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, 2019, IDACORP had 1,985 full-time employees, 1,976 of whom were employed by Idaho Power, and 8 part-time employees, 6 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 hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.
Available Information
IDACORP and Idaho Power make available free of charge on their websites their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC). IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com. The contents of these websites are not part of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Annual Report).
UTILITY OPERATIONS
Background
Idaho Power provided electric utility service to approximately 572,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2019. Approximately 477,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, health care, government, and education. Idaho Power also provides irrigation customers with electric utility service to operate irrigation pumps during the agricultural growing season. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 72 cities in Idaho and 7 cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and 3 counties in Oregon. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of 1.3 million.
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, hydropower project relicensing, and system reliability, among other items.
Regulatory Accounting
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation, with the impacts of rate regulation reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. These principles sometimes result in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates or when otherwise directed to begin amortization by a regulator. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. Idaho Power records regulatory assets or liabilities if it expects the amounts will be reflected in future prices, based on regulatory orders or other available evidence.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective
income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that the amounts will be recovered from or returned to customers in future rates.
Business Strategy
IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. 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:
In executing the focus areas above, IDACORP seeks to balance the interests of shareholders, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results and strong credit ratings by continuing to provide safe, fair-priced, reliable service to its customers from a diversified source of generation resources.
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.
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 deferred or accrued under specific authorization from the IPUC or OPUC. Deferred amounts are generally collected from and accrued amounts are generally refunded to retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. 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 over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery may be capped at 3 percent of base revenue annually at the discretion of the IPUC, with any excess deferred for collection in a subsequent year. Idaho Power collects most of its energy efficiency program costs through energy efficiency riders on customer bills.
Wholesale Markets: Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 hydropower generation facilities are operated to optimize the water that is available by choosing when to run hydropower generation units and when to store water in reservoirs. Idaho Power at times operates these and its other generation facilities to take advantage of market opportunities. These decisions affect the timing and volumes of market purchases and market sales. Even in below-normal water years, there are opportunities to vary water usage to capture wholesale marketplace economic benefits, maximize generation unit efficiency and meet peak loads. Compliance factors such as allowable river stage elevation changes and flood control requirements also influence these generation dispatch decisions. Idaho Power's wholesale energy sales depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as market power prices at the time when those resources are available. A reduction in either factor leads to lower wholesale energy sales.
Idaho Power’s OATT rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1. The FERC oversees mandatory transmission and network reliability standards, as well as power and transmission markets, including protection against market manipulation. These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, which have responsibility for compliance and enforcement of transmission and reliability standards.
Retail Energy Sales: Weather, seasonal customer demand, energy efficiency, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned, and associated expenses are not incurred, evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak during the winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and mild temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could continue to alter demand for Idaho Power's electric energy. Approximately 95 percent of Idaho Power’s retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.”
The table that follows presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type.
(1)
The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers as disclosed in Note 4 - “Revenues” to the consolidated financial statements included in this report.
(2)
The IPUC allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the Hells Canyon Complex (HCC) relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation, described in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report, Idaho Power was collecting $10.7 million annually.
Competition: Idaho Power's electric utility business has historically been recognized as a natural monopoly. Idaho Power 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.
Power Supply
Overview: Idaho Power primarily relies on company-owned hydropower, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Market purchases and sales are used to supplement Idaho Power's generation and balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
Weather, load demand, supply constraints, economic conditions, and availability of generation resources impact power supply costs. Idaho Power’s annual hydropower generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydropower generation conditions increase production at Idaho Power’s hydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Economic conditions and governmental regulations can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the financial impacts to Idaho Power of volatile fuel and power costs.
Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. Idaho Power reached its highest all-time system peak demand of 3,422 megawatts (MW) on July 7, 2017. Idaho Power's highest all-time winter peak demand of 2,527 MW was last achieved on January 6, 2017. During these and other similarly heavy load periods, Idaho Power’s system is fully committed to serve load and meet required operating reserves. The table that follows shows Idaho Power’s total power supply for the last three years.
Hydropower Generation: Idaho Power operates 17 hydropower projects located on the Snake River and its tributaries. Together, these hydropower facilities provide a total nameplate capacity of 1,796 MW and annual generation of approximately 8.7 million MWh under median water conditions. The amount of water available for hydropower generation depends on several factors-the amount of snowpack in the mountains upstream of Idaho Power’s hydropower facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summer time irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s hydropower projects on the Snake River.
In 2019 and 2018, reservoir storage carryover from the previous year coupled with near-normal winter snowpack resulted in 8.3 million MWh and 8.7 million MWh of hydropower generation, respectively. In 2017, above normal winter and spring precipitation resulted in 8.9 million MWh of hydropower generation. During low water years, when stream flows into Idaho Power’s hydropower projects are reduced, Idaho Power’s hydropower generation is reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. For 2020, Idaho Power estimates annual generation from its hydropower facilities will be between 6.5 million MWh and 8.5 million MWh.
Idaho Power obtains licenses for its hydropower projects from the FERC, similar to other utilities that operate nonfederal hydropower projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental agencies. The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the HCC, its largest hydropower
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 Hydropower Projects.”
Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydropower projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include, among other items, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, and possible takeover of a project after expiration of its license upon payment of net investment and severance damages.
Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants:
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Jim Bridger, located in Wyoming, in which Idaho Power has a one-third interest;
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North Valmy, located in Nevada, in which Idaho Power has a 50 percent interest; and
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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. Idaho Power expects to meet 2020 fuel requirements through existing inventory and coal contracts and expects to be able to meet future coal requirements through new or existing coal supply contracts. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the North Valmy plant. Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019, as planned, and plans to end its participation in unit 2 by December 31, 2025.
Portland General Electric Company is the operator of the Boardman power plant. Idaho Power believes that it has sufficient inventory and coal contracts to supply the Boardman plant with fuel through 2020. As approved by the Oregon Environmental Quality Commission, Idaho Power plans to cease coal-fired operations at the Boardman power plant no later than December 31, 2020. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the Boardman power plant.
Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined cycle power plant and the Danskin and Bennett Mountain natural gas-fired simple cycle combustion turbine power plants. All three plants are located in Idaho.
Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is transported through the Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. These transportation agreements vary in contract length but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. This firm storage contract expires in 2043. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
As of December 31, 2019, Idaho Power had approximately 12.6 million MMBtu of natural gas financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through July 2021. Idaho Power plans to manage the procurement of additional natural gas for the peaking units on the daily spot market or from storage inventory as necessary to meet system requirements and fueling strategies.
Purchased Power: As described below, Idaho Power purchases power in the wholesale market as well as 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 2019 and 2018, Idaho Power purchased 1.6 million MWh and 1.8 million MWh of power through wholesale market purchases at an average cost of $21.95 per MWh and $28.82 per MWh, respectively. During both 2019 and 2018, Idaho Power sold 2.2 million MWh of power in wholesale market sales, with an average price of $32.80 per MWh and $23.53 per MWh, respectively.
Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has the following notable long-term power purchase contracts and energy exchange agreements:
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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.
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USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs Unit #1 geothermal power plant located near Vale, Oregon. The contract term ends in 2037.
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Clatskanie People's Utility - for up to 18 MW of generation from the Arrowrock hydropower project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The contract term ends in 2020. Idaho Power has the right to renew the agreement for an additional five-year term.
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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.
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Jackpot Holdings LLC - a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility, with an expected in-service date in 2022. The agreement was approved by the IPUC in December 2019 and is, as of the date of this report, pending approval by the OPUC.
PURPA Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA qualifying facilities as mandated by federal law. As of December 31, 2019, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of 1,136 MW of nameplate generation capacity, with an additional 11 MW nameplate capacity of projects projected to be on-line by 2022. The energy sales agreements for these qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA qualifying facilities during the last three years is included in the following table:
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:
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Idaho Power is required to purchase all of the output delivered from the contracted qualifying facilities, subject to some exceptions such as adverse impacts on system reliability.
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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 adjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.
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OPUC jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years.
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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 using an avoided cost methodology based on IPUC regulations.
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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.
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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 using an avoided cost methodology based on OPUC regulations.
Participation in Western Energy Imbalance Market: In April 2018, Idaho Power began participating in an energy imbalance market in the western United States (Western EIM) under which the participating parties enabled their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States.
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 project is a proposed 300-mile, high-voltage transmission line between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West project is a proposed 1,000-mile, high-voltage transmission lines project between a station located near Douglas, Wyoming and the Hemingway station. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 - MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.
Resource Planning
Integrated Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP). Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2019, which was amended in January 2020. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission resource options, and identifies potential near-term and long-term actions. The four primary goals of the IRP are to:
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identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;
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ensure the selected resource portfolio balances cost, risk, and environmental concerns;
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give equal and balanced treatment to supply-side, demand-side, and transmission resources; and
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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.
The load forecast assumptions Idaho Power used in its 2019 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads.
As noted above, on January 31, 2020, Idaho Power amended the originally filed 2019 IRP with additional information and modeling results. The updated 2019 IRP identified a preferred resource portfolio and action plan, which includes the completion of the Boardman-to-Hemingway transmission line in 2026, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger plant by 2030, including the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the addition of a 120-MW solar resource in 2022. However, as noted in the 2019 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These uncertainties, as well as others, will likely result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. As of the date of this report, proceedings relating to the amended 2019 IRP are pending at the IPUC and OPUC.
Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 27 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:
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financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
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energy efficiency programs for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, air duct sealing, and energy efficient lighting;
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incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes;
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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
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participation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.
In 2019, Idaho Power’s energy efficiency programs reduced energy usage by approximately 205,000 MWh compared with 173,000 in 2018. For 2019, Idaho Power had a demand response available capacity of approximately 397 MW. In 2019, 2018, and 2017, Idaho Power expended approximately $49 million, $44 million, and $48 million, respectively, on both energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the power cost adjustment mechanisms. Energy efficiency program expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.
Environmental, Social, and Governance Initiatives
IDACORP’s and Idaho Power’s boards of directors are responsible for the oversight of the companies’ environmental, social, and governance (ESG) initiatives and are regularly informed of the goals, measures, and results of the companies' ESG and sustainability programs. IDACORP and Idaho Power publicly release annual sustainability reports and the most current sustainability report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power. The sustainability reports and related website content are not incorporated by reference into this 2019 Annual Report. IDACORP’s and Idaho Power’s ESG initiatives include:
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establishing responsible management goals to related to the companies’ impact on the environment, such as
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the "Clean Today, Cleaner Tomorrow.®" goal to provide Idaho Power's customers with 100-percent clean energy by 2045,
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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,
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continuing various environmental stewardship programs along the Snake River, including fish habitat preservation and restoration,
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wildfire mitigation planning and actions, and
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wildlife habitat, archaeological and cultural resource, and raptor protection stewardships.
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operational excellence in providing reliable, fair priced, and clean energy,
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engaging and empowering Idaho Power’s workforce (including succession planning at all levels, employee development, retirement planning education, and providing competitive pension benefits),
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promoting a culture of safety and inclusiveness for all employees, and
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building strong community partnerships for healthy economic development in Idaho Power’s service area.
Voluntary CO2 Emissions Intensity Reduction Goal: Idaho Power is engaged in voluntary greenhouse gas (GHG) emissions intensity reduction efforts. In 2013, IDACORP's and Idaho Power's boards of directors extended a goal they originally established in 2009, seeking to reduce the company-owned resource portfolio average carbon dioxide (CO2) emissions intensity to 15-20 percent below 2005 levels of 1,194 lbs CO2/MWh for the 2010-2017 cumulative period. Idaho Power has achieved and furthered the reduction goal several times, which now extends through 2020. Through 2019, Idaho Power was beating its current C02 emissions intensity goal, with an average reduction of 29 percent since 2010.
Idaho Power's estimated historic CO2 emissions intensity from its generation facilities is as follows (in lbs CO2/MWh):
Reduction in Coal-Fired Generation: Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. Continued review of the economic appropriateness of further investments in coal-fired plants was included in an IPUC order in February 2014, in which the IPUC requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning and promptly apprise the IPUC of developments that could impact the company's continued reliance on the North Valmy plant as a coal-fired resource. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy plant in connection with Idaho Power's plan to end its participation in the operation of units 1 and 2. Idaho Power ended its participation in the operation of unit 1 in December 2019, as planned, and plans to end its participation in unit 2 by December 31, 2025. The plan to end Idaho Power's participation in operations of units 1 and 2 at the North Valmy plant was based primarily on the economics of operating the plant. The settlement stipulations are described in Part II, Item 7 - MD&A - "Regulatory Matters” in this report.
Environmental Regulation and Costs
Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with
permits and licenses. In addition to generally applicable regulations, Idaho Power's three co-owned coal-fired power plants, three natural gas combustion turbine power plants, and 17 hydropower generating plants are subject to a broad range of environmental requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Item 7 - MD&A - "Environmental Matters" in this report.
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):
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. At December 31, 2019, the unamortized amount of IFS’s portfolio was approximately $4 million ($126 million in gross tax credit investments, net of $122 million of accumulated amortization). IFS generated tax credits of $2.9 million in 2019 and $2.6 million in both 2018 and 2017. In 2019, 2018, and 2017, IFS received distributions related to fully-amortized affordable housing investments that reduced IDACORP's income tax expense by $3.2 million, $0.3 million, and $1.1 million, respectively.
