017 2018 (thousands of dollars) Idaho Power 2017 $ $ 98,042 21,871 35,137 100,041 4,200 91,867 9,299 360,457 294,471 614,144 10,940 3,875 108,440 28,465 1,060,335 699,878 $ $ 98,744 21,066 31,086 109,673 3,540 94,493 8,636 367,238 306,002 584,329 8,016 5,182 103,407 21,242 1,028,178 660,940 $ $ 98,042 21,826 35,137 44,532 1,086 91,867 9,121 301,611 294,471 614,144 10,940 — 108,440 26,855 1,054,850 753,239 $ $ 98,744 21,025 31,086 44,106 — 94,493 8,435 297,889 306,002 584,329 8,016 980 103,407 21,097 1,023,831 725,942 IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the consolidated balance sheets of Idaho Power. See Note 1 - "Summary of Significant Accounting Policies" for further discussion of accounting policies related to income taxes. Tax Credit Carryforwards As of December 31, 2018, IDACORP had $60.5 million of general business credit carryforwards for federal income tax purposes and $39.5 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2027 to 2038, and the Idaho investment tax credit expires from 2023 to 2032. 95 Uncertain Tax Positions IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2018 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. The open tax years for examination are 2018 for federal and 2014-2018 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. In 2018, the IRS completed its examination of IDACORP's 2017 tax year with no unresolved income tax issues. Income Tax Reform In December 2017, the Tax Cuts and Jobs Act was signed into law, which significantly reforms the Internal Revenue Code of 1986, as amended. Effective January 1, 2018, the Tax Cuts and Jobs Act permanently lowers the corporate tax rate to 21 percent from the existing maximum rate of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense, eliminates the alternative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of executive compensation. Public utility companies, such as Idaho Power, retain the deductibility of interest expense and are excluded from the bonus depreciation provisions; however, traditional accelerated tax depreciation methods are still available. Due to the enactment of the Tax Cuts and Jobs Act and following generally accepted accounting principles, at December 31, 2017, IDACORP and Idaho Power remeasured all deferred income tax assets and liabilities. The effects of these adjustments resulted in a net tax expense for 2017, as shown in the rate reconciliation table above. Also, as shown above, in 2018, a net tax benefit was recognized for the remeasurement of deferred taxes for the adjustment of temporary differences as a result of IDACORP's 2017 consolidated income tax return filings. Additionally, in 2017, the net deferred tax liabilities at both companies decreased by approximately $672 million. Idaho Power's regulatory asset deferred income tax liability item decreased as the related regulatory asset was reduced in two primary ways: (1) the decrease in the federal income tax rate decreased the future cost to customers for funding the net deferred income tax liabilities resulting from the cumulative impacts of using the flow-through income tax accounting method for regulatory purposes and (2) the decrease in the federal income tax rate also reduced the net-to-gross multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in income tax law also reduced the deferred income tax liability for depreciation-related timing differences under the normalized tax accounting method. As this reduction will flow back to customers in the future under the statutorily prescribed average rate assumption method, it was recorded as a regulatory liability on the consolidated balance sheets of the companies. On March 12, 2018, Idaho House Bill 463 was enacted which lowered the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent effective January 1, 2018. The Idaho tax rate reduction did not have a material impact on IDACORP's and Idaho Power's 2018 income tax expense or deferred tax asset and liability balances. 3. REGULATORY MATTERS IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters. Regulatory Assets and Liabilities The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. 96 The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars): Description Regulatory Assets: Income taxes(2) Unfunded postretirement benefits(3) Pension expense deferrals Energy efficiency program costs(4) Power supply costs(5) Fixed cost adjustment(5) Valmy Plant settlements(5) Asset retirement obligations(6) Long-term service agreement Other Total Regulatory Liabilities: Income taxes(7) Depreciation-related excess deferred income taxes(8) Removal costs(6) Investment tax credits Deferred revenue-AFUDC(9) Energy efficiency program costs(4) Power supply costs(5) Settlement agreement sharing mechanism(5) Mark-to-market assets(10) Other Total As of December 31, 2018 Remaining Amortization Period Earning a Return(1) Not Earning a Return Total as of December 31, 2018 2017 $ — $ 614,144 $ 614,144 $ 584,329 — 126,811 1,398 — 34,502 77,512 — 16,095 720 257,038 278,674 21,025 — — 8,001 — 17,655 10,653 6,984 957,136 $ 278,674 147,836 1,398 — 42,503 77,512 280,166 127,721 6,273 3,137 30,856 44,633 17,655 26,748 7,704 $ 1,214,174 15,767 27,907 11,307 $ 1,132,096 2019-2020 2019-2028 2019-2043 2019-2055 $ $ — $ 98,042 $ 98,042 $ 98,744 190,062 — — 95,660 5,259 35,815 5,025 — 2,419 334,240 — 183,798 92,790 39,486 — 6,507 — 3,700 6,314 430,637 $ 190,062 183,798 92,790 135,146 5,259 42,322 5,025 3,700 8,733 764,877 $ $ 193,991 184,993 87,385 119,666 408 5,443 — 22 8,796 699,448 2019-2020 2019-2020 $ (1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return. (2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes." (3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 12 - "Benefit Plans." (4) The energy efficiency asset represents the Oregon jurisdiction balance and the liability represents the Idaho jurisdiction balance. (5) This item is discussed in more detail in this Note 3 - "Regulatory Matters." (6) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement Obligations." (7) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes." (8) The Tax Cuts and Jobs Act, enacted on December 22, 2017, reduced the deferred income tax assets and liabilities. For depreciation-related timing differences under the normalized tax accounting method, this reduction will flow back to customers under the statutorily prescribed average rate assumption method. (9) Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license. (10) Mark-to-market assets and liabilities are discussed in Note 17 - "Fair Value Measurements." Idaho Power’s regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact. Power Cost Adjustment Mechanisms and Deferred Power Supply Costs In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment 97 mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation. The Idaho deferral period or Idaho- jurisdiction power cost adjustment (PCA) year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes: • • a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism. The table below summarizes the three most recent PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC: Effective Date June 1, 2018 $ Change (millions) Notes $ (30.4) The $30.4 million total decrease in PCA rates includes a $7.8 million one-time benefit for June 1, 2017 June 1, 2016 $ $ income tax benefits accrued from January 1 to May 31, 2018, and the income taxes related to Idaho Power's open access transmission tariff (OATT) rate. See "Income Tax Reform - Regulatory Treatment" below for more information. 10.6 The net increase in PCA rates included an offsetting $13.0 million reduction for the refund of previously collected Idaho energy efficiency rider funds. 17.3 The net increase in PCA rates included the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of the October 2014 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds. 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. Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power’s actual Oregon-jurisdictional return on equity (Oregon ROE) for the year is at least 100 basis points below Idaho Power’s last authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power’s actual Oregon ROE for that year is at least 100 basis points above Idaho Power’s last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2018, 2017, and 2016 did not have a material impact on the companies' financial statements. 98 Notable Idaho Regulatory Matters Idaho Base Rate Changes: Idaho base rates were most recently established in 2012, and adjusted in 2014, 2017, and 2018. Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date. As noted above in this Note 3, the IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. In June 2018, the IPUC issued an order adjusting base rates for the impacts of income tax reform, as discussed below in "Income Tax Reform - Regulatory Treatment." October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table included under "Income Tax Reform - Regulatory Treatment" below. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) for 2018 was above 10.0 percent. In both 2016 and 2017, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent and 10.0 percent. 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. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory Treatment" below. Income Tax Reform - Regulatory Treatment: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to file a report with the IPUC, identifying and quantifying the financial impact of the income tax reform changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates and corresponding revenues to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full-year 2017. In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease 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. 99 The May 2018 Idaho Tax Reform Settlement Stipulation also provides for the indefinite extension, with modifications, of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019. The table below summarizes and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho Tax Reform Settlement Stipulation that will be applicable commencing on January 1, 2020. October 2014 Idaho Earnings Support and Sharing Settlement Stipulation (Effective through December 31, 2019) 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. 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 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished. If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 25 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho Power. In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their respective terms. Also in May 2018, the Public Utility Commission of Oregon (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 earlier resolved in a regulatory proceeding, 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. Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is 100 included in the variable kilowatt-hour charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Any annual increase in the FCA recovery is capped at 3 percent of base revenue, with any excess deferred for collection in a subsequent year. The following table summarizes FCA amounts approved for collection in the prior three FCA years: FCA Year 2017 2016 2015 Period Rates in Effect June 1, 2018-May 31, 2019 June 1, 2017-May 31, 2018 June 1, 2016-May 31, 2017 Annual Amount (in millions) $15.6 $35.0 $28.1 Hells Canyon Complex Relicensing Costs Settlement Stipulation: In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor, recognizing that a total of $216.