HAWAIIAN ELECTRIC CO INC - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

•

international, national and local economic and political conditions—including the state of the Hawaii tourism, defense and construction industries; the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by ASB, which could result in higher loan loss provisions and write-offs); decisions concerning the extent of the presence of the federal government and military in Hawaii; the implications and potential impacts of future Federal government shutdowns, including the impact to our customers to pay their electric bills and/or bank loans and the impact on the state of Hawaii economy; the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions; and the potential impacts of global and local developments (including economic conditions and uncertainties; unrest, terrorist acts, wars, conflicts, political protests, deadly virus epidemic, potential pandemic or other crisis; the effects of changes that have or may occur in U.S. policy, such as with respect to immigration and trade);

•	the effects of future actions or inaction of the U.S. government or related agencies, including those related to the U.S. debt ceiling or budget funding, monetary policy, trade policy and tariffs, and other policy and regulatory changes advanced or proposed by President Trump and his administration;

•	weather, natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes, lava flows and the increasing effects of climate change, such as more severe storms, flooding, droughts, heat waves, and rising sea levels) and wildfires, including their impact on the Company’s and Utilities’ operations and the economy;

•	the timing, speed and extent of changes in interest rates and the shape of the yield curve;

•	the ability of the Company and the Utilities to access the credit and capital markets (e.g., to obtain commercial paper and other short-term and long-term debt financing, including lines of credit, and, in the case of HEI, to issue common stock) under volatile and challenging market conditions, and the cost of such financings, if available;

•	the risks inherent in changes in the value of the Company’s pension and other retirement plan assets and ASB’s securities available for sale, and the risks inherent in changes in the value of the Company’s pension liabilities, including changes driven by interest rates;

•	changes in laws, regulations (including tax regulations), market conditions, interest rates and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;

•	the impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated, as amended by the Economic Growth, Regulatory Relief and Consumer Protection Act;

•	increasing competition in the banking industry (e.g., increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);

•

the potential delay by the Public Utilities Commission of the State of Hawaii (PUC) in considering (and potential disapproval of actual or proposed) renewable energy proposals and related costs; reliance by the Utilities on outside parties such as the state, independent power producers (IPPs) and developers; and uncertainties surrounding technologies, solar power, wind power, biofuels, environmental assessments required to meet renewable portfolio standards (RPS) goals and the impacts of implementation of the renewable energy proposals on future costs of electricity;

•

the ability of the Utilities to develop, implement and recover the costs of implementing the Utilities’ action plans included in their updated Power Supply Improvement Plans, Demand Response Portfolio Plan, Distributed Generation Interconnection Plan, Grid Modernization Plans, and business model changes, which have been and are continuing to be developed and updated in response to the orders issued by the PUC, the PUC’s April 2014 statement of its inclinations on the future of Hawaii’s electric utilities and the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customer interests and the state’s public policy goals, and subsequent orders of the PUC;

•	capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management, distributed generation (DG), combined heat and power or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

•	fuel oil price changes, delivery of adequate fuel by suppliers and the continued availability to the electric utilities of their energy cost recovery clauses (ECRCs);

•	the continued availability to the electric utilities or modifications of other cost recovery mechanisms, including the purchased power adjustment clauses (PPACs), rate adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales to mitigate the effects of declining kilowatthour sales;

•	the ability of the Utilities to recover increasing costs and earn a reasonable return on capital investments not covered by RAMs;

•	the ability of the Utilities to achieve performance incentive goals currently in place;

•	the impact from the PUC’s implementation of performance-based ratemaking for the Utilities pursuant to Act 005, Session Laws 2018, including the potential addition of new performance incentive mechanisms (PIMs), third-party proposals adopted by the PUC in its implementation of performance-based regulation (PBR), and the implications of not achieving performance incentive goals;

•	the impact of fuel price levels and volatility on customer satisfaction and political and regulatory support for the Utilities;

---

•	the risks associated with increasing reliance on renewable energy, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;

•	the growing risk that energy production from renewable generating resources may be curtailed and the interconnection of additional resources will be constrained as more generating resources are added to the Utilities’ electric systems and as customers reduce their energy usage;

•	the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);

•	the potential that, as IPP contracts near the end of their terms, there may be less economic incentive for the IPPs to make investments in their units to ensure the availability of their units;

•	the ability of the Utilities to negotiate, periodically, favorable agreements for significant resources such as fuel supply contracts and collective bargaining agreements and avoid or mitigate labor disputes and work stoppages;