IDA-WEST ENERGY COMPANY
Ida-West operates and has a 50 percent ownership interest in nine hydropower projects that have a total nameplate capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydropower projects at a cost of approximately $9 million in 2019 and $10 million in both 2018 and 2017.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
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.
RYAN N. ADELMAN, 45
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Vice President of Transmission & Distribution, Engineering and Construction, October 2019 - present
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Regional Manager for the Southeast Region of Idaho Power Company, January 2018 - October 2019
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Transmission & Distribution Projects Senior Manager of Idaho Power Company, January 2015 - December 2017
DARREL T. ANDERSON, 61
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Chief Executive Officer of Idaho Power Company, January 2014 - present
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President and Chief Executive Officer of IDACORP, Inc., May 2014 - present
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President and Chief Executive Officer of Idaho Power Company, January 2014 - September 2019
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Member of the Boards of Directors of IDACORP, Inc. and Idaho Power Company since September 2013
BRIAN R. BUCKHAM, 41
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Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - present
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Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - February 2017
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In-house legal counsel of IDACORP, Inc. and Idaho Power Company, April 2010 - March 2016
SARAH E. GRIFFIN, 50
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Vice President of Human Resources of Idaho Power Company, October 2019 - present
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Director of Human Resources of Idaho Power Company, May 2014 - October 2019
LISA A. GROW, 54
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President of Idaho Power Company, October 2019 - present
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Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - October 2019
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Senior Vice President of Operations of Idaho Power Company, January 2016 - March 2016
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Senior Vice President - Power Supply of Idaho Power Company, October 2009 - December 2015
JAMES BO D. HANCHEY, 44
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Vice President of Customer Operations and Chief Safety Officer of Idaho Power Company, October 2019 - present
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Customer Service Senior Manager of Idaho Power Company, February 2018 - October 2019
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Regional Manager of Southern Region of Idaho Power Company, May 2014 - February 2018
STEVEN R. KEEN, 59
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Senior Vice President - Chief Financial Officer, and Treasurer of IDACORP, Inc., May 2014 - present
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Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 2014 - present
JEFFREY L. MALMEN, 52
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Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present
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Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, October 2008 - March 2016
TESSIA PARK, 58
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Vice President of Power Supply of Idaho Power Company, January 2016 - present
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Director of Load Serving Operations of Idaho Power Company, September 2012 - December 2015
KEN W. PETERSEN, 56
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Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - present
ADAM RICHINS, 41
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Senior Vice President and Chief Operating Officer of Idaho Power Company, October 2019 - present
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Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - October 2019
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General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017
ITEM 1A.
ITEM 1A. RISK FACTORS
IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below should not be considered a complete list of potential risks that the companies may encounter. These risk factors may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Matters Impacting Future Results" in this report, and information in other reports the companies file with the SEC, may be important to understanding any statement in this 2019 Annual Report or elsewhere and should be considered carefully when making any investment decisions relating to IDACORP or Idaho Power.
IDACORP's and Idaho Power's businesses regularly face risks, many of which may cause future results to be different than anticipated as of the date of this report. Below are certain important utility-specific regulatory, operational, legal and compliance, financial and investment, and general business risks. IDACORP's and Idaho Power's reactions to material future developments as well as the utility industry's reactions to those developments may also impact the Companies' future results.
Utility-Specific Regulatory Risks
Utility-specific regulatory risk includes the risks that federal, state, or local regulators may impose additional requirements and costs on Idaho Power and the utility industry, or require Idaho Power as a utility to make adverse changes to its business models, strategies, and practices.
State or federal regulators may not approve customer rates that provide timely or sufficient recovery of Idaho Power's costs or allow Idaho Power to earn a reasonable rate of return, which could cause IDACORP's and Idaho Power's financial condition and results of operations to be adversely affected. The prices that the IPUC and OPUC authorize Idaho Power to charge customers for its retail services, and the tariff rate that the FERC permits Idaho Power to charge for its transmission services, are generally the most significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, liquidity, and financial condition. Idaho Power's ability to recover its costs and earn a reasonable rate of return can be affected by many regulatory factors, including the timing difference between when Idaho Power incurs costs and when Idaho Power recovers those costs in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs included in rates and the amount of actual costs incurred. Idaho Power is often required to incur costs before the IPUC, OPUC, or FERC approves the recovery of those costs, such as construction costs for new facilities, changes in the long-term cost-effectiveness or changes to the operating conditions of Idaho Power's assets that could result in early retirements of utility facilities, the costs of compliance with legislative and regulatory requirements, increased funding levels of a defined benefit pension plan, and the costs of damage from fires, weather-related events, and natural disasters. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basis that they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. Ratemaking has generally been premised on estimates of historic costs based on a test year, so if a given year’s actual costs are higher than historic costs, rates may not be sufficient to cover actual costs. While rate regulation is also premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard. Decisions are subject to judicial appeal, which could lead to further uncertainty in regulatory proceedings.
Economic, political, legislative, public policy, or regulatory pressures may lead stakeholders to seek rate reductions or refunds, limits on rate increases, or lower allowed rates of return on investments for Idaho Power. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates. The IPUC and OPUC may adopt different methods of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. Compliance with state and federal regulatory standards may also limit Idaho Power's ability to operate profitably. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings or significant regulatory lag may cause Idaho Power to record an impairment of its assets or otherwise adversely affect cash flows and earnings and result in lower credit ratings, reduced access to capital and higher financing costs, and reductions or delays in planned capital expenditures.
For additional information relating to Idaho Power's state and federal regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Regulatory Matters," and Note 3 - "Regulatory Matters" to the consolidated financial statements of Part II - Item 8 in this report.
Idaho Power's cost recovery mechanisms may not function as intended and are subject to change or elimination, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustment mechanism in Idaho. The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differences between these two amounts is deferred for future recovery from, or refund to, customers through rates. Volatility in power supply costs continues to be significant, in large part due to fluctuations in hydropower generation conditions and high costs for the purchase of renewable energy under mandatory long-term contracts. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. The fixed cost adjustment mechanism is a decoupling mechanism designed to remove a portion of Idaho Power's disincentive to invest in and support energy efficiency activities. This mechanism allows Idaho Power to charge Idaho residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case. The power cost and fixed cost adjustment mechanisms are generally subject to change at the discretion of applicable state regulators, who could decide to modify or eliminate either mechanism in a manner that adversely impacts IDACORP's and Idaho Power's financial condition, cash flows, and results of operations.
Operational Risks
Operational risk relates to risks arising from the systems, assets, processes, people, and external factors that affect the operation of IDACORP's or Idaho Power's businesses.
IDACORP's and Idaho Power's business, financial condition, and results of operations may be negatively affected by changes in customer growth or customer usage. Changes in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, expansion or loss of service area, changes in customer needs and expectations, adoption rates of energy efficiency measures, customer-generated power such as from solar panels and gas-fired generators, demand-side management requirements, regulation or deregulation, and adverse economic conditions. An economic downturn or recession could also negatively impact customer use and reduce revenues and cash flows, thus adversely affecting results of operations. Many electric utilities, including Idaho Power, have experienced a decline in usage per customer, in part attributable to energy efficiency activities. State or federal regulations may be enacted to encourage or require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, legislation to deregulate electric service, and customers seeking alternative sources of energy and electric service. If customers choose to generate their own energy, discontinue a portion or all service from Idaho Power, or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of its services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho residential customers has declined from 1,039 kWh in 2010 to 936 kWh in 2019. Rate mechanisms, such as the Idaho fixed cost adjustment, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's volume-based energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in IDACORP and Idaho Power modifying or eliminating large generation or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.
Conversely, if Idaho Power were to experience an unanticipated increase in the demand for energy through, for example, the rapid addition of new industrial and commercial customers or population growth in the service area, Idaho Power may be required to rely on higher-cost purchased power to meet peak system demand and may need to accelerate investment in additional generation or transmission resources. If the incremental costs associated with the unanticipated changes in loads
exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.
Changes in weather conditions, severe weather, and the impacts of climate change can adversely affect IDACORP's and Idaho Power's operating results and cause them to fluctuate seasonally. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.
Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, droughts, heat waves, fires, floods, snow loading, and other extreme weather events, and impact Idaho Power’s ability to generate or import power on transmission lines from other geographic areas. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and extended or mass outages, increasing costs and other operating and maintenance expenses, including emergency response planning and preparedness expenses, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to higher temperatures are likely to decrease power generation from hydropower plants.
Idaho Power's customers' energy needs vary with weather and to the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require Idaho Power to invest in generating assets and transmission and distribution infrastructure, while decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions creating high energy demand may raise wholesale electricity prices for power that Idaho Power purchases to serve customers, increasing the cost of energy Idaho Power provides to its customers, and at the same time can increase the revenues Idaho Power receives for wholesale market sales of excess generation during regional extreme weather events. Variations in hydropower generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus hydropower in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs.
The costs of repairing and replacing infrastructure or liability for personal injury, loss of life, and property damage from utility equipment that fails as a result of significant weather and weather-related events, including fires, may not be covered in full by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators. In addition, state and federal legislation and regulations have been proposed in recent years; including in the State of Oregon, to limit the severity and impact of climate change, such as imposing mandatory reductions in greenhouse gas emissions, which could increase Idaho Power’s power supply and compliance costs. If financial markets increasingly view climate change or greenhouse gas emissions as a financial or investment risk for electric utilities, it could negatively affect IDACORP's and Idaho Power's ability to access debt and equity capital markets on favorable terms. For additional information relating to legislation, regulations, and legal proceedings related to environmental matters, see Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report.
New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could cause decreased customer energy demand and decreased revenues. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, power storage, and energy efficiency. In particular, in recent years the net cost of solar generation has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar generation. There is potential that customer-owned power generation systems, particularly if coupled with power storage devices, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way
Idaho Power manages its distribution systems, and reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. Advances in technology that reduce the costs of alternative methods of producing electric energy could result in loss of revenue and customers, and may require Idaho Power to make significant expenditure reductions to remain competitive. These changes in technology could also alter the channels through which customers buy or utilize energy, which could reduce Idaho Power's revenues or impact Idaho Power's expenses. A reduction in load, however, would not necessarily reduce Idaho Power's need for ongoing investments in its infrastructure to reliably serve its customers. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency would result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.
Acts or threats of terrorism, cyber attacks, data or physical security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid could require significant expenditures, or result in claims against the companies, and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. Federal regulators have stated that a number of organizations continue to seek opportunities to exploit potential vulnerabilities in the U.S. energy infrastructure and that those attacks have become increasingly frequent and sophisticated. Some of Idaho Power's facilities are deemed "critical infrastructure," in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk electric power system, national economic security, and public health and safety. The possibility that infrastructure facilities, such as generation facilities and electric transmission or distribution facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack, including by nation states or nation state-sponsored groups (whether originating internally or externally), may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Idaho Power's electric transmission systems are part of an interconnected regional grid, and therefore, it faces the risk of causing or being subject to a blackout due to grid disturbances or disruptions on a neighboring interconnected system. Cyber threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power, such as process breakdowns, human error, security architecture or design vulnerabilities, or by third parties, such as computer hackings, cyber attacks, computer viruses, or other destructive or disruptive software, denial of service attacks, social engineering or other malicious activities, or any combination of the foregoing, could result in a degradation or disruption in the energy grid and the services of the companies. Physical or cyber attacks against key suppliers or service providers could have a similar effect on IDACORP and Idaho Power.
Political, economic, social, or financial market instability or damage to or interference with Idaho Power’s operating assets, customers, or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair, or other costs, any of which may materially adversely affect Idaho Power in ways that cannot be predicted as of the date of this report. The breach of certain information technology systems could adversely affect IDACORP's and Idaho Power's ability to correctly record, process and report customer, business, and financial information. Any of these risks could materially affect the companies’ consolidated financial results. These events, and governmental actions in response, could result in a material decrease in revenues and increase costs to protect, repair, and insure Idaho Power's assets and operate its business.
Idaho Power's operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. No security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, human error, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. Any security breaches, such as misappropriation, misuse, leakage, falsification or accidental release or loss of information maintained in IDACORP's and Idaho Power's information technology systems, including customer data, could result in violations of privacy and other laws, financial loss to Idaho Power or to its customers, customer dissatisfaction or diminished customer confidence, damage to Idaho Power’s reputation, and significant litigation and penalty exposure, all of which could materially affect Idaho Power's financial condition and results of operations.
Changes in capital expenditures for infrastructure and the risks associated with permitting and construction of utility infrastructure 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 high-voltage transmission line projects, which are intended to help meet future customer energy demands. Construction projects are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:
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the ability to timely obtain labor or materials at reasonable costs;
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defaults by suppliers and contractors;
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equipment, engineering, and design failures;
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unexpected environmental and geological problems;
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the effects of adverse weather conditions;
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availability of financing;
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load forecasts;
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the ability to obtain and comply with permits and land use rights, and environmental constraints; and
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delays and costs associated with disputes and litigation with third parties.
The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable or unwilling to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.
Factors contributing to lower hydropower generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power derives a significant portion of its power supply from its hydropower facilities. During 2018 and 2019, 65 percent and 62 percent, respectively, of Idaho Power's electric power from Idaho Power-owned generation was from hydropower facilities. Due to Idaho Power’s heavy reliance on hydropower generation, factors such as precipitation and snowpack, the timing of run-off, and the availability of water in the Snake River basin can significantly affect its operations. The combination of a long-term trend of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights reduce Snake River flows available for hydropower generation. When hydropower generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and market power purchases; therefore, costs increase and opportunities for wholesale energy sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydropower generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity.
