0000354707 us-gaap:ConstructionLoansMember us-gaap:UnlikelyToBeCollectedFinancingReceivableMember 2019-12-31 0000354707 srt:ParentCompanyMember he:ASBHawaiiInc.Member he:ConsolidatedSubsidiaryMember 2017-01-01 2017-12-31




     


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[X]☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20162019
OR
[  ]☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

Exact Name of RegistrantCommissionI.R.S. Employer
Commission
as Specified in Its Charter
File Number
Registrant; State of Incorporation;
Address; and Telephone Number
I.R.S. Employer
Identification No.
1-8503Hawaiian Electric Industries, Inc.
HAWAIIAN ELECTRIC INDUSTRIES, INC., a Hawaii corporation
1001 Bishop Street, Suite 2900, Honolulu, Hawaii 96813
Telephone (808) 543-5662
1-850399-0208097
1-4955Hawaiian Electric Company, Inc.
HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation
900 Richards Street, Honolulu, Hawaii 96813
Telephone (808) 543-7771
1-495599-0040500


State of Hawaii
(State or other jurisdiction of incorporation)
1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813 - Hawaiian Electric Industries, Inc. (HEI)
1001 Bishop Street, Suite 2500, Honolulu, Hawaii  96813 - Hawaiian Electric Company, Inc. (Hawaiian Electric)
(Address of principal executive offices and zip code)
 Registrant’s telephone number, including area code:
 (808) 543-5662 - HEI
(808) 543-7771 - Hawaiian Electric
Not applicable
(Former name or former address, if changed since last report.)

Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each classTrading Symbol 
Name of each exchange
on which registered
Hawaiian Electric Industries, Inc. Common Stock, Without Par Value New York Stock Exchange
Hawaiian Electric Company, Inc.
Guarantee with respect to 6.50% Cumulative Quarterly
Income Preferred Securities Series 2004 (QUIPSSM)
of HECO Capital Trust III
HE		 New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of each class
Hawaiian Electric Industries, Inc. None
Hawaiian Electric Company, Inc. Cumulative Preferred Stock
   
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Hawaiian Electric Industries, Inc.  Yes   X     No 
Yes
☒No☐Hawaiian Electric Company, Inc.Yes☐No  X  ☒
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Hawaiian Electric Industries, Inc.  Yes     No   X  
Yes
☐No☒Hawaiian Electric Company, Inc.Yes☐No  X ☒
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Hawaiian Electric Industries, Inc.  Yes   X     No 
Yes
☒No☐Hawaiian Electric Company, Inc.Yes  X ☒No☐
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Hawaiian Electric Industries, Inc.  Yes   X     No 
Yes
☒No☐Hawaiian Electric Company, Inc.Yes  X ☒No☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
Hawaiian Electric Industries, Inc.:Hawaiian Electric Company, Inc.:
Large accelerated filer☒Smaller reporting company☐Large accelerated filer☐Smaller reporting company☐
Accelerated filer☐Emerging growth company☐Accelerated filer☐Emerging growth company☐
Non-accelerated filer☐Non-accelerated filer☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Hawaiian Electric Industries, Inc.
Large accelerated filer  X 
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company  
Yes		☐No☐Hawaiian Electric Company, Inc.
Large accelerated filer
Accelerated filer
Non-accelerated filer  X 
(Do not check if a smaller reporting company)
Smaller reporting company  
Yes		☐No☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Hawaiian Electric Industries Inc.  Yes     No   X  
Hawaiian Electric Company, Inc.  Yes     No   X  
Aggregate market value
of the voting and non-
voting common equity
held by non-affiliates of
the registrants as of
Number of shares of common stock
outstanding of the registrants as of
June 30, 2016June 30, 2016February 13, 2017
Hawaiian Electric Industries, Inc. (HEI)Yes☐No☒ $3,547,453,796
108,187,063
(Without par value)
108,745,265
(Without par value)
Hawaiian Electric Company, Inc. (Hawaiian Electric)Yes☐No☒
 None 
15,805,327
 ($6 2/3 par value)
16,019,785
 ($6 2/3 par value)
       
  
Aggregate market value
of the voting and non-
voting common equity
held by non-affiliates of
the registrants as of
 
Number of shares of common stock
 outstanding of the registrants as of
  June 30, 2019 June 30, 2019 February 13, 2020
Hawaiian Electric Industries, Inc. (Without Par Value) $4,745,752,027 108,972,492 108,973,328
Hawaiian Electric Company, Inc.
($6-2/3 Par Value)
 None 16,751,488 17,048,783
       
 
DOCUMENTS INCORPORATED BY REFERENCE


Hawaiian Electric’s Exhibit 99.1, consisting of:
Hawaiian Electric’s Directors, Executive Officers and Corporate Governance—Part III
Hawaiian Electric’s Executive Compensation—Part III
Hawaiian Electric’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—
Part III
Hawaiian Electric’s Certain Relationships and Related Transactions, and Director Independence—Part III
Hawaiian Electric’s Principal Accounting Fees and Services—Part III


Selected sections of Proxy Statement of HEI for the 20172020 Annual Meeting of Shareholders to be filed-Part III
 
 
This combined Form 10-K represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. Hawaiian Electric makes no representations as to any information not relating to it or its subsidiaries.
 






TABLE OF CONTENTS
  Page
   
Glossary of Terms
ii
Cautionary Note Regarding Forward-Looking Statements
vi
  
 
PART I
 
   
Item 1.
Business
1
Item 1A.
Risk Factors
2517
Item 1B.
Unresolved Staff Comments
3528
Item 2.
Properties
3628
Item 3.
Legal Proceedings
3628
Item 4.
Mine Safety Disclosures
3628
Information About Our Executive Officers of the Registrant (HEI)
3729
 
PART II
 
   
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
3730
Item 6.
Selected Financial Data
3931
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
4133
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
7969
Item 8.
Financial Statements and Supplementary Data
8272
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
180166
Item 9A.
Controls and Procedures
180166
Item 9B.
Other Information
181167
   
 
PART III
 
   
Item 10.
Directors, Executive Officers and Corporate Governance
181167
Item 11.
Executive Compensation
182168
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
183169
Item 13.
Certain Relationships and Related Transactions, and Director Independence
184169
Item 14.
Principal Accounting Fees and Services
184170
   
 
PART IV
 
   
Item 15.
Exhibits and Financial Statement Schedules
184170
Item 16.Form 10-K Summary
170
Signatures
190182


 




i




GLOSSARY OF TERMS
Defined below are certain terms used in this report:
Terms Definitions
   
ABO Accumulated benefit obligation
ACLAllowance for credit losses as determined under the new credit loss standard (ASU No. 2016-13), which requires the measurement of lifetime expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts)
ADITAccumulated deferred income tax balances
AES Hawaii AES Hawaii, Inc.
AFSAvailable-for-sale
AFUDC Allowance for funds used during construction
ALLAllowance for loan losses, as determined under the existing credit loss standard, requires recording the allowance based on an incurred loss model
AOCI Accumulated other comprehensive income (loss)
AOS Adequacy of supply
APBO Accumulated postretirement benefit obligation
ARO Asset retirement obligations
ASB American Savings Bank, F.S.B., a wholly-owned subsidiary of ASB Hawaii Inc.
ASB Hawaii ASB Hawaii, Inc. (formerly American Savings Holdings, Inc.), a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
ASC Accounting Standards Codification
ASU Accounting Standards Update
Btu British thermal unit
CAA Clean Air Act
CERCLA Comprehensive Environmental Response, Compensation and Liability Act
Chevron Chevron Products Company, which assigned their fuel oil supply contracts with the Utilities to Island Energy Services, LLC.LLC
CIPCIAC Campbell Industrial ParkContributions in aid of construction
CIS Customer Information System
Company 
When used in Hawaiian Electric Industries, Inc. sections and in the Notes to Consolidated Financial Statements, “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under Hawaiian Electric); ASB Hawaii, Inc. and its subsidiary, American Savings Bank, F.S.B.; HEI Properties, Inc. (dissolved in 2015); Hawaiian Electric Industries Capital Trust IIPacific Current, LLC and Hawaiian Electric Industries Capital Trust III (inactive financing entities - dissolvedits subsidiaries, Hamakua Holdings, LLC (and its subsidiary, Hamakua Energy, LLC) and terminated in 2015);Mauo Holdings, LLC (and its subsidiary, Mauo, LLC) and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
When used in Hawaiian Electric Company, Inc. sections, “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries.
Consolidated Financial Statements HEI’s andor Hawaiian Electric's combinedElectric’s Consolidated Financial Statements, including notes, in Item 8 of this Form 10-K
Consumer Advocate Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
CT-1CBRE Combustion turbine No. 1Community-based renewable energy
D&O Decision and order from the PUC
DBEDTState of Hawaii Department of Business Economic Development and Tourism
DBF State of Hawaii Department of Budget and Finance
DG Distributed generation
DERDistributed energy resources
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOH State of Hawaii Department of Health of the State of Hawaii
DRIP HEI Dividend Reinvestment and Stock Purchase Plan
DSMDemand-side management
ECAC Energy cost adjustment clause
ECRCEnergy cost recovery clause
EEPS Energy Efficiency Portfolio Standards
EGU Electrical generating unit
EIP 2010 Executive Incentive Plan, as amended
EPA Environmental Protection Agency - federal

ii


GLOSSARY OF TERMS (continued)

TermsDefinitions
EPS Earnings per share
ERISA Employee Retirement Income Security Act of 1974, as amended
ERL Environmental Response Law of the State of Hawaii
ERP/EAMEnterprise Resource Planning/Enterprise Asset Management
ESGEnvironmental, social and governance
Exchange Act Securities Exchange Act of 1934
FASB Financial Accounting Standards Board
FDIC Federal Deposit Insurance Corporation
FDICIA Federal Deposit Insurance Corporation Improvement Act of 1991

ii


GLOSSARY OF TERMS (continued)

TermsDefinitions
federal U.S. Government
FERC Federal Energy Regulatory Commission
FHLB Federal Home Loan Bank
FHLMC Federal Home Loan Mortgage Corporation
FICO FinancingFair Isaac Corporation
Fitch Fitch Ratings, Inc.
FNMA Federal National Mortgage Association
FRB Federal Reserve Board
GAAP Accounting principles generally accepted in the United States of America
GHG Greenhouse gas
GNMA Government National Mortgage Association
Gramm Act Gramm-Leach-Bliley Act of 1999
HC&SHamakua Energy Hawaiian Commercial & Sugar Company, a division
Hamakua Energy, LLC, an indirect subsidiary of A&B-Hawaii, Inc.Pacific Current and successor in interest to Hamakua Energy Partners, L.P., an affiliate of Arclight Capital Partners (a Boston based private equity firm focused on energy infrastructure investments) and successor in interest to Encogen Hawaii, L.P.
Hawaii Electric Light Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
Hawaiian Electric Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated financing subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.
Hawaiian Electric’s MD&A Hawaiian Electric Company, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K
HEI Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., ASB Hawaii, Inc., HEI Properties, Inc. (dissolved in 2015), Hawaiian Electric Industries Capital Trust II (dissolved and terminated in 2015), Hawaiian Electric Industries Capital Trust III (dissolved and terminated in 2015)Pacific Current, LLC and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
HEI's 2017HEI’s 2020 Proxy Statement Selected sections of Proxy Statement for the 20172020 Annual Meeting of Shareholders of Hawaiian Electric Industries, Inc. to be filed after the date of this Form 10-K and not later than 120 days after December 31, 2019, which are incorporated in this Form 10-K by reference
HEI’s MD&A Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K
HEIPIHEI Properties, Inc. (dissolved in 2015), a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
HEIRSP Hawaiian Electric Industries Retirement Savings Plan
HEPHELOC Hamakua Energy Partners, L.P., successor in interest to Encogen Hawaii, L.P.
HTBHawaiian Tug & Barge Corp. On November 10, 1999, HTB sold substantially allHome equity line of its operating assets and the stock of its subsidiary, Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.credit
HPOWER City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
HSFOHigh sulfur fuel oil
HTMHeld-to-maturity
IPP Independent power producer
IRP Integrated resource plan
IRR Interest rate risk
Island EnergyIsland Energy Services, LLC (a fuel oil supplier and subsidiary of One Rock Capital Partners, L.P.), who purchased Chevron's Hawaii assets on November 1, 2016 and was assigned Chevron's fuel oil supply contracts with the Utilities.
Kalaeloa Kalaeloa Partners, L.P.
kV Kilovolt
kW Kilowatt/s (as applicable)
KWHkWh Kilowatthour/s (as applicable)
LNG Liquefied natural gas
LSFO Low sulfur fuel oil
LTIP Long-term incentive plan
MATSMercury and Air Toxics Standards
Maui Electric Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.

iii


GLOSSARY OF TERMS (continued)

TermsDefinitions
MauoMauo, LLC, an indirect subsidiary of Pacific Current
MBtu Million British thermal unit
MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger As provided in the Merger Agreement (see below), merger of NEE Acquisition Sub II, Inc. with and into HEI, with HEI surviving, and then merger of HEI with and into NEE Acquisition Sub I, LLC, with NEE Acquisition Sub I, LLC surviving as a wholly owned subsidiary of NextEra Energy, Inc.

iii


GLOSSARY OF TERMS (continued)