•	new technological developments that could affect the operations and prospects of the Utilities and ASB or their competitors such as the commercial development of energy storage and microgrids and banking through alternative channels;

•	cybersecurity risks and the potential for cyber incidents, including potential incidents at HEI, its third-party vendors, and its subsidiaries (including at ASB branches and electric utility plants) and incidents at data processing centers used, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general IT controls;

•	failure to achieve cost savings consistent with the minimum $246 million in Enterprise Resource Planning/Enterprise Asset Management

•

federal, state, county and international governmental and regulatory actions, such as existing, new and changes in laws, rules and regulations applicable to HEI, the Utilities and ASB (including changes in taxation, increases in capital requirements, regulatory policy changes, environmental laws and regulations (including resulting compliance costs and risks of fines and penalties and/or liabilities), the regulation of greenhouse gas emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

•	developments in laws, regulations and policies governing protections for historic, archaeological and cultural sites, and plant and animal species and habitats, as well as developments in the implementation and enforcement of such laws, regulations and policies;

•	discovery of conditions that may be attributable to historical chemical releases, including any necessary investigation and remediation, and any associated enforcement, litigation or regulatory oversight;

•	decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs as a result of adverse regulatory audit reports or otherwise);

•	decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, such as with respect to environmental conditions or RPS);

•

potential enforcement actions by the Office of the Comptroller of the Currency (OCC), the Federal Reserve Board (FRB), the Federal Deposit Insurance Corporation (FDIC) and/or other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);

•	the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);

•	changes in accounting principles applicable to HEI and its subsidiaries, including the adoption of new U.S. accounting standards, the potential discontinuance of regulatory accounting, the effects of potentially required consolidation of variable interest entities (VIEs), or required capital/finance lease or on-balance-sheet operating lease accounting for PPAs with IPPs;

•	downgrades by securities rating agencies in their ratings of the securities of HEI and Hawaiian Electric and their impact on results of financing efforts;

•	faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage-servicing assets of ASB;

•	changes in ASB’s loan portfolio credit profile and asset quality and/or mix, which may increase or decrease the required level of provision for loan losses, allowance for loan losses (ALL) and charge-offs;

•	the adoption of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020, which may result in more volatility in the provision for loan losses prospectively;

•	changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;

•	unanticipated changes from the expected discontinuance of LIBOR and the transition to an alternative reference rate, which may include adverse impacts to the Company’s cost of capital, loan portfolio and interest income on loans;

•	the final outcome of tax positions taken by HEI and its subsidiaries;

•	the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the Utilities’ transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits);

•	the ability of the Company’s non-regulated subsidiary, Pacific Current, LLC (Pacific Current), to achieve its performance and growth objectives, which in turn could affect its ability to service its non-recourse debt;

•	the Company’s reliance on third parties and the risk of their non-performance;

•	the impact of activism that could delay the construction, or preclude the completion, of third-party or Utility projects that are required to meet electricity demand and RPS goals; and

•	other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports previously and subsequently filed by HEI and/or Hawaiian Electric with the Securities and Exchange Commission (SEC).

---

---

---

---

1	Since May 2018, Puna Geothermal Venture (PGV) has been offline due to lava flow on Hawaii Island; therefore, PGV’s capability has not been incorporated into the utility’s firm contract power capability as of December 31, 2019.

2	Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

---

1	Hawaiian Electric units at normal ratings; Hawaii Electric Light and Maui Electric units at reserve ratings.

2

Nonutility generators - Hawaiian Electric: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 68.5 MW (HPOWER, refuse-fired); Hawaii Electric Light: 60 MW (Hamakua Energy, LLC, oil-fired). Hawaii Electric Light also has a firm capacity PPA with PGV for 34.6 MW. However, since May 2018, PGV has been offline due to lava flow on Hawaii Island; therefore, PGV’s capability has not been incorporated into the utility’s firm contract power capability as of December 31, 2019.

3	Noncoincident and nonintegrated.

---

---

---

---

---

3	Hawaiian Electric has a 37-year land lease on 102 acres, effective July 1, 2017, with the Secretary of the Navy.

5	The four plants are situated on Maui Electric-owned land having a combined area of 60.7 acres.

2	There are an additional 56,358 barrels of diesel oil storage capacity off-site at Aloha Petroleum, Ltd. (Aloha Petroleum)-owned terminalling facilities.