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in the fourth quarter of 2017, which included $4.3 million for costs incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as other operations and maintenance (O&M) expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the $216.5 million of associated costs to be reasonably and prudently incurred. Western Energy Imbalance Market Costs: Idaho Power's participation in the energy imbalance market implemented in the western United States (Western EIM) commenced on April 4, 2018. The Western EIM aims to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. In January 2017, in response to Idaho Power's request to match costs with benefits of Western EIM participation, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. In November 2017, Idaho Power filed an application with the IPUC requesting authorization to establish an interim method of recovery for costs associated with participation in the Western EIM. Through March 2018, Idaho Power had deferred $1.0 million of incremental other O&M costs. In the second quarter of 2018, Idaho Power amortized those costs in accordance with the provisions of the May 2018 Idaho Tax Reform Settlement Stipulation discussed above. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for recovery of ongoing Western EIM-related costs through Idaho Power's PCA mechanism, beginning April 2018. The recovery mechanism provides for monthly incremental revenue, which includes a return on and return of Western EIM-related capital costs and recovery of ongoing Western EIM operating costs. As of April 1, 2018, Idaho Power ceased deferring incremental Western EIM participation O&M start-up costs, and began recognizing the monthly incremental revenue associated with Western EIM participation. From April through December 2018, Idaho Power recorded $2.2 million as a regulatory asset within the PCA balance per the stipulation in order to match the costs with the benefits of the Western EIM. Valmy Base Rate Adjustment Settlement Stipulations In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant). The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the 101 difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 settlement stipulation associated with income tax reform described above, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. Notable Oregon Regulatory Matters Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the OPUC issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base. In June 2018, the OPUC also issued an order adjusting base rates for the impacts of income tax reform, as discussed above in "Income Tax Reform - Regulatory Treatment." Federal Regulatory Matters - Open Access Transmission Tariff Rates Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows: Applicable Period October 1, 2018 to September 30, 2019 October 1, 2017 to September 30, 2018 October 1, 2016 to September 30, 2017 October 1, 2015 to September 30, 2016 OATT Rate (per kW-year) $ $ $ $ 31.25 34.90 25.52 23.43 Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $123.1 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service. 4. REVENUES On January 1, 2018, IDACORP and Idaho Power adopted ASU 2014-09, Revenue from Contracts with Customers, using the modified retrospective method. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, the companies recorded no cumulative-effect adjustment. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands): Year Ended December 31, 2017 2016 2018 Electric utility operating revenues: Revenue from contracts with customers Alternative revenue programs and other revenues Total electric utility operating revenues $ 1,312,112 $ 1,320,004 $ 1,216,796 54,470 $ 1,366,582 24,889 $ 1,344,893 42,557 $ 1,259,353 102 Revenues from Contracts with Customers Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09, Revenue from Contracts with Customers. Idaho Power assesses revenues on a contract-by- contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands): Year Ended December 31, 2017 2016 2018 Revenues from contracts with customers: Retail revenues: Residential (includes $34,625, $17,320 and $29,170, respectively, related to the FCA(1)) Commercial (includes $1,299, $876 and $1,087, respectively, related to the FCA(1)) Industrial Irrigation Provision for sharing Deferred revenue related to HCC relicensing AFUDC(2) Total retail revenues Less: FCA mechanism revenues(1) Wholesale energy sales Transmission wheeling revenues Energy efficiency program revenues Other revenues from contracts with customers Total revenues from contracts with customers $ 530,527 $ 552,333 $ 514,954 310,299 190,130 158,001 (5,025) (8,780) 1,175,152 (35,924) 52,845 59,094 35,703 319,195 195,124 150,030 — (10,706) 1,205,976 (18,196) 24,790 43,970 39,241 302,650 182,590 156,505 — (10,706) 1,145,993 (30,257) 11,900 32,496 33,754 25,242 $ 1,312,112 24,223 $ 1,320,004 22,910 $ 1,216,796 (1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers. (2) As part of its January 30, 2009, general rate case order, the IPUC is allowing Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff- based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year. Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates. Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $3.6 million, $4.7 million, and $4.2 million for 2018, 2017, and 2016, respectively. 103 Residential Customers: Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales. Provision for Sharing: Idaho Power's sharing mechanism is associated with the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation that provides for the sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. Based on full-year 2018 Idaho ROE, Idaho Power recorded a $5.0 million provision against current revenues for sharing of earnings with customers for 2018. During 2017 and 2016, Idaho Power recorded no sharing of earnings with customers. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in Note 3 - "Regulatory Matters." Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales. Transmission Wheeling Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be part of a long-term capacity contract, short-term contract, or on-demand when available. Transmission wheeling revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission wheeling revenues are affected by changes in Idaho Power’s OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region. Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2018, Idaho Power's energy efficiency rider balances were a $5.3 million regulatory liability in the Idaho jurisdiction and a $1.4 million regulatory asset in the Oregon jurisdiction. 104 Alternative Revenue Programs and Other Revenues While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of the FCA mechanism, which may increase or decrease tariff-based rates billed to customers. The FCA mechanism is described in detail in Note 3 - "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when the regulator-specified conditions for recognition have been met. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that had been initially recorded in prior periods when regulator-specified conditions were met. When those amounts are included in the price of utility service and billed to customers, such amounts are recorded as recovery of the associated regulatory asset or liability and not as revenues. The table below presents the FCA mechanism revenues and other revenues (in thousands): Year Ended December 31, 2017 2016 2018 Alternative revenue programs and other revenues: FCA mechanism revenues Derivative revenues Total alternative revenue programs and other revenues IDACORP's Other Revenues $ $ 35,924 18,546 54,470 $ 18,196 6,693 24,889 $ $ 30,257 12,300 42,557 IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydroelectric generation projects that satisfy the requirements of PURPA. 105 5. LONG-TERM DEBT The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars): 2018 2017 First mortgage bonds: 4.50% Series due 2020 3.40% Series due 2020 2.95% Series due 2022 2.50% Series due 2023 6.00% Series due 2032 5.50% Series due 2033 5.50% Series due 2034 5.875% Series due 2034 5.30% Series due 2035 6.30% Series due 2037 6.25% Series due 2037 4.85% Series due 2040 4.30% Series due 2042 4.00% Series due 2043 3.65% Series due 2045 4.05% Series due 2046 4.20% Series due 2048 Total first mortgage bonds Pollution control revenue bonds: 5.15% Series due 2024(1) 5.25% Series due 2026(1) Variable Rate Series 2000 due 2027 Total pollution control revenue bonds American Falls bond guarantee Unamortized issuance costs and discounts Total IDACORP and Idaho Power outstanding debt(2) Current maturities of long-term debt Total long-term debt $ — $ 100,000 75,000 75,000 100,000 70,000 50,000 55,000 60,000 140,000 100,000 100,000 75,000 75,000 250,000 120,000 220,000 130,000 100,000 75,000 75,000 100,000 70,000 50,000 55,000 60,000 140,000 100,000 100,000 75,000 75,000 250,000 120,000 — 1,665,000 1,575,000 49,800 116,300 4,360 170,460 19,885 (20,557) 1,834,788 — 49,800 116,300 4,360 170,460 19,885 (19,222) 1,746,123 — $ 1,834,788 $ 1,746,123 (1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds outstanding at December 31, 2018, to $1.831 billion. (2) At December 31, 2018 and 2017, the overall effective cost rate of Idaho Power's outstanding debt was 4.83 percent and 4.87 percent, respectively. At December 31, 2018, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars): 2019 2020 2021 2022 2023 Thereafter $ — $ 100,000 $ — $ 75,000 $ 75,000 $ 1,605,345 Long-Term Debt Issuances, Maturities, and Availability In March 2018, Idaho Power issued $220 million in principal amount of 4.20% first mortgage bonds, secured medium-term notes, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, $130 million in principal amount of 4.50% first mortgage bonds, medium-term notes, Series H, due March 2020. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium of $4.6 million. Idaho 106 Power used a portion of the net proceeds of the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption. In March 2016, Idaho Power issued $120.0 million in principal amount of 4.05% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2046. In April 2016, Idaho Power redeemed, prior to maturity, $100.0 million in principal amount of 6.15% first mortgage bonds, secured medium-term notes, Series H, due April 2019. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium of $14.0 million. Idaho Power used a portion of the net proceeds from the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption. 