Idaho Power’s use of coal and natural gas to fuel power generation facilities exposes it to commodity availability and price risk, which can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. As part of its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, regulations related to greenhouse gas emissions, and changes in technology. Natural gas
transportation to Idaho Power's three natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience regulatory, financial, or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power's failure to provide service due to such disruptions may also result in fines, penalties, or cost disallowances through the regulatory process. Idaho Power may not be able to fully or timely recover these increased costs through rates, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.
Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes or attrition, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, wildfires, acts of terrorism or sabotage (both cyber and asset-based), the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties (including tort liability), and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area during high-load periods. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third-parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third-party contractors to perform work on its generation, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, reputational harm, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.
Accidents, terrorist acts, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, uncontrolled release of water from hydropower dams, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could also expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire and increasing the magnitude of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and commonly hot, dry summer conditions, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs in the event there are fires that are deemed to be separate occurrences covered by self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected.
Purchases of power from renewable energy projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. An abundance of intermittent, non-dispatchable generation from renewable energy projects interconnected with Idaho Power's system has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. As of December 31, 2019, Idaho Power had federally-mandated contracts to purchase energy from 127 on-line projects with third parties. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydropower and fossil fuel-fired generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in additional generation. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and revenue and shifts in customer costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. If Idaho Power is unable to timely recover those costs through its power cost adjustment mechanisms or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.
Legal and Compliance Risks
Legal and compliance risk relates to risks arising from government and regulatory action and from legal proceedings and compliance with applicable laws, rules, orders, regulations, policies, and procedures, including those related to financial reporting, environmental, health, and safety, and potential changes in legal requirements.
Changes in legislation, regulation, and government policy may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. Changes in, and uncertainty with respect to, federal, state, and local legislation, regulation, and government policy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals and recently enacted legislation that could have a material impact on IDACORP and Idaho Power include, but are not limited to, tax reform, utility regulation, infrastructure renewal programs, environmental regulation, and modifications to accounting and public company reporting requirements. Further, the proposals and new legislation could have an impact on the rate of growth of Idaho Power’s customers and their willingness to expand operations and increase electric service requirements. Laws, regulations, and policies relating to environmental compliance could change and require IDACORP and Idaho Power and their customers to modify their business strategy or affect their returns on investment by restricting activities and projects or subjecting them to increased compliance costs. Although the United States has not adopted any international or federal greenhouse gas emissions reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. The state of Oregon, for instance, has been pursuing cap-and-trade legislation for greenhouse gas emissions. Idaho Power could also become subject to climate change lawsuits and an adverse outcome could require substantial expenditures and could possibly require payment of damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition, or cash flows if such costs are not recovered through regulated rates. IDACORP and Idaho Power are monitoring the implementation by federal, state, and local governmental authorities of various executive orders and are unable to predict whether and to what extent such actions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.
Changes in income tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for income taxes. Amounts of income tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. These judgments may include estimates for potential outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal, or through litigation. In recent years, state regulatory mechanisms with income tax-related provisions (such as Idaho Power's May 2018 Idaho tax reform settlement stipulation with the IPUC), has significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of potential future income tax proceedings, or the state public utility commissions' treatment of those outcomes, could differ materially from the amounts
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.
In response to state and federal regulatory requirements, judicial decisions and international accords, emissions of greenhouse gases including, most significantly CO2 could be restricted in the future. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that would affect Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
In addition, some environmental regulations are currently subject to litigation and not yet final. As a result of this uncertainty, approaches to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot foresee the potential impacts these regulations would have on Idaho Power's operations or financial condition. Idaho Power is not guaranteed timely or full recovery through customer rates or insurance of costs associated with environmental regulations, environmental compliance, 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. For further discussion of environmental matters that may affect Idaho Power, see "Environmental Matters" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report.
Obligations imposed in connection with hydropower license renewals may require large capital expenditures, increase operating costs, reduce hydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its
largest hydropower generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydropower projects, which may be reflected in hydropower licenses, including for the Hells Canyon Complex. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydropower facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydropower generation available to meet Idaho Power’s generation requirements. Idaho Power cannot predict the requirements that might be imposed during the relicensing process, the financial impact of those requirements, whether a new multi-year license will ultimately be issued, and whether the IPUC or OPUC will allow recovery through rates of the substantial costs incurred in connection with the licensing process and subsequent compliance. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydropower generation, which could negatively affect results of operations and financial condition.
Idaho Power could be subject to penalties, reputational harm, 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 $1.3 million per day per violation. As a utility with a large customer base, Idaho Power is subject to adverse publicity focused on the reliability of its services and the speed with which it is able to respond to electric outages caused by storm damage or other unanticipated events. Adverse publicity could harm the reputations of IDACORP and Idaho Power; may make state legislatures, utility commissions, and other regulatory authorities less likely to view the companies in a favorable light; and may cause Idaho Power to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. The imposition of any of the foregoing 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.
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.
Financial and Investment Risks
Financial and investment risks relate to IDACORP's and Idaho Power's ability to meet financial obligations and mitigate exposure to market risks, including liquidity risks and the ability to raise capital and cost of funding, risks related to credit ratings, credit risk, liquidity, interest rates, and commodity prices.
Volatility or disruptions in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing and ability to execute on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The credit facilities represent commitments by the participating banks to make loans and issue letters of credit. However, the ability and obligation of the participating 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 on favorable terms. Idaho Power's ability to issue long-term debt is also subject to a number of conditions included in an indenture, and Idaho Power's ability to issue long-term debt and commercial paper is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all.
Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper or short-term or long-term debt at reasonable interest rates and terms or at all. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on IDACORP's and Idaho Power's operating results. Changes in interest rates may also impact the fair value of the debt securities in Idaho Power's pension funds, as well as Idaho Power's ability to earn a return on short-term investments of excess cash. Also, while the credit facilities represent a contractual obligation to make loans, one or more of the participating banks may default on their obligations to make loans under, or may withdraw from, the credit facilities.
Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities include financial covenants that limit the amount of debt that can be outstanding as a percentage of total capital, and Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. The companies must also make specified representations in connection with request for loans and it is possible that they may be unable to do so at the time of such request, which would limit or eliminate the obligation of the banks to provide loans. Failure to maintain these representations and covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could limit their ability to pursue certain projects and adversely impact IDACORP's and Idaho Power's financial condition, results of operations, and liquidity.
A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and rate mechanisms, the effectiveness of management, resource risks and power supply costs, and other factors. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. In addition, IDACORP's or Idaho Power's credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access short- and long-term capital under reasonable terms or at all, reduce the pool of potential lenders, increase borrowing costs under existing credit facilities, limit access to the commercial paper market, require the companies to pay a higher interest rate on their debt, limit the ability of IDACORP to declare and make dividends, and require the companies to post additional performance assurance collateral with transaction counterparties. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, IDACORP's and Idaho Power's ability to pursue improvements or acquisitions (including generating capacity and transmission assets, which may be necessary for future growth), financial condition and results of operations could be adversely affected.
Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. The interest rates for any borrowings under IDACORP and Idaho Power’s credit facilities, as amended in November 2019, are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero percent, provided that, an alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available, or if lenders have increased costs due to changes in LIBOR, IDACORP and Idaho Power may suffer from potential increases in interest rates on any borrowings.
Idaho Power’s risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to buy and sell power, natural gas, and transmission service, enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financial hedge transactions to mitigate in part exposure to variable commodity prices. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments used for hedging might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative
instruments, and any such failure to mitigate exposure could result in financial losses. Certain of Idaho Power's purchase or sale, hedging, and derivative agreements may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. Idaho Power has additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts and by vendors for infrastructure development projects. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor or supplier would need to replace the security with an acceptable substitute, which may be impracticable and may expose Idaho Power to losses resulting from a vendor or supplier default. If the security were not replaced, the party could be in default under the contract and Idaho Power's remedies for default may be inadequate to fully compensate Idaho Power for its losses. Forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions that Idaho Power may not be able to collect in customer rates. The FERC may take action to limit volatility in the energy market by imposing price limits or other market restrictions to control market-based rate sales, which could adversely affect the companies' financial results. As a result, risk management actions, or the failure or inability to manage commodity availability and price and counterparty risk, may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations. Further, the bankruptcy or insolvency of a counterparty to commodity or other transactions could impair Idaho Power’s ability to collect amounts receivable from those counterparties, potentially including the ability to collect or retain collateral posted by a counterparty. Idaho Power is a participant in the energy markets, including the Western EIM, and engages in direct and indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the Western EIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the Western EIM to make payments when due on its obligations 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.
The performance of pension and postretirement benefit plan investments, increasing health care costs, and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. Idaho Power's self-insured costs of health care benefits for eligible employees and retirees have increased in recent years and Idaho Power believes these costs will continue to rise. As benefit costs continue to rise, there is no assurance that the IPUC and OPUC will continue to allow recovery.
The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.
If the assumptions underlying coal mine reclamation at Bridger Coal Company and related forecast trust fund growth are materially inaccurate, Idaho Power’s costs could be greater than anticipated or be incurred sooner than anticipated. Bridger Coal Company, a subsidiary of Idaho Power, uses both surface and underground methods to mine coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closure obligations and standards for mining of coal. Bridger Coal Company’s estimate of reclamation liability and bonding obligations is reviewed periodically by Idaho Power’s management committee, audit committee of the board of directors, external and internal auditors, and by government regulators. Idaho
Power funds a trust to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected.
As a holding company, IDACORP does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other means. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiary's actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, tax obligations, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which may reduce or cease payment of dividends at any time. See Note 7 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.
General Risks
General risks include other risks specific to IDACORP and Idaho Power that are not categorized above.
IDACORP's and Idaho Power's activities are concentrated in one industry and in one region, which exposes it to risks from lack of diversification, regional economic conditions, and regional legislation and regulation. IDACORP and Idaho Power do not have diversified operations or sources of revenue. Idaho Power comprises the bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and Idaho Power's future performance, revenues, and collectability of revenues, as well as expenses, will be affected by regional economic conditions, regulatory and legislative activity, weather conditions, and other events and conditions in its service area and in the electric power industry.
The impacts of a retiring workforce with specialized utility-specific functions and the inability to hire qualified third-party vendors could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and 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 2020 and in the near-term. At December 31, 2019, approximately 22 percent of Idaho Power's employees were eligible for regular or early retirement under Idaho Power's defined benefit pension plan. This will require Idaho Power to attract, train, and retain new employees to help prevent a loss of institutional knowledge and avoid a skills gap. Idaho Power does not have employment contracts with its officers or key employees and cannot guarantee that any member of its management or any key employee at the IDACORP parent or any subsidiary level will continue to serve in any capacity for any particular period of time. The loss of skills and institutional knowledge of experienced employees and the failure to hire and the costs associated with attracting, training, and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.
Idaho Power also hires third-party vendors to assist in performing a variety of ordinary business functions, such as power plant maintenance, data warehousing and management, software development and licensing, electric transmission and distribution operations, billing and metering processes, and vegetation management, among other things. In recent years, Idaho Power has experienced increased competition and rising prices for many forms of third-party vendor services. While Idaho Power does not rely entirely on third-party vendors for many of these business functions, the unavailability of such vendors could adversely affect the quality and cost of Idaho Power's electric service and negatively impact its results of operation.
Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board (FASB) and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of
operations nor the timing of such changes. Idaho Power meets the requirements under GAAP to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
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 hydropower generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. As of December 31, 2019, the system also includes approximately 4,830 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 21 transmission substations, 9 switching stations, 31 mixed-use transmission and distribution substations, 185 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,968 pole-miles of distribution lines.
Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for all of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - MD&A - "Regulatory Matters - Relicensing of Hydropower Projects” in this report.
Idaho Power's hydropower projects and other owned and co-owned generating facilities and their nameplate capacities, as of the date of this report, are included in the table below.
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 hydropower plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Refer to Note 11 - “Contingencies” to the consolidated financial statements included in this report.
ITEM 4.
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.
PART II
ITEM 5.
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 14, 2020, there were 8,583 holders of record of IDACORP common stock. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.
For information regarding IDACORP's dividend policy, see Part II - Item 7 - MD&A - "Liquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends see, Note 7 - "Common Stock" to the consolidated financial statements included in this report.
During the quarter ended December 31, 2019, IDACORP effected the following repurchases of common stock:
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, 2014, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI
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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 2018 compared with 2017 can be found in their Annual Report on Form 10-K for the year ended December 31, 2018 (2018 Annual Report). See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2018 Annual Report for further information on the companies' prior period results of operations. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.
INTRODUCTION
IDACORP is a holding company whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity.
Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; and Ida-West Energy Company, an operator of small hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
EXECUTIVE OVERVIEW
IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements and recognitions during 2019 include:
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IDACORP achieved net income growth for a twelfth consecutive year;
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IDACORP provided a 13 percent cumulative annual total shareholder return over the past three years, including share price appreciation and dividends paid;
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Idaho Power's customer count grew 2.5 percent in 2019;
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Idaho Power achieved its lowest ever recorded employee safety incident rate, which was significantly below the national average and the average of peer utilities of similar size;
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Idaho Power reached its highest ever recorded residential customer satisfaction score, the highest of any investor-owned utility in the nation, as rated by an independent third party;
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Idaho Power continued its strong performance in system reliability, slightly behind 2018's record reliability score;
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IDACORP increased its quarterly common stock dividend from $0.63 per share to $0.67 per share, as a part of a 123 percent increase in quarterly dividends approved over the last eight years;
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IDACORP adopted a new dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, an increase from the previous policy adopted in 2011 that targeted a dividend payout ratio of between 50 percent to 60 percent of sustainable earnings;
•
Idaho Power reached an agreement with NV Energy, approved by the IPUC and OPUC, that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and 2025, respectively. As planned, Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019;
•
Idaho Power announced its "Clean Today, Cleaner Tomorrow.®" goal to provide its customers with 100-percent clean energy by 2045; and
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Idaho Power beat its carbon dioxide (CO2) emissions intensity goal, with an average reduction of 29 percent since 2010.