---

---

---

•	ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2019 with a Tier 1 leverage ratio of 9.1% (4.0%), a common equity Tier 1 capital ratio of 13.2% (4.5%), a Tier 1 capital ratio of 13.2% (6.0%) and a total capital ratio of 14.3% (8.0%).

•	ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2019 with a Tier 1 leverage ratio of 9.1% (5.0%), a common equity Tier 1 capital ratio of 13.2% (6.5%), a Tier 1 capital ratio of 13.2% (8.0%) and a total capital ratio of 14.3% (10.0%).

---

---

---

---

•	the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, Hawaiian Electric, to pay dividends to HEI in the event that the consolidated common stock equity of the Utilities falls below 35% of total capitalization of the electric utilities;

•

the provisions of an HEI agreement entered into with federal bank regulators in connection with its acquisition of its bank subsidiary, ASB, which require HEI to contribute additional capital to ASB (up to a maximum amount of additional capital of $28.3 million as of December 31, 2019 under the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI (HEI Diversified Inc.) and the Federal Savings and Loan Insurance Corporation) upon request of the regulators in order to maintain ASB’s regulatory capital at the level required by regulation;

•	the minimum capital and capital distribution regulations of the OCC that are applicable to ASB and capital regulations that become applicable to HEI and ASB Hawaii;

•	the receipt of a letter from the FRB communicating the OCC’s and FRB’s non-objection to the payment of any dividend ASB proposes to declare and pay to ASB Hawaii and HEI; and

•	the provisions of preferred stock resolutions and debt instruments of HEI and its subsidiaries.

---

---

•

ASB, one of the largest financial institutions in the state, is in direct competition for deposits and loans not only with two larger institutions that have substantial capital, technology and marketing resources, but also with smaller Hawaii institutions and other U.S. institutions, including credit unions, mutual funds, mortgage brokers, finance companies and investment banking firms. Larger financial institutions may have greater access to capital at lower costs, which could impair ASB’s ability to compete effectively. New or significant advances in technology (e.g., significant advances in internet banking) could render the operations of ASB less competitive or obsolete.

•

The Utilities face competition from IPPs; customer self-generation, with or without cogeneration; customer energy storage; and the potential formation of community-based, cooperative ownership or municipality structures for electrical service on all islands it serves. With the exception of certain identified projects, the Utilities are required to use competitive bidding to acquire a future generation resource unless the PUC finds competitive bidding to be unsuitable. The PUC sets policies for distributed generation (DG) interconnection agreements and standby rates. The results of competitive bidding, competition from IPPs, customer self-generation, and potential cooperative ownership or municipality structures for electric utility service, and the rate at which technological developments facilitating nonutility generation of electricity, combined heat and power technology, off-grid microgrids, and customer energy storage may render the operations of the Utilities less competitive or outdated and adversely affect the Utilities and the results of their operations.

---

---

---

---

---

---

---

•	local, regional, national and other economic and political conditions that could result in declines in employment and real estate values, which in turn could adversely affect the ability of borrowers to make loan payments and the ability of ASB to recover the full amounts owing to it under defaulted loans;

•	the ability of borrowers to obtain insurance and the ability of ASB to place insurance where borrowers fail to do so, particularly in the event of catastrophic damage to collateral securing loans made by ASB;

•	faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing assets of ASB;

•	changes in ASB’s loan portfolio credit profiles and asset quality, which may increase or decrease the required level of allowance for loan losses;

•	technological disruptions affecting ASB’s operations or financial or operational difficulties experienced by any outside vendor on whom ASB relies to provide key components of its business operations, such as business processing, network access or internet connections;

•	events of default and foreclosure of loans whereby ASB becomes the owner of a mortgage properties that presents environmental risk or potential clean up liability;

•	the impact of legislative and regulatory changes, including changes affecting capital requirements, increasing oversight of and reporting by banks, or affecting the lending programs or other business activities of ASB;

•	additional legislative changes regulating the assessment of overdraft, interchange and credit card fees, which can have a negative impact on noninterest income;

•	public opinion about ASB and financial institutions in general, which, if negative, could impact the public’s trust and confidence in ASB and adversely affect ASB’s ability to attract and retain customers and expose ASB to adverse legal and regulatory consequences;

•	increases in operating costs (including employee compensation expense and benefits and regulatory compliance costs), inflation and other factors, that exceed increases in ASB’s net interest, fee and other income; and

•	the ability of ASB to maintain or increase the level of deposits, ASB’s lowest costing funds.

---

---

---

---

---

*	At December 31.