TermsDefinitions
Merger Agreement Agreement and Plan of Merger by and among HEI, NextEra Energy, Inc., NEE Acquisition Sub II, Inc. and NEE Acquisition Sub I, LLC, dated December 3, 2014 and terminated July 16, 2016
Moody’s Moody’s Investors Service’s
MOUMemorandum of Understanding
MPIRMajor Project Interim Recovery
MSFO Medium sulfur fuel oil
MOUMSR Memorandum of UnderstandingMortgage servicing right
MW Megawatt/s (as applicable)
MWh Megawatthour/s (as applicable)
NA Not applicable
NAAQSNational Ambient Air Quality Standard
NEE NextEra Energy, Inc.
NEM Net energy metering
NII Net interest income
NM Not meaningful
NPBC Net periodic benefits costs
NQSONPPC Nonqualified stock optionsNet periodic pension costs
O&M Other operation and maintenance
OCC Office of the Comptroller of the Currency
OPEB Postretirement benefits other than pensions
OTS Office of Thrift Supervision, Department of Treasury
OTTI Other-than-temporary impairment
Pacific CurrentPacific Current, LLC, a wholly owned subsidiary of HEI and indirect parent company of Hamakua Energy and Mauo
PBO Projected benefit obligation
PCB Polychlorinated biphenyls
PGV Puna Geothermal Venture
PIMsPerformance incentive mechanisms
PPA Power purchase agreement
PPAC Purchased power adjustment clause
PSDPrevention of Significant Deterioration
PSIPs Power Supply Improvement Plans
PUC Public Utilities Commission of the State of Hawaii
PURPA Public Utility Regulatory Policies Act of 1978
PVPhotovoltaic
QF Qualifying Facility under the Public Utility Regulatory Policies Act of 1978
QTL Qualified Thrift Lender
RAM Rate adjustment mechanism
RBA Revenue balancing account
Registrant Each of Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.
REIP Renewable Energy Infrastructure Program
RFP Request for proposals
RHI Renewable Hawaii, Inc., a wholly-owned nonregulated subsidiary of Hawaiian Electric Company, Inc.
ROA Return on assets
ROACE Return on average common equity
RORB Return on rate base
RPS Renewable portfolio standards
S&P Standard & Poor’s
SARSASB Stock appreciation rightSustainability Accounting Standards Board
SEC Securities and Exchange Commission

iv


GLOSSARY OF TERMS (continued)

TermsDefinitions
See Means the referenced material is incorporated by reference (or means refer to the referenced section in this document or the referenced exhibit or other document)
SLHCs Savings & Loan Holding Companies
SOIP 1987 Stock Option and Incentive Plan, as amended. Shares of HEI common stock reserved for issuance under the SOIP were deregistered and delisted in 2015.
Spin-Off The previously planned distribution to HEI shareholders of all of the common stock of ASB Hawaii immediately prior to the Merger, which was terminated
SPRBs Special Purpose Revenue Bonds
ST Steam turbine
state State of Hawaii

iv


GLOSSARY OF TERMS (continued)

TermsTax Act Definitions2017 Tax Cuts and Jobs Act (H.R. 1, An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018)
TCFD Task Force on Climate-related Financial Disclosure
TDR Troubled debt restructuring
Tesoro Tesoro Hawaii Corporation dba BHP Petroleum Americas Refining Inc., a fuel oil supplier
TOOTS The Old Oahu Tug Service, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
Trust III HECO Capital Trust III
UBC Uluwehiokama Biofuels Corp., a wholly-owned nonregulated subsidiary of Hawaiian Electric Company, Inc.
Utilities Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited
VIE Variable interest entity




v




Cautionary Note Regarding Forward-Looking Statements
This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (Hawaiian Electric) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions and usually include words such as “will,” “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic, political and market factors, among other things. These forward-looking statements are not guarantees of future performance.
Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:
international, national and local economic conditions, and political conditions—including the state of the Hawaii tourism, defense and construction industries,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,conditions; and the potential impacts of global and local developments (including global economic conditions and uncertainties,uncertainties; unrest, terrorist acts, wars, conflicts, political protests, deadly virus epidemic, potential pandemic or other crisis; the effects of the United Kingdom’s referendumchanges that have or may occur in U.S. policy, such as with respect to withdraw from the European Union, unrest, the conflict in Syria, terrorist acts by ISIS or others, potential conflict or crisis with North Koreaimmigration and potential pandemics)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, andtrade policy and regulationtariffs, and other policy and regulatory changes advanced or proposed by President Trump and his administration;
weather, and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes, lava flows and the potentialincreasing 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'sCompany’s and Utilities'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;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;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 impacts of the termination of the Merger with NextEra Energy, Inc. (NEE) and the resulting loss of NEE’s resources, expertise and support (e.g., financial and technological), including potentially higher costs and longer lead times to increase levels of renewable energy and to complete projects like Enterprise Resource Planning/Enterprise Asset Management (ERP/ERM) and smart grids, and a higher cost of capital;
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, proposed undersea cables, 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, proposedwhich have been and beingare continuing to be developed and updated in response to the four orders thatissued by the PUC, issued inthe PUC’s April 2014 in which the PUC: directed the Utilities to develop, among other things, Power Supply Improvement Plans, a Demand Response Portfolio Plan and a Distributed Generation Interconnection Plan; described the PUC’sstatement 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;goals, and emphasizedsubsequent orders of the need to “leap ahead” of other states in creating a 21st century generation system and modern transmission and distribution grids;PUC;
capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management, (DSM), 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 adjustmentrecovery clauses (ECACs)(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;
vi

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;

vi


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'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;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;
new technological developments,competitors such as the commercial development of energy storage and microgrids that could affect the operations of the Utilities;and banking through alternative channels;
cyber securitycybersecurity risks and the potential for cyber incidents, including potential incidents at HEI, ASBits third-party vendors, and the Utilitiesits subsidiaries (including at ASB branches and electric utility plants) and incidents at data processing centers they use,used, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technologyIT controls;
failure to achieve cost savings consistent with the minimum $246 million in Enterprise Resource Planning/Enterprise Asset Management
(ERP/EAM) project-related benefits (including $150 million in operation and maintenance (O&M) benefits) to be delivered to customers over its 12-year estimated useful life;
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 (GHG) 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 ability of the Utilities to recover increasing costs and earn a reasonable return on capital investments not covered by RAMs;
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 the Utilities and ASB,its subsidiaries, including the adoption of new U.S. accounting standards, the potential discontinuance of regulatory accounting, and the effects of potentially required consolidation of variable interest entities (VIEs), or required capitalcapital/finance lease or on-balance-sheet operating lease accounting for PPAs with IPPs;
changesdowngrades by securities rating agencies in their ratings of the securities of HEI and Hawaiian Electric and thetheir 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 the Utilities and ASB;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).
Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, Hawaiian Electric, ASB, Pacific Current and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether written or oral and whether as a result of new information, future events or otherwise.



vii




PART I
ITEM 1.BUSINESS
HEI Consolidated
HEI and subsidiaries and lines of business.  HEI is a holding company with its subsidiaries principally engaged in electric utility, banking, and renewable/sustainable infrastructure investment businesses operating in the State of Hawaii. HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in electric utility and banking businesses operating primarily in the State of Hawaii. HEI’s predecessor, Hawaiian Electric, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result of a 1983 corporate reorganization, Hawaiian Electric became an HEI subsidiary and common shareholders of Hawaiian Electric became common shareholders of HEI. As a holding company with no significant operations of its own, HEI’s sources of funds are dividends or other distributions from its operating subsidiaries, borrowings, and sales of equity. The rights of HEI and its creditors and shareholders to participate in any distribution of the assets of any of HEI’s subsidiaries are subject to the prior claims of the creditors and preferred shareholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized as primary. The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions (see Note 14 of the Consolidated Financial Statements). HEI is headquartered in Honolulu, Hawaii and has three reportable segments—Electric utility, Bank, and Other.
Electric Utility.Hawaiian Electric and its operating utility subsidiaries, Hawaii Electric Light Company, Inc. (Hawaii Electric Light) and Maui Electric Company, Limited (Maui Electric), are regulated electric public utilities. Hawaiianutilities that provide essential electric service to approximately 95% of Hawaii’s population through the operation of five separate grids that serve communities on the islands of Oahu, Hawaii, Maui, Lanai and Molokai. Over the past few years, the three utilities have been working on restructuring their functions and processes across the islands under an initiative to improve operational efficiencies, provide consistent positive customer experience, and reduce cost. This initiative was substantially completed in 2019 and, as of January 1, 2020, the three utilities now operate under one brand, “Hawaiian Electric,” on all five islands served by the utilities, but remain three separate entities. See also owns all“Electric utility” section below.
Bank. HEI acquired American Savings Bank, F.S.B. (ASB) in 1988. ASB is one of the common securitieslargest financial institutions in the State of HECO Capital Trust III (a Delaware statutory trust)Hawaii (based on total assets), whichwith assets totaling approximately $7.2 billion as of December 31, 2019. ASB provides a wide array of banking and other financial services to consumers and businesses. See also “Bank” section below.
Other. The “Other” segment is composed of HEI’s corporate-level operating, general and administrative expenses and the results of Pacific Current, LLC (Pacific Current). Pacific Current was formed in September 2017 to effectfocus on investing in non-regulated clean energy and sustainable infrastructure in the issuanceState of $50 million of cumulative quarterly income preferred securities in 2004, forHawaii to help reach the benefit of Hawaiian Electric,state’s sustainability goals. See also “Electric utility— Hawaii Electric Light firm capacity PPAs” section below and Maui Electric. In December 2002, Hawaiian Electric formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects, but it has made no investments and currently is inactive. In September 2007, Hawaiian Electric formed another subsidiary, Uluwehiokama Biofuels Corp. (UBC), to invest in a biodiesel refining plant to be builtNote 2 of the Consolidated Financial Statements for additional information on the island of Maui, which project has been terminated.
Besides Hawaiian Electric and its subsidiaries, HEIPacific Current activities. The “Other” segment also currently owns directly or indirectly the following subsidiaries:includes ASB Hawaii, Inc. (ASB Hawaii) (a holding company, formerly known as American Savings Holdings, Inc.) and its subsidiary, American Savings Bank, F.S.B. (ASB); HEI Properties, Inc. (HEIPI), which was dissolved on December 11, 2015; Hawaiian Electric Industries Capital Trusts II and III (both formed in 1997 to be available for trust securities financings, but both were dissolved and terminated on December 14, 2015);owns ASB, and The Old Oahu Tug Service, Inc. (TOOTS)., which is inactive.
ASB, acquired byAdditional information.For additional information about HEI, in 1988, is one of the largest financial institutions in the State of Hawaii with assets of $6.4 billion as of December 31, 2016.
HEIPI, whose predecessor company was formed in February 1998, held venture capital investments. HEIPI was dissolved on December 11, 2015.
TOOTS administers certain employeesee HEI’s MD&A, HEI’s “Quantitative and retiree-related benefit programsQualitative Disclosures about Market Risk” and monitors matters related to its predecessor’s former maritime freight transportation operations.
Termination of proposed Merger.For information concerning the termination of HEI's Merger Agreement with NextEra Energy, Inc., see Note 2 of theHEI’s Consolidated Financial Statements.
Additional information.The Company’s website address is www.hei.com, where annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (last 10 years) are made available free of charge in the Investor Relations section as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC (and available at the SEC’s website at www.sec.gov). The information on the Company’s website is not incorporated by reference in this annual report on Form 10-K unless, and except to the extent, specifically incorporated herein by reference. HEI and Hawaiian Electric currently make available free of charge through this website their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. HEI and Hawaiian Electric intend to continue to use HEI’s website as a means of disclosing additional information. Such disclosures will be included on HEI’s website in the Investor Relations section. Accordingly, investors should routinely monitor such portions of HEI’s website, in addition to following HEI’s, Hawaiian Electric’s and ASB’s press releases, SEC filings and public conference calls and webcasts. Investors may also wish to refer to the PUC website at dms.puc.hawaii.gov/dms in order to review documents filed with and issued by the PUC. No information at the PUC website is incorporated herein by reference.reference, and the Company has no control over its accuracy or completeness.
Commitments and contingencies.  See “HEI Consolidated—Liquidity and capital resources –Selected contractual obligations and commitments” in HEI’s MD&A, Hawaiian Electric’s “Commitments and contingencies” below and Note 5 of the Consolidated Financial Statements.
Regulation. HEI and Hawaiian Electric are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementing regulations, which requires holding companies and their subsidiaries to grant the Federal Energy Regulatory Commission (FERC) access to books and records relating to FERC’s jurisdictional rates. FERC granted HEI and Hawaiian Electric a waiver from its record retention, accounting and reporting requirements, effective May 2006.