Summary of 2019 Financial Results
The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2019, 2018, and 2017 (in thousands, except earnings per share amounts):
The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2019, from the year ended December 31, 2018 (items are in millions and are before tax unless otherwise noted):
IDACORP's net income increased $6.1 million for 2019 compared with 2018, primarily due to higher net income at Idaho Power and IFS.
Idaho Power's customer growth of 2.5 percent added $18.8 million to Idaho Power's operating income compared with 2018. Lower sales volumes on a per-customer basis decreased operating income by $21.4 million in 2019 compared with 2018, primarily due to lower irrigation sales. Greater precipitation and more moderate spring and summer temperatures in Idaho Power's service area led agricultural irrigation customers to use 12 percent less energy per customer to operate irrigation pumps during 2019 compared with 2018. To a lesser extent, sales volumes on a per-customer basis in 2019 were negatively affected by lower per-customer commercial and industrial sales.
The net decrease in retail revenues per MWh reduced operating income by $2.8 million in 2019 compared with 2018. As provided by the settlement stipulation approved by the IPUC in 2018 related to income tax reform, retail revenues per MWh in 2019 were reduced by $7.4 million of non-cash accruals for future amortization related to regulatory deferrals that would otherwise be a future liability of Idaho customers, compared with a $1.5 million revenue reduction in 2018. In 2018, a corresponding $4.0 million of non-cash accruals were recorded as other O&M expense for the amortization of specified deferrals. The decrease in retail revenues per MWh from these non-cash accruals was partially offset by changes in the customer sales mix, as volumes sold to residential customers in 2019 made up a greater portion of the customer sales mix compared with 2018. Residential customers generally pay a higher per-MWh rate than other customers.
During 2019, transmission wheeling-related revenues decreased $5.3 million compared with 2018. Idaho Power's open access transmission tariff (OATT) rates decreased 10 percent in October 2018 and 13 percent in October 2019. To a lesser extent, lower volumes also reduced transmission wheeling-related revenues.
Other O&M expenses were $8.7 million lower in 2019 compared with 2018, as Idaho Power's continued focus on managing other O&M expenses resulted in lower expenses across a number of areas. Lower bad debt expense reduced other O&M expenses by $1.1 million, due primarily to enhanced collection efforts and a strong economy. Also, other O&M expenses in 2018 included $4.0 million of non-cash amortization expense of regulatory deferrals pursuant to the settlement stipulation approved by the IPUC in 2018 related to income tax reform.
Based on its 2019 Idaho ROE, Idaho Power recorded no additional ADITC amortization or provision against current revenues for sharing of earnings with customers in 2019 under the Idaho regulatory settlement stipulation approved in October 2014. In 2018, Idaho Power recorded a $5.0 million provision against revenues for sharing of earnings with customers.
Non-operating income and expenses, net, increased $9.9 million in 2019 compared with 2018. As disclosed in Note 12 - "Benefit Plans" to the consolidated financial statements included in this report, a temporary deviation from an Idaho Power substantive postretirement plan resulted in a $4.2 million charge in 2018 that did not recur in 2019. Allowance for equity funds used during construction increased $2.8 million in 2019 as the average construction work in progress balance was higher throughout 2019 compared with 2018. Also, investment income from the Rabbi trust associated with Idaho Power's nonqualified defined benefit pension plans increased $2.2 million based on stronger asset returns in 2019 compared with 2018.
During 2018, Idaho Power recorded tax benefits for a $5.7 million remeasurement of deferred taxes resulting from income tax reform and $1.3 million for tax-deductible bond redemption costs incurred in 2018. There was no such remeasurement or bond redemption in 2019. These items, combined with higher pre-tax net income in 2019, resulted in higher income tax expense in 2019 compared with 2018. Amortization of vintage investment tax credits that became available in 2019 lowered income tax expense by $3.4 million, most of which is not expected to recur.
At IFS, a $3.0 million increase in distributions from the sale of low-income housing properties led to higher IFS net income in 2019 compared with 2018.
2020 Initiatives and Strategy
IDACORP’s strategy is focused on four areas: growing financial strength, improving Idaho Power's core business, enhancing Idaho Power’s brand, and keeping employees safe and engaged. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to provide safe, fair-priced, reliable service to its customers from diversified generation resources. For more information on the business strategy of the companies, see Part I, Item 1 - “Business - Business Strategy” in this report.
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 prices that Idaho Power is authorized to charge for its electric and transmission services are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and prudently managing expenses and investments. Idaho Power has regulatory settlement stipulations in Idaho that include provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent (9.4 percent after 2019) return on year-end equity in the Idaho jurisdiction (Idaho ROE). The settlement stipulations also provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. The settlement stipulations provide for modifications of certain terms and the indefinite extension of the mechanism beyond the original termination date of December 31, 2019. The specific terms of these settlement stipulations are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. During 2020, Idaho Power will
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.
•
Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure and purchase power. In recent years, Idaho Power has seen growth in the number of customers in its service area. In 2019, Idaho Power's customer count grew by 2.5 percent. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Employment in Idaho Power's service area grew by approximately 3.2 percent based on Idaho Department of Labor preliminary December 2019 data. Idaho Power continues to support State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area.
In June 2019, Idaho Power released its 2019 Integrated Resource Plan (IRP), Idaho Power's long-term forecast of loads and resources, which was amended in January 2020. For more information on the 2019 IRP, including the load forecast assumptions Idaho Power used in its 2019 IRP, refer to "Resource Planning" in Item 1 - "Business" in this Form 10-K.
•
Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year, when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to Idaho residential and small commercial customers is mitigated through the FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the consolidated financial statements in this report.
Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms.
•
Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.
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Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies heavily on natural gas and coal to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs.
•
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, increase the cost of constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade, and due to economic factors in part associated with the costs of compliance with environmental regulation, has accelerated the retirement dates of its jointly-owned coal-fired generating plants.
•
Water Management and Relicensing of the Hells Canyon Hydropower Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydropower generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.
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 2019 are compared with 2018.
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years.
For purposes of illustration, Boise, Idaho, weather-related information for the last two years is presented in the table that follows.
(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 2019, retail sales volumes decreased less than 1 percent compared with the prior year. Greater precipitation and more moderate spring and summer temperatures in Idaho Power's service area led agricultural irrigation customers to use 12 percent less energy per customer to operate irrigation pumps during 2019. Customer growth partially offset the decrease in sales volumes per customer during 2019 compared with 2018, with the number of Idaho Power's customers growing by 2.5 percent.
Total system generation in 2019 was consistent with that of the prior year. An increase in natural gas generation more than offset decreases in hydropower and coal generation.
Wholesale energy sales volumes decreased 75 thousand MWh, or 3 percent, during 2019 compared with 2018, due primarily to a decrease in purchased power, both in market purchases and in purchases under PURPA contracts, resulting in decreased energy available for wholesale energy sales. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power in the wholesale energy markets.
The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms."
Operating Revenues
Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of customers for the last two years.
(1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.
(2) The IPUC allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.
Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last two 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 based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.
Retail Revenues: Retail revenues decreased $44.5 million in 2019 compared with 2018. The primary factors affecting retail revenues during the period were the following:
•
Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanism, decreased retail revenues by $3.8 million in 2019 compared with 2018. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to income tax reform described further in "Regulatory Matters" in this MD&A reduced revenues in 2019 more significantly than in 2018. Customer rates also include the return to customers of amounts related to the PCA mechanism, which decreased revenues by $42.8 million in 2019 compared with 2018. The return to customers of amounts related to the PCA mechanism in rates does not have a significant effect on operating income as a corresponding amount is recorded as a reduction of expense in the same period it is returned through rates.
•
Customers: Customer growth of 2.5 percent increased retail revenues by $27.0 million in 2019 compared with 2018.
•
Usage: Lower usage (on a per customer basis), primarily by irrigation customers, decreased retail revenues by $30.9 million during 2019 compared with 2018. Greater precipitation and more moderate spring and summer temperatures in Idaho Power's service area led agricultural irrigation customers to use 12 percent less energy per customer to operate irrigation pumps during 2019. To a lesser extent, sales volumes on a per-customer basis were negatively affected by lower per-customer commercial and industrial sales.
•
Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small general service customers during 2019 increased the amount of FCA revenue accrued by $1.0 million compared with 2018.
•
Sharing: In 2019, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers as Idaho ROE was above 10.0 percent. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
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 two years (in thousands, except for MWh amounts).
In 2019, wholesale energy revenue increased by $18.4 million, or 35 percent, compared with 2018. Wholesale energy sales volumes decreased 3 percent in 2019 compared with 2018, but the average price of wholesale energy sales was 39 percent higher for 2019 compared with 2018. During the fourth quarter of 2018, a natural gas pipeline ruptured in British Columbia, Canada, disrupting natural gas flows to the Pacific Northwest and Western Canada, driving up energy and natural gas prices in
the region. During the first half of 2019, the pipeline was operating at reduced capacity, which contributed to continued elevated energy prices during that period.
Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling decreased $5.3 million in 2019 compared with 2018. Idaho Power's OATT rates decreased 10 percent in October 2018 and 13 percent October 2019. To a lesser extent, lower volumes also reduced transmission wheeling-related revenues. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate.
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, 2019, Idaho Power's energy efficiency rider balances were a $0.3 million regulatory asset in the Idaho jurisdiction and a $1.2 million regulatory asset in the Oregon jurisdiction.
Operating Expenses
Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last two years (in thousands, except for MWh amounts).
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 hydropower and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. The other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.
Purchased power expense decreased $8.5 million, or 3 percent, in 2019 compared with 2018, primarily due to a 7 percent decrease in the volume of other non-PURPA power purchases. Other non-PURPA purchased power volumes decreased as Idaho Power used its own generation to meet customer demand. These volume decreases were partially offset by increases in cost per MWh of power purchased from all sources.
Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years (in thousands, except per MWh amounts).
(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 increased $23.7 million, or 18 percent, in 2019 compared with 2018, due to a 9 percent increase in thermal generation volume and higher average costs per MWh for natural gas. Higher gas generation was mostly due to economic-based decisions to use the Danskin and Bennett Mountain gas-fired power plants as baseload resources and to increase generation at the Langley Gulch plant in 2019 compared with 2018. In 2019, gains on financial gas hedges included in fuel expense were $8.7 million lower than in 2018, increasing average costs per MWh for natural gas. In October 2018, a natural gas pipeline ruptured in British Columbia, Canada, which disrupted natural gas distribution to the Pacific Northwest region and Western Canada and drove up energy prices in the region. In accordance with its ongoing risk management policies, Idaho Power held financial gas hedges at the time of the rupture. Most of these realized hedging gains benefit customers through the power cost adjustment mechanisms described below.
Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less 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 hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.
The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last two years (in thousands).
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 2019 and 2018, most of the difference is accrued. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism).
Idaho Power accrued $7.7 million more in power supply costs in 2019 compared with 2018 as actual net power supply costs were lower relative to forecasted costs. In addition, Idaho Power recorded $47.2 million of amortization of the prior-year authorized balances in 2019, compared with $0.6 million of amortization in 2018.
Other Operations and Maintenance Expenses: Other O&M expenses decreased $8.7 million, or 2 percent, in 2019 compared with 2018, as Idaho Power's continued focus on managing other O&M expenses resulted in lower expenses across a number of areas. Lower bad debt expense reduced other O&M expenses by $1.1 million, due primarily to enhanced collection efforts and a strong economy. Also, other O&M expenses in 2018 included $4.0 million of non-cash amortization expense of regulatory deferrals pursuant to the settlement stipulation approved by the IPUC in 2018 related to income tax reform.
Income Taxes
IDACORP's and Idaho Power's 2019 income tax expense increased $7.1 million and $10.1 million, respectively, when compared with 2018. During 2018 Idaho Power recorded tax benefits for a $5.7 million remeasurement of deferred taxes resulting from income tax reform and $1.3 million for tax-deductible bond redemption costs incurred in 2018. There was no such remeasurement or bond redemption in 2019. Also, 2018 included a benefit from plant-related income tax return adjustments, which reduced Idaho Power income tax expense in 2018. These items, combined with greater 2019 net income, resulted in higher income tax expense in 2019 compared with 2018. Amortization of vintage investment tax credits that became available in 2019 lowered tax expense by $3.4 million, most of which is not expected to recur. Also, at IFS, a $3.0 million increase in distributions from the sale of low-income housing properties reduced income tax expense at IDACORP in 2019 compared with 2018.
For additional information relating to IDACORP's and Idaho Power's income taxes 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 hydropower and thermal generation facilities also require continuing upgrades and component replacement. On an accrual basis, Idaho Power's additions to electric plant, excluding AFUDC, were $295 million in 2019 and $274 million in 2018. Cash construction expenditures, excluding AFUDC and excluding net costs of removing assets from service, were $268 million in each of 2019 and 2018. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of more than $1.6 billion expected over the period from 2020 through 2024.
Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. As of February 14, 2020, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:
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their respective $100 million and $300 million revolving credit facilities;
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IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 17, 2019, which may be used for the issuance of debt securities and common stock;
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Idaho Power's shelf registration statement filed with the SEC on May 17, 2019, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance pursuant to state regulatory authority; and
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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 2020, the companies believe they will be able to meet capital requirements and fund corporate expenses during 2020 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business, together with proceeds from either draws on credit facilities or Idaho Power's issuance of debt securities. IDACORP and Idaho Power believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.
IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.
IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2019, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
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 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 2019 were $367 million and $344 million, respectively, decreases of $125 million and $75 million for IDACORP and Idaho Power, respectively, when compared with 2018. Significant items that affected the companies' operating cash flows in 2019 relative to 2018 were as follows:
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a $6 million increase and $2 million increase in IDACORP and Idaho Power net income, respectively;
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changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed cost adjustment amounts accrued or deferred and refunded or collected under Idaho rate mechanisms, decreased operating cash inflows by $53 million;
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Idaho Power received $19 million of distributions from IERCo's investment in BCC for 2019, compared with $29 million in 2018; changes in distributions from year to year are primarily driven by changes in the timing of cash needs associated with BCC;
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changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $7 million and $4 million at IDACORP and Idaho Power, respectively; and
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changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, other current assets, and accounts payable, as follows:
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timing of collections of accounts receivable balances decreased operating cash flows by $7 million and $5 million for IDACORP and Idaho Power, respectively;
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the changes in other current assets decreased cash flows by $20 million, which was primarily due to the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants; and
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timing of accounts payable payments decreased operating cash flows by $39 million for IDACORP and increased operating cash flows by $16 million for Idaho Power (the difference relates to the timing of estimated income tax payments from Idaho Power to IDACORP).
Investing Cash Flows
Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. Idaho Power's construction expenditures, including AFUDC, were $279 million and $278 million in 2019 and 2018, respectively. These capital expenditures were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. As discussed in "Capital Requirements" below, Idaho Power received $2 million and $22 million in 2019 and 2018 from Boardman-to-Hemingway project joint permitting participants relating to a portion of these permitting expenditures.
Idaho Power has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased equity securities of $11 million in both 2019 and 2018. Idaho Power received $5 million of proceeds from the sales of equity securities in both 2019 and 2018.
Financing Cash Flows
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2019 and 2018:
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in August 2019, Idaho Power purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in 2024 decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent. Idaho Power expects the lower interest rates to reduce interest expense by approximately $5.6 million annually for the next five years and $3.9 million annually thereafter for the final two years of the longer-lived bonds;
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in March 2018, Idaho Power issued $220 million in principal amount of 4.20% first mortgage bonds Series K, maturing March 1, 2048;
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in April 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;
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IDACORP and Idaho Power paid dividends of approximately $130 million and $121 million in 2019 and 2018, respectively.
Financing Programs and Available Liquidity
IDACORP Equity Programs: From time to time, IDACORP enters into sales agency agreements under which it offers and sells shares of its common stock through a third-party agent. The most recent sales agency agreement terminated in May 2016. IDACORP has no current plans to issue equity securities other than under its equity compensation plans during 2020, and as of the date of this report, IDACORP has not pursued the execution of a new sales agency agreement.
Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal
amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2022, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of seven percent.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Idaho Power's Indenture of Mortgage and Deed of Trust dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). 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, 2019, was limited to approximately $669 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, 2019, Idaho Power could issue approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.
Pollution Control Tax-Exempt Bonds: In August 2019, Idaho Power purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in 2024 decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent. Idaho Power expects the lower interest rates to reduce interest expense by approximately $5.6 million annually for the next five years and $3.9 million annually thereafter for the final two years of the longer-lived bonds.
Refer to Note 5 - “Long-Term Debt” to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.
IDACORP and Idaho Power Credit Facilities: In December 2019, IDACORP and Idaho Power entered into amendments to credit agreements for their $100 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $100 million at any one time outstanding, including swingline loans not to exceed $10 million at any one time and letters of credit not to exceed $50 million at any one time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time and letters of credit not to exceed $50 million at any one time outstanding. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR Market Index rate will not be less than zero percent. An alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating, as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities. The credit facilities terminate on December 6, 2024, though IDACORP and Idaho Power may request up to two-one-year extensions of the credit agreements, subject to certain conditions.
Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total
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, 2019, the leverage ratios for IDACORP and Idaho Power were 43 percent and 45 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, 2019, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2020.
The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and 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.
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 December 2026.
IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.
Available Short-Term Borrowing Liquidity
The following table outlines available short-term borrowing liquidity as of the dates specified (in thousands):
IDACORP and Idaho Power had no short term commercial paper outstanding during the years ended December 31, 2019 and 2018. At February 14, 2020, 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:
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, 2019, Idaho Power had $1.4 million of performance assurance collateral posted. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2019, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $10.3 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.
Capital Requirements
On an accrual basis, Idaho Power's additions to electric plant, excluding AFUDC, were $295 million in 2019. Idaho Power's cash construction expenditures, excluding AFUDC, were $268 million during the year ended December 31, 2019. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to electric plant for 2020 through 2024 (in millions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. However, given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table.
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 2020 through 2024 and estimated costs include the following:
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$35-$65 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;
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$85-$125 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
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$15-$35 million per year for ongoing improvements and replacements at thermal plants;
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$60-$95 million per year for hydropower plant improvement programs, including relicensing costs; and
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$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, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line, Idaho Power would seek to retain at least that percentage interest in the completed project. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate.
Approximately $106 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2019. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $72 million as of December 31, 2019, from project participants for their share of costs. As of the date of this report, no material co-participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power.
Idaho Power's share of the remaining permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, which includes approximately $105 million of Idaho Power's share of estimated costs related to design and early construction, which are primarily included in the table in the period 2022-2024. These preliminary estimates of Idaho Power’s share of early construction costs could significantly change as the construction timeline nears and as the project participants further align on future activities, allocation of ownership interests, and cost estimates.
The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, 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. In September 2019, the Department of the Navy issued its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands. In November 2019, third parties filed a lawsuit in the federal district court of Oregon, challenging the BLM and U.S. Forest Service records of decision for the Boardman-to-Hemingway project. On February 13, 2020, Idaho Power filed a motion to intervene in the legal proceeding. The litigation is in its initial phases and remains pending as of the date of this report.
In the separate Oregon state permitting process, the Oregon Department of Energy (ODOE) issued a Draft Proposed Order in May 2019 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The ODOE is expected to issue a Proposed Order in the first half of 2020. Idaho Power currently expects the EFSC to issue a final order and site certificate in 2021. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date for the transmission line will be in 2026 or some time thereafter.
Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $41 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2019. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $250 million and $450 million,
including AFUDC. Idaho Power's estimated share of ongoing expenditures for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.
The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. In May 2017, a federal bill was signed into law that issued a right-of-way for certain portions of the remaining Gateway West segments. In April 2018, the BLM published its record of decision for the outstanding portions of the remaining segments. PacifiCorp is currently constructing a 140-mile segment of their portion of the project in Wyoming, scheduled to be completed by the end of 2020. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.
Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 35 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 April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.
Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for its hydropower relicensing efforts and could incur significant expenditures if required to install additional environmental controls at its Jim Bridger coal-fired plant. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business - Environmental Regulation and Costs" of this report. The capital portion of these amounts is included in the Capital Requirements table above but does not include costs related to 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 2019, which was amended in January 2020. The 2019 IRP identified a preferred resource portfolio and action plan, which includes the completion of the Boardman-to-Hemingway transmission line in 2026, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant units 1 and 2 in 2019 and 2025, respectively, the end to Idaho Power's participation in coal-fired operations at the Jim Bridger plant by 2030, with the exit from two of the four Jim Bridger plant units in 2022 and 2026, respectively, and the addition of a 120 megawatt (MW) solar resource in 2022. However, as noted in the 2019 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These uncertainties, as well as others, likely will result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions. Additional information on Idaho Power's 2019 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.
Potential Future Rate Base Additions
As noted previously in this MD&A, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Idaho Power's current rate
base of $2.7 billion was established in June 2012, when the IPUC issued an order approving the inclusion of the investment and associated costs of the Langley Gulch plant in rates. Through December 31, 2019, Idaho Power has placed $0.7 billion of property, plant, and equipment in service since June 2012, net of accumulated depreciation. These assets could be included in future rate base if Idaho Power were to file a general rate case, though Idaho Power has no plans to do so in 2020. Idaho Power expects to place in service an additional $0.7 billion of rate base-eligible projects over the next five years. Idaho Power expects it could also add up to an additional $1.3 billion to rate base over the next several years by completing projects currently in process with uncertain in-service dates or due to additional spending required by completion of the projects. These projects include HCC relicensing, additional capital expenditures to comply with the expected requirements of a new HCC license, post-relicensing water temperature mitigation efforts at HCC, the Boardman-to-Hemingway project either at or above Idaho Power's current ownership percentage in the project, and certain distribution system modernization projects.
Defined Benefit Pension Plan Contributions and Recovery
Idaho Power contributed $40 million to its defined benefit pension plan in each of 2019 and 2018. Idaho Power's minimum required contribution to be made during 2020 is estimated to be $14 million. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40 million to the pension plan during 2020. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond 2020, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to 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, 2019 and 2018, Idaho Power's deferral balance associated with the Idaho jurisdiction was $173 million and $148 million, respectively. Deferred pension costs are expected to be amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Contractual Obligations
The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2019, for the respective periods in which they are due:
In March 2019, Idaho Power signed a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility. The agreement was approved by the IPUC in December 2019 and is, as of the date of this report, pending approval by the OPUC. If approved, the agreement would increase contractual obligations by $136 million over the 20-year term. In October 2019, Idaho Power exercised its right under the power purchase agreement to negotiate during the fourth quarter of 2019 for the acquisition by Idaho Power or one of its affiliates of the planned 120-MW solar facility. Idaho Power and its affiliates did not ultimately reach an agreement to acquire ownership of the facility.
Dividends
The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.
IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions. In 2019, IDACORP's board of directors increased the target long-term dividend payout ratio to between 60 percent and 70 percent of sustainable IDACORP earnings from the previous policy adopted in 2011, that targeted a dividend payout ratio of between 50 percent to 60 percent of sustainable earnings. Notwithstanding the dividend policy adopted by IDACORP's board of directors,
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 2019 and 2018, IDACORP's board of directors voted to increase the quarterly dividend to $0.67 per share and $0.63 per share of IDACORP common stock, respectively. IDACORP's dividends during 2019 were 55.5 percent of actual 2019 earnings.
For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 7 - “Common Stock” to the consolidated financial statements included in this report.
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 $58.3 million at December 31, 2019, representing IERCo's one-third share of BCC's total reclamation obligation of $175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2019, the value of the reclamation trust fund totaled $139.5 million. During 2019, the reclamation trust fund made no distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
In May 2019, the state of Wyoming enacted legislation that limits a mine operator's maximum amount of self-bonding. Idaho Power and the co-owners of BCC have until December 2020 to comply with the new regulations, which would reduce the portion of Idaho Power's guarantee of reclamation activities and obligations at BCC that Idaho Power is allowed to self-bond. As of the date of this report, Idaho Power believes the cost of any insurance, third-party assurance, or additional collateral that might be required for this guarantee due to the new law would be immaterial to the companies' consolidated financial statements.
REGULATORY MATTERS
Introduction
Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.
Idaho Power's development of regulatory filings takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of these regulatory filings. These factors include, among others, in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011. In 2012, large single-issue rate cases for the Langley Gulch power plant resulted in the resetting of base rates in both Idaho and Oregon. 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. The IPUC and OPUC have also approved base rate changes in single-issue cases subsequent to 2014. Between general rate cases, Idaho Power relies upon customer growth, a fixed cost adjustment mechanism, power cost adjustment mechanisms, tariff riders, and other mechanisms to mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. Idaho Power continues to assess the need and timing of filing a general rate case in its two retail jurisdictions, based on its consideration of the factors described above, but does not anticipate filing a general rate case in 2020.
Notable Retail Rate Changes in Idaho and Oregon
Included in the table that follows are notable regulatory developments during 2019 and 2018 that affected Idaho Power's results for the periods or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanism and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.
Idaho and Oregon General Rate Cases
Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011. In the general rate case, the IPUC issued an order approving a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.
Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.
Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. In September 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.
Other Notable Regulatory Matters
October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho customers for the period from 2015 through 2019. The more specific terms and conditions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "May 2018 Idaho Tax Reform Settlement Stipulation" of this MD&A.
In 2019, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year Idaho ROE was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers.
Idaho Power recorded the following amounts for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations (in millions):
May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction was provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018, through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018, to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism decreased to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.
The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism to become effective beginning January 1, 2020, with no defined end date. The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its term. IDACORP and Idaho Power believe that the terms
allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. At December 31, 2019, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.
Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. In December 2019, Idaho Power filed an application with the OPUC requesting approval of Idaho Power’s quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.
For more information on the settlement stipulations and their impacts on results, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy plant in 2019 and 2025, respectively. In May 2019, the IPUC issued an order approving the North Valmy plant exit agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1 and removed approximately $160 million from both Utility plant in service and Accumulated provision for depreciation on the consolidated balance sheets at December 31, 2019.
In June 2017, the OPUC also approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 Oregon Income Tax Reform Settlement Stipulation described below, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant exit agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.