**	Calculated using December 31 market price per common share divided by basic earnings per common share.

***	At December 31. Represents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 13, 2020, HEI had 5,564 registered shareholders (i.e., holders of record of HEI common stock), 22,060 DRIP participants and total shareholders of 24,651.

---

*	At December 31.

---

---

---

---

*	Moody’s long-term debt rating was withdrawn because HEI does not currently have any outstanding, publicly traded debt. Moody’s continues to rate Hawaiian Electric’s long-term debt. See ‘Electric utility–Liquidity and capital resources’ below.

**	On February 20, 2020, S&P revised HEI’s outlook to positive and affirmed HEI’s issuer credit and commercial paper ratings.

---

1	Includes contractual obligations and commitments for capital expenditures and expense amounts.

---

1.	obligations under guarantee contracts,

2.	retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serve as credit, liquidity or market risk support to that entity for such assets,

3.	obligations under derivative instruments, and

4.	obligations under a material variable interest held by the Company or the Utilities in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company or the Utilities, or engages in leasing, hedging or research and development services with the Company or the Utilities.

---

---

---

---

1	The rate schedules of the electric utilities currently contain ECRCs (changed from ECACs in 2019) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

2	The rate schedules of the electric utilities currently contain PPACs through which changes in purchase power expenses (except purchased energy costs) are passed on to customers.

3	kWh sales were higher in 2019 when compared to the prior year due largely to warmer humid weather in 2019 than 2018.

---

1	Final D&O was issued on June 22, 2018.

---

•

In December 2014, the PUC approved a PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and Na Pua Makani Power Partners, LLC (NPM) for a proposed 24-MW wind farm on Oahu. The NPM wind farm was expected to be placed into service by August 31, 2019, but has been delayed due to an appeal of the decision in the Habitat Conservation Permit contested case. NPM has now received its Habitat Conservation Permit and is constructing the project. Life of the Land (LOL) filed a Motion for Relief to argue the PPA approval was invalid and should be revised. The Utilities and the Consumer Advocate filed an opposition to this motion for relief. A hearing on the motion for relief was held on November 22, 2019. The PUC has not yet ruled.

•

In July 2017, the PUC approved, with certain modifications and conditions, three PPAs for solar energy on Oahu with Waipio PV, LLC for 45.9 MW, Lanikuhana Solar, LLC for 14.7 MW and Kawailoa Solar, LLC for 49.0 MW. The three projects are now owned by Clearway Energy Group LLC, whose controlling investor is Global Infrastructure Partners. On September 19, 2019, Lanikuhana Solar and Waipio PV projects achieved commercial operations. On November 20, 2019, Kawailoa Solar, LLC achieved commercial operations.

•	In July 2018, the PUC approved Maui Electric’s PPA with Molokai New Energy Partners to purchase solar energy from a PV plus battery storage project. The 4.88 MW project will deliver no more than 2.64 MW at any time to the Molokai system. The project is expected to be in service in 2020.

•

In November 2018, Hawaiian Electric filed with the PUC a PPA for Renewable As-Available Energy dated October 22, 2018 between Hawaiian Electric and EE Ewa, LLC (Palehua) for a proposed 46.8 MW wind farm on Oahu, subject to PUC approval. On September 6, 2019, the PUC issued an order dismissing without prejudice Hawaiian Electric’s application for a waiver of the proposed Palehua wind project from the PUC’s framework for competitive bidding and approval of the PPA. Due to the foregoing, the PPA has been declared null and void.

•

On December 31, 2019, Hawaii Electric Light and PGV entered into an Amended and Restated Power Purchase Agreement (ARPPA), subject to approval by the PUC. The ARPPA extends the term of the existing PPA by 25 years to 2052, expands the firm capacity of the facility to 46 MW and delinks the pricing for energy delivered from the facility from fossil fuel prices to reduce cost to customers. The existing PPA (except for lower-tiered pricing for certain energy dispatched above 30 MW) will remain in effect until it is superseded by the ARPPA when the expanded capacity is in commercial operation.

---

•

As of December 31, 2019, there were approximately 471 MW, 104 MW and 118 MW of installed distributed renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, for tariff-based private customer generation programs, namely Standard Interconnection Agreement, Net Energy Metering, Net Energy Metering Plus, Customer Grid Supply, Customer Self Supply, Customer Grid Supply Plus and Interim Smart Export. As of December 31, 2019, an estimated 29% of single-family homes on the islands of Oahu, Hawaii and Maui have installed private rooftop solar systems, and approximately 18% of the Utilities’ total customers have solar systems.