HEI is subject to an agreement entered into with the PUC (the PUC Agreement) which, among other things, requires PUC approval of any change in control of HEI. The PUC Agreement also requires HEI to provide the PUC with periodic financial


information and other reports concerning intercompany transactions and other matters. It also prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions”also Note 14 of the Consolidated Financial Statements and “Electric utility—Regulation” below.
HEI and ASB Hawaii are subject to Federal Reserve Board (FRB) registration,regulation, supervision and reporting requirements as savings and loan holding companies. As a result of the enactment of the Dodd-Frank Act, supervision and regulation of HEI and ASB Hawaii, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the Office of the Comptroller of the Currency (OCC) in July 2011. In the event the OCC has reasonable cause to believe that any activity of HEI or ASB Hawaii constitutes a serious risk to the financial safety, soundness or stability of ASB, the OCC is authorized to impose certain restrictions on HEI, ASB Hawaii and/or any of their subsidiaries. Possible restrictions include precluding or limiting: (i) the payment of dividends by ASB; (ii) transactions between ASB, HEI or ASB Hawaii, and their subsidiaries or affiliates; and (iii) any activities of ASB that might expose ASB to the liabilities of HEI and/or ASB Hawaii and their other affiliates. See “Restrictions on dividendsalso Note 14 of the Consolidated Financial Statements.
The Gramm-Leach-Bliley Act of 1999 (Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, distributions” below.
Bank regulations generally prohibitthereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and their nonthrift subsidiaries from engaging in activities other than those which are specifically enumerated in the regulations. However,one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, ASB Hawaii and ASB is “grandfathered” under the Gramm-Leach-BlileyGramm Act of 1999 (Gramm Act) so that HEI and its subsidiaries arewill be able to continue to engage in their current activities so long as ASB satisfies themaintains its qualified thrift lender (QTL) status test discussed under “Bank—Regulation—Qualified thrift lender test.” ASB met the QTL test at all times during 2016;2019; however, the failure of ASB to satisfy the QTL test in the future could result in a need for HEI to divest ASB. Under the Gramm Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the authorized financial holding companies permitted under the Gramm Act.
HEI is also affected by provisions of the Dodd-Frank Act relating to corporate governance and executive compensation, including provisions requiring shareholder “say on pay” and “say on pay frequency” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors and further restricting proxy voting by brokers in the absence of instructions. See “Bank—Legislation and regulation” in HEI’s MD&A for a discussion of effects of the Dodd-Frank Act on HEI and ASB.
Restrictions on dividends and other distributions.HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s principal sources of funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently, its creditors and shareholders, to participate in any distribution of the assets of any of its subsidiaries are subject to the prior claims of the creditors and preferred shareholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized as primary.
The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capitalization of the electric utilities (including the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restricted in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed as relinquishing any right the PUC may have to review the dividend policies of the electric utility subsidiaries. As of December 31, 2016, the consolidated common stock equity of HEI’s electric utility subsidiaries was 57% of their total capitalization (as calculated for purposes of the PUC Agreement). As of December 31, 2016, Hawaiian Electric and its subsidiaries had common stock equity of $1.8 billion of which approximately $729 million was not available for transfer to HEI without regulatory approval.
The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank—Regulation—Prompt corrective action.” All dividends are subject to review by the OCC and FRB and receipt of a letter from the FRB communicating the agencies’ non-objection to the payment of any dividend ASB proposes to declare and pay to ASB Hawaii and HEI.
. Also see Note 14 to the Consolidated Financial Statements.
HEI and its subsidiaries are also subject to debt covenants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual


restrictions applicable to HEI and/or its subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock.
Environmental regulation.  HEI and its subsidiaries are subject to federal and state statutes and governmental regulations pertaining to water quality, air quality and other environmental factors. See the “Environmental regulation” discussions in the “Electric utility” and “Bank” sections below.
Securities ratings. See the Fitch Ratings, Inc. (Fitch), Moody’s Investors Service’s (Moody’s)below, and Standard & Poor’s (S&P) ratings of HEI’s and Hawaiian Electric’s securities and discussion under “Liquidity and capital resources” (both “HEI Consolidated” and “Electric utility”) in HEI’s MD&A. These ratings reflect only the view, at the time the ratings are issued,Note 1 of the applicable rating agency from whom an explanation of the significance of such ratings may be obtained. There is no assurance that any such credit rating will remain in effect for any given period of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances so warrant. Any such lowering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketability of HEI’s and/or Hawaiian Electric’s securities, which could increase the cost of capital of HEI and Hawaiian Electric, and could affect costs, including interest charges, under HEI's and/or Hawaiian Electric's debt securities and credit facilities. Neither HEI nor Hawaiian Electric management can predict future rating agency actions or their effects on the future cost of capital of HEI or Hawaiian Electric.Consolidated Financial Statements.
Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii for the benefit of Hawaiian Electric and its subsidiaries, but the source of their repayment are the unsecured obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the Department, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on revenue bonds currently outstanding and issued prior to 2009 are insured, but the ratings of these insurers have been withdrawn—see “Electric Utility—Liquidity and capital resources” in HEI’s MD&A.
Employees. The Company had full-time employees as follows:
December 312016
 2015
 2014
 2013
 2012
2019
 2018
 2017
 2016
 2015
HEI41
 39
 44
 43
 42
45
 46
 41
 41
 39
Hawaiian Electric and its subsidiaries2,662
 2,727
 2,759
 2,764
 2,658
2,670
 2,704
 2,724
 2,662
 2,727
ASB and its subsidiaries1,093
 1,152
 1,162
 1,159
 1,170
ASB1,126
 1,148
 1,115
 1,093
 1,152
3,796
 3,918
 3,965
 3,966
 3,870
3,841
 3,898
 3,880
 3,796
 3,918
The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. The International Brotherhood of Electrical Workers Local 1260 represents roughly half of the Utilities'Utilities’ workforce covered by a collective bargaining agreement that expires on October 31, 2018.2021.
Properties. HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in December 2017.2022. See the discussions under “Electric Utility” and “Bank” belowsections for a description of properties they own and lease.
Hamakua Energy, LLC, an indirect wholly owned by HEI subsidiaries.subsidiary of Pacific Current, LLC, owns a total of approximately 93 acres located on the Hamakua coast on the island of Hawaii. Its power plant is situated on approximately 59 acres and the remaining 34 acres includes surrounding parcels of which 30 acres are located on the ocean front.

2


Electric utility
Hawaiian Electric and subsidiaries and service areas. Hawaiian Electric, Hawaii Electric Light and Maui Electric (Utilities) are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively. HawaiianOver the past few years, the three utilities have been working on restructuring their functions and processes across the islands under an initiative to improve operational efficiencies, provide consistent positive customer experience, and reduce cost. This initiative was substantially completed in 2019 and, as of January 1, 2020, the three utilities now operate under one brand, “Hawaiian Electric, acquired Maui Electric in 1968 and Hawaii Electric Light in 1970. ” on all five islands served by the utilities, but remain three separate entities.
In 2016,2019, the electric utilities’ revenues and net income amounted to approximately 88%89% and 58% (impacted by merger termination fee and other impacts at corporate),72% respectively, of HEI’s consolidated revenues and net income, compared to approximately 90%89% and 85%71% in 20152018 and approximately 92%88% and 82%73% in 2014,2017, respectively.
The islands of Oahu, Hawaii, Maui, Lanai and Molokai have a combined population estimated at 1.4 million, or approximately 95% of the total population of the State of Hawaii, and comprise a service area of 5,815 square miles. The principal communities served include Honolulu (on Oahu), Hilo and Kona (on Hawaii) and Wailuku and Kahului (on Maui). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural operations. The state has granted Hawaiian Electric, Hawaii Electric Light and Maui Electric nonexclusive franchises, which authorize the Utilities to construct, operate and maintain facilities over and under public streets and sidewalks. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.


Sales of electricity.
Years ended December 312016 2015 20142019 2018 2017
(dollars in thousands)Customer accounts* Electric sales revenues Customer accounts* Electric sales revenues Customer accounts* Electric sales revenuesCustomer accounts* Electric sales revenues Customer accounts* Electric sales revenues Customer accounts* Electric sales revenues
Hawaiian Electric304,261
 $1,466,225
 302,958
 $1,636,245
 301,953
 $2,134,094
306,368
 $1,784,982
 305,456
 $1,789,527
 304,948
 $1,592,016
Hawaii Electric Light85,029
 309,521
 84,309
 343,843
 83,421
 420,647
86,576
 360,019
 85,758
 371,713
 85,925
 331,697
Maui Electric70,872
 306,767
 70,533
 343,722
 70,042
 420,734
72,522
 372,034
 71,875
 364,967
 71,352
 323,882
460,162
 $2,082,513
 457,800
 $2,323,810
 455,416
 $2,975,475
465,466
 $2,517,035
 463,089
 $2,526,207
 462,225
 $2,247,595
* As of December 31.
SeasonalityRegulatory mechanisms. Kilowatthour (KWH)Base electric rates are set in rate cases, and each of the three utilities is currently on a triennial rate case cycle. The regulatory framework includes a number of mechanisms designed to provide utility financial stability during the transition toward the state’s 100% renewable energy goals. For example, under the sales decoupling mechanism, the utilities are allowed to recover from customers, target test year revenues, independent of the level of kilowatthour (kWh) sales, which have declined, with the exception of 2019, as privately-owned distributed energy resources have been added to the grid and energy efficiency measures have been put into place. A summary of these regulatory mechanisms is as follows:
MechanismDescription
Sales decouplingProvides predictable revenue stream by fixing net revenues at the level approved in last rate case (revenues not linked to kWh sales)
Revenue adjustment mechanism (RAM)Annually adjusts revenue to recover general inflation of operations and maintenance expenses and baseline plant additions between rate cases
Major Projects Interim Recovery adjustment mechanism (MPIR)Reduces regulatory lag and permits recovery in between rate cases through the revenue balancing account (RBA) of costs (net of benefits) for major capital projects including, but not restricted to, projects to advance renewable energy
Energy cost recovery clause (ECRC) and purchased power adjustment clause (PPAC)Allows for timely recovery of fuel and purchased power costs to reduce earnings volatility. Symmetrical fossil fuel cost risk-sharing (98% customer/2% utility) mechanism established for Hawaiian Electric and Maui Electric capped at $2.5 million and $0.6 million, respectively. Hawaii Electric Light’s ECRC does not have cost risk-sharing mechanism
Pension and post-employment benefit trackersAllow tracking of pension and post-employment benefit costs and contributions above or below the cost included in rates in a separate regulatory asset/liability account
Renewable energy infrastructure programPermits recovery of renewable energy infrastructure projects through a surcharge

Seasonality. kWh sales of the Utilities follow a seasonal pattern, but they do not experience extreme seasonal variations due to extreme weather variations experienced by some electric utilities on the U.S. mainland. KWHIn Hawaii, kWh sales in Hawaii tend to increase in the warmer, more humid months as a result of increased demand for air conditioning.conditioning, and with cloudy and rainy weather due to lower production by


privately owned customer PV systems. In 2019, kWh sales increased over prior year due to warmer and more humid than average weather and this is the first time kWh sales have increased over prior year since 2007.
Significant customers. The Utilities derived approximately 11%, 11% and 12% of their operating revenues in 2016, 20152019, 2018 and 2014 respectively,2017 from the sale of electricity to various federal government agencies.
Under the Energy Policy Act of 2005, the Energy Independence and Security Act of 2007 and/or executive orders: (1) federal agencies must establish energy conservation goals for federally funded programs, (2) goals were set to reduce federal agencies’ energy consumption by 3% per year up to 30% by fiscal year 2015 relative to fiscal year 2003, and (3) renewable energy goals were established for electricity consumed by federal agencies. Hawaiian Electric continues to work with various federal agencies to implement measures that will help them achieve their energy reductionefficiency, resilience and renewable energy objectives.
State of Hawaii and U.S. Department of Energy MOU. On September 15, 2014, the State of Hawaii and the U.S. Department of Energy executed a Memorandum of Understanding (MOU) recognizing that Hawaii is embarking on the next phase of its clean energy future. The MOU provides the framework for a comprehensive, sustained effort to better realize its vast renewable energy potential and allow Hawaii to push forward in three main areas: the power sector, transportation and energy efficiency. This next phase will focus on stimulating deployment of clean energy infrastructure as a catalyst for economic growth, energy system innovation and test bed investments.objectives.
The PUC issued a decision and order (D&O) on January 3, 2012 approving a framework for Energy Efficiency Portfolio Standards (EEPS) that set 2008 as the initial base year for evaluation and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GWH by 2015 and 975 GWH by each of the years 2020, 2025 and 2030. These goals may be revised through goal evaluations scheduled every five years or as the result of recommendations by an EEPS technical working group (TWG) for consideration by the PUC. The interim and final reduction goals will be allocated among contributing entities by the EEPS TWG. The PUC may establish penalties in the future for failure to meet the goals. Another of the initiatives under the Energy Agreement was advanced when the PUC approved the implementation of revenue decoupling for the Utilities under which they are allowed to recover PUC-approved revenue requirements that are not based on the amount of electricity sold. Both the EEPS and the implementation of revenue decoupling could have an impact on sales.
The statewide Energy Efficiency Potential Study issued in December 2013 indicated that Hawaii was on track to meet the 2015 interim EEPS target, and that available untapped energy efficiency resources in Hawaii exceed the EEPS goal of 4,300 GWH. However, no changes have been made to the goals or Framework that govern the achievement of EEPS. The Division of Consumer Advocacy’s 2016 Compliance Resolution Fund Report states that it appears Hawaii is progressing towards meeting its 2020 goals. Neither HEI nor Hawaiian Electric management can predict with certainty the impact of these or other governmental mandates or the September 2014 MOU on HEI’s or Hawaiian Electric’s future results of operations, financial condition or liquidity.