Customer-Owned Generation Filing: Customer-owned generation allows customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it utilizes energy supplied by Idaho Power’s grid. If its system generates more energy than the customer uses, the energy goes back to the grid and Idaho Power applies a corresponding kWh credit to the customer’s bill. In May 2018, the IPUC issued an order authorizing the creation of two new customer classes for residential and small commercial customers who install their own on-site generation, with no change to pricing or compensation. Since October 2018, Idaho Power has initiated two cases related to studying the costs and benefits of customer-owned generation on Idaho Power’s system, and exploring whether, and to what extent, there should be modifications to the customer-owned generation pricing structure for residential and small general service customers (Residential and Small Commercial Case), and large commercial, industrial, and irrigation customers (Large Commercial, Industrial, and Irrigation Case). The IPUC issued orders in the Residential and Small Commercial Case during December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to
the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) continue to allow customers with on-site generation prior to December 20, 2019, to be subject to the billing terms in place on that date until December 20, 2045. As of the date of this report, both the Residential and Small Commercial Case and Large Commercial, Industrial, and Irrigation Case are ongoing, and Idaho Power does not expect these cases to materially affect its financial condition or results of operations.
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 hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.
The following table summarizes the change in deferred (accrued) net power supply costs over last year (in millions):
Open Access Transmission Tariff Rate Proceedings
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs for FERC-approved expenditures associated with its transmission system. In August 2019, Idaho Power filed its 2019 final transmission rate with the FERC, reflecting a transmission rate of $27.32 per kW-year, to be effective for the period from October 1, 2019, to September 30, 2020. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $107.0 million. The OATT rate in effect from October 1, 2018, to September 30, 2019, was $31.25 per kW-year based on a net annual transmission revenue requirement of $123.1 million. The decrease in the OATT rate is largely attributable to federal tax reform and increased short-term firm and non-firm transmission revenues in 2018, which serve as an offset to the transmission revenue requirement. Historic OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Relicensing of Hydropower Projects
Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through
the regulatory process. In April 2018, the IPUC approved a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third-party intervenor and determined that $216.5 million in expenditures incurred for relicensing through December 31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date. Relicensing costs of $326 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2019. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $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, 2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $152 million. In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.
Hells Canyon Complex: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 35 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA) listed species pending the relicensing of the project. In August 2007, the FERC Staff issued a final 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 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 filed and withdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it was working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, provided that Idaho Power take no action that might result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approval of the State of Idaho. In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the 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 2019, the states of Idaho and Oregon, along with Idaho Power, reached a settlement pertaining to the CWA Section 401 certification that resolved the fish passage conflict between the parties. The settlement requires Idaho Power to increase the number of Chinook salmon it releases each year through expanded hatchery production. Additionally, Idaho Power is required to fund a total of $12 million of research and water quality improvements in the HCC over a 20-year period following the issuance of the license. These measures are in exchange for Oregon removing the fish passage requirement from the Oregon Section 401 certification for at least the first 20 years after final license issuance. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million over the first 20 years of the new license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third-party lawsuits were filed against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and mercury issues associated with the Snake River and HCC. Idaho Power has intervened in one of the third-party lawsuits and may intervene in the other two as well. No parties challenged the Idaho CWA Section 401
certification. On December 30, 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. The FERC has received several comments opposing the Offer of Settlement and its decision relating to the Offer of Settlement is pending as of the date of this report. Idaho Power continues to expect the FERC to issue an HCC license no earlier than 2022.
In September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, under the NMFS's and USFWS's jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Each of the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.
Idaho Power continues to work with Idaho and Oregon on measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards and associated measures identified in the final Section 401 certifications, and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns. Measures identified in the final Section 401 certifications included construction of aerated runners at the Brownlee project (part of the HCC), modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements to address water temperatures during a small portion of the year. These and any other additional measures to satisfy relicensing requirements have added and will add substantially to project costs.
As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, as of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2022.
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, 2019, and 2018, Idaho Power's REC sales totaled $5.5 million and $2.9 million, respectively.
Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market. Historically, Idaho Power has generally not received the RECs associated with PURPA projects. However, an order issued by the IPUC in 2012 provides that Idaho Power will own a portion of the RECs generated by some PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.
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 hydropower and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of December 31, 2019, Idaho Power had contracts to purchase energy from 129 on-line PURPA projects. An additional three contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.
The following table sets forth, as of December 31, 2019, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.
The projects not yet on-line include one hydropower PURPA project and two solar PURPA projects that are scheduled to be on-line in 2020 and one solar PURPA project scheduled to be on-line in 2022. The non-PURPA solar project is scheduled to be on-line in 2022.
In September 2019, the FERC issued a Notice of Proposed Rulemaking that, if adopted, could affect how states determine PURPA project avoided cost rates for purchases of power generated from qualified facilities (QF), which facilities are eligible for QF status, whether and when certain QFs can enter into purchase agreements with utilities, and how parties can contest the eligibility of a generation facility seeking QF status. As of the date of this report, Idaho Power is unable to determine the impact of these potential changes on the company's future obligations for new PURPA power purchase contracts, as it would require further action by the state public utility commissions to implement many of the changes. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could reduce the number of future PURPA generation projects, which could reduce purchased power costs for Idaho Power. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.
ENVIRONMENTAL MATTERS
Overview
Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Affordable Clean Energy (ACE) rule and other Clean Air Act (CAA) requirements, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three co-owned coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydropower projects are also subject to a number of water discharge standards and other environmental requirements.
Compliance with current and future environmental laws and regulations may:
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increase the operating costs of generating plants;
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increase the construction costs and lead time for new facilities;
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require the modification of existing generating plants, which could result in additional costs;
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require the curtailment or shut-down of existing generating plants; or
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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 North Valmy plant was also based primarily on the economics of operating the 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 2020 to 2022. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond 2022, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. The outcome of federal agencies' review of regulations covered by executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or reduction or elimination of permitting requirements. Executive orders resulting in modifications to federal regulations could, on the other hand, be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federal regulations or bolster environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power 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 hydropower facilities. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward.
In November 2018, the U.S. Supreme Court held that an area is eligible for designation as a critical habitat under the ESA only if it is also "habitat" for the species as defined in the statute, which generally means the area can support the species without modification, and as part of the designation, the USFWS must also consider the costs compared to the benefits of such designation. Idaho Power believes this ruling may limit the number of areas designated as critical habit and could also reduce Idaho Power’s obligations for mitigation under the ESA. Furthermore, in August 2019, the USFWS and the NMFS issued a set of regulatory changes to some of the standards under which listings, delisting, and reclassifications, and critical habitat designations are made. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could reduce the role of climate change models in listing decisions and the designations of critical habitat in areas where species are not present, which could also reduce Idaho Power's obligations for mitigation under the ESA related to various construction and relicensing projects.
The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's hydropower projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydropower facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower 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 hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.
Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statements across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.
In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.
In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In December 2018, the BLM issued draft resource management plan amendments and a final environmental impact statements to modify the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.
ESA Issues Related to Specific Projects:
Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has yet to be initiated and the NMFS and the USFWS continue to gather and consider information relative to the effects of relicensing on relevant ESA listed species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. 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 2020 is unlikely.
Boardman-to-Hemingway and Gateway West Transmission Projects: In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass. Most of the species are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed routes for the Boardman-to-Hemingway and Gateway West transmission line projects to continue to impact the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation. The USFWS has also indicated it intends to designate critical habitat for the species. If critical habitat is designated within the vicinity of the transmission line projects, Idaho Power expects that the designation could increase the cost of obtaining permits for the projects and could further delay the in-service date of the projects.
The Washington ground squirrel inhabits various locations throughout two of the counties within the proposed routes for Boardman-to-Hemingway. It is not listed under the federal ESA, but it is considered endangered under Oregon law and the Boardman-to-Hemingway project will need to avoid ground squirrel colonies during construction. If colonies are found within the proposed site boundary during pre-construction surveys, re-siting the transmission would require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the project.
Endangered Species Act and National Environmental Policy Act Developments: In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydropower facilities owned and operated by the U.S. Army Corps of Engineers and located on the lower Snake River, National Oceanic and Atmospheric Administration's
National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the National Environmental Policy Act (NEPA) by failing to prepare a comprehensive environmental impact statement on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement process to examine hydropower dams on the lower Snake River, which Idaho Power expects will take place over a five-year period. In January 2020, the presidential administration's Council on Environmental Quality proposed rules to narrow federal agencies' NEPA obligations, which if adopted, may expedite projects and reduce the number of actions subject to NEPA review. None of Idaho Power’s hydropower facilities are included in the studies.
Climate Change and the Regulation of Greenhouse Gas Emissions
Overview: Long-term climate change could significantly affect Idaho Power's business in a variety of ways, including:
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changes in temperature and precipitation could affect customer demand and energy loads;
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extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;
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changes in the amount and timing of snowpack and stream flows could affect hydropower generation;
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legislative and/or regulatory developments related to climate change could affect plants and operations, including restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources; and
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consumer preference for, and resource planning decisions requiring, renewable or low greenhouse gas (GHG)-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.
Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing CO2 emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. Some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate, particularly in light of continued low natural gas prices that decrease the cost to operate natural gas-fired power plants. As a result, Idaho Power ended its participation in coal-fired operations at the North Valmy plant unit 1 in December 2019 and plans to end its participation in unit 2 in 2025, and plans to cease coal-fired operations at the Boardman power plant no later than December 31, 2020.
A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial 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/Affordable Clean Energy Rule: The U.S. Environmental Protection Agency (EPA) has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.
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. In June 2019, the EPA released the ACE rule to replace the CPP under Section 111(d) of the CAA for existing electric utility generating units. The new rule provides states with new emissions guidelines that inform the state development of standards of performance to reduce CO2 emissions from existing generation facilities and is limited to reduction and compliance measures that occur at the physical location of each plant, removing the proposal to require reductions outside the boundaries of plants. The ACE rule also provides for more state-specific control over implementation of the rule to address greenhouse gas emissions from existing coal-fired power plants, with a focus on state evaluation of improvement potential, technical feasibility, applicability, and remaining useful life of each unit. States are required to submit their compliance plans to the EPA by July 2022. In August 2019, twenty-two states sued the EPA in federal appeals court to challenge the ACE rule.
Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, as of the date of this report Idaho Power is uncertain whether and to what extent the ACE rule may impact its operations in the near term. Idaho Power's preliminary review of the rule indicates that it may not have substantial impacts on Idaho Power's operation of existing thermal generation units due to its planned retirements and other planned upgrades at generating facilities.
State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO2 equivalent annually. The Boardman coal-fired power plant located in Oregon, in which Idaho Power is a 10-percent owner, is subject to and in compliance with Oregon's GHG reporting requirements but is scheduled to cease coal-fired operations in 2020.
In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, and requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.
The State of Idaho has not passed legislation specifically regulating GHGs. Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry, a national, voluntary GHG emissions reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emissions reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs."
Clean Air Act Matters
Overview: In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.
MATS Implementation: The final MATS rule under the CAA, previously referred to as the Utility Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in compliance
with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending. In August 2018, the EPA began reconsidering the justification behind the MATS rule and reviewing the regulations emissions standards. In December 2018, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. The emissions standards and other requirements of the MATS rule, however, remain in place. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, which does not significantly impact Idaho Power’s operations or financial results.
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 emissions reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items relevant to Idaho Power include the following:
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NO2: In 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a one-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO2.
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SO2: In 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO2 NAAQS because of a lack of definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO2 standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO2 for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.
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Ozone: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of U.S. counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.
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 selective catalytic reduction (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. 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.
In February 2019, PacifiCorp submitted to the WDEQ an alternative regional haze compliance plan for the Jim Bridger plant that includes a reduced plant-wide monthly limit on emissions for NOx and SO2 and an annual total emissions cap of NOx and SO2 for units 1-4. If approved as proposed, the alternative plan would likely eliminate the requirement to install add-on NOx controls at Jim Bridger units 1 and 2. If the compliance plan as proposed is not approved by WDEQ and finalized, Idaho Power
will re-evaluate options with PacifiCorp to ensure it complies with EPA and WDEQ rules, but does not believe it would move forward with the installation of SCR equipment at units 1 and 2.
Clean Water Act Matters
Definition of “Waters of the United States” Under the CWA: In August 2015, the EPA and U.S. Army Corps of Engineers' (USACE) final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS Rule). Idaho Power believes that the 2015 rule potentially expanded federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. The WOTUS Rule was widely challenged in both federal district and circuit courts. In January 2020, the EPA and USACE finalized the rule to repeal the WOTUS Rule and set new and more expansive standards for determining which waters are subject to the CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule.
Idaho Power believes the repeal rule and the WOTUS Rule will continue to be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho and should the revised definition take effect in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area. Similarly, because the CWA, as interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its hydropower plants, Idaho Power does not expect reinstatement would have a material impact on Idaho Power's operations or financial condition.
CWA Matters Related to Hydropower Relicensing: Idaho Power is also addressing CWA issues associated with the relicensing of its HCC. See “Relicensing of Hydropower Projects” in this MD&A for additional information on the impact of the CWA on that relicensing effort.