•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2019, there were 34 MW, 3 MW and 5 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

•

In July 2018, the PUC approved Hawaiian Electric’s 3-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC (PBT) to supply 2 million to 4 million gallons of biodiesel at Hawaiian Electric’s Schofield Generating Station and the Honolulu International Airport Emergency Power Facility (HIA Facility) and any other generating unit on Oahu, as necessary. The PBT contract became effective on November 1, 2018. Hawaiian Electric also has a spot buy contract with PBT to purchase additional quantities of biodiesel at or below the price of diesel. Some purchases of “at parity” biodiesel have been made under the spot purchase contract, which was recently extended through June 2021.

•	Hawaiian Electric has a contingency supply contract with REG Marketing & Logistics Group, LLC to also supply biodiesel to any generating unit on Oahu in the event PBT is not able to supply necessary quantities. This contingency contract has been extended to November 2020, and will continue with no volume purchase requirements.

•	Under a request for proposal process governed by the PUC and monitored by independent observers, in February 2018, the Utilities issued RFPs for 220 MW of renewable generation on Oahu, 50 MW of renewable generation on Hawaii Island, and 60 MW of renewable generation on Maui. The Utilities selected a final award group for Hawaii Island in August 2018 and for Maui and Oahu in September 2018.

•

In continuation of its February 2018 request for proposal process, the Utilities issued its Stage 2 Renewable RFPs for Oahu, Maui and Hawaii Island and Grid Services RFP on August 22, 2019. This procurement plan sought approximately 900 MW of renewable energy, including 594 MW on Oahu, 135 MW on Maui and a range between 32 to 203 MW on Hawaii Island. This second phase, as approved by the PUC, was open to all renewable and storage resources, including efforts to add more renewable generation, renewable plus storage, standalone storage and grid services. The scope of these RFPs has been expanded to accelerate renewable energy procurements beyond the remainder of the 2022 targets identified in Stage 1 to include the energy requirement associated with the planned retirement of the Kahului Power Plant on Maui and the upcoming expiration of the agreement for the AES Hawaii facility on Oahu. For the Grid Services RFP, the targets had been expanded in alignment with the Renewable RFPs.

---

•

On November 27, 2019, the Utilities issued RFPs for renewable generation paired with energy storage on the islands of Lanai and Molokai. Projects may come online as early as 2022. The Utilities are seeking PV paired with storage or small wind (specified as 100 kW turbines or smaller) on Molokai and PV paired with storage on Lanai. Proposals for the Molokai RFP were received on February 14, 2020, and are currently being evaluated by the Utilities. The Lanai RFP has been temporarily postponed, while the Utilities reevaluate the system needs. The Utilities expect to issue an update to the Lanai RFP no later than March 10, 2020.

---

1	Short-term borrowings as of December 31, 2019 reflect the impact of funding for a senior note of $82 million included in long-term debt, net, which was paid off on January 1, 2020 (see Note 6 of the Consolidated Financial Statements).

1

The maximum amount of external short-term borrowings by Hawaiian Electric during 2019 was $158 million. At December 31, 2019, Hawaiian Electric had short-term borrowings from Hawaii Electric Light of $8 million and Maui Electric had short-term borrowings from Hawaiian Electric of $27.7 million, which intercompany borrowings are eliminated in consolidation. In addition to the short-term borrowings above, Hawaiian Electric drew $50 million on December 23, 2019 on a 364-day term loan facility (see Note 5 of the Consolidated Financial Statements).

---

**	On February 20, 2020, S&P revised Utilities’ outlook to positive and affirmed Utilities’ issuer credit and commercial paper ratings.

---

---

---

---

---

1.	deepening customer relationships;

2.	building out product and service offerings to open new segments;

3.	fully deploying online and remotely-assisted account opening capabilities; and

4.	prioritizing efficiency actions to gain earnings leverage on organic growth.

1.	attracting and retaining low-cost deposits, particularly those in non-interest bearing transaction accounts;

2.	diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable rate loans;

3.	focusing investment growth in securities that exhibit less extension risk (i.e., risk of longer average lives) as rates rise.

•	2019 vs. 2018

---

---

1	Includes loans held for sale, at lower of cost or fair value, of $6.3 million, $2.3 million and $7.4 million as of December 31, 2019, 2018 and 2017, respectively.