Selected consolidated electric utility operating statistics.
Years ended December 312016
 2015
 2014
 2013
 2012
2019
 2018
 2017
 2016
 2015
KWH sales (millions) 
  
  
  
  
kWh sales (millions) 
  
  
  
  
Residential2,332.7
 2,396.5
 2,379.7
 2,450.9
 2,582.0
2,439.3
 2,410.8
 2,334.5
 2,332.7
 2,396.5
Commercial2,911.5
 2,977.8
 3,022.0
 3,105.9
 3,074.4
2,793.0
 2,810.8
 2,867.9
 2,911.5
 2,977.8
Large light and power3,555.1
 3,532.9
 3,524.5
 3,462.7
 3,499.8
3,467.2
 3,425.1
 3,443.3
 3,555.1
 3,532.9
Other46.0
 49.3
 50.0
 50.0
 49.8
40.5
 42.1
 44.7
 46.0
 49.3
8,845.3
 8,956.5
 8,976.2
 9,069.5
 9,206.0
8,740.0
 8,688.8
 8,690.4
 8,845.3
 8,956.5
KWH net generated and purchased (millions)         
kWh net generated and purchased (millions)         
Net generated4,940.4
 5,124.5
 5,131.3
 5,352.0
 5,601.7
4,972.7
 4,966.4
 4,888.4
 4,940.4
 5,124.5
Purchased4,349.1
 4,308.3
 4,306.7
 4,195.2
 4,093.2
4,168.6
 4,139.3
 4,247.1
 4,349.1
 4,308.3
9,289.5
 9,432.8
 9,438.0
 9,547.2
 9,694.9
9,141.3
 9,105.7
 9,135.5
 9,289.5
 9,432.8
RPS (%)28.4
 26.7
 26.8
 25.8
 23.2
Losses and system uses (%)4.6
 4.8
 4.7
 4.8
 4.8
4.2
 4.4
 4.7
 4.6
 4.8
Energy supply (December 31)         
         
Net generating capability—MW1,669
 1,669
 1,787
 1,787
 1,787
1,737
 1,739
 1,673
 1,669
 1,669
Firm and other purchased capability—MW551
 555
 575
 567
 545
Firm and other purchased capability—MW1
517
 517
 551
 551
 555
2,220
 2,224
 2,362
 2,354
 2,332
2,254
 2,256
 2,224
 2,220
 2,224
Net peak demand—MW1
1,593
 1,610
 1,554
 1,535
 1,535
Btu per net KWH generated10,710
 10,632
 10,613
 10,570
 10,533
Average fuel oil cost per Mbtu (cents)862.3
 1,206.5
 2,087.6
 2,103.2
 2,210.4
Net peak demand—MW2
1,601
 1,598
 1,584
 1,593
 1,610
Btu per net kWh generated10,860
 10,826
 10,812
 10,710
 10,632
Average fuel oil cost per MBtu (cents)1,337.6
 1,420.2
 1,114.3
 862.3
 1,206.5
Customer accounts (December 31)         
         
Residential402,818
 400,655
 398,256
 394,910
 392,025
409,689
 407,505
 406,241
 402,818
 400,655
Commercial55,089
 54,878
 54,924
 54,616
 54,005
54,233
 54,075
 53,732
 55,089
 54,878
Large light and power670
 659
 596
 556
 577
700
 696
 656
 670
 659
Other1,585
 1,608
 1,640
 1,660
 1,636
844
 813
 1,596
 1,585
 1,608
460,162
 457,800
 455,416
 451,742
 448,243
465,466
 463,089
 462,225
 460,162
 457,800
Electric revenues (thousands) 
  
  
  
  
 
  
  
  
  
Residential$638,776
 $709,886
 $879,605
 $892,438
 $952,159
$791,398
 $788,028
 $691,857
 $638,776
 $709,886
Commercial711,553
 798,202
 1,027,588
 1,044,166
 1,060,983
829,000
 843,326
 766,921
 711,553
 798,202
Large light and power720,878
 802,366
 1,051,119
 1,015,079
 1,062,226
884,722
 882,443
 776,808
 720,878
 802,366
Other11,306
 13,356
 17,163
 17,008
 17,392
11,915
 12,410
 12,009
 11,306
 13,356
$2,082,513
 $2,323,810
 $2,975,475
 $2,968,691
 $3,092,760
$2,517,035
 $2,526,207
 $2,247,595
 $2,082,513
 $2,323,810
Average revenue per KWH sold (cents)23.54
 25.90
 33.15
 32.73
 33.60
Average revenue per kWh sold (cents)28.80
 29.07
 25.86
 23.54
 25.90
Residential27.38
 29.62
 36.96
 36.41
 36.88
32.44
 32.69
 29.64
 27.38
 29.62
Commercial24.44
 26.81
 34.00
 33.62
 34.51
29.68
 30.00
 26.74
 24.44
 26.81
Large light and power20.28
 22.71
 29.82
 29.31
 30.35
25.52
 25.76
 22.56
 20.28
 22.71
Other24.61
 27.05
 34.36
 34.02
 34.93
29.39
 29.47
 26.82
 24.61
 27.05
Residential statistics         
         
Average annual use per customer account (KWH)5,806
 5,996
 6,000
 6,220
 6,596
Average annual use per customer account (kWh)5,967
 5,923
 5,779
 5,806
 5,996
Average annual revenue per customer account$1,590
 $1,776
 $2,218
 $2,265
 $2,432
$1,936
 $1,936
 $1,713
 $1,590
 $1,776
Average number of customer accounts401,796
 399,674
 396,640
 394,024
 391,437
408,768
 407,044
 403,983
 401,796
 399,674
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.



Generation statistics. The following table contains certain generation statistics as of and for the year ended December 31, 2016.2019. The net generating and firm purchased capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.
Hawaiian Electric Hawaii Electric Light Maui Electric   Hawaiian Electric Hawaii Electric Light Maui Electric  
 Island of
Oahu		 Island of
Hawaii		 Island of
Maui		 Island of
Lanai		 Island of
Molokai		 Total  Island of
Oahu		 Island of
Hawaii		 Island of
Maui		 Island of
Lanai		 Island of
Molokai		 Total
Net generating and firm purchased capability (MW) as of December 31, 20161
            
Net generating and firm purchased capability (MW) as of December 31, 20191
           
Conventional oil-fired steam units999.5
 49.4
 35.9
 —
 —
 1,084.8
 999.5
 50.1
 35.9
 —
 —
 1,085.5
Diesel—
 27.0
 96.8
 9.3
 9.6
 142.7
 —
 29.5
 96.8
 9.4
 9.8
 145.5
Combustion turbines (peaking units)101.8
 —
 —
 —
 —
 101.8
 230.8
 —
 —
 —
 —
 230.8
Other combustion turbines—
 46.3
 —
 —
 2.2
 48.5
 —
 46.3
 —
 —
 2.2
 48.5
Combined-cycle unit—
 56.3
 113.6
 —
 —
 169.9
 —
 56.3
 113.6
 —
 —
 169.9
Biodiesel121.0
 —
 —
 —
 —
 121.0
 57.4
 —
 —
 —
 —
 57.4
Firm contract power2
456.5
 94.6
 —
 —
 —
 551.1
 456.5
 60.0
 —
 —
 —
 516.5
1,678.8
 273.6
 246.3
 9.3
 11.8
 2,219.8
 1,744.2
 242.2
 246.3
 9.4
 12.0
 2,254.1
                       
Net peak demand (MW)3
1,192.0
 188.5
 201.0
 5.7
 5.7
 1,592.9
 1,193.0
 192.1
 204.3
 6.1
 6.0
 1,601.5
Reserve margin40.2% 45.1% 23.2% 63.2% 107.0% 40.8% 44.8% 26.1% 23.2% 54.1% 100.0% 40.7%
Annual load factor66.7% 69.4% 63.5% 62.9% 62.3% 66.6% 65.4% 66.7% 62.5% 64.4% 61.7% 65.2%
KWH net generated and purchased (millions)6,963.1
 1,145.7
 1,118.2
 31.4
 31.1
 9,289.5
 
kWh net generated and purchased (millions)6,833.8
 1,122.1
 1,118.6
 34.4
 32.4
 9,141.3
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: 34.6 MW (Puna Geothermal venture, geothermal) and 60 MW (Hamakua Energy, Partners, L.P.,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.


Generating reliability and reserve margin.  Hawaiian Electric serves the island of Oahu and Hawaii Electric Light serves the island of Hawaii. Maui Electric has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai. Hawaiian Electric, Hawaii Electric Light and Maui Electric have isolated electrical systems that are not currently interconnected to each other or to any other electrical grid and, thus, each maintains a higher level of reserve generation and cost structure than is typically carried by interconnected mainland U.S. utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak electric demands, to provide for scheduled maintenance of generating units (including the units operated by IPPs relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system.
See “Adequacy of supply” in HEI’s MD&A under “Electric utility.”
Nonutility generation.  The Utilities have supported state and federal energy policies which encourage the development of renewable energy sources that reduce the use of fuel oil as well as the development of qualifying facilities. The Utilities'Utilities’ renewable energy sources and potential sources range from wind, solar, photovoltaic, geothermal, wave and hydroelectric power to energy produced by the burning of bagasse (sugarcane waste), municipal waste and other biofuels.
The rate schedules of the electric utilities contain ECRCs (changed from ECACs in 2019) and PPACs that allow them to recover costs of fuel and purchase power expenses. The PUC approved the PPACs for the first time for Hawaiian Electric, Hawaii Electric Light and Maui Electric in March 2011, February 2012 and May 2012, respectively.
In addition to the firm capacity PPAs described below, the electric utilities also purchase energy on an as-available basis directly from nonutility generators and through its Feed-In Tariff programs. The electric utilities also receive renewable energy from customers under its Net Energy Metering and Customer Grid Supply programs.
The PUC has allowed rate recovery for the firm capacity and purchased energy costs for the electric utilities’ approved firm capacity and as-available energy PPAs.


Hawaiian Electric firm capacity PPAs. Hawaiian Electric currently has three major PPAs that provide a total of 456.5 MW of firm capacity, representing 28%26% of Hawaiian Electric’s total net generating and firm purchased capacity on the Island of Oahu as of December 31, 2016.2019.


In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended, (through Amendment No. 2), provides that, for a period of 30 years beginning September 1992, Hawaiian Electric will purchase 180 megawatts (MW) of firm capacity. The AES Hawaii coal-fired cogeneration plant utilizes a “clean coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). See “Commitments and contingencies–Power purchase agreements–AES Hawaii, Inc.” in Note 4 to3 of the Consolidated Financial Statements for an update regarding this PPA.
In OctoberUnder a 1988 PPA, as amended, Hawaiian Electric entered into an agreement withis committed to purchase 208 MW of firm capacity from Kalaeloa Partners, L.P. (Kalaeloa), a limited partnership, which, through affiliates, contracted to design, build, operate and maintain a QF. The agreement with Kalaeloa, as amended, provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991 and terminating in May 2016.. The Kalaeloa facility, which is a QF, is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that utilizes waste heat from the combustion turbines. Following two additional amendments, effective in 2005, Kalaeloa currently supplies Hawaiian Electric with 208 MW of firm capacity. In January 2011, Hawaiian Electric initiated renegotiation ofand Kalaeloa are currently in negotiations to address the agreement with Kalaeloa (exempt from the PUC’s Competitive Bidding Framework).PPA term that ended on May 23, 2016. The PPA as amended, automatically extends on a month-to-month basis as long as the parties are still negotiating in good faith. On August 1, 2016,faith, but would end 60 days after either party notifies the parties entered into an agreementother in writing that negotiations have terminated. Hawaiian Electric and Kalaeloa have agreed that neither party will give written notice of termination ofterminate the PPA prior to OctoberJuly 31, 2017.2020. This agreement complementscontemplates continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution.
Hawaiian Electric also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (HPOWER). Under the amended PPA, the HPOWER facility supplied Hawaiian Electric with 46 MW of firm capacity. In May 2012, Hawaiian Electric entered into anas amended and restated, PPA with the City and County of HonoluluHawaiian Electric is committed to purchase additional firm capacity (including the then existing 46 MW) from the expanded HPOWER facility for a term of 20 years from the commercial operation date (April 2, 2013). Under the amended and restated PPA, which the PUC approved, Hawaiian Electric purchases 68.5 MW of firm capacity.capacity annually through April 2033.
Hawaii Electric Light and Maui Electric firm capacity PPAs. As of December 31, 2016, Hawaii Electric Light has two major PPAs forthat provide a total of 94.6 MW.MW of firm capacity, representing 34% of Hawaii Electric Light’s total net generating and firm purchased capacity on the Island of Hawaii as of December 31, 2019.
Hawaii Electric Light has a 35-year PPA, as amended, with Puna Geothermal Venture (PGV) for 3034.6 MW of firm capacity from its geothermal steam facility, which will expire on December 31, 2027. In February 2011,Since May 2018, PGV facility has been offline due to lava flow on Hawaii Island. PGV is committed to restoring their facility to commercial operation. On December 31, 2019, Hawaii Electric Light and PGV amended the PPA for the pricing on a portion of the energy payments and entered into a newan Amended and Restated PPA for Hawaiiwith PGV to, among other things, extend the term by 25 years to 2052 and expand the firm capacity capable of being delivered to 46 MW, subject to PUC approval. See “New renewable PPAs” in the “Developments in renewable energy efforts” section in Electric Light to acquire an additional 8 MW of firm, dispatchable capacity. The PUC approved the amendment and the new PPA in December 2011. PGV’s expansion became commercially operational in March 2012 for a total facility capacity of 34.6 MW.Utility’s MD&A.
In October 1997, Hawaii Electric Light entered into an agreement with Encogen, which has beenwas succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement requires Hawaii Electric Light to purchase up to 60 MW (net) of firm capacity for a period of 30 years, expiring on December 31, 2030. The dual-train combined-cycle (DTCC) facility which primarily burns naphtha (a mixture of liquid hydrocarbons), consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines.turbines, which primarily burns naphtha (a mixture of liquid hydrocarbons) and small amounts of biodiesel beginning in November 2019. In December 2015,November 2017, Hamakua Energy, LLC, an indirect subsidiary of HEI, purchased the plant from HEP.
In May 2012, Hawaii Electric Light signed an agreement to purchase the 60 MW HEP generating plant, subject to PUC approval. In February 2016, Hawaii Electric Light and Hawaiian Electric filed an application with the PUC requesting approval  of Hawaii Electric Light’s purchase of the HEP Facility, the parties’ proposed financing plan, the recovery of revenue requirements for the plant additions associated with the purchase through Hawaii Electric Light’s Decoupling Rate Adjustment Mechanism above the RAM Cap, the inclusion of the costs under certain fuel contracts through Hawaii Electric Light’s ECAC and termination of the existing PPA. A decision on the application requesting PUC approval is pending.
Maui Electric had a PPA with HC&SHu Honua Bioenergy, LLC (Hu Honua) for 1621.5 MW of firm capacity. Subsequently, HC&S decreasedrenewable, dispatchable firm capacity fueled by locally grown biomass on the island of Hawaii. This PPA was approved by the PUC in December 2013, however, the approval was appealed. The Supreme Court issued a decision remanding the matter to 8 MW effective January 1, 2015. In October 2015, followingthe PUC approval,for further proceedings. See “Commitments and contingencies–Power purchase agreements–Hu Honua Bioenergy, LLC” in Note 3 of the Consolidated Financial Statements for an amended PPA between update regarding this PPA.
Maui Electric and HC&S became effective, which changed the pricing structure and rates for energy sold to firm capacity PPAs.  Maui Electric eliminated thehas no firm capacity payment to HC&S and Maui Electric’s minimum purchase obligation, provided that Maui Electric may request up to 4 MW of scheduled energy during certain months and be provided up to 16 MW of emergency power and extended the term of the PPA from 2014 to 2017. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of diesel oil or coal. In January 2016, HC&S announced it will discontinue the growing and harvesting of sugar cane, and provided Maui Electric with a notice of termination of the amended PPA. Effective December 23, 2016, Maui Electric and HC&S mutually terminated the PPA to coincide with the end of HC&S' harvesting operations.PPAs.