Review of Federal Coal Leases
In January 2016, the Secretary of the U.S. Department of the Interior issued an order directing the BLM to prepare a Programmatic Environmental Impact Statement (PEIS) to analyze potential reforms to the federal coal lease program and placed a moratorium on new federal coal leasing, with limited exceptions, pending completion of the PEIS. In January 2017, the Secretary of the Department of the Interior ordered a cessation of all work on the PEIS and in March 2017 lifted the moratorium on new federal coal leases. As of the date of this report, Idaho Power believes that BCC has adequate reserves under existing leases to satisfy its coal delivery obligations to the Jim Bridger plant during the term of the existing coal supply contract through 2024, and that the Jim Bridger plant will otherwise have access to sufficient coal supplies for its operation for the foreseeable future. However, the lifting of the moratorium could increase the availability of BCC's coal resources and lower the cost of leases for those coal resources.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
When preparing financial statements in accordance with the accounting principles generally accepted in the United States of America (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosures. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.
Accounting for Rate Regulation
Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.
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 $1.4 billion of regulatory assets and $0.8 billion of regulatory liabilities at December 31, 2019. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.
Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters.
Income Taxes
IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.
Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are recorded for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.
Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.
Pension and Other Postretirement Benefits
Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, and two unfunded nonqualified deferred compensation plans for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits).
The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.
The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2019, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2020 pension expense will be decreased to 3.60 percent from the 4.55 percent rate used in 2019.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when
interest rates were generally much higher. The long-term rate of return used to calculate the 2020 pension expense will be decreased to 7.4 percent from the 7.5 percent used in 2019.
Gross net periodic pension and other postretirement benefit cost for these plans totaled $50.0 million and $51.2 million for the years ended December 31, 2019 and 2018, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2020, gross pension and other postretirement benefit costs are expected to total approximately $54.9 million, which takes into account the change in the discount rate noted above.
Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $97.1 million decrease in the combined benefit obligations of the plans as of December 31, 2019. A 0.5 percent decrease in the plans' discount rates would have resulted in an $110.0 million increase in the combined benefit obligations of the plans as of December 31, 2019.
The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2019, a total of $173 million of expense was deferred as a regulatory asset. Idaho Power expects to defer approximately $26 million of expense in 2020. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million in 2019 and 2018.
Refer to Note 12 - “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.
RECENTLY ISSUED ACCOUNTING AND AUDITING PRONOUNCEMENTS
On June 1, 2017, the Public Company Accounting Oversight Board (PCAOB) issued Auditing Standard 3101, The Auditor's Report on an Audit of Financial Statements When the Auditor Expresses an Unqualified Opinion (AS 3101). AS 3101 includes a new requirement to describe critical audit matters arising from the audit of the current period's financial statements in the auditor's report. The requirements related to critical audit matters in AS 3101 were effective for audits of fiscal years ending on or after June 30, 2019, for large accelerated filers; and for fiscal years ending on or after December 15, 2020, for all other companies to which the requirements apply. Therefore, critical audit matters are included in the Report of Independent Registered Public Accounting Firm for IDACORP's consolidated financial statements as of and for the year ended December 31, 2019, and AS 3101 will be effective for Idaho Power as of and for the year ending December 31, 2020.
For a listing of other new and recently adopted accounting standards, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the consolidated financial statements included in this report.
ITEM 7A.
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, 2019. IDACORP and Idaho Power have not entered into any of these market-risk-sensitive instruments for trading purposes.
Interest Rate Risk
IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.
Variable Rate Debt: As of December 31, 2019, IDACORP and Idaho Power had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt.
Fixed Rate Debt: As of December 31, 2019, both IDACORP and Idaho Power had $1.8 billion in fixed rate debt, with a fair market value of approximately $2.1 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $262.2 million if market interest rates were to decline by one percentage point from their December 31, 2019, levels.
Commodity Price Risk
IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These effects of changes in commodity prices on Idaho Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk.
A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.
The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy and associated standards implementing the Risk Management Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of selected Idaho Power officers and other senior managers, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to Idaho Power's Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Risk Management Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its Integrated Resource Plan. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.
The Risk Management Policy and associated standards require monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The power supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load,
and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Risk Management Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by the power supply unit for consistency and compliance with the Risk Management Policy and associated standards. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.
Credit Risk
IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.
The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2019, Idaho Power had $1.4 million of performance assurance collateral posted related to these contracts. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, 2019, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $10.3 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.
Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.
Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.
Equity Price Risk
IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements and Financial Statement Schedules
All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included.
IDACORP, Inc.
Consolidated Statements of Income
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
IDACORP, Inc.
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Equity
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Income
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Idaho Power Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Retained Earnings
The accompanying notes are an integral part of these statements.
IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to the Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.
Nature of Business
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant (Jim Bridger plant) owned in part by Idaho Power.
IDACORP’s other notable wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and Ida-West Energy Company (Ida-West), an operator of small hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
Principles of Consolidation
IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues and expenses of each company and its wholly-owned subsidiaries listed above, as well as any variable interest entities (VIEs) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.
IDACORP also consolidates one variable interest entity (VIE), Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2019, Marysville had approximately $18 million of assets, primarily a hydropower plant, and approximately $6 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.
The BCC joint venture is also a VIE, but because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner, Idaho Power is not the primary beneficiary. The carrying value of Idaho Power's investment in BCC was $40.7 million at December 31, 2019, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $58.3 million guarantee for mine reclamation costs, which is discussed further in Note 10 - "Commitments."
IFS's affordable housing limited partnership and other real estate investments are also VIEs for which IDACORP is not the primary beneficiary. IFS's limited partnership interests range from 4 to 99 percent and were acquired between 1996 and 2019. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $3.7 million at December 31, 2019.
Ida-West's other investments in PURPA facilities, Idaho Power's investment in BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 15 - "Investments").
Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation.
The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly-owned plants (see Note 13 - "Property, Plant and Equipment and Jointly-Owned Projects").
Regulation of Utility Operations
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power’s operations are discussed in more detail in Note 3 - "Regulatory Matters."
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. Accordingly, actual results could differ from those estimates.
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one 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, 2019 and 2018. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
On January 1, 2018, IDACORP and Idaho Power adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power. Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues."
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.9 percent in 2019, 2.8 percent in 2018, and 2.9 percent in 2017.
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 2019, 2018, or 2017.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells Canyon Complex (HCC) relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power’s weighted-average monthly AFUDC rate was 7.6 percent for 2019, 2018 and 2017.
Income Taxes
IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial
statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
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.
Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.
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.
New and Recently Adopted Accounting Pronouncements
Recently Adopted Accounting Pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on 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. IDACORP and Idaho Power adopted ASU 2016-02 on January 1, 2019. The adoption did not have a material impact on their respective financial statements. Neither IDACORP nor Idaho Power has material agreements that meet the definition of a lease under ASU 2016-02.
Recent Accounting Pronouncements Not Yet Adopted
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, to provide financial statement users with more information about expected credit losses on financial instruments. The ASU revises the incurred loss impairment methodology to reflect current expected credit losses and requires consideration of a broader range of information to estimate credit losses. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. IDACORP and Idaho Power are finalizing the assessment of the financial impacts of adoption, but do not believe that the adoption of ASU 2016-13 will have a material impact on their respective financial statements.
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 recognition of such implementation costs with the accounting for costs incurred to implement an internal-use software solution. However, the balance sheet line item for presentation of capitalized implementation costs for a cloud arrangement that is a service contract should be the same as that for the prepayment of fees related to the same arrangement, while capitalized implementation costs for internal-use software solutions are often included in property, plant, and equipment as an intangible asset. 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 finalizing the assessment of the financial impacts of adoption, but do not believe the adoption of ASU 2018-15 will not have a material impact on their respective financial statements.
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
The items comprising income tax expense are as follows:
The components of the net deferred tax liability are as follows:
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, 2019, IDACORP had $36.7 million of general business credit carryforwards for federal income tax purposes and $39.4 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2032 to 2039, and the Idaho investment tax credit expires from 2024 to 2033.
Uncertain Tax Positions
IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2019 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. The open tax years for examination are 2019 for federal and 2016-2019 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. In 2019, the IRS completed its examination of IDACORP's 2018 tax year with no unresolved income tax issues.
Income Tax Reform
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law, which significantly reformed the Internal Revenue Code of 1986, as amended. Effective January 1, 2018, the Tax Cuts and Jobs Act permanently lowers the corporate tax rate to 21 percent from the existing maximum rate of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense, eliminates the alternative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of executive compensation. Public utility companies, such as Idaho Power, retain the full deductibility of interest expense and are excluded from the bonus depreciation provisions; however, traditional accelerated tax depreciation methods are still available.
Due to the enactment of the Tax Cuts and Jobs Act and following generally accepted accounting principles, at December 31, 2017, IDACORP and Idaho Power remeasured all deferred income tax assets and liabilities. The effects of these adjustments resulted in a net tax expense for 2017, as shown in the rate reconciliation table above. Also, as shown above, in 2018, a net tax benefit was recognized for the remeasurement of deferred taxes for the adjustment of temporary differences as a result of IDACORP's 2017 consolidated income tax return filings.
Additionally, in 2017, the net deferred tax liabilities at both companies decreased by approximately $672 million. Idaho Power's regulatory asset deferred income tax liability item decreased as the related regulatory asset was reduced in two primary ways: (1) the decrease in the federal income tax rate decreased the future cost to customers for funding the net deferred income tax liabilities resulting from the cumulative impacts of using the flow-through income tax accounting method for regulatory purposes and (2) the decrease in the federal income tax rate also reduced the net-to-gross multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in income tax law also reduced the deferred income tax liability for depreciation-related timing differences under the normalized tax accounting method. As this reduction will flow back to customers in the future under the statutorily prescribed average rate assumption method, it was recorded as a regulatory liability on the consolidated balance sheets of the companies. See Note 3 - "Regulatory Matters" for more information.
On March 12, 2018, Idaho House Bill 463 was enacted which lowered the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent effective January 1, 2018. The Idaho tax rate reduction did not have a material impact on IDACORP's and Idaho Power's 2018 income tax expense or deferred tax asset and liability balances.
3. REGULATORY MATTERS
IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.
Regulatory Assets and Liabilities
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record 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.
The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
(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) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its Idaho jurisdiction, Idaho Power’s inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the difference between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.
(5)
The energy efficiency asset includes the Oregon jurisdiction balance at December 31, 2019 and 2018. The Idaho jurisdiction balance was an asset at December 31, 2019, and a liability at December 31, 2018.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. 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.
(10) Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.
(11) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers.
Idaho Power’s regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less 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 Idaho Power (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
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a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.
The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC:
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. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2019, 2018, and 2017 did not have a material impact on the companies' financial statements.
Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2019.
January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were
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.
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.
October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in the table included under "Income Tax Reform - Idaho Regulatory Treatment" below.
In 2019 and 2017, Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) for both years was between 9.5 percent and 10.0 percent. In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers as Idaho ROE was above 10.0 percent. Accordingly, at December 31, 2019, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation described in "Income Tax Reform - Idaho Regulatory Treatment" below.
May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.
In May 2018, the IPUC 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 provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction was provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism decreased to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.
The May 2018 Idaho Tax Reform Settlement Stipulation 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 became applicable on January 1, 2020.
The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its respective term.
Valmy Base Rate Adjustment Settlement Stipulations: In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North
Valmy coal-fired power plant in 2019 and 2025, respectively. In May 2019, the IPUC issued an order approving the North Valmy plant agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1.
Other Notable Idaho Regulatory Matters
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is 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. The IPUC has discretion to cap the annual increase in the FCA recovery 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:
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.
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 Public Utility Commission of Oregon (OPUC) issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.
In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. In December 2019, Idaho Power filed an application with the OPUC requesting approval of Idaho Power’s quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.
In June 2017, the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the
May 2018 settlement stipulation associated with income tax reform described above, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs for FERC-approved expenditures associated with its transmission system. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $107.0 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. REVENUES
IDACORP and Idaho Power adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), using the modified retrospective method on January 1, 2018. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, the companies recorded no cumulative-effect adjustment. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):
Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09, Revenue from Contracts with Customers (Topic 606). Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):
(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.
(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually.
Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year.
Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates.
Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $2.6 million, $3.6 million, and $4.7 million for 2019, 2018, and 2017, respectively.
Residential Customers: Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives.
Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers.
Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class.
Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales.
Provision for Sharing: Idaho Power's sharing mechanism is associated with the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation that provides for the sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. Based on full-year 2019 Idaho ROE, Idaho Power recorded no provision against current revenues for sharing of earnings with customers for 2019. Idaho Power recorded $5.0 million of sharing of earnings with customers during 2018 and no provision was recorded during 2017. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation is described further in Note 3 - "Regulatory Matters."
Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales.
Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be part of a long-term capacity contract, short-term contract, or on-demand when available. Transmission wheeling-related revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission wheeling-related revenues are affected by changes in Idaho Power’s OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region.
Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2019, Idaho Power's energy efficiency rider balances were a $0.3 million regulatory asset in the Idaho jurisdiction and a $1.2 million regulatory asset in the Oregon jurisdiction.
Alternative Revenue Programs and Derivative Revenues
While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of the FCA mechanism, which may increase or decrease tariff-based rates billed to customers. The FCA mechanism is described in detail in Note 3 - "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when the regulator-specified conditions for recognition have been met. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that had been initially recorded in prior periods when regulator-specified conditions were met. When those amounts are included in the price of utility service and billed to customers, such amounts are recorded as recovery of the associated regulatory asset or liability and not as revenues.
The table below presents the FCA mechanism revenues and derivative revenues (in thousands):
IDACORP's Other Revenues
IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydropower generation projects that satisfy the requirements of PURPA.