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 extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of 7.0 percent. On September 27, 2016, Idaho Power entered into a selling agency agreement with seven banks in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium term notes, Series K (Series K Notes), 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. The Forty-eighth Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture. As of December 31, 2018, $280 million in principal amount of Series K Notes remained available for issuance under the Indenture. The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year. The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds. As of December 31, 2018, Idaho Power could issue under its Indenture approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-eighth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2018 was limited to approximately $669 million under the Indenture. 107 6. NOTES PAYABLE Credit Facilities On November 6, 2015, IDACORP and Idaho Power entered into Credit Agreements replacing the existing Second Amended and Restated Credit Agreements, dated October 26, 2011, to provide credit facilities that may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $100 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions. The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR 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 margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original maturity date of November 6, 2020, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, subject to certain conditions. On November 7, 2017, IDACORP and Idaho Power executed the second extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 4, 2022. No other terms of the credit facilities, included the amount of permitted borrowing under the credit agreements, were affected by the extensions. At December 31, 2018, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2018, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at December 31, 2018, and December 31, 2017: Commercial paper balances: At the end of year Average during the year Weighted-average interest rate At the end of the year IDACORP Idaho Power Total 2018 2017 2018 2017 2018 2017 $ $ — $ — $ — $ 588 $ — $ — $ — $ 839 $ — $ — — $ 1,427 —% —% —% —% —% —% 108 7. COMMON STOCK IDACORP Common Stock The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 2018: Balance at beginning of year Continuous equity program (inactive) Dividend reinvestment and stock purchase plan Employee savings plan Long-term incentive and compensation plan(1) Balance at end of year 2018 50,420,017 — — — — 50,420,017 Shares issued 2017 50,420,017 — — — — 50,420,017 2016 50,352,051 — — — 67,966 50,420,017 Shares reserved December 31, 2018 3,000,000 2,576,723 3,567,954 1,302,869 (1) During 2018 and 2017, IDACORP granted 75,761 and 72,397 restricted stock unit awards, respectively, to employees and 12,950 and 12,050 shares of common stock, respectively, to directors but made no original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. Restrictions on Dividends Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2018, the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.4 billion and $1.2 billion, respectively, at December 31, 2018. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At December 31, 2018, IDACORP and Idaho Power were in compliance with those covenants. Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31, 2018, Idaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP. Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report, Idaho Power has no preferred stock outstanding. In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings. 8. SHARE-BASED COMPENSATION IDACORP has one share-based compensation plan — the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units (together, Restricted Stock), performance shares and performance-based units (together, Performance-Based Shares), and several other types of share-based awards. At December 31, 2018, the maximum number of shares available under the LTICP was 720,408. 109 Restricted Stock and Performance-Based Shares Awards Restricted Stock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights, except that holders of restricted stock units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period, reduced for any forfeitures during the vesting period. Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of performance-based units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded can range from zero to 200 percent of the target award. Dividends or dividend equivalents, as applicable, are accrued during the vesting period and paid out based on the final number of shares awarded. The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense over the requisite service period based on the estimated achievement of performance targets, reduced for any forfeitures during the vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of this portion of the awards is charged to compensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained. A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees: Nonvested shares/units at January 1, 2018 Shares/units granted Shares/units forfeited Shares/units vested Nonvested shares/units at December 31, 2018 IDACORP Idaho Power Number of Shares/Units Weighted- Average Grant Date Fair Value 201,078 106,992 (5,179) (96,856) 206,035 $ $ 72.37 79.28 85.07 60.30 81.31 Number of Shares/Units 199,652 106,402 (5,179) (96,016) 204,859 Weighted- Average Grant Date Fair Value 72.39 $ 79.29 85.07 60.31 81.31 $ The total fair value of shares vested was $8.3 million in 2018, $7.5 million in 2017, and $8.3 million in 2016. At December 31, 2018, IDACORP had $8.0 million of total unrecognized compensation cost related to nonvested share-based compensation. Idaho Power's share of this amount was $7.9 million. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue and/or treasury shares for these awards. In 2018, a total of 12,950 shares were awarded to directors at a grant date fair value of $81.05 per share. Directors elected to defer receipt of 3,237 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units. Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars): Compensation cost Income tax benefit(1) IDACORP 2017 2018 2016 2018 Idaho Power 2017 2016 $ $ 9,362 2,410 $ 7,384 2,887 $ 5,561 2,174 $ 9,276 2,388 $ 7,304 2,856 5,494 2,148 110 (1) Due to the Tax Cuts and Jobs Act, the effective income tax rate was reduced in 2018 for both IDACORP and Idaho Power, which is described in Note 2 - "Income Taxes." No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the consolidated statements of income. 9. EARNINGS PER SHARE The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2018, 2017, and 2016 (in thousands, except for per share amounts): Year Ended December 31, 2017 2018 2016 Numerator: Net income attributable to IDACORP, Inc. $ 226,801 $ 212,419 $ 198,288 Denominator: Weighted-average common shares outstanding - basic Effect of dilutive securities Weighted-average common shares outstanding - diluted Basic earnings per share Diluted earnings per share 10. COMMITMENTS Purchase Obligations 50,432 78 50,510 4.50 4.49 $ $ 50,361 63 50,424 4.22 4.21 $ $ 50,298 75 50,373 3.94 3.94 $ $ At December 31, 2018, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars): Cogeneration and power production Fuel 2019 $ 238,748 43,163 2020 $ 242,206 29,121 2021 $ 248,258 28,010 2022 $ 251,216 8,389 2023 $ 256,403 8,379 Thereafter $2,805,159 84,182 As of December 31, 2018, Idaho Power had 1,119 MW nameplate capacity of PURPA-related projects on-line, with an additional 29 MW nameplate capacity of projects projected to be on-line in 2019. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $190 million in 2018, $170 million in 2017, and $154 million in 2016. Idaho Power also has the following long-term commitments (in thousands of dollars): Joint-operating agreement payments(1) Easements and other payments Maintenance and service agreements(1) FERC and other industry-related fees(1) 2019 2020 2021 2022 2023 Thereafter $ 2,902 $ 2,902 $ 2,902 $ 2,902 $ 2,902 $ 14,512 240 34,089 14,277 1,321 15,694 12,714 1,321 10,739 12,714 1,331 11,713 12,714 1,328 4,140 12,714 16,831 54,927 63,568 (1) Approximately $29 million, $20 million, and $71 million of the obligations included in joint-operating agreement payments, maintenance and service agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes. IDACORP’s expense for operating leases was not material for the years ended 2018, 2017, and 2016. 111 Guarantees Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $58.4 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 was $101.9 million. During 2018, the reclamation trust fund made distributions of $6.7 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal. IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2018, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations. 11. CONTINGENCIES IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted. IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company’s provision of electric service and the operation of its generation, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. In recent years, Idaho Power has regularly received claims by both governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations. 112 12. BENEFIT PLANS Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits. Pension Plans Idaho Power has two pension plans–a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under these plans are based on years of service and the employee's final average earnings. Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2018, 2017, and 2016, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars): Change in projected benefit obligation: Benefit obligation at January 1 Service cost Interest cost Actuarial (gain) loss Benefits paid Projected benefit obligation at December 31 Change in plan assets: Fair value at January 1 Actual (loss) return on plan assets Employer contributions Benefits paid Fair value at December 31 Funded status at end of year Amounts recognized in the statement of financial position consist of: Other current liabilities Noncurrent liabilities Net amount recognized Amounts recognized in accumulated other comprehensive income consist of: Net loss Prior service cost Subtotal Less amount recorded as regulatory asset Net amount recognized in accumulated other comprehensive income Accumulated benefit obligation 113 Pension Plan SMSP 2018 2017 2018 2017 $ $ $ 999,344 37,836 38,833 (84,758) (39,398) 951,857 895,060 33,742 38,957 67,758 (36,173) 999,344 $ 110,303 (316) 4,248 (7,050) (4,867) 102,318 99,570 759 4,315 10,635 (4,976) 110,303 697,683 (47,681) 40,000 (39,398) 650,604 — — — — — $ (301,253) $ (301,661) $ (102,318) $ (110,303) 607,568 86,288 40,000 (36,173) 697,683 — — — — — $ — $ (5,010) (105,293) $ (301,253) $ (301,661) $ (102,318) $ (110,303) (5,158) $ (97,160) (301,253) (301,661) — $ $ $ $ $ 278,720 62 278,782 (278,782) $ 277,052 68 277,120 (277,120) — $ — $ 30,496 399 30,895 — 30,895 $ $ 41,333 498 41,831 — 41,831 814,549 $ 850,763 $ 94,630 $ 100,222 As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately $92.5 million and $85.7 million at December 31, 2018 and 2017, respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets. The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets. Service cost Interest cost Expected return on assets Amortization of net loss Amortization of prior service cost Net periodic pension cost Regulatory deferral of net periodic