2	Includes recognition of net deferred loan fees of $0.2 million, $0.1 million and $1.7 million for 2019, 2018 and 2017 respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

3	For 2019, 2018 and 2017, the taxable-equivalent basis adjustments made to the table above were not material.

4	Defined as net interest income, on a fully taxable equivalent basis, as a percentage of average total interest-earning assets.

---

---

1	Includes renegotiated loans.

---

---

---

1	Based on the contractual rate that was being charged at the time the loan was restructured or placed on nonaccrual status.

---

---

---

1	As of December 31, 2019, no investment exceeded 10% of ASB’s shareholder’s equity.

2	Weighted average yield on the mortgage revenue bonds is computed on a tax equivalent basis using a federal statutory tax rate of 21%.

---

---

---

---

---

---

---

---

---

---

---

•

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. Such controls include the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or incurring future reductions in rates.

•	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 PUC for the Company, regulatory statutes, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the PUC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•	For regulatory matters in process, we inspected the Company’s filings with the PUC and the filings with the PUC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•	We obtained analyses from management, which includes input from regulatory and legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery, or a future reduction in rates.

---

•	We tested the effectiveness of controls over the Allowance, including management’s controls over the respective qualitative factors.

•	We evaluated the reasonableness and conceptual soundness of the Allowance modeling framework, including the use of qualitative factors.

•	We tested the mathematical accuracy of the calculation of the qualitative Allowance as well as the accuracy and completeness of data used as inputs to the determination of qualitative factors.

•	We evaluated the qualitative factors applied to the historical loss rates under the incurred loss model, including assessing the basis for the factors and the reasonableness of the qualitative factors used in the Allowance.

•

In order to identify potential bias in the determination of the Allowance, we performed analytical analysis, including retrospective review, where we compared the estimate of losses to actual losses, analyzed ratios of the Allowance to loans and other relevant metric, such as losses and nonperforming loans, and performed peer analysis where we compared relevant metrics to comparable financial institutions.

•	We evaluated the directional consistency and magnitude of the qualitative adjustments as well as the absolute value of the Allowance attributable to the qualitative adjustments.

---

•	We tested the effectiveness of management’s internal controls over key assumptions and judgments, expected loss estimation models, selection and application of new accounting policies, and disclosure of the impact of adoption discussed in the financial statements.

•	We evaluated the adequacy of the Company’s disclosure related to the Adoption of ASU No. 2016-13.

•	We evaluated the appropriateness of the Company’s policies, methodologies, and elections involved in the adoption of the expected loss model.

•	We tested the mathematical accuracy of the expected loss estimation models, including the completeness and accuracy of inputs to the models.

•	We involved credit specialist to assist us in evaluating the reasonableness and conceptual soundness of the methodology as applied in the expected loss estimation models.

•	We evaluated the reasonableness of management’s key assumptions and judgments in estimating future credit losses.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

Level 1:	Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used to measure fair value whenever available.

Level 2:

Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3:	Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

---

•

With respect to Topic 326, Financial Instruments - Credit Losses, ASU No. 2019-04 allows entities to measure the allowance for credit losses on accrued interest receivable balances separately from other components of the amortized cost basis of associated financial assets, or to make an accounting policy election not to measure an allowance for credit losses on accrued interest receivable amounts if an entity writes off the uncollectible accrued interest receivable balance in a timely manner and makes certain disclosures. ASU No. 2019-04 also allows an entity to make an accounting policy election regarding the presentation and disclosure of accrued interest receivables and the related allowance for credit losses for those accrued interest receivables. ASU No. 2019-04 also clarifies certain issues related

---

•	With respect to Topic 815, Derivatives and Hedging, ASU No. 2019-04 provides amendments, among others, that address partial-term fair value hedges, fair value hedge basis adjustments, and certain transition requirements.

•	With respect to Topic 825, Financial Instruments, ASU No. 2019-04 clarifies the scope of the guidance and disclosure requirements with respect to recognizing and measuring financial instruments.

---

---

---

---

---

---

1	Contributions in aid of construction balances are included in capital expenditures.

---

---

---

---

---

---

•	Service Quality performance incentives are measured on a calendar-year basis. The PIM tariff requires the performance targets, deadbands and the amount of maximum financial incentives used to determine the PIM financial incentive levels for each of the PIMs to be re-determined upon issuance of an interim or final order in a general rate case for each utility.

•

Service Reliability Performance measured by System Average Interruption Duration and Frequency Indexes (penalties only). Target performance is based on each utility’s historical 10-year average performance with a deadband of one standard deviation. The maximum penalty for each performance index is 20 basis points applied to the common equity share of each respective utility’s approved rate base (or maximum penalties of approximately $6.7 million - for both indices in total for the three utilities).