5. LONG-TERM DEBT
The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars):
(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, 2019, to $1.831 billion. These two bonds were purchased and remarketed in August of 2019. See "Long-Term Debt Issuances, Maturities, and Redemptions" below.
(2) At December 31, 2019 and 2018, the overall effective cost rate of Idaho Power's outstanding debt was 4.50 percent and 4.83 percent, respectively.
At December 31, 2019, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
Long-Term Debt Issuances, Maturities, and Redemptions
In March 2018, Idaho Power issued $220.0 million in principal amount of 4.20% first mortgage bonds, secured medium-term notes, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, $130.0 million in principal amount of 4.50% first mortgage bonds, secured medium-term notes, Series H, due March 2020. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium of $4.6
million. Idaho Power used a portion of the net proceeds from the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption.
In August 2019, Idaho Power purchased and remarketed two of its outstanding series of pollution control tax-exempt bonds, one in the aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in 2024, and the other in the aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in 2024 decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in 2026 decreased from 5.25 percent to 1.70 percent.
Idaho Power 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 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2022, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of 7.0 percent.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). 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.
As of the date of this report, Idaho Power has not entered into a selling agency agreement under the new shelf agreement. The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects 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, 2019, Idaho Power could issue under its Indenture approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-eighth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2019 was limited to approximately $669 million under the Indenture.
6. NOTES PAYABLE
Credit Facilities
On December 6, 2019, IDACORP and Idaho Power entered into amendments to their outstanding Credit Agreements, which provide credit facilities that may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.
The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero percent. An alternate benchmark rate selected by the administrative agent for the credit facilities and IDACORP and Idaho Power will apply during any period in which the LIBOR rate is unavailable or unascertainable. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original maturity date of December 6, 2024, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, subject to certain conditions.
At December 31, 2019, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2019, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. IDACORP’s and Idaho Power's short-term borrowings were zero at December 31, 2019, and December 31, 2018.
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, 2019:
(1) During 2019, 2018, and 2017, IDACORP granted 70,419, 75,761, and 72,397 restricted stock unit awards, respectively, to employees and 9,594, 12,950, and 12,050 shares of common stock, respectively, to directors but made 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, 2019, the leverage ratios for IDACORP and Idaho Power were 43 percent and 45 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.5 billion and $1.3 billion, respectively, at December 31, 2019. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At December 31, 2019, IDACORP and Idaho Power were in compliance with those covenants.
Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31, 2019, Idaho Power's common equity capital was 55 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, 2019, the maximum number of shares available under the LTICP was 613,394.
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:
The total fair value of shares vested was $9.4 million in 2019, $8.3 million in 2018, and $7.5 million in 2017. At December 31, 2019, IDACORP had $7.9 million of total unrecognized compensation cost related to nonvested share-based compensation. Idaho Power's share of this amount was $7.8 million. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue and/or treasury shares for these awards.
In 2019, a total of 9,594 shares were awarded to directors at a grant date fair value of $98.41 per share. Directors elected to defer receipt of 3,198 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):
(1) Due to tax reform, the effective income tax rate was reduced in 2018 for both IDACORP and Idaho Power, which is described in Note 2 - "Income Taxes."
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, 2019, 2018, and 2017 (in thousands, except for per share amounts):
10. COMMITMENTS
Purchase Obligations
At December 31, 2019, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
As of December 31, 2019, Idaho Power had 1,136 MW nameplate capacity of PURPA-related projects on-line, with an additional 11 MW nameplate capacity of projects projected to be on-line by 2022. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $187 million in 2019, $190 million in 2018, and $170 million in 2017.
Also, in March 2019, Idaho Power signed a 20-year power purchase agreement to purchase the output from a planned 120-megawatt solar facility. The agreement was approved by the IPUC in December 2019 and is, as of the date of this report, pending approval by the OPUC. If approved, the agreement would increase contractual obligations by $136 million over the 20-year term.
Idaho Power also has the following long-term commitments (in thousands of dollars):
(1) Approximately $27 million, $48 million, and $131 million of the obligations included in joint-operating agreement payments, maintenance and service agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
IDACORP’s expense for operating leases was not material for the years ended 2019, 2018, and 2017.
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 $58.3 million at December 31, 2019, representing IERCo's one-third share of BCC's total reclamation obligation of $175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2019, the value of the reclamation trust fund was $139.5 million. During 2019, the reclamation trust fund made no distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
In May 2019, the state of Wyoming enacted legislation that limits a mine operator's maximum amount of self-bonding. Idaho Power and the co-owners of BCC have until December 2020 to comply with the new regulations, which would reduce the portion of Idaho Power's guarantee of reclamation activities and obligations at BCC that Idaho Power is allowed to self-bond. As of the date of this report, Idaho Power believes the cost of any insurance, third-party assurance, or additional collateral that might be required for this guarantee due to the new law would be immaterial to the companies' consolidated financial statements.
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, 2019, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
11. CONTINGENCIES
IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.
IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company’s provision of electric service and the operation of its generation, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. In recent years, Idaho Power has regularly received claims by 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.
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.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.
The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2019 are due primarily to decreases in the assumed discount rates of both plans from December 31, 2018, to December 31, 2019. The actuarial gains affecting the benefit obligations for the pension and SMSP plans in 2018 are due primarily to increases in the assumed discount rates from December 31, 2017, to December 31, 2018. For more information on discount rates, see “Plan Assumptions” below in this Note 12.
As a non-qualified plan, the SMSP has 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 $97.6 million and $92.5 million at December 31, 2019 and 2018, 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.
(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 $15.1 million, $15.2 million, and $16.2 million respectively, was recognized in "Other operations and maintenance" and $11.0 million, and $11.6 million, and $11.2 million respectively, was recognized in "Other expense, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2019, 2018, and 2017.
The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2019, 2018, and 2017, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, IDACORP's and Idaho Power's minimum required contribution to the pension plan is estimated to be $14 million during 2020. Depending on market conditions and cash flow considerations in 2020, Idaho Power could contribute up to $40 million to the pension plan during 2020 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position.
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):
(1) Contributions and benefits paid are each net of $3.3 million and $3.1 million of plan participant contributions for 2019 and 2018, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
(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 shows the components of other comprehensive income for the plan (in thousands of dollars):
(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):
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:
(1) The 2019 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 1.97% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0.6% for employees in their fortieth year of service and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.7 percent in 2019 and is assumed to decrease to 5.9 percent in 2020, 5.2 percent in 2021, 5.1 percent in 2022 and to gradually decrease to 3.9 percent by 2091. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.0 percent, or equal to the medical trend rate if lower, for all years.
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2019, for the pension asset portfolio by asset class is set forth below:
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;
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match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of 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 30 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.
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).
(1) The postretirement benefits assets are primarily life insurance contracts.
For the years ended December 31, 2019 and 2018, there were no material transfers into or out of Levels 1, 2, or 3.
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Commingled Funds: These funds, made up of the international and emerging markets equity securities and commodities fund measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.
Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 9 years. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were approximately $7.7 million, $7.7 million, and $7.4 million in 2019, 2018, and 2017, respectively.
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, 2019, and 2018, were approximately $2 million.
13. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2019 and 2018 (in thousands of dollars):
At December 31, 2019, Idaho Power's construction work in progress balance of $552.5 million included relicensing costs of $326.0 million for the HCC, Idaho Power's largest hydropower complex. In 2019, 2018, and 2017, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes in 2019 and 2018 and $10.7 million when grossed-up for the effect of income taxes in 2017 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, 2019, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $151.7 million.
Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2019 (in thousands of dollars):
(1) Idaho Power’s share of nameplate capacity.
(2) Idaho Power ended its participation in coal-fired operations at unit 1 of the North Valmy plant on December 31, 2019.
IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power’s coal purchases from the joint venture were $73.6 million in 2019, $81.8 million in 2018, and $86.4 million in 2017.
Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8.6 million in 2019, $9.7 million in 2018, and $9.8 million in 2017.
IDACORP's consolidated VIE, Marysville, owns a hydropower plant with a net book value of $14.7 million and $15.2 million at December 31, 2019 and 2018, respectively.
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 reclamation and removal costs at its jointly-owned coal-fired generation facilities.
Idaho Power also has additional AROs associated with its transmission system, hydropower facilities, natural gas-fired generation facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 2019 and 2018.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
15. INVESTMENTS
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):
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):
Investments in Equity Securities
Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securities were immaterial at December 31, 2019 and December 31, 2018. The following table summarizes sales of equity securities (in thousands of dollars):
Investments in Affordable Housing
IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified affordable housing projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.
16. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018, and 2017 (in thousands of dollars):
(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, 2019 and 2018 (in thousands of dollars):
(1) Current asset derivative amounts offset include $45 thousand of collateral payable at December 31, 2018.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2019 and 2018 (in thousands of units):
Credit Risk
At December 31, 2019, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2019, was $3.0 million. Idaho Power posted $1.4 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2019, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $6.7 million to cover open liability positions as well as completed transactions that have not yet been paid.
17. FAIR VALUE MEASUREMENTS
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access.
• Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.
IDACORP and Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.
• 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, 2019 and 2018.
The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018 (in thousands of dollars):
(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, 2019 and 2018, using available market information and appropriate valuation methodologies (in thousands).
(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 hydropower 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.
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 hydropower generation projects, and IDACORP’s holding company expenses.
The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands):
19. OTHER INCOME AND EXPENSE
The following table presents the components of IDACORP’s other income (expense), net and Idaho Power's other income (expense), net (in thousands of dollars):
(1) The 2018 pension and postretirement non-service costs includes $4.2 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 12 - "Benefit Plans."
20. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the years ended December 31, 2019, 2018, and 2017 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
(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).
The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2019, 2018, and 2017 (in thousands of dollars). Items in parentheses indicate increases to net income.
(1) Amortization of these items is included in IDACORP's consolidated income statements in other operating expenses and in Idaho Power's consolidated income statements in other expense, net.
(2) The tax benefit is included in income tax expense in the consolidated income statements of both IDACORP and Idaho Power.
21. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.8 million in 2019 and $0.7 million in both 2018 and 2017.
At December 31, 2019 and 2018, Idaho Power had a $1.9 million payable to IDACORP, which was included in its accounts payable to affiliates balance on its consolidated balance sheets. In 2019, Idaho Power paid IDACORP certain estimated income taxes that had been accrued at December 31, 2018.
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s hydropower projects located in Idaho. Idaho Power paid Ida-West $8.6 million in 2019, $9.7 million in 2018, and $9.8 million in 2017 for that power.
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, 2019 and 2018, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedules listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements
Critical Audit Matter Description
Idaho Power Company ("Idaho Power"), the principal operating subsidiary of the Company, is subject to rate regulation by the Federal Energy Regulatory Commission and the Idaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Idaho and Oregon. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense.
Idaho Power’s rates are subject to regulatory rate-setting processes. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects Idaho Power to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
Additionally, consistent with orders and directives of the Commissions, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers for amounts collected prior to costs being incurred. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions and the application of flow-through accounting for income taxes included the following, among others:
•
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities.
•
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•
We read relevant regulatory orders issued by the Commissions for Idaho Power and evaluated whether such orders were appropriately reflected in the Company's financial statements.
•
For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders.
•
With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 20, 2020
We have served as the Company's auditor since 1932.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Idaho Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 20, 2020
We have served as the Company's auditor since 1932.
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA
The following unaudited information is presented for each quarter of 2019 and 2018 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures - IDACORP, Inc.
The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2019, have concluded that IDACORP, Inc.’s disclosure controls and procedures are effective as of that date.
Internal Control Over Financial Reporting - IDACORP, Inc.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2019. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
Based on its assessment, management concluded that, as of December 31, 2019, IDACORP’s internal control over financial reporting is effective based on those criteria.
IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2019 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2019.
February 20, 2020
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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 20, 2020, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. 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 20, 2020
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, 2019, have concluded that Idaho Power Company's disclosure controls and procedures are effective as of that date.
Internal Control Over Financial Reporting - Idaho Power Company
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2019. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
Based on its assessment, management concluded that, as of December 31, 2019, Idaho Power’s internal control over financial reporting is effective based on those criteria.
Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2019 and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2019.
February 20, 2020
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Idaho Power Company
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 20, 2020, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. 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 20, 2020
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, 2019 that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
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,” “Delinquent Section 16(a) Reports,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 2020 annual meeting of shareholders are hereby incorporated by reference.
Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”
ITEM 11.
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 2020 annual meeting of shareholders is hereby incorporated by reference.
ITEM 12.
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 2020 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2019, 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
ITEM 13.
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 2020 annual meeting of shareholders are hereby incorporated by reference.
ITEM 14.
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 2020 annual meeting of shareholders is hereby incorporated by reference.
Idaho Power: The table below presents the aggregate fees of Idaho Power's principal independent registered public accounting firm, Deloitte & Touche LLP, billed or is expected to bill to Idaho Power for the fiscal years ended December 31, 2019 and 2018:
Policy on Audit Committee Pre-Approval:
Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2019 and 2018, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee.
In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed
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.
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.
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 IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2019 are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements.
IDACORP, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
IDACORP, INC.
CONDENSED STATEMENTS OF CASH FLOWS
IDACORP, INC.
CONDENSED BALANCE SHEETS
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 2019 Form 10-K, Part II, Item 8.
Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $133 million, $124 million, and $116 million in 2019, 2018, and 2017, respectively.
IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2019, 2018, and 2017
(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.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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.
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.
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.