Fuel oil usage and supply.  The rate schedules of the Utilities include ECRCs (changed from ECACs in 2019) under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. See discussion of rates and issues relating to the ECACECRC below under “Rates,” and “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates” and “Electric utility—Material estimates and critical accounting policies–Revenues” in HEI’s MD&A.
Hawaiian Electric’s steam generating units consume low sulfur fuel oil (LSFO) and Hawaiian Electric’s combustion turbine peaking units consume diesel, except forincluding Hawaiian Electric'sElectric’s Campbell Industrial Park generating facility which operates exclusively onrecently converted from B99 grade biodiesel.biodiesel to diesel. Hawaiian Electric’s Schofield Generating Station consumes mostly B99 grade biodiesel, but is permitted to also burn ultra low sulfur diesel (ULSD).
Hawaii Electric Light’s and Maui Electric’s steam generating units burn industrialhigh sulfur fuel oil (IFO)(HSFO) and Hawaii Electric Light’s and Maui Electric’s Maui combustion turbine generating units burn diesel. Hawaii Electric Light’s and Maui Electric’s Maui, Molokai, and Lanai diesel engine generating units burn ultra-low-sulfur diesel. All of the fuel purchased for the Utilities(except for fuel purchased for Lanai) is purchased under the new fuel supply contracts with Island Energy Services, LLC (previously with Chevron Products Company), which began on January 1, 2017 and will terminate at the end of 2019.ULSD.
See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 4 of the Consolidated Financial Statements.Electric utility’s MD&A.


The following table sets forth the average cost of fuel oil used by Hawaiian Electric, Hawaii Electric Light and Maui Electric to generate electricity in 2016, 20152019, 2018 and 2014:2017:
 Hawaiian Electric Hawaii Electric Light Maui Electric Consolidated
 $/Barrel ¢/MBtu $/Barrel ¢/MBtu $/Barrel ¢/MBtu $/Barrel ¢/MBtu
201651.30
 815.2
 53.27
 876.9
 62.21
 1,048.6
 53.49
 862.3
201571.86
 1,144.8
 79.03
 1,307.3
 84.38
 1,425.7
 74.71
 1,206.5
2014130.71
 2,075.4
 121.49
 2,002.5
 130.51
 2,198.9
 129.65
 2,087.6
 Hawaiian Electric Hawaii Electric Light Maui Electric Consolidated
 $/Barrel ¢/MBtu $/Barrel ¢/MBtu $/Barrel ¢/MBtu $/Barrel ¢/MBtu
201981.02
 1,304.8
 81.96
 1,354.0
 86.58
 1,454.8
 82.17
 1,337.6
201886.11
 1,371.8
 89.81
 1,489.5
 93.60
 1,573.6
 87.90
 1,420.2
201767.96
 1,087.1
 68.02
 1,125.2
 72.29
 1,214.6
 68.78
 1,114.3
The average per-unit cost of fuel oil consumed to generate electricity for Hawaiian Electric, Hawaii Electric Light and Maui Electric reflects a different volume mix of fuel types and grades as follows:
 Hawaiian Electric Hawaii Electric Light Maui Electric
 % LSFO
 % Biodiesel/Diesel
 % IFO
 % Diesel
 % MSFO
 % Diesel
201697
 3
 49
 51
 19
 81
201596
 4
 43
 57
 16
 84
201497
 3
 47
 53
 20
 80
In December 2000, Hawaii Electric Light and Maui Electric executed contracts of private carriage with Hawaiian Interisland Towing, Inc. for the employment of a double-hull tank barge for the shipment of medium sulfur fuel oil (MSFO) and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. The contracts have been extended through December 31, 2021. In July 2011, the carriage contracts were assigned to Kirby Corporation (Kirby), which provides refined petroleum and other products for marine transportation, distribution and logistics services in the U.S. domestic marine transportation industry.
Kirby never takes title to the fuel oil or diesel fuel, but does have custody and control while the fuel is in transit from Oahu. If there were an oil spill in transit, Kirby is generally contractually obligated to indemnify Hawaii Electric Light and/or Maui Electric for resulting clean-up costs, fines and damages. Kirby maintains liability insurance coverage for an amount in excess of $1 billion for oil spill related damage. State law provides a cap of $700 million on liability for releases of heavy fuel oil transported interisland by tank barge. In the event of a release, Hawaii Electric Light and/or Maui Electric may be responsible for any clean-up, damages, and/or fines that Kirby and its insurance carrier do not cover.
 Hawaiian Electric Hawaii Electric Light Maui Electric
 % LSFO
 % Biodiesel/Diesel
 % HSFO
 % Diesel
 % HSFO
 % Diesel
201993
 7
 44
 56
 24
 76
201896
 4
 39
 61
 23
 77
201795
 5
 43
 57
 23
 77
The prices that Hawaiian Electric, Hawaii Electric Light and Maui Electric pay for purchased energy from certain older nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation index. The energy prices for Kalaeloa, which purchases LSFO from Par Hawaii Refining, LLC (PAR), vary primarily with the price of Asian crude oil. A portion of PGV energy prices are based on the electric utilities’ respective short-run avoided energy cost rates (which vary with their composite fuel costs), subject to minimum floor rates specified in their approved PPA. HEPHamakua Energy energy prices vary primarily with Hawaii Electric Light’s diesel costs.


the cost of naphtha.
The Utilities estimate that 65%64% of the net energy they generate or purchase will come from fossil fuel oil in 20172020 compared to 67%66% in 2016.2019. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFOHSFO and diesel. The PPAs with AES Hawaii and HEPHamakua Energy require that they maintain certain minimum fuel inventory levels.
Rates.  Hawaiian Electric, Hawaii Electric Light and Maui Electric are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation” below.
General rate increases require the prior approval of the PUC after public and contested case hearings. Rates for Hawaiian Electric and its subsidiaries include ECRCs (changed from ECACs in 2019), and PPACs. Under current law and practices, specific and separate PUC approval is not required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. PURPA requires the PUC to periodically review the ECACsadjustment clauses related to energy cost of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change. PUC approval is also required for all surcharges and adjustments before they are reflected in rates.
See “Electric utility–Most recent rate proceedings, “Electric utility–Certain factors that may affect future results and financial condition–Regulation of electric utility rates”” and “Electric utility–Material estimates and critical accounting policies–Revenues” in HEI’s MD&A and “Interim increases” and “Utility projects” under “Commitments and contingencies” in Note 43 of the Consolidated Financial Statements.
Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii.  Randall Y. Iwase is the Chair of the PUC (for a term that will expire in June 2020) and was formerly a state legislator, Honolulu city council member, supervising deputy attorney general, and Chair of the Hawaii State Tax Review Commission. The other commissioners are Lorraine H. Akiba (for a term that will expire in June 2018), who previously was an attorney in private practice who earlier served as the Director of the State Department of Labor and Industrial Relations, and Thomas C. Gorak (appointed on an interim basis beginning July 2016), who was also an attorney in private practice before serving as the PUC's chief legal and regulatory advisor.
The Division of Consumer Advocacy is led by its newly appointed Executive Director, Dean Nishina, who most recently served as the division's Public Utilities Administrator.
Competition.  See “Electric utility–Certain factors that may affect future results and financial condition–Competition” in HEI’s MD&A.
Electric and magnetic fields.  The generation, transmission and use of electricity produces low-frequency (50Hz-60Hz) electrical and magnetic fields (EMF). While EMF has been classified as a possible human carcinogen by more than one public health organization and remains the subject of ongoing studies and evaluations, no definite causal relationship between EMF and health risks has been clearly demonstrated to date and there are no federal standards in the U.S. limiting occupational or residential exposure to 50Hz-60Hz EMF. The Utilities are continuing to monitor the ongoing research and continue to participate in utility industry funded studies on EMF and, where technically feasible and economically reasonable, continue to pursue a policy of prudent avoidance in the design and installation of new transmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on the Utilities in the future.
Global climate change and greenhouse gas (GHG) emissions reduction.  The Utilities shares the concerns of many regarding the potential effects of global climate changes and the human contributions to this phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressing global climate changes requires commitment by the private sector, all levels of government, and the public, the Utilities are committed to taking direct action to mitigate GHG emissions from its operations. See “Environmental regulation–Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements.
Legislation.  See “Electric utility–Legislation and regulation” in HEI’s MD&A.
Commitments and contingencies.  See “Selected contractual obligations and commitments” in Hawaiian Electric’s MD&A and “Electric utility–Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HEI’s MD&A, Item 1A. Risk Factors, and Note 4 of the Consolidated Financial Statements for a discussion of important commitments and contingencies.
Regulation.  The PUC regulates the rates, issuance of securities, accounting and certain other aspects of the operations of Hawaiian Electric and its electric utility subsidiaries. See the previous discussion under “Rates” and the discussions under