benefit cost(1) Previously deferred pension cost recognized(1) Net periodic benefit cost recognized for financial reporting(1)(2) Pension Plan 2017 $ 33,742 38,957 (45,138) 13,190 28 40,779 (38,699) 17,154 2018 $ 37,836 38,833 (52,302) 13,558 6 37,931 (36,153) 17,154 2016 $ 32,019 37,813 (42,081) 13,331 59 41,141 (39,335) 17,154 SMSP 2018 2017 $ (316) $ 759 4,315 — 2,963 127 8,164 — — 4,248 — 3,788 98 7,818 — — 2016 $ 1,228 4,275 — 3,532 168 9,203 — — $ 18,932 $ 19,234 $ 18,960 $7,818 $ 8,164 $ 9,203 (1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. (2) Of total net periodic benefit cost recognized for financial reporting $15.2 million, $16.2 million, and $16.4 million, respectively, was recognized in "Other operations and maintenance" and $11.6 million, $11.2 million, and $11.8 million, respectively, was recognized in "Other expense, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2018, 2017, and 2016. The following table shows the components of other comprehensive income for the plans (in thousands of dollars): Pension Plan 2017 2018 2016 2018 Actuarial (loss) gain during the year $ (15,226) $ (26,608) $ (23,753) $ Plan amendment service cost Reclassification adjustments for: Amortization of net loss Amortization of prior service cost Adjustment for deferred tax effects Adjustment due to the effects of regulation Other comprehensive income recognized related to pension benefit plans — — (81) 13,558 6 428 1,234 13,190 28 1,744 11,646 13,331 59 4,083 6,361 SMSP 2017 $ (10,635) $ — 2,963 127 1,555 — 2016 (2,933) (120) 3,532 168 (253) — 7,049 — 3,788 98 (2,815) — $ — $ — $ — $ 8,120 $ (5,990) $ 394 In 2019, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $16.5 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2018, relating to the pension plan and SMSP. This amount consists of $13.9 million of amortization of net loss for the pension plan and $2.5 million of amortization of net loss and $0.1 million of amortization of prior service cost for the SMSP. The following table summarizes the expected future benefit payments of these plans (in thousands of dollars): Pension Plan SMSP 2019 2020 2021 2022 2023 2023-2028 $ $ 38,177 5,266 40,287 5,716 $ $ 42,403 5,901 $ 44,489 6,071 $ 46,671 6,431 264,707 31,867 As of December 31, 2018, IDACORP's and Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2019. Depending on market conditions and cash flow considerations in 2019, Idaho Power could contribute up to 114 $40 million to the pension plan during 2019 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. Postretirement Benefits Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power’s future obligations under this plan. The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars): Change in accumulated benefit obligation: Benefit obligation at January 1 Service cost Interest cost Actuarial (gain) loss Benefits paid(1) Plan amendments Benefit obligation at December 31 Change in plan assets: Fair value of plan assets at January 1 Actual (loss) return on plan assets Employer contributions(1) Benefits paid(1) Fair value of plan assets at December 31 Funded status at end of year (included in noncurrent liabilities) 2018 2017 $ $ $ 70,051 1,051 2,643 (2,688) (4,604) — 66,453 38,294 (1,330) 1,031 (4,604) 33,391 (33,062) $ 63,876 973 2,783 5,769 (3,562) 212 70,051 34,999 5,112 1,745 (3,562) 38,294 (31,757) (1) Contributions and benefits paid are each net of $3.1 million and $3.4 million of plan participant contributions for 2018 and 2017, respectively. Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars): Net (loss) gain Prior service cost Subtotal Less amount recognized in regulatory assets Net amount recognized in accumulated other comprehensive income The net periodic postretirement benefit cost was as follows (in thousands of dollars): 2018 2017 (330) $ 222 (108) 108 — $ 2,777 269 3,046 (3,046) — $ $ Service cost Interest cost Expected return on plan assets Immediate recognition of loss from temporary deviation(1) Amortization of prior service cost Net periodic postretirement benefit cost 2018 2017 2016 $ $ 1,051 2,643 (2,467) 4,216 47 5,490 $ $ 973 2,783 (2,307) — 47 1,496 $ $ 1,116 2,766 (2,474) — 26 1,434 (1) In 2018, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other expense, net" on the consolidated statements of income of the companies. 115 The following table shows the components of other comprehensive income for the plan (in thousands of dollars): Actuarial loss during the year Prior service cost arising during the year Reclassification adjustments for: Immediate recognition of loss from temporary deviation(1) Reclassification adjustments for amortization of prior service cost Adjustment for deferred tax effects Adjustment due to the effects of regulation Other comprehensive income related to postretirement benefit plans 2018 2017 2016 $ (1,109) $ — (2,964) $ (212) (1,600) — 4,216 47 270 (3,424) — 47 807 2,322 $ — $ — $ — 26 615 959 — (1) In 2018, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other expense, net" on the consolidated statements of income of the companies. The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars): Expected benefit payments Plan Assumptions 2019 $ 5,438 2020 $ 5,051 2021 $ 4,894 2022 2023 2023-2027 $ 4,732 $ 4,549 $ 20,080 The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans: Discount rate Rate of compensation increase(1) Medical trend rate Dental trend rate Measurement date Pension Plan SMSP Postretirement Benefits 2018 2017 2018 2017 2018 2017 4.55% 4.25% — — 3.95% 4.17% — — 4.60% 4.75% — — 3.95% 4.75% — — 12/31/2018 12/31/2017 12/31/2018 12/31/2017 4.60% — 6.3% 4.0% 12/31/2018 3.95% — 6.8% 4.0% 12/31/2017 (1) The 2018 rate of compensation increase assumption for the pension plan includes an inflation component of 2.50% plus a 1.75% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0% for employees in their fortieth year of service and beyond. The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans: Discount rate Expected long-term rate of return on assets Pension Plan 2017 SMSP 2017 2018 3.95% 4.45% 4.60% 3.95% 4.45% 4.60% 3.95% 4.45% 4.60% 2016 2016 2016 2018 2018 Postretirement Benefits 2017 7.50% 7.50% 7.50% — — — 6.75% 6.75% 7.25% Rate of compensation increase Medical trend rate Dental trend rate 4.25% 4.17% 4.11% 4.75% 4.75% 4.50% — — — — — — — — — — — — — 6.3% 4.0% —% 6.8% 4.0% —% 8.3% 5.0% 116 The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.3 percent in 2018 and is assumed to decrease to 5.7 percent in 2019, 5.1 percent in 2020, 5.1 percent in 2021 and to gradually decrease to 4.1 percent by 2076. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.0 percent, or equal to the medical trend rate if lower, for all years. A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2018 (in thousands of dollars): Effect on total of cost components Effect on accumulated postretirement benefit obligation Plan Assets One-Percentage-Point Increase Decrease $ $ 339 3,222 (247) (2,483) Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2018, for the pension asset portfolio by asset class is set forth below: Asset Class Debt securities Equity securities Real estate Other plan assets Total Target Allocation Actual Allocation December 31, 2018 24% 56% 7% 13% 100% 26% 56% 6% 12% 100% Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants. The three major goals in Idaho Power’s asset allocation process are to: determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations; • • match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of benefit payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and • maintain a prudent risk profile consistent with ERISA fiduciary standards. Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price. Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst- case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets. 117 Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three- level fair value hierarchy described in Note 17 - "Fair Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars). Level 1 Level 2 Level 3 Total Assets at December 31, 2018 Cash and cash equivalents Short-term bonds Intermediate bonds Long-term bonds Equity Securities: Large-Cap Equity Securities: Mid-Cap Equity Securities: Small-Cap Equity Securities: Micro-Cap Equity Securities: International Equity Securities: Emerging Markets Plan assets measured at NAV (not subject to hierarchy disclosure) Equity Securities: Global and International Equity Securities: Emerging Markets Real estate Private market investments Commodities fund Total Postretirement plan assets(1) Assets at December 31, 2017 Cash and cash equivalents Short-term bonds Intermediate bonds Long-term bonds Equity Securities: Large-Cap Equity Securities: Mid-Cap Equity Securities: Small-Cap Equity Securities: Micro-Cap Equity Securities: International Equity Securities: Emerging Markets Plan assets measured at NAV (not subject to hierarchy disclosure) Equity Securities: International Equity Securities: Emerging Markets Real estate Private market investments Commodities fund Total Postretirement plan assets(1) $ 9,717 20,644 20,595 — 71,176 71,419 53,401 30,387 7,104 6,519 $ — $ — 87,646 40,857 — — — — — — $ 290,962 $ 128,503 $ 758 $ 32,633 $ $ — $ 9,717 20,644 — — 108,241 40,857 — 71,176 — 71,419 — 53,401 — 30,387 — 7,104 — 6,519 — 95,653 29,757 39,846 35,041 30,842 — $ 650,604 — $ 33,391 Level 1 Level 2 Level 3 Total $ 20,852 20,475 20,699 — 95,179 81,127 62,502 32,753 6,774 8,785 $ — $ — 82,923 40,707 — — — — — — — $ 20,852 — 20,475 — 103,622 40,707 — 95,179 — 81,127 — 62,502 — 32,753 — 6,774 — 8,785 — 83,589 36,255 38,435 31,618 35,010 $ 349,146 $ 123,630 $ 567 $ 37,727 $ $ — $ 697,683 — $ 38,294 (1) The postretirement benefits assets are primarily life insurance contracts. For the years ended December 31, 2018 and 2017, there were no material transfers into or out of Levels 1, 2, or 3. 118 Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV: Level 2 Bonds: These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets. Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices. Commingled Funds: These funds, made up of the global, international, emerging markets equity securities, and commodities fund measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days. Real Estate: Real estate holdings represent investments in commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests. Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer. Employee Savings Plan Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were approximately $7.7 million, $7.4 million, and $7.5 million in 2018, 2017, and 2016, respectively. 119 Post-employment Benefits Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-employment benefits included in other deferred credits on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2018, and 2017, were approximately $2 million. 13. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2018 and 2017 (in thousands of dollars): Production Transmission Distribution General and Other Total in service Accumulated provision for depreciation In service - net 2018 2017 Balance $ 2,654,201 1,201,092 1,792,284 456,279 6,103,856 (2,210,781) $ 3,893,075 Avg Rate Balance Avg Rate 3.10% $ 2,598,940 1,163,240 1.89% 1,710,126 2.24% 433,856 6.40% 5,906,162 2.84% (2,098,274) $ 3,807,888 3.07% 1.94% 2.44% 6.01% 2.87% At December 31, 2018, Idaho Power's construction work in progress balance of $480.3 million included relicensing costs of $297.0 million for the HCC, Idaho Power's largest hydroelectric complex. In 2018, 2017, and 2016, the IPUC authorized Idaho Power to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes in 2018 and $10.7 million when grossed-up for the effect of income taxes in 2017 and 2016 prior to income tax reform described in Note 2 - "Income Taxes") of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2018, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $135.1 million. Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2018 (in thousands of dollars): Name of Plant Jim Bridger units 1-4 Boardman Valmy units 1 and 2 Location Rock Springs, WY Boardman, OR Winnemucca, NV (1) Idaho Power’s share of nameplate capacity. Utility Plant in Service $ 733,451 82,459 410,947 Construction Work in Progress $ 5,141 4 248 Accumulated Provision for Depreciation 334,731 $ 74,748 279,643 Ownership % 33 10 50 MW(1) 771 64 284 IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power’s coal purchases from the joint venture were $81.8 million in 2018, $86.4 million in 2017, and $92.9 million in 2016. Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $9.7 million in 2018, $9.8 million in 2017, and $7.8 million in 2016. IDACORP's consolidated VIE, Marysville, owns a hydroelectric plant with a net book value of $15.2 million and $15.7 million at December 31, 2018 and 2017, respectively. 120 14. ASSET RETIREMENT OBLIGATIONS (ARO) The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under this order do not earn a return on investment. Accretion, depreciation, and gains or losses related to the Boardman generating facility are exempted from such regulatory treatment as Idaho Power is now collecting amounts related to the decommissioning of Boardman in rates. Idaho Power’s recorded AROs relate to the removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities and the reclamation and removal costs at its jointly-owned coal-fired generation facilities. Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements. Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 2018 and 2017. The following table presents the changes in the carrying amount of AROs (in thousands of dollars): Balance at beginning of year Accretion expense Revisions in estimated cash flows Liability incurred Liability settled Balance at end of year 15. INVESTMENTS 2018 2017 26,415 1,055 (751) 129 (56) 26,792 $ $ 26,257 1,015 (791) — (66) 26,415 $ $ The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars): Idaho Power investments: Bridger Coal Company (equity method investment) Exchange traded short-term bond funds and cash equivalents Executive deferred compensation plan investments Total Idaho Power investments Investments in affordable housing (IDACORP Financial Services) Ida-West joint ventures (equity method investments) Total IDACORP investments 2018 2017 $ $ 49,878 36,471 17 86,366 3,446 11,366 101,178 $ $ 68,566 30,249 17 98,832 5,521 11,345 115,698 121 Equity Method Investments Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture, Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings of unconsolidated equity-method investments (in thousands of dollars): Bridger Coal Company (Idaho Power) Ida-West joint ventures Total Investments in Equity Securities 2018 2017 2016 $ $ 10,712 1,737 12,449 $ $ 9,267 2,107 11,374 $ $ 10,855 2,016 12,871 Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains and losses on available-for-sale securities were immaterial at December 31, 2018 and December 31, 2017. The following table summarizes sales of available-for-sale securities (in thousands of dollars): Proceeds from sales Gross realized gains from sales Investments in Affordable Housing 2018 2017 2016 $ $ 5,007 — $ 4,989 — 15,693 54 IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified affordable housing projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense. 16. DERIVATIVE FINANCIAL INSTRUMENTS Commodity Price Risk Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop. All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below. 122 The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2018, 2017, and 2016 (in thousands of dollars): Financial swaps Financial swaps Financial swaps Financial swaps Forward contracts Forward contracts Forward contracts Location of Realized Gain/(Loss) on Derivatives Recognized in Income Operating revenues Purchased power Fuel expense Other operations and maintenance Operating revenues Purchased power Fuel expense Gain/(Loss) on Derivatives Recognized in Income(1) 2017 2018 2016 $ 1,316 $ 7,828 22,563 118 41 (54) (186) $ 902 166 701 (84) 55 (69) 4 1,405 586 (1,947) (161) (54) 86 139 (1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities. Settlement gains and losses on electricity swap contracts are recorded on the income statement in revenues from contracts with customers or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense. See Note 17 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities. Derivative Instrument Summary The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2018 and 2017 (in thousands of dollars): Balance Sheet Location December 31, 2018 Current: Other current assets Financial swaps Financial swaps Other current liabilities Forward contracts Other current liabilities Other liabilities Long-term: Financial swaps Total December 31, 2017 Current: Other current assets Financial swaps Financial swaps Other current liabilities Forward contracts Other current liabilities Long-term: Financial swaps Total Other assets Asset Derivatives Liability Derivatives Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities $ $ $ $ 4,639 — — — 4,639 18 553 — 4 575 $ $ $ $ (984) (1) $ 3,655 — — — — $ 938 806 104 — (984) — $ 3,655 64 $ 1,912 $ $ (938) — — — (938) — (553) — — (553) $ $ 18 — — 4 22 $ — $ 1,971 2 — (748) (2) — — $ 1,973 $ — (748) $ $ $ $ — 806 104 64 974 — 1,223 2 — 1,225 (1) Current asset derivative amounts offset include $45 thousand of collateral payable for the period ending December 31, 2018. (2) Current liability derivative amounts offset include $196 thousand of collateral receivable for the period ending December 31, 2017. 123 The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2018 and 2017 (in thousands of units): Commodity Electricity purchases Electricity sales Natural gas purchases Natural gas sales Credit Risk Units MWh MWh MMBtu MMBtu December 31, 2018 2017 52 39 7,514 446 312 224 7,028 140 At December 31, 2018, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency. Credit-Contingent Features Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2018, was $1.9 million. Idaho Power posted no cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2018, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $7.8 million to cover open liability positions as well as completed transactions that have not yet been paid. 17. FAIR VALUE MEASUREMENTS IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: • Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access. • Level 2: Financial assets and liabilities whose values are based on the following: a) quoted prices for similar assets or liabilities in active markets; b) quoted prices for identical or similar assets or liabilities in non-active markets; c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability. IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data. 124 • Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2018 and 2017. The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2018 and 2017 (in thousands of dollars): December 31, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Money market funds and commercial paper IDACORP(1) Idaho Power Derivatives Equity securities Liabilities: Derivatives $ $ 97,833 79,228 3,655 36,488 — $ — — — $ — $ 97,833 79,228 — 3,655 — 36,488 — $ 28,038 10,260 22 30,266 — $ — — — — $ 28,038 10,260 — — 22 30,266 — $ 870 $ 104 $ — $ 974 $ 1,223 $ 2 $ — $ 1,225 (1) Holding company only. Does not include amounts held by Idaho Power. Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivatives are valued using New York Mercantile Exchange and Intercontinental Exchange pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Equity securities consist of employee-directed investments related to an executive deferred compensation plan and actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a Rabbi trust. The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2018 and 2017, using available market information and appropriate valuation methodologies (in thousands). IDACORP Assets: Notes receivable(1) Liabilities: Long-term debt(1) Idaho Power Liabilities: Long-term debt(1) December 31, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value (thousands of dollars) $ 3,804 $ 3,804 $ 3,804 $ 3,804 1,834,788 1,942,773 1,746,123 1,915,459 $ 1,834,788 $ 1,942,773 $ 1,746,123 $ 1,915,459 (1) Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 17 - "Fair Value Measurements." Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value. 125 18. SEGMENT INFORMATION IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture. IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, and IDACORP’s holding company expenses. The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands): 2018 Revenues Operating income Other income, net Interest income Equity-method income Interest expense Income before income taxes Income tax expense (benefit) Income attributable to IDACORP, Inc. Total assets Expenditures for long-lived assets Utility Operations All Other Eliminations Consolidated Total $ 1,366,582 295,256 $ 11,646 8,923 10,712 85,891 240,646 18,312 222,334 6,254,400 277,823 4,170 1,666 (1) 1,573 1,737 712 4,263 (926) 4,467 163,540 30 $ — $ — 1,370,752 296,922 — (655) — (655) — — — (35,186) — 11,645 9,841 12,449 85,948 244,909 17,386 226,801 6,382,754 277,853 126 2017 Revenues Operating income Other income, net Interest income Equity-method income Interest expense Income before income taxes Income tax expense (benefit) Income attributable to IDACORP, Inc. Total assets Expenditures for long-lived assets 2016 Revenues Operating income Other income, net Interest income Equity-method income Interest expense Income before income taxes Income tax expense (benefit) Income attributable to IDACORP, Inc. Total assets Expenditures for long-lived assets Utility Operations All Other Eliminations Consolidated Total $ $ $ $ 1,344,893 313,602 12,356 6,044 9,267 83,660 257,609 51,262 206,347 5,995,435 285,471 1,259,353 277,297 15,852 4,235 10,855 81,812 226,427 37,185 189,242 6,236,744 296,948 $ $ 4,593 1,943 191 295 2,107 297 4,239 (2,602) 6,072 143,696 17 2,667 6,285 6 127 2,016 344 8,090 (756) 9,046 73,137 2 — $ — — (211) — (211) — — — (93,726) — — $ — — (121) — (121) — — — (19,984) — 1,349,486 315,545 12,547 6,128 11,374 83,746 261,848 48,660 212,419 6,045,405 285,488 1,262,020 283,582 15,858 4,241 12,871 82,035 234,517 36,429 198,288 6,289,897 296,950 127 19. OTHER INCOME AND EXPENSE The following table presents the components of IDACORP’s other expense, net and Idaho Power's other expense, net (in thousands of dollars): IDACORP Interest and dividend income, net Carrying charges on regulatory assets Pension and postretirement non-service costs(1) Income from life insurance investments Other income Total other expense, net Idaho Power Interest and dividend income, net Carrying charges on regulatory assets Pension and postretirement non-service costs(1) Income from life insurance investments Other expense Total other expense, net 2018 2017 2016 $ 5,605 4,075 (15,781) 2,779 455 (2,867) $ $ 3,872 2,310 (11,194) 2,090 813 (2,109) $ $ 4,688 4,075 (15,781) 2,779 (1,612) (5,851) $ $ 3,787 2,310 (11,194) 2,090 (1,749) (4,756) $ 4,466 2,082 (11,806) 2,588 738 (1,932) 4,460 2,082 (11,806) 2,588 (1,871) (4,547) $ $ $ $ (1) The 2018 pension and postretirement non-service costs includes $4.2 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 12 - "Benefit Plans." 20. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the years ended December 31, 2018, 2017, and 2016 (in thousands of dollars). Items in parentheses indicate reductions to AOCI. Defined benefit pension items Balance at beginning of period Other comprehensive income before reclassifications Amounts reclassified out of AOCI to net income Net current-period other comprehensive income Cumulative effect of change in accounting principle(1) Balance at end of period Year Ended December 31, 2018 2017 2016 $ $ (30,964) $ 5,234 2,886 8,120 — (22,844) $ (20,882) $ (7,872) 1,882 (5,990) (4,092) (30,964) $ (21,276) (1,859) 2,253 394 — (20,882) (1) The cumulative effect of change in accounting principle relates to the 2017 adoption of ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220). 128 The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2018, 2017, and 2016 (in thousands of dollars). Items in parentheses indicate increases to net income. Amortization of defined benefit pension items(1) Prior service cost Net loss Total before tax Tax benefit(2) Net of tax Total reclassification for the period Amount Reclassified from AOCI Year Ended December 31, 2018 2017 2016 $ $ 98 3,788 3,886 (1,000) 2,886 2,886 $ $ 127 2,963 3,090 (1,208) 1,882 1,882 $ $ 168 3,532 3,700 (1,447) 2,253 2,253 (1) Amortization of these items is included in IDACORP's consolidated income statements in other operating expenses and in Idaho Power's consolidated income statements in other expense, net. (2) The tax benefit is included in income tax expense in the consolidated income statements of both IDACORP and Idaho Power. 21. RELATED PARTY TRANSACTIONS IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.7 million in both 2018 and 2017 and $0.8 million in 2016. At December 31, 2018 and 2017, Idaho Power had a $1.9 million and $57.3 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets. In 2018, Idaho Power paid IDACORP certain estimated income taxes that had been accrued at December 31, 2017. Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectric projects located in Idaho. Idaho Power paid Ida-West $9.7 million in 2018, $9.8 million in 2017, and $7.8 million in 2016 for that power. 129 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of IDACORP, Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and the schedules listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2019, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ DELOITTE & TOUCHE LLP Boise, Idaho February 21, 2019 We have served as the Company's auditor since 1932. 130 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholder and the Board of Directors of Idaho Power Company Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2019, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ DELOITTE & TOUCHE LLP Boise, Idaho February 21, 2019 We have served as the Company's auditor since 1932. 131 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA The following unaudited information is presented for each quarter of 2018 and 2017 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported. IDACORP, Inc. 2018 Revenues Operating income Net income Net income attributable to IDACORP, Inc. Basic earnings per share Diluted earnings per share 2017 Revenues Operating income(1) Net income Net income attributable to IDACORP, Inc. Basic earnings per share Diluted earnings per share Idaho Power Company 2018 Revenues Income from operations Net income 2017 Revenues Income from operations(1) Net income March 31 June 30 September 30 December 31 Quarter Ended $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 310,107 50,589 36,111 36,142 0.72 0.72 302,544 53,627 33,006 33,102 0.66 0.66 309,461 51,120 35,857 301,964 54,350 32,482 $ $ $ $ $ $ $ $ 339,952 82,835 62,593 62,288 1.24 1.23 333,006 81,907 50,096 49,831 0.99 0.99 338,699 82,659 60,637 331,768 81,777 48,381 $ $ $ $ $ $ $ $ 408,801 115,233 102,591 102,231 2.03 2.02 408,324 123,707 91,076 90,634 1.80 1.80 407,355 114,963 100,194 406,655 123,293 88,329 311,892 48,265 26,228 26,140 0.52 0.52 305,612 56,304 39,010 38,852 0.77 0.77 311,067 48,581 25,646 304,506 56,554 37,155 (1) Operating income in 2017 reflects the 2018 adoption of Accounting Standards Update 2017-07. Retrospective adjustments were made to prior periods to conform with current period presentation. For additional information, refer to Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report. 132 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. Disclosure Controls and Procedures - IDACORP, Inc. ITEM 9A. CONTROLS AND PROCEDURES The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2018, have concluded that IDACORP, Inc.’s disclosure controls and procedures are effective as of that date. Internal Control Over Financial Reporting - IDACORP, Inc. Management’s Annual Report on Internal Control Over Financial Reporting The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that: • • • pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2018. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on its assessment, management concluded that, as of December 31, 2018, IDACORP’s internal control over financial reporting is effective based on those criteria. IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2018 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2018. February 21, 2019 133 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of IDACORP, Inc. Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2018 of the Company and our report dated February 21, 2019 expressed an unqualified opinion on those financial statements and financial statement schedules. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ DELOITTE & TOUCHE LLP Boise, Idaho February 21, 2019 134 Disclosure Controls and Procedures - Idaho Power Company The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2018, have concluded that Idaho Power Company's disclosure controls and procedures are effective as of that date. Internal Control Over Financial Reporting - Idaho Power Company Management’s Annual Report on Internal Control Over Financial Reporting The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that: • • • pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2018. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on its assessment, management concluded that, as of December 31, 2018, Idaho Power’s internal control over financial reporting is effective based on those criteria. Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2018 and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2018. February 21, 2019 135 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholder and Board of Directors of Idaho Power Company Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2018 of the Company and our report dated February 21, 2019 expressed an unqualified opinion on those financial statements and financial statement schedule. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ DELOITTE & TOUCHE LLP Boise, Idaho February 21, 2019 136 Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company There have been no changes in IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting. None. ITEM 9B. OTHER INFORMATION PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders are hereby incorporated by reference. Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.” ITEM 11. EXECUTIVE COMPENSATION The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders is hereby incorporated by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers, and Five-Percent Shareholders” to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2018, with respect to the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) pursuant to which equity securities of IDACORP may be issued. Equity Compensation Plan Information (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (b) Weighted- average exercise price of outstanding options, warrants and rights (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 139,353 (1) $ — 139,353 $ $ — (2) — — 720,408 (3) — 720,408 Plan Category Equity compensation plans approved by shareholders Equity compensation plans not approved by shareholders Total (1) Represents shares subject to outstanding time-based restricted stock units and performance-based restricted stock units (at target). (2) Time-based restricted stock units and performance-based restricted stock units have no exercise price. (3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards. The number of shares listed in this column excludes (i) issued but unvested performance-based restricted shares and (ii) issued but unvested time-based restricted shares, in both cases as of December 31, 2018. 137 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders are hereby incorporated by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES IDACORP: The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the 2019 annual meeting of shareholders is hereby incorporated by reference. Idaho Power: The table below presents the aggregate fees of Idaho Power's principal independent registered public accounting firm, Deloitte & Touche LLP, billed or is expected to bill to Idaho Power for the fiscal years ended December 31, 2018 and 2017: Audit fees Audit-related fees(1) Tax fees(2) All other fees(3) Total (1) Includes accounting-related consultation services. (2) Includes fees for consultation related to tax planning and accounting. (3) Accounting research tool subscription. Policy on Audit Committee Pre-Approval: 2018 1,437,100 29,550 26,125 1,895 1,494,670 $ $ 2017 1,379,000 39,400 40,000 2,000 1,460,400 $ $ Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2018 and 2017, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee. In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre- approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed services; however, the Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre- approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval. 138 In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles: • the independent public accounting firm cannot function in the role of management of Idaho Power; and • the independent public accounting firm cannot audit its own work. The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (1) and (2) Refer to Part II, Item 8 - “Financial Statements and Supplementary Data” for a complete listing of consolidated financial statements and financial statement schedules. (3) Exhibits. Note Regarding Reliance on Statements in Agreements: The agreements filed as exhibits to this Annual Report on Form 10-K are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements. Exhibit No. 2 3.1 3.2 3.3 3.4 3.5 3.6 3.7 Exhibit Description Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998 Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989 Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991 Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993 Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998 Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000 Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005 Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007 139 Incorporated by Reference Form File No. S-4 333-48031 Exhibit No. A Date Included Herewith 3/16/1998 S-3 Post- Effective Amend. No. 2 S-3 33-00440* 4(a)(xiii) 6/30/1989 33-65720* 4(a)(ii) 7/7/1993 S-3 33-65720* 4(a)(iii) 7/7/1993 S-8 Post- Effective Amend. No. 1 10-Q 33-56071-9 9 3(d) 10/1/1998 1-3198 3(a)(iii) 8/4/2000 8-K 1-3198 3.3 1/26/2005 8-K 1-3198 3.3 11/19/2007 Exhibit No. 3.8 3.9 3.10 3.11 3.12 3.13 3.14 4.1 4.2 Exhibit Description Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012 Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect Articles of Incorporation of IDACORP, Inc. Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998 Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998 Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012 Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust: Incorporated by Reference Form File No. 8-K 1-3198 Exhibit No. 3.14 Date Included Herewith 5/21/2012 8-K 1-3198 3.2 3.1 3.2 11/19/2007 11/4/1998 11/4/1998 333-64737 333-64737 333-00139- 99 3(b) 9/22/1998 1-14465 3.13 5/21/2012 S-3 S-3 Amend. No. 1 S-3 Post- Effective Amend. No. 1 8-K 10-Q 1-14465 3.15 10/30/2014 2-3413* B-2 File number 1-MD, as Exhibit B-2-a, First, July 1, 1939* File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943* File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947* File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948* File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949* File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951* File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957* File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957* File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957* File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958* File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958* File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959* File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960* File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961* File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964* File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966* File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966* File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972* File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974* File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974* File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974* File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976* File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978* File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979* File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981* File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982* File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986* File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989* File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990* File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991* File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991* 140 Exhibit No. Exhibit Description Incorporated by Reference Form File No. Exhibit No. Date Included Herewith File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992* File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993* File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993* File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000 File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001 File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003 File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003 File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty- ninth, October 1, 2003 File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005 File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006 File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007 File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007 File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008 File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010 File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010 File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013 File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 10.1 10.2 10.3 10.4 Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.16) Agreement of Idaho Power Company to furnish certain debt instruments Agreement of IDACORP, Inc. to furnish certain debt instruments Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating Corporation Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010 Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rights Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 10-Q 1-3198 4(b) 8/4/2000 S-3 33-65720* 4(f) 7/7/1993 10-Q 1-14465 4(c)(ii) 11/6/2003 S-3 Post- Effective Amend. No. 2 8-K 33-00440* 2(a)(iii) 6/30/1989 1-14465 4.1 2/28/2001 8-K 1-14465 4.2 2/28/2001 S-3 333-67748 4.13 8/16/2001 10-Q 1-3198 4.12 8/5/2010 10-K 10-K 1-14465, 1-3198 1-14465, 1-3198 10.4 2/19/2015 10.5 2/19/2015 S-3 33-65720* 10(h) 7/7/1993 S-3 33-65720* 10(h)(i) 7/7/1993 141 Incorporated by Reference Form File No. S-3 33-65720* Exhibit No. 10(h)(ii) Date Included Herewith 7/7/1993 10-Q 1-14465* 10.58 5/7/2009 S-3 33-65720* 10(m) 7/7/1993 8-K 1-14465, 1-3198 10.1 11/9/2015 8-K 1-14465, 1-3198 10.2 11/9/2015 10-K 1-14465, 1-3198 10.20 2/23/2017 10-K 1-14465, 1-3198 10.21 2/23/2017 10-K 1-14465, 1-3198 10.12 2/22/2018 Exhibit No. 10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 Exhibit Description Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.3 Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company Limited Credit Agreement, dated November 6, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein Credit Agreement, dated November 6, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein Letter Agreement, effective as of November 7, 2016, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement Letter Agreement, effective as of November 7, 2016, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement Letter Agreement, effective as of November 7, 2017, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement 142 Exhibit No. 10.13 10.14 10.15 10.16 10.171 10.181 10.191 10.201 10.211 10.221 10.231 10.241 10.251 10.261 10.271 10.281 10.291 10.301 Exhibit Description Letter Agreement, effective as of November 7, 2017, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company Guaranty Agreement, dated February 10, 1992, between Idaho Power Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008 Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017 Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017 Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006 IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 16, 2017 Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006 Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006 Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008 Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008 Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010 IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 19, 2019 IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017 IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting) 143 Incorporated by Reference Form File No. 10-K 1-14465, 1-3198 Exhibit No. 10.13 Date Included Herewith 2/22/2018 8-K S-3 1-3198 10.1 10/10/2006 33-65720* 10(m)(i) 7/7/1993 10-Q 1-3198 10(c) 8/4/2000 10-K 10-Q 10-K 10-Q 10-Q 10-K 10-Q 10-Q 10-K 10-K 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 10.15 2/26/2009 10.62 11/1/2012 10.31 2/23/2017 10.1 8/3/2017 1-14465, 1-3198 10(h) (viii) 11/2/2006 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 10.22 2/22/2018 10(h) (xix) 10(h) (xx) 11/2/2006 11/2/2006 10.24 2/26/2009 10.25 2/26/2009 8-K 1-14465, 1-3198 10.1 3/24/2010 10-K 1-14465, 1-3198 10.41 2/23/2017 X X Exhibit No. 10.311 10.321 10.331 10.341 10.351 10.361 10.371 10.381 10.391 10.401 10.411 10.421 10.431 10.441 10.451 10.461 10.471 10.481 10.491 10.501 21.1 23.1 23.2 31.1 31.2 31.3 31.4 Exhibit Description IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal) IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal) IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting) (For 2017 and 2018 Outstanding Awards) IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal) (For 2017 and 2018 Outstanding Awards) IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal) (For 2017 and 2018 Outstanding Awards) IDACORP, Inc. Executive Incentive Plan, as amended and restated November 14, 2018 Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008 IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 2019 Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement (November 16, 2008) Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred Compensation Agreement (November 16, 2008) Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016 Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016 Second Amendment to the Idaho Power Company Employee Savings Plan, as amended January 1, 2018 Third Amendment to the Idaho Power Company Employee Savings Plan, as amended April 26, 2018 Subsidiaries of IDACORP, Inc. Consent of Registered Independent Accounting Firm Consent of Registered Independent Accounting Firm IDACORP, Inc. Rule 13a-14(a) CEO certification IDACORP, Inc. Rule 13a-14(a) CFO certification Idaho Power Rule 13a-14(a) CEO certification Idaho Power Rule 13a-14(a) CFO certification 144 Incorporated by Reference Form File No. Exhibit No. Date Included Herewith X 10-K 10-K 10-K 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 10.42 2/23/2017 10.43 2/23/2017 10.44 2/23/2017 10-K 1-14465, 1-3198 10.32 2/26/2009 10-K 10-K 10-K 10-K 10-K 10-K 10-K 10-K 10-K 10-K 10-Q 10-Q 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 1-14465, 1-3198 10.46 2/26/2009 10.47 2/26/2009 10.48 2/26/2009 10.49 2/26/2009 10.50 2/26/2009 10.51 2/26/2009 10.52 2/26/2009 10.53 2/26/2009 10.59 2/18/2016 10.61 2/23/2017 10.1 11/2/2017 10.4 5/3/2018 X X X X X X X X X X Exhibit No. 32.1 32.2 32.3 32.4 95.1 Exhibit Description IDACORP, Inc. Section 1350 CEO certification IDACORP, Inc. Section 1350 CFO certification Idaho Power Section 1350 CEO certification Idaho Power Section 1350 CFO certification Mine Safety Disclosures 101.INS XBRL Instance Document 101.SCH XBRL Taxonomy Extension Schema Document 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document 101.LAB XBRL Taxonomy Extension Label Linkbase Document 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document 101.DEF XBRL Taxonomy Extension Definition Linkbase Document Incorporated by Reference Form File No. Exhibit No. Date Included Herewith X X X X X X X X X X X * Exhibit originally filed with the U.S. Securities and Exchange Commission in paper format and as such, a hyperlink is not available. (1) Management contract or compensatory plan or arrangement 145 IDACORP, INC. SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF COMPREHENSIVE INCOME Income: Equity in income of subsidiaries Investment income Total income Expenses: Operating expenses Interest expense Other expenses Total expenses Income Before Income Taxes Income Tax Benefit Net Income Attributable to IDACORP, Inc. Other comprehensive income (loss) Comprehensive Income Attributable to IDACORP, Inc. 