•	Call Center Performance measured by the percentage of calls answered within 30 seconds. Target performance is based on the annual average performance for each utility for the most recent 8 quarters with a deadband of 3% above and below the target. The maximum penalty or reward is 8 basis points applied to the common equity share of

---

•

In December 2018, the Utilities accrued $2.1 million in estimated penalties for service reliability, net of call center performance rewards, for 2018. As a result of a PUC order denying the exclusion of the impact of a specific project on the service reliability performance, in May 2019, Hawaiian Electric accrued an additional $1.3 million in service reliability penalties related to 2018. The net service quality performance penalties related to 2018 were reflected in the 2019 annual decoupling filing and will reduce customer rates in the period June 1, 2019 through May 31, 2020.

•	In December 2019, the Utilities accrued $0.3 million in estimated rewards for call center performance, net of service reliability penalties, for 2019. The net service quality performance rewards related to 2019 will be reflected in the 2020 annual decoupling filing and will increase customer rates in the period June 1, 2020 through May 31, 2021.

•

Procurement of low-cost variable renewable resources through the request for proposal process in 2018 measured by comparison of the procurement price to target prices. The incentive is a percentage of the savings determined by comparing procured price to a target of 11.5 cents per kilowatt-hour for renewable projects with storage capability and 9.5 cents per kilowatt-hour for energy-only renewable projects. For PPAs filed by December 31, 2018 and subsequently approved by the PUC, the incentive is 20% of the savings, with a cap of $3.5 million for the three utilities in total. For PPAs filed in January, February, and March 2019 and subsequently approved by the PUC, scaled incentives are 15%, 10% and 5%, respectively, of the savings for PPAs, with a cap of $3 million for the three utilities in total. There are no penalties. On March 25, 2019, the PUC approved six contracts, which were filed by December 31, 2018 and qualified for incentives. A seventh contract, which was filed in February 2019 and approved in August 2019, also qualified for incentives. Half of the incentive is earned upon PUC approval of the contract and the other half is eligible to be earned in the year following the in-service date of the projects. The Utilities accrued $1.7 million in incentives in March 2019, which were reflected in the 2019 annual decoupling filing and will be recovered in rates in the period June 1, 2019 through May 31, 2020.

*	The 2017 Tax Cuts and Jobs Act (the Tax Act) had two incremental impacts in 2019. First, the 2019 RAM calculation for all of the Utilities incorporated additional amortization of the regulatory liability associated with certain deferred taxes. Secondly, Maui Electric incorporated a $2.8 million adjustment in its 2018 annual decoupling filing related to the Tax Act which is not recurring in 2019.

•	Greater cost control and reduced rate volatility;

•	Efficient investment and allocation of resources regardless of classification as capital or operating expense;

•	Fair distribution of risks between utilities and customers; and

•	Fulfillment of State policy goals.

---

---

---

---

---

---

---

---

---

---

---

[1]	Eliminations of intercompany receivables and payables and other intercompany transactions.

[2]	Elimination of investment in subsidiaries, carried at equity.

---

---

---

---

---

---

---

---

---

---

---

---

1	The period end balances reflect all paydowns and charge-offs since the modification period. TDRs fully paid off, charged-off, or foreclosed upon by period end are not included.

---

---

---

---

---

---

---

---

1	See components of “Total long-term debt” and unamortized debt issuance costs in Hawaiian Electric and subsidiaries’ Consolidated Statements of Capitalization.

---

---

1

The Company and the Utilities adopted ASU No. 2018-02 as of the beginning of the fourth quarter of 2017 and elected to reclassify the income tax effects of the Tax Act from AOCI to retained earnings. Other than this reclassification to retained earnings, the Company and the Utilities release the income tax effects in AOCI from AOCI when the specific AOCI items (e.g., on a security-by-security basis for ASB’s gains/losses on investment securities) are included in net income.

---

---

1	The fixed capacity payment related to the existing PPA with PGV, which will expire on December 31, 2027, is not included as a lease liability as of December 31, 2019 as the facility has been offline since May 2018 due to lava flow on Hawaii Island. The annual capacity payment is approximately $7 million. The lease liability will be remeasured when PGV is back in service.

---

---

---

---

---

---

---

1	Asset allocation (excluding cash) is applicable to only HEI and the Utilities. As of December 31, 2019 and 2018, nearly all of ASB’s pension assets were invested in fixed income securities.