“Electric “Electric utility–Results of operations–Most recent rate proceedings” and “Electric utility–Certain factors that may affect future results and financial condition–Regulation of electric utility rates” in HEI’s MD&A.
Any adverse decision or policy made or adopted by the PUC, or any prolonged delay in rendering a decision, could have a material adverse effect on consolidated Hawaiian Electric’s and the Company’s results of operations, financial condition or liquidity.proceedings.”
On September 15, 2014, the State of Hawaii and the U.S. Department of Energy executed a MOUMemorandum of Understanding (MOU) recognizing that Hawaii is embarking on the next phase of its clean energy future. The MOU provides the framework for a comprehensive, sustained effort to better realize Hawaii'sits vast renewable energy potential and allow itHawaii to push forward in three main areas: the power sector, transportation and energy efficiency. This next phase will focusis focused on stimulating deployment of clean energy infrastructure as a catalyst for economic growth, energy system innovation and test bed investments.
Energy efficiency. The PUC issued an order on January 3, 2012 approving a framework for Energy Efficiency Portfolio Standards (EEPS) that set 2008 as the initial base year for evaluation and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GWH by 2015 and 975 GWH by each of the years 2020, 2025 and 2030. Pursuant to the PUC’s EEPS framework, the PUC has contracted with a public benefits fee administrator to operate and manage energy


efficiency programs, and any incentive and/or penalty mechanisms related to the achievement of the goals are at the discretion of the PUC.
The Division of Consumer Advocacy’s 2018 Compliance Resolution Fund Report states that Hawaii continues to progress towards its 2020 Renewable Portfolio Standards and EEPS goals. The EEPS has contributed to lower kWh sales; however, the implementation of sales decoupling has delinked sales and revenues. See “Regulatory mechanisms” above.
Electrification of Transportation. In June 2018, the PUC initiated a proceeding to review the Utilities��� Electrification of Transportation (EoT) Strategic Roadmap, which provided an economic analysis for light duty electric vehicles on the island of Oahu, Maui and Hawaii. In July 2019 the Utilities filed a study analyzing data regarding the critical backbone for electric vehicle charging needs in their service territories. In October 2019, the Utilities filed their EoT Workplan, establishing a schedule to continue implementation of the EoT roadmap with a focus on EV rate design and make-ready charging infrastructure in the near-term.
Renewable Portfolio Standards.In 2015, Hawaii’s RPS law was amended to require electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045, respectively. Energy savings resulting from energy efficiency programs do not count toward the RPS since 2014 (only electrical generation using renewable energy as a source counts).
Affiliate transactions. Certain transactions between HEI’s electric public utility subsidiaries (Hawaiian Electric, Hawaii Electric Light and Maui Electric) and HEI and affiliated interests (as defined by statute) are subject to regulation by the PUC. All contracts of $300,000 or more in a calendar year for management, supervisory, construction, engineering, accounting, legal, financial and similar services and for the sale, lease or transfer of property between a public utility and affiliated interests must be filed with the PUC to be effective, and the PUC may issue cease and desist orders if such contracts are not filed. All such “affiliated contracts” for capital expenditures (except for real property) must be accompanied by comparative price quotations from two nonaffiliates, unless the quotations cannot be obtained without substantial expense. Moreover, all transfers of $300,000 or more of real property between a public utility and affiliated interests require the prior approval of the PUC and proof that the transfer is in the best interest of the public utility and its customers. If the PUC, in its discretion, determines that an affiliated contract is unreasonable or otherwise contrary to the public interest, the utility must either revise the contract or risk disallowance of payments under the contract for rate-making purposes. In rate-making proceedings, a utility must also prove the reasonableness of payments made to affiliated interests under any affiliated contract of $300,000 or more by clear and convincing evidence.
In December 1996, the PUC issued an order in a docket that had been opened to review the relationship between HEI and Hawaiian Electric and the effects of that relationship on the operations of Hawaiian Electric. The order adopted the report of the consultant the PUC had retained and orderedrequired Hawaiian Electric to continue to provide the PUC with periodic status reports on its compliance with the PUC Agreement (pursuant to which HEI became the holding company of Hawaiian Electric). Hawaiian Electric files such status reports annually. In the order, the PUC also required the Utilities to present a comprehensive analysis of the impact that the holding company structure and investments in nonutility subsidiaries have on a case-by-case basis on the cost of capital to each utility in future rate cases and remove any such effects from the cost of capital. The Utilities have made presentations in their subsequent rate cases to support their positions that there was no evidence that would modify the PUC’s finding that Hawaiian Electric’s access to capital did not suffer as a result of HEI’s involvement in nonutility activities and that HEI’s diversification did not permanently raise or lower the cost of capital incorporated into the rates paid by Hawaiian Electric’s utility customers.
In December 2018, the PUC established a set of requirements governing transactions and sharing of information between the Utilities and its affiliates (Affiliate Transaction Requirements, ATRs), which was subsequently modified and clarified in January 2019 following the Utilities’ motion for reconsideration. The PUC stated the intent of the ATRs is to establish safeguards to avoid potential market power benefits and cross-subsidization between regulated and unregulated activities. The requirements include rules on interactions with affiliates, information handling, business development, political activities, promotional activities, sales of products and services, and employee sharing restrictions. The ATRs include implementing an internal code of conduct, a compliance plan, including policies and procedures to comply with the requirements, and having an audit conducted every three years that examines the compliance with the requirements. Penalties for non-compliance depend on the severity of the violation, and can range from daily fines to divestiture of the Utilities by the holding company.
Other regulations.The Utilities are not subject to regulation by the FERC under the Federal Power Act, except under Sections 210 through 212 (added by Title II of PURPA and amended by the Energy Policy Act of 1992), which permit the FERC to order electric utilities to interconnect with qualifying cogenerators and small power producers, and to wheel power to other electric utilities. Title I of PURPA, which relates to retail regulatory policies for electric utilities, and Title VII of the Energy Policy Act of 1992, which addresses transmission access, also apply to the Utilities. The Utilities are also required to file various operational reports with the FERC.
Because they are located in the State of Hawaii, Hawaiian Electric and its subsidiaries are exempt by statute from limitations set forth in the Powerplant and Industrial Fuel Use Act of 1978 on the use of petroleum as a primary energy source.
See also “HEI–Regulation” above.
Environmental regulation.  Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, are subject to periodic inspections by federal, state and, in some cases, local environmental regulatory agencies, including agencies responsible for the regulation of water quality, air quality, hazardous and other waste and hazardous materials. These inspections may result in the identification of items needing corrective or other action. Except as otherwise disclosed in this report (see “Certain factors that may affect future results“Risk Factors” in Item 1A, and financial condition–Environmental matters” for HEI Consolidated, the Electric utilityNotes 1 and the Bank sections in HEI’s MD&A and Note 43 of the Consolidated Financial Statements, which are incorporated herein by reference), the Company believesUtilities believe that each subsidiary has appropriately responded to environmental conditions



conditions requiring action and that, as a result of such actions, such environmental conditions will not have a material adverse effect on the Company or Hawaiian Electric.capital expenditures, earnings and competitive position of the Utilities.
Water quality controls. The generating stations, substations and other utility facilities operate under federal and state water quality regulations and permits, including, but not limited to, the Clean Water Act National Pollution Discharge Elimination System (governing point source discharges, including wastewater and storm water discharges), and the Safe Drinking Water Act Underground Injection Control (regulating disposal of wastewater into the subsurface),. On February 1, 2018, the Spill Prevention, Control and Countermeasure (SPCC) program,Ninth Circuit Court of Appeals ruled that under certain circumstances, where there may be a connection to surface water, discharges from underground injection control wells may require National Pollution Discharge Elimination System permits. This case was appealed to the U.S. Supreme Court who heard the matter in November of 2019. A final decision is expected in the first quarter of 2020.
Oil pollution controls.  The Oil Pollution Act of 1990 (OPA) (governingestablishes programs that govern actual or threatened oil releases and imposingimposes strict liability on responsible parties for clean-up costs and damages to natural resources and property), and other regulations associated with discharges of oil and other substances to surface water.property. The federal Environmental Protection Agency (EPA) regulations under OPA also require certain facilities that use or store petroleumoil to prepare and implement SPCCSpill Prevention, Control and Countermeasures (SPCC) Plans in order to prevent releases of petroleumoil to navigable waters of the U.S. Certain facilities are also required to prepare and implement Facility Response Plans (FRPs) to ensure prompt and proper response to releases of oil. The Utilities'utility facilities that are subject to SPCC Plan requirements, including most power plants, base yards, and certain substations,FRP requirements have prepared and are implementingimplemented SPCC Plans.Plans and FRPs.
The Company believes that each subsidiary’s costs of responding to petroleum releases to date will not have a material adverse effect on the respective subsidiary or the Company.
Air quality controls. The Clean Air Act (CAA) establishes permitting programs to reduce air pollution. The CAA amendments of 1990, established the federal Title V Operating Permit Program (in Hawaii known as the Covered Source Permit program) to ensure compliance with all applicable federal and state air pollution control requirements. The 1977 CAA Amendments established the New Source Review (NSR) permitting program, which affect new or modified generating units by requiring a permit to construct under the CAA and the controls necessary to meet the National Ambient Air Quality Standards (NAAQS).Standards.
Title V operating permits have been issued for all of the Utilities’ affected generating units.
Hazardous waste and toxic substances controls. The operations of the electric utility and former freight transportation subsidiaries of HEI are subject to EPA regulations that implement provisions of the Resource Conservation and Recovery Act (RCRA), the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA, also known as Superfund), the Superfund Amendments and Reauthorization Act (SARA), and the Toxic Substances Control Act (TSCA).
RCRA underground storage tank (UST) regulations require all facilities that use USTs for storing petroleum products to comply with established leak detection, spill prevention, standards for tank design and retrofits, financial assurance, operator training, and tank decommissioning and closure requirements. All of the Utilities’ USTs currently meet the applicable requirements.
The Emergency Planning and Community Right-to-Know Act under SARA Title III requires the Utilities to report potentially hazardous chemicals present in their facilities in order to provide the public with information so that emergency procedures can be established to protect the public in the event of hazardous chemical releases. Since January 1, 1998, the steam electric industry category has been subject to Toxics Release Inventory (TRI) reporting requirements.
The TSCA regulations specify procedures for the handling and disposal of polychlorinated biphenyls (PCBs), a compound found in some transformer and capacitor dielectric fluids. The TSCA regulations also apply to responses to releases of PCBs to the environment. The Utilities have instituted procedures to monitor compliance with these regulations and have implemented a program to identify and replace PCB transformers and capacitors in their systems. systems. In AprilApril 2010, the EPA issued an Advance Notice of Proposed Rule Making announcing its intent to reassess PCB regulations. The EPA projects that it will publish a notice of proposed rulemaking in November 2017.has ceased activity on the PCB reassessment.
Hawaii’s Environmental Response Law (ERL), as amended, governs releases of hazardous substances, including oil, to the environment in areas within the state’s jurisdiction. Responsible parties under the ERL are jointly, severally, and strictly liable for a release of a hazardous substance. Responsible parties include owners or operators of a facility where a hazardous substance is located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed.
The Utilities periodically discover leaking petroleum-containingoil-containing equipment such as USTs, piping, and transformers. Each subsidiary reports releases from such equipment when and as required by applicable law and addresses the releases in compliance with applicable regulatory requirements.
Research and development. The Utilities expensed approximately $4.2 million, $3.3 million and $2.9 million in 2016, 2015 and 2014, respectively, for research and development (R&D). In 2016, 2015 and 2014, the electric utilities’ contributions to the Electric Power Research Institute (EPRI) accounted for approximately 52%, 67% and 76% of R&D expenses, respectively. The Utilities continue to collaborate with EPRI, Energy Excelerator, other utilities, national testing labs, leading edge companies and various stakeholders to learn what new technologies and solutions are being developed, tested, and implemented elsewhere