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 $ $ $ 226,567 865 227,432 $ 211,974 26 212,000 198,061 3 198,064 668 713 — 1,381 226,051 (750) 226,801 8,120 234,921 $ 708 294 30 1,032 210,968 (1,451) 212,419 (5,990) 206,429 $ 716 333 45 1,094 196,970 (1,318) 198,288 394 198,682 The accompanying note is an integral part of these statements. IDACORP, INC. CONDENSED STATEMENTS OF CASH FLOWS Operating Activities: Net cash provided by operating activities Investing Activities: Net cash provided by (used in) investing activities Financing Activities: Dividends on common stock Decrease in short-term borrowings Change in intercompany notes payable Other Net cash used in financing activities Net increase in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year 2018 Year Ended December 31, 2017 (thousands of dollars) 2016 $ 197,185 $ 113,849 $ 139,077 — — — (121,421) — (2,867) (3,614) (127,902) 69,283 29,617 98,900 $ (113,127) — 17,097 (3,321) (99,351) 14,498 15,119 29,617 $ (104,985) (20,000) 2,421 (3,422) (125,986) 13,091 2,028 15,119 $ The accompanying note is an integral part of these statements. 146 IDACORP, INC. CONDENSED BALANCE SHEETS Assets Current Assets: Cash and cash equivalents Receivables Other Total current assets Investment in subsidiaries Other Assets: Deferred income taxes Other Total other assets Total assets Liabilities and Shareholders’ Equity Current Liabilities: Accounts payable Taxes accrued Other Total current liabilities Other Liabilities: Intercompany notes payable Other Total other liabilities IDACORP, Inc. Shareholders’ Equity Total Liabilities and Shareholders' Equity December 31, 2018 2017 (thousands of dollars) $ $ 98,900 2,046 98 101,044 29,617 52,359 98 82,074 2,294,464 2,189,017 17,593 277 17,870 34,040 374 34,414 $ 2,413,378 $ 2,305,505 $ — $ 8,354 899 9,253 17 17,423 626 18,066 32,929 836 33,765 2,370,360 2,413,378 35,140 914 36,054 2,251,385 $ 2,305,505 $ The accompanying note is an integral part of these statements. NOTE TO CONDENSED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Pursuant to rules and regulations of the U.S. Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2018 Form 10-K, Part II, Item 8. Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $124 million, $116 million, and $108 million in 2018, 2017, and 2016, respectively. 147 IDACORP, INC. SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2018, 2017, and 2016 Classification 2018: Reserves deducted from applicable assets: Reserve for uncollectible accounts Reserve for uncollectible notes Other Reserves: Injuries and damages 2017: Reserves deducted from applicable assets: Reserve for uncollectible accounts Reserve for uncollectible notes Other Reserves: Injuries and damages 2016: Reserves deducted from applicable assets: Reserve for uncollectible accounts Reserve for uncollectible notes Other Reserves: Injuries and damages Additions Balance at Beginning of Year Charged to Income Charged (Credited) to Other Accounts Deductions(1) Balance at End of Year (thousands of dollars) $ $ $ $ 2,193 402 $ 3,363 — $ 392 — $ 3,959 — 1,469 855 — 447 $ 1,132 402 $ 5,753 — $ 324 — $ 5,016 — 1,792 687 — 1,010 $ 1,355 552 $ 3,917 — $ 263 — $ 4,403 150 1,874 848 — 930 1,989 402 1,877 2,193 402 1,469 1,132 402 1,792 (1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, and notes reserves, includes reversals of amounts previously reserved. 148 IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2018, 2017, and 2016 Additions Balance at Beginning of Year Charged to Income Charged (Credited) to Other Accounts Deductions(1) Balance at End of Year (thousands of dollars) Classification 2018: Reserves deducted from applicable assets: Reserve for uncollectible accounts $ 2,193 $ 3,363 $ 392 $ 3,959 $ 1,989 Other Reserves: Injuries and damages 2017: Reserves deducted from applicable assets: 1,469 855 — 447 1,877 Reserve for uncollectible accounts $ 1,132 $ 5,753 $ 324 $ 5,016 $ 2,193 Other Reserves: Injuries and damages 2016: Reserves deducted from applicable assets: 1,792 687 — 1,010 1,469 Reserve for uncollectible accounts $ 1,355 $ 3,917 $ 263 $ 4,403 $ 1,132 Other Reserves: Injuries and damages 1,874 848 — 930 1,792 (1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, includes reversals of amounts previously reserved. 149 None. ITEM 16. FORM 10-K SUMMARY SIGNATURES Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. February 21, 2019 Date IDACORP, INC. By: /s/ Darrel T. Anderson Darrel T. Anderson President and Chief Executive Officer 150 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature /s/ Robert A. Tinstman Robert A. Tinstman /s/ Darrel T. Anderson Darrel T. Anderson President and Chief Executive Officer and Director /s/ Steven R. Keen Steven R. Keen Senior Vice President, Chief Financial Officer, and Treasurer /s/ Kenneth W. Petersen Kenneth W. Petersen Vice President, Controller, and Chief Accounting Officer /s/ Thomas Carlile Thomas Carlile /s/ Richard J. Dahl Richard J. Dahl /s/ Annette G. Elg Annette G. Elg /s/ Ronald W. Jibson Ronald W. Jibson /s/ Judith A. Johansen Judith A. Johansen /s/ Dennis L. Johnson Dennis L. Johnson /s/ Christine King Christine King /s/ Richard J. Navarro Richard J. Navarro Title Date Chairman of the Board February 21, 2019 (Principal Executive Officer) February 21, 2019 (Principal Financial Officer) February 21, 2019 (Principal Accounting Officer) February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 Director Director Director Director Director Director Director Director 151 Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES February 21, 2019 Date Idaho Power Company By: /s/ Darrel T. Anderson Darrel T. Anderson President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature /s/ Robert A. Tinstman Robert A. Tinstman /s/ Darrel T. Anderson Darrel T. Anderson President and Chief Executive Officer and Director /s/ Steven R. Keen Steven R. Keen Senior Vice President, Chief Financial Officer, and Treasurer /s/ Kenneth W. Petersen Kenneth W. Petersen Vice President, Controller, and Chief Accounting Officer /s/ Thomas Carlile Thomas Carlile /s/ Richard J. Dahl Richard J. Dahl /s/ Annette G. Elg Annette G. Elg /s/ Ronald W. Jibson Ronald W. Jibson /s/ Judith A. Johansen Judith A. Johansen /s/ Dennis L. Johnson Dennis L. Johnson /s/ Christine King Christine King /s/ Richard J. Navarro Richard J. Navarro Title Date Chairman of the Board February 21, 2019 (Principal Executive Officer) February 21, 2019 (Principal Financial Officer) February 21, 2019 (Principal Accounting Officer) February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 February 21, 2019 Director Director Director Director Director Director Director Director 152 IDACORP INC. & IDAHO POWER ( ) total years of service FOR YOUR REFERENCE Darrel T. Anderson (23) President and Chief Executive Offi cer Brian R. Buckham (8) Senior Vice President and General Counsel Patrick A. Harrington (33) Corporate Secretary Steven R. Keen (36) Senior Vice President, Chief Financial Offi cer and Treasurer Jeffrey L. Malmen (11) Senior Vice President of Public Affairs Ken W. Petersen (20) Vice President, Controller and Chief Accounting Offi cer IDAHO POWER Lisa A. Grow (31) Senior Vice President and Chief Operating Offi cer Jeffrey S. Glenn (3) Vice President of Information Technology and Chief Information Offi cer Tessia Park (21) Vice President of Power Supply N. Vern Porter (29) Vice President of Transmission & Distribution Engineering and Chief Safety Offi cer Adam J. Richins (7) Vice President of Customer Operations and Business Development Tim E. Tatum (23) Vice President of Regulatory Affairs IDACORP, Inc., Boise, Idaho-based and formed in 1998, is a holding company composed of Idaho Power, a regulated energy company; IDACORP Financial, a holder of affordable housing projects and other real estate investments; and Ida-West Energy, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978. Idaho Power began operations in 1916 and employs approximately 2,000 people to serve a 24,000-square-mile service area in southern Idaho and eastern Oregon. With 17 low-cost hydroelectric projects as the core of its generation portfolio, Idaho Power’s nearly 560,000 residential, business and agricultural customers pay some of the nation’s lowest prices for electricity. To learn more about IDACORP or Idaho Power, visit idacorpinc.com or idahopower.com. Forward-Looking Statements: Please refer to IDACORP’s and Idaho Power’s Annual Report on Form 10-K for a description of the risks and uncertainties related to the forward-looking statements included in this Annual Report. Dividend Payment Dates IDACORP, Inc. common stock dividends are paid quarterly on or about the 28th of February, and the 30th of May, August and November. Transfer Agent/Registrar For IDACORP, Inc. Common Stock EQ Shareowner Services 1110 Centre Pointe Curve, Suite 101 Mendota Heights, MN 55120 1-800-565-7890 Common Stock Information Ticker symbol: IDA Listed: New York Stock Exchange, 11 Wall St. New York, NY 10005 Contacts Broker/Analyst Contact: Justin S. Forsberg Director of Investor Relations Phone: 208-388-2728, Fax: 208-433-4782 Email: jforsberg@idacorpinc.com Shareowner Contact: Colette Shepard Phone: 1-800-635-5406, 208-388-2564, Fax: 208-388-6955 Email: cshepard@idacorpinc.com Corporate Headquarters Mailing: P.O. Box 70, Boise, ID 83707-0070 Street: 1221 W. Idaho St., Boise, ID 83702-5627 Phone: 208-388-2200 Website: idacorpinc.com SEC Form 10-K The IDACORP, Inc. and Idaho Power combined Form 10-K has been fi led with the Securities and Exchange Commission. The Form 10-K and this Annual Report to Shareholders also are available on our website at idacorpinc.com. This report is prepared for the information of shareholders of the company and is not to be used by others in connection with any sale, offer for sale or solicitation of any offer to buy any securities. 2019 Annual Meeting The 2019 Annual Meeting of Shareholders will be held at Idaho Power’s corporate headquarters, 1221 W. Idaho St., Boise, Idaho at 10 a.m. local time on Thursday, May 16, 2019. Formal notice of the meeting will be mailed to shareholders on or about Monday, April 1, 2019. COMPARISON OF CUMULATIVE TOTAL RETURN $100 Invested Dec. 31, 2013 Period Ended Dec. 31, 2018 2018 Annual REPORT 2 0 1 8 I D A C O R P A n n u a l R e p o r t P.O. Box 70 Boise, ID 83707-0070 idacorpinc.com 

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