2	Asset allocation (excluding cash) is applicable to only HEI and the Utilities. ASB does not fund its other benefits.

---

---

(a)

Represents investments in funds that primarily invest in non-U.S., emerging markets equities. Redemption frequency for pension benefits assets as of December 31, 2019 were: daily, 60% and monthly, 40%, and as of December 31, 2018 were daily, 32% and monthly, 68%. Redemption frequency for other benefits assets as of December 31, 2019 were: daily, 59% and monthly, 41% and as of December 31, 2018 were: daily, 27% and monthly, 73%.

(b)	Represents investments in fixed income securities invested in a US-dollar denominated fund that seeks to exceed the Barclays Capital Long Corporate A or better Index through investments in US-dollar denominated fixed income securities and commingled vehicles.

(c)	Represents investments in cash equivalent funds. This class includes funds that invest primarily in securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. For pension benefits, the fund may also invest in fixed income securities of investment grade issuers.

---

---

---

1	For 2019, 2018 and 2017, the Company has not capitalized any share-based compensation.

(1)	Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

---

(1)	Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.

(1)	Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

---

*	The 2018 deferred income tax expense includes the final adjustment to reduce the provisional amount recorded in 2017 pursuant to Staff Accounting Bulletin No. 118 (SAB No. 118). See “Major tax developments” disclosure below for details of the accounting for the enactment of the Tax Act.

**	Represents 2019 federal and state tax credits, primarily related to the West Loch PV project, deferred and amortized starting in 2020. See West Loch PV Project discussion in Note 3.

---

1

As of December 31, 2019, HEI consolidated and Hawaiian Electric consolidated have deferred tax assets of $8.7 million and $6.7 million respectively, relating to the benefit of state tax credit carryforwards of $11.7 million and $9 million respectively. These state tax credit carryforwards primarily relate to the West Loch PV project and do not expire. The Company concluded that as of December 31, 2019, a valuation allowance is not required.

---

---

---

---

---

---

2	Derivatives are included in Other liabilities in the balance sheets.

---

(1)	Represent percent of outstanding principal balance.

---

1	Operating income for the fourth quarter of 2019 includes gains on property sales totaling $10.8 million, and net income and net income for common stock includes $7.9 million (or $0.07 per share (basic and diluted) at ASB’s 26.8% statutory tax rate).

2	The quarterly basic earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.

3	The quarterly diluted earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.

---

(1)	is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)	is accumulated and communicated to HEI management, including HEI’s CEO and CFO, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(1)	is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)	is accumulated and communicated to Hawaiian Electric management, including Hawaiian Electric’s CEO and CFO, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

---

•	“Nominees for three Class III directors whose terms expire at the 2023 Annual Meeting”

•	“Nominee for one Class I director whose term expires at the 2021 Annual Meeting”

•	“Continuing Class I directors whose terms expire at the 2021 Annual Meeting”

•	“Continuing Class II directors whose terms expire at the 2022 Annual Meeting”

•	“Committees of the Board” (portions regarding whether HEI has an audit & risk committee and identifying its members; no other portion of the Committees of the Board section is incorporated herein by reference)

•	“Audit & Risk Committee Report” (portion identifying audit & risk committee financial experts who serve on the HEI Audit & Risk Committee only; no other portion of the Audit & Risk Committee Report is incorporated herein by reference)

---

•	Pages 6 to 31 of Hawaiian Electric Exhibit 99.1 to this Form 10-K;

•	The discussion of “2018-20 Long-Term Incentive Plan” at pages 15-16 of Hawaiian Electric’s Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2017; and

•	Information concerning compensation paid to directors of Hawaiian Electric who are also directors of HEI under the section of HEI’s 2020 Proxy Statement entitled, “Director Compensation.”

---

*	Under the amended EIP as of December 31, 2019, RSUs count as one share against shares available for issuance less estimated shares withheld for taxes under net share settlement which again become available for the issuance of new shares on a one-to-one basis.

(2)	This represents the number of shares available as of December 31, 2019 for future awards, including 2,448,827 shares available for future awards under the amended EIP and 310,263 shares available for future awards under the 2011 Nonemployee Director Plan.

---

---

---

---

---

---

(a)	Primarily recoveries.

(b)	Bad debts charged off.

(c)	Represents provision for loan losses.

(d)	Reclass (reversal) of allowance for one customer account into other long term assets in 2018 and 2017 were $(4,934), and $841, respectively.

---

---

---

---

---

---

---

---