and can be applied to helping the State achieve a 100% clean energy future. The Utilities utilize an expanded reference of R&D to highlight the demonstration of technologies. Included in the R&D expenses were amounts related to evaluating, testing, and demonstrating new and emerging technologies, biofuels, energy storage, demand response, environmental compliance, power quality, electric and hybrid plug in vehicles and other renewables (e.g., integration of distributed energy resources onto the utility grid, grid modernization, solar resource evaluation, advanced inverter testing, and modeling of high PV penetration circuits).
Additional information.  For additional information about Hawaiian Electric, see Hawaiian Electric’s MD&A, Hawaiian Electric’s “Quantitative and Qualitative Disclosures about Market Risk” and Hawaiian Electric’s Consolidated Financial Statements.Statements, including the Notes thereto.
Properties. Hawaiian Electric owns four generating plants on the island of Oahu at Waiau, Kahe, Campbell Industrial Park (CIP) and Honolulu. Hawaiian Electric currently operates three of the four generation plants; the fourth, in downtown Honolulu, was deactivated in 2014. These plants have an aggregate net generating capability of 1,214 MW asAs of December 31, 2016. The City and County of Honolulu is seeking to condemn a portion of2019, the Honolulu plant site for its rail project.Utilities’ ownership in generating assets was as follows:
PropertyLocation (island)Principal Fuel TypeGenerating Capacity (MW)Status
Hawaiian Electric:
Waiau1
OahuLSFO / Diesel480.8Active
Kahe1
OahuLSFO620.5Active
Campbell Industrial Park (CIP)1
OahuDiesel129.0Active
Honolulu Power Plant1
OahuN/A—Deactivated in 2014
Schofield Generating Station2
OahuBiodiesel / ULSD49.4Active
West Loch PV Project3
OahuRenewable (Solar)20.0Active
Hawaii Electric Light4:
ShipmanHawaiiN/A—Retired in 2015
WaimeaHawaiiULSD7.5Active
KeaholeHawaiiDiesel / ULSD77.6Active
PunaHawaiiHSFO / Diesel36.7Active
Hill/KanoelehuaHawaiiHSFO / ULSD55.4Active
Distributed generators at substation sitesHawaiiULSD5.0Active
Maui Electric5:
KahuluiMauiHSFO35.9Active
MaalaeaMauiDiesel / ULSD210.4Active
Miki BasinLanaiULSD9.4Active
PalaauMolokaiULSD12.0Active
1 The four plants are situated on Hawaiian Electric-owned land having a combined area of 535 acres and three parcels of land totaling 5.5 acres under leases expiring between December 31, 2018 and June 30, 2021, with options to extend to June 30, 2026. Additionally,542 acres.
2 Hawaiian Electric has negotiated two leases: 1) a 35 year35-year land lease on 8.13 acres, effective September 1, 2016 with(with an option to extend an additional 10 yearsyears), with the Department of the Army to install, operate, and maintain a 50 MW power generation plant on 8.13 acres, and 2) a 37 year lease, effective July 1, 2017 or upon PUC approval (whichever is sooner) with the Secretary of the Navy to install, operate and maintain a 28 MW renewable generation site on 102 acres. In addition, Hawaiian Electric owns a total of 132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.Army.
3
Hawaiian Electric has a 37-year land lease on 102 acres, effective July 1, 2017, with the Secretary of the Navy.
Hawaiian Electric owns buildings and approximately 11.6 acres of land located in Honolulu which house its operating and engineering departments. It also leases an office building and certain office spaces in Honolulu, and a warehousing center in Kapolei.4 The lease for the office building expires in November 2021, with an option to extend through November 2024. Leases for certain office and warehouse spaces expire on various dates from May 31, 2017 through July 31, 2025, some with options to extend to various dates through December 31, 2034.
Hawaiian Electric's Barbers Point Tank Farm (BPTF) has three storage tanks with an aggregate of 1 million barrels of storage for low sulfur fuel oil (LSFO). The BPTF is located in Campbell Industrial Park, on the same property as the CIP Generating Station, and is the central fuel storage facility where LSFO purchased by Hawaiian Electric is received and stored. From the BPTF, LSFO is transported via Hawaiian Electric owned underground pipelines to the Kahe and Waiau Power Plants. Hawaiian Electric also has fuel storage facilities at each of its plant sites with a nominal aggregate capacity of 770,000 barrels for LSFO storage, 44,000 barrels for diesel storage, and 88,000 barrels for biodiesel storage. Hawaiian Electric also owns a fuel storage facility at Iwilei that was used to provide fuel to the Honolulu Power Plant. The Honolulu Power Plant was deactivated on January 31, 2014 and any future fuel supplies will be delivered directly to the plant by truck. The Iwilei fuel storage facility's tanks and pumping infrastructure are being removed, and the facility is being reconfigured for other purposes.
Hawaii Electric Light owns and operates four generating plants on the island of Hawaii in Hilo, Waimea, Keahole and Puna, along with distributed generators at substation sites. These plants have an aggregate net generating capability of 179 MW as of December 31, 2016 (excluding several small run-of-river hydro units). Hawaii Electric Light's Shipman plant in Hilo was deactivated in 2014 and retired in 2015. The plants (including a baseyard on the same parcel as the Hilo plant) are situated on Hawaii Electric Light-owned land having a combined area of approximately 44 acres. The distributed generators are located within Hawaii Electric Light-owned substation sites having a combined area of approximately 4four acres. Hawaii Electric Light also owns
5
The four plants are situated on Maui Electric-owned land having a combined area of 60.7 acres.
As of December 31, 2019, the Utilities ownership in fuel storage facilities at these sites with a usable storage capacity of 48,000 barrels of medium sulfur fuel oil (MSFO) and 81,802 barrels of diesel.was as follows:
FacilityLocation (island)Fuel TypeCapacity (barrels in thousands)Generation Serviced
Hawaiian Electric:
Barbers Point Tank FarmOahuLSFO1,000Kahe, Waiau
Generation sites - various (in aggregate)OahuLSFO770Various
Generation sites - various (in aggregate)OahuDiesel132Various
Generation sites - various (in aggregate)OahuBiodiesel11Various
Hawaii Electric Light1:
Generation sites - various (in aggregate)HawaiiHSFO48Various
Generation sites - various (in aggregate)HawaiiDiesel82Various
Maui Electric2:
Generation sites - various (in aggregate)MauiHSFO81Various
Generation sites - various (in aggregate)MauiDiesel95Various
1 There are an additional 19,200 barrels of diesel and 22,770 barrels of MSFOHSFO storage capacity for Hawaii Electric Light-owned fuel off-site at Island Energy Services, LLC (Island Energy)-owned terminalling facilities (previously Chevron-owned)facilities.
2
There are an additional 56,358 barrels of diesel oil storage capacity off-site at Aloha Petroleum, Ltd. (Aloha Petroleum)-owned terminalling facilities.



Other properties.  The Utilities own overhead transmission and distribution lines, underground cables, pole (some jointly) and metal high voltage towers. Electric lines are located over or under public and nonpublic properties.
Hawaiian Electric owns a total of 132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located. Hawaiian Electric also owns buildings and approximately 11.6 acres of land located in Honolulu, which house its operating and engineering departments. It also leases an office building and certain office spaces in Honolulu, land for office spaces and storage in Pearl City, and a warehousing center in Kapolei.
Hawaii Electric Light pays a storage fee to Island Energy and has no other interest in the property, tanks or other infrastructure situated on their property. Hawaii Electric Light also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its accounting, customer services and administrative offices. Hawaii Electric Light also leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, Hawaii Electric Light owns a total of approximately 100 acres of land, and leases a total of approximately 8.5 acres of land, on which hydro facilities, substations and switching stations, microwave facilities and transmission lines are located. The deeds to the sites located in Hilo contain certain restrictions, but the restrictions do not materially interfere with the use of the sites for public utility purposes.
On 37.7 acres ofMaui Electric’s administrative offices, as well as its land, Maui Electric: (1) owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 246.3 MW as of December 31, 2016, (2) has offices (administrative, engineering and distribution departments)departments, are situated on 9.1 acres of Maui Electric-owned land in Kahului, and (3) owns fuel oil storage facilities with a total maximum usable


capacity of 81,272 barrels of MSFO and 94,586 barrels of diesel. There are an additional 56,358 barrels of diesel oil storage capacity off-site at Aloha Petroleum, Ltd. (Aloha Petroleum)-owned terminalling facilities, for which Maui Electric pays storage fees.Kahului. Maui Electric also owns two, 1 MW stand-by diesel generatorsapproximately 18 acres of land which house some of its substations, leases approximately 3,600 square feet of land for its telecommunication and amicrowave facilities, leases approximately 6,000 gallon fuel storage tank in Hanasquare feet of land at Kahului Harbor for pipeline purposes, and 65.7leases 17,958 square feet of land at Puunene for the Puunene Substation. Maui Electric also owns approximately 89 acres of undeveloped land at Waena.
Maui Electric also ownsWaena, Palaau, and operates smaller distribution systems, generation systems (with an aggregate net capability of 21.1 MW as of December 31, 2016) and fuelKahului. Fuel storage facilities on the islands of Lanai and Molokai, primarily on its own land.
Other properties.  The Utilities own overhead transmission and distribution lines, underground cables, poles (some jointly) and metal high voltage towers. Electric lines are located over or under publicon Maui Electric-owned properties at Kahului Baseyard, Kahului Power Plant, Maalaea Power Plant, Miki Basin, Palaau, and nonpublic properties. LinesHana. Two, 1-MW stand-by diesel generators are added when needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. Under Hawaii law,located within the PUC generally must determine whether new 46 kilovolt (kV), 69 kV or 138 kV lines can be constructed overhead or must be placed underground.Maui Electric-owned land at Hana Substation.
See “Hawaiian Electric and subsidiaries and service areas” above for a discussion of the nonexclusive franchises of Hawaiian Electric and subsidiaries. Most of the leases, easements and licenses for Hawaiian Electric’s, Hawaii Electric Light’s and Maui Electric’s lines have been recorded.
See “Generation statistics” above and “Limited insurance” in HEI’s MD&A for a further discussion of some of the electric utility properties.
Bank
General.  ASB is one of the largest financial institutions headquartered in the State of Hawaii with assets of $7.2 billion and deposits of $6.3 billion, as of December 31, 2019. ASB is a full-service community bank that serves both consumer and commercial customers and operates 49 branches on the islands of Oahu (34), Maui (6), Hawaii (5), Kauai (3), and Molokai (1). ASB was acquired by HEI in 1988, and prior to its acquisition, ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2016, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $6.4 billion and deposits of $5.5 billion.
In 2016,2019, ASB’s revenues and net income amounted to approximately 12%11% and 23% (impacted by the merger termination fee and other impacts at corporate)41% of HEI’s consolidated revenues and net income, respectively, compared to approximately 10%11% and 34%41% in 20152018 and approximately 8%12% and 31%41% in 2014, respectively.2017.
At the time of HEI’s acquisition of ASB, in 1988, HEI agreed with the OTS’Office of Thrift Supervision (OTS), Department of Treasury’s predecessor regulatory agency, that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to ensure that ASB would have the capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 31, 2016,2019, as a result of certain HEI contributions of capital to ASB over the years, HEI’s maximum obligation under the agreement to contribute additional capital has been reduced to approximately $28.3 million. ASB is subject to OCC regulations on dividends and other distributions and ASB must receive a letter of non-objection from the OCCFRB communicating the OCC’s and FRB before it canFRB’s non-objection to the payment of any dividend ASB proposes to declare and pay a dividend to ASB Hawaii and HEI.
The following table sets forth selected data for ASB (average balances calculated using the average daily balances):
Years ended December 312016
 2015
 2014
Common equity to assets ratio 
  
  
Average common equity divided by average total assets9.34% 9.53% 9.87%
Return on assets     
Net income for common stock divided by average total assets0.92
 0.95
 0.95
Return on common equity     
Net income for common stock divided by average common equity9.90
 9.93
 9.60
Asset/liability management.  See HEI’s “Quantitative and Qualitative Disclosures about Market Risk.”
Consolidated average balance sheet and interest income and interest expense.  See “Bank—Results of operations—Average balance sheet and net interest margin” in HEI’s MD&A.
The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a prorata basis.
Years ended December 312019
 2018
 2017
Equity to assets ratio 
  
  
Average equity divided by average total assets9.30% 8.86% 9.10%
Return on assets     
Net income divided by average total assets1.25
 1.20
 1.02
Return on equity     
Net income divided by average equity13.48
 13.51
 11.20



 2016 vs. 2015 2015 vs. 2014
(in thousands)Rate Volume Total Rate Volume Total
Interest income 
  
  
  
  
  
Interest-earning deposits$228
 $(169) $59
 $9
 $92
 $101
FHLB stock192
 (148) 44
 144
 (84) 60
Securities purchased under resale agreements—
 —
 —
 (10) (10) (20)
Available-for-sale investment securities           
Taxable(1,018) 4,961
 3,943
 (158) 3,471
 3,313
Non-taxable14
 14
 28
 (214) (215) (429)
Total available-for-sale investment securities(1,004) 4,975
 3,971
 (372) 3,256
 2,884
Loans     
      
Residential 1-4 family(2,103) 444
 (1,659) (2,451) 1,793
 (658)
Commercial real estate1,037
 8,345
 9,382
 (1,831) 4,485
 2,654
Home equity line of credit686
 1,052
 1,738
 (402) 1,197
 795
Residential land(77) 94
 17
 (73) 68
 (5)
Commercial2,538
 (2,077) 461
 (552) 540
 (12)
Consumer1,908
 3,145
 5,053
 1,933
 734
 2,667
Total loans3,989
 11,003
 14,992
 (3,376) 8,817
 5,441
Total increase (decrease) in interest income3,405
 15,661
 19,066
 (3,605) 12,071
 8,466
Interest expense 
  
  
  
  
  
Savings(103) (42) (145) —
 (123) (123)
Interest-bearing checking—
 (34) (34) —
 (13) (13)
Money market(5) 8
 3
 —
 9
 9
Time certificates(589) (1,054) (1,643) —
 (144) (144)
Advances from Federal Home Loan Bank21
 (35) (14) —
 —
 —
Securities sold under agreements to repurchase(285) 689
 404
 672
 (919) (247)
Total (increase) decrease in interest expense(961) (468) (1,429) 672
 (1,190) (518)
Increase (decrease) in net interest income$2,444
 $15,193
 $17,637
 $(2,933) $10,881
 $7,948
See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in earning assets and costing liabilities.
Noninterest income. In addition to net interest income, ASB has various sources of noninterest income, including fee income from credit and debit cards, fee income from deposit liabilities, mortgage banking income and other financial products and services. See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in noninterest income.
Lending activities.
General. The following table sets forthSee Note 4 of the Consolidated Financial Statements for the composition of ASB’s loans receivable held for investment:


December 312016 2015 2014 2013 2012
(dollars in thousands)Balance 
% of
total

 Balance % of
total
 Balance % of
total
 Balance % of
total
 Balance % of
total
Real estate: 1 
 
  
  
  
  
  
  
  
  
  
Residential 1-4 family$2,048,051
 43.2
 $2,069,665
 44.8
 $2,044,205
 46.0
 $2,006,007
 48.2
 $1,866,450
 49.2
Commercial real estate800,395
 16.9
 690,561
 14.9
 531,917
 12.0
 440,443
 10.6
 375,677
 9.9
Home equity line of credit863,163
 18.2
 846,294
 18.3
 818,815
 18.4
 739,331
 17.8
 630,175
 16.6
Residential land18,889
 0.4
 18,229
 0.4
 16,240
 0.4
 16,176
 0.4
 25,815
 0.7
Commercial construction126,768
 2.7
 100,796
 2.2
 96,438
 2.2
 52,112
 1.3
 43,988
 1.2
Residential construction16,080
 0.3
 14,089
 0.3
 18,961
 0.4
 12,774
 0.3
 6,171
 0.2
Total real estate3,873,346
 81.7

3,739,634
 80.9
 3,526,576
 79.4
 3,266,843
 78.6
 2,948,276
 77.8
Commercial692,051
 14.6
 758,659
 16.4
 791,757
 17.8
 783,388
 18.8
 721,349
 19.0
Consumer178,222
 3.7
 123,775
 2.7
 122,656
 2.8
 108,722
 2.6
 121,231
 3.2
Total loans4,743,619
 100.0
 4,622,068
 100.0
 4,440,989
 100.0
 4,158,953
 100.0
 3,790,856
 100.0
Less: Deferred fees and discounts(4,926)  
 (6,249)  
 (6,338)  
 (8,724)  
 (11,638)  
Allowance for loan losses(55,533)  
 (50,038)  
 (45,618)  
 (40,116)  
 (41,985)  
Total loans, net$4,683,160
  
 $4,565,781
  
 $4,389,033
  
 $4,110,113
  
 $3,737,233
  
1
Includes renegotiated loans.
The increase in the loans receivable balance in 2016 was primarily due to growth in the commercial real estate, consumer, commercial construction and home equity lines of credit (HELOC) loan portfolios as a result of demand for these loan types, partly offset by a decrease in the commercial and residential 1-4 family loan portfolios. The growth in the commercial real estate, consumer, commercial construction and HELOC loan portfolios was consistent with ASB's loan growth strategy. The decrease in the commercial loan portfolio was due to the strategic reduction of ASB's nationally syndicated loan portfolio by $93 million. The decrease in the residential loan portfolio was due to ASB's decision to sell a portion of its loan production with low interest rates to control its interest rate risk.
The increase in the loans receivable balance in 2015 was primarily due to growth in commercial real estate, HELOC and residential 1-4 family loan portfolios, partly offset by a decrease in the commercial loan portfolio. The growth in the commercial real estate, HELOC and residential loan portfolios was driven by demand for this loan type and was consistent with ASB's loan growth strategy.
The increase in the loans receivable balance in 2014 was primarily due to growth in commercial real estate, HELOC, commercial construction and residential 1-4 family loan portfolios. The growth in the commercial real estate and commercial construction loan portfolios were driven by demand for these loan types as the Hawaii economy continues to improve. The growth in the HELOC and residential loan portfolios were consistent with ASB’s mix target and loan growth strategy.
The increase in the loans receivable balance in 2013 was primarily due to growth in the residential, HELOC, commercial and commercial real estate loan portfolios. The growth in these portfolios was consistent with ASB’s mix target and loan growth strategy.
The increase in the loans receivable balance in 2012 was primarily due to growth in commercial, commercial real estate, consumer and HELOC loans as ASB targeted these portfolios because of their shorter duration and/or variable rates. Offsetting these 2012 loan portfolio increases was a decrease in the residential loan portfolio. Although ASB produced nearly $1.0 billion of new, long-term residential loans in 2012, nearly double the level for 2011, it sold more than half those loans to control interest rate risk and repayments were also higher than in 2011.


The following table summarizes our loans receivable held for investment based upon contractually scheduled principal payments allocated to the indicated maturity categories:
December 312016
Due
In
1 year
or less

 
After 1 year
through
5 years

 
After
5 years

 Total
(in millions) 
  
  
  
Commercial – Fixed$51
 $129
 $22
 $202
Commercial – Adjustable209
 241
 40
 490
Total commercial260
 370
 62
 692
Commercial construction – Fixed—
 —
 —
 —
Commercial construction – Adjustable31
 96
 —
 127
Total commercial construction31
 96
 —
 127
Residential construction – Fixed16
 —
 —
 16
Residential construction – Adjustable—
 —
 —
 —
Total residential construction16
 —
 —
 16
Total loans – Fixed67
 129
 22
 218
Total loans – Adjustable240
 337
 40
 617
Total loans$307
 $466
 $62
 $835
Origination, purchase and sale of loans. Generally, residential and commercial real estate loans originated by ASB are collateralized by real estate located in Hawaii. For additional information, including information concerning the geographic distribution of ASB’s mortgage-relatedmortgage-backed securities portfolio and the geographic concentration of credit risk, see Note 15 toof the Consolidated Financial Statements. The demand for loans is primarily dependent on the Hawaii real estate market, business conditions, interest rates and loan refinancing activity.
Residential mortgage lending. ASB originates fixed rate and adjustable rate loans secured by single family residential property, including investor-owned properties, with maturities of up to 30 years. ASB’s general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For non-owner-occupied residential properties,property purchases, the loan-to-value ratio may not exceed 80%75% of the lower of the appraised value or purchase price at origination.
Construction and development lending. ASB provides fixed rate loans for the construction of one-to-four unit residential and commercial properties. Construction loan projects are typically short term in nature. Construction and development financing generally involves a higher degree of credit risk than long-term financing on improved, occupied real estate. Accordingly, construction and development loans are generally priced higher than loans collateralized by completed structures. ASB’s underwriting, monitoring and disbursement practices with respect to construction and development financing are designed to ensure sufficient funds are available to complete construction projects. See “Loan“Bank—Loan portfolio risk elements” in HEI’s MD&A and “Multifamily residential and commercial real estate lending” below.
Multifamily residential and commercial real estate lending. ASB provides permanent financing and construction and development financing collateralized by multifamily residential properties (including apartment buildings) and collateralized by commercial and industrial properties (including office buildings, shopping centers and warehouses) for its own portfolio as well as for participation with other lenders. Commercial real estate lending typically involves long lead times to originate and fund. As a result, production results can vary significantly from period to period.
Consumer lending. ASB offers a variety of secured and unsecured consumer loans. Loans collateralized by deposits are limited to 90% of the available account balance. ASB offers home equity lines of credit, clean energy loans, secured and unsecured VISA cards (through a third party issuer), checking account overdraft protection and other general purpose consumer loans.
Commercial lending. ASB provides both secured and unsecured commercial loans to business entities. This lending activity is designed to diversify ASB’s asset structure, shorten maturities, improve rate sensitivity of the loan portfolio and attract commercial checking deposits. ASB offers commercial loans with terms up to ten years.
Loan origination fee and servicing income. In addition to interest earned on residential mortgage loans, ASB receives income from servicing loans, for late payments and from other related services. Servicing fees are received on loans originated and subsequently sold by ASB where ASB acts as collection agent on behalf of third-party purchasers.


ASB charges the borrower at loan settlement a loan origination fee. See “Loans receivable”“Loans” in Note 1 of the Consolidated Financial Statements.
Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of real estate secured loans. In a foreclosure action, the property collateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold. As of December 31, 2016, 2015 and 2014, ASB had $1.2 million, $1.0 million and $0.9 million, respectively, of real estate acquired in settlement of loans.
In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2016, 2015, 2014, 2013 and 2012 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured loans:
December 312016
 2015
 2014
 2013
 2012
(dollars in thousands) 
  
  
  
  
Nonaccrual loans— 
  
  
  
  
Real estate 
  
  
  
  
Residential 1-4 family$11,154
 $20,554
 $19,253
 $19,679
 $26,721
Commercial real estate223
 1,188
 5,112
 4,439
 6,750
Home equity line of credit3,080
 2,254
 1,087
 2,060
 2,349
Residential land878
 970
 720
 3,161
 8,561
Residential construction—
 —
 —
 —
 —
Total real estate15,335
 24,966
 26,172
 29,339
 44,381
Commercial6,708
 20,174
 10,053
 18,781
 20,222
Consumer1,282
 895
 661
 401
 284
Total nonaccrual loans$23,325
 $46,035
 $36,886
 $48,521
 $64,887
Troubled debt restructured loans not included above— 
  
  
  
  
Real estate 
  
  
  
  
Residential 1-4 family$14,450
 $13,962
 $13,525
 $9,744
 $6,759
Commercial real estate1,346
 —
 —
 —
 —
Home equity line of credit4,934
 2,467
 480
 171
 —
Residential land2,751
 4,713
 7,130
 7,476
 11,090
Total real estate23,481
 21,142
 21,135
 17,391
 17,849
Commercial14,146
 1,104
 2,972
 1,649
 43
Consumer10
 —
 —
 —
 —
Total troubled debt restructured loans$37,637
 $22,246
 $24,107
 $19,040
 $17,892
In 2016, nonaccrual loans decreased $22.7 million primarily due to upgrades of specific commercial and commercial real estate loans, payoff of a troubled commercial loan and a segment of residential mortgages transferred to held-for-sale. Nonaccrual commercial and residential loans decreased by $13.5 million and $9.4 million, respectively. ASB evaluates a restructured loan transaction to determine if the borrower is in financial difficulty and if the restructured terms are considered concessions—typically terms that are out of market, beyond normal or reasonable standards, or otherwise not available to a non-troubled borrower in the normal marketplace. A loan classified as TDR must meet both criteria of financial difficulty and concession. Accruing TDR loans increased $15.4 million in 2016 primarily due to increases of $13.0 million and $2.5 million of commercial and HELOC loans, respectively, classified as TDR. The increase in commercial loans classified as TDR was primarily due to two commercial credits being classified as TDR.
In 2015, nonaccrual loans increased $9.1 million primarily due to higher nonaccrual commercial loans of $10.1 million. TDR loans decreased $1.9 million in 2015 primarily due to decreases of $2.4 million and $1.9 million of residential land and commercial loans, respectively, classified as TDR. HELOC loans classified as TDR increased by $2.0 million.


In 2014, nonaccrual loans decreased $11.6 million primarily due to the payoff of commercial loans that were on nonaccrual status and repayments in the residential land portfolio. TDR loans increased $5.1 million in 2014 primarily due to increases of $3.8 million and $1.3 million of residential 1-4 and commercial loans, respectively, classified as TDR.
In 2013, nonaccrual loans decreased $16.4 million due to improved credit quality in the residential 1-4 family, commercial real estate and commercial loans, and repayments in the residential land portfolio. The improvement is attributed to the continued stabilization or increase of property values, more financial flexibility of borrowers, and overall general economic improvement in the State of Hawaii. TDR loans increased $1.1 million in 2013 primarily due to increases of $3.0 million and $1.6 million of residential 1-4 and commercial loans, respectively, classified as TDR, partly offset by a $3.6 million decrease in residential land loans classified as TDR.
Impact of nonperforming loans on interest income. The following table presents the gross interest income for both nonaccrual and restructured loans that would have been recognized if such loans had been current in accordance with their original contractual terms, and had been outstanding throughout the period or since origination if held for only part of the period. The table also presents the interest income related to these loans that was actually recognized for the period.
(dollars in millions)Year ended December 31, 2016
Gross amount of interest income that would have been recorded in accordance with original contractual terms, and had been outstanding throughout the period or since origination, if held for only part of the period 1
$3
Interest income actually recognized2
Total interest income foregone$1
1
Based on the contractual rate that was being charged at the time the loan was restructured or placed on nonaccrual status.

Allowance for loan losses. See “Allowance for loan losses” in Note 1 of the Consolidated Financial Statements.
The following table presents the changes in the allowance for loan losses:
(dollars in thousands)2016
 2015
 2014
 2013
 2012
Allowance for loan losses, January 1$50,038
 $45,618
 $40,116
 $41,985
 $37,906
Provision for loan losses16,763
 6,275
 6,126
 1,507
 12,883
Charge-offs         
Residential 1-4 family639
 356
 987
 1,162
 3,183
Home equity line of credit112
 205
 196
 782
 716
Residential land138
 —
 81
 485
 2,808
Total real estate889
 561
 1,264
 2,429
 6,707
Commercial5,943
 1,074
 1,872
 3,056
 3,606
Consumer7,413
 4,791
 2,414
 2,717
 2,517
Total charge-offs14,245
 6,426
 5,550
 8,202
 12,830
Recoveries 
  
  
  
  
Residential 1-4 family421
 226
 1,180
 1,881
 1,328
Home equity line of credit59
 80
 752
 358
 108
Residential land461
 507
 469
 868
 1,443
Total real estate941
 813
 2,401
 3,107
 2,879
Commercial1,093
 2,773
 1,636
 1,089
 649
Consumer943
 985
 889
 630
 498
Total recoveries2,977
 4,571
 4,926
 4,826
 4,026
Allowance for loan losses, December 31$55,533
 $50,038
 $45,618
 $40,116
 $41,985
Ratio of allowance for loan losses to loans receivable held for investment1.17% 1.08% 1.03% 0.97% 1.11%
Ratio of provision for loan losses during the year to average total loans0.36% 0.14% 0.14% 0.04% 0.35%
Ratio of net charge-offs during the year to average total loans0.24% 0.04% 0.01% 0.09% 0.24%


The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans:
December 312016 2015 2014
(dollars in thousands)Allow-ance balance 
Allowance
to loan
receivable
%
 
Loan
receivable
% of
total
 Allow-ance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total		 Allow-ance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total
Real estate 
  
  
  
  
  
  
  
  
Residential 1-4 family$2,873
 0.14
 43.2
 $4,186
 0.20
 44.8
 $4,662
 0.23
 46.0
Commercial real estate16,004
 2.00
 16.9
 11,342
 1.64
 14.9
 8,954
 1.68
 12.0
Home equity line of credit5,039
 0.58
 18.2
 7,260
 0.86
 18.3
 6,982
 0.85
 18.4
Residential land1,738
 9.20
 0.4
 1,671
 9.17
 0.4
 1,875
 11.55
 0.4
Commercial construction6,449
 5.09
 2.7
 4,461
 4.43
 2.2
 5,471
 5.67
 2.2
Residential construction12
 0.07
 0.3
 13
 0.09
 0.3
 28
 0.15
 0.4
Total real estate32,115
 0.83
 81.7
 28,933
 0.77
 80.9
 27,972
 0.79
 79.4
Commercial16,618
 2.40
 14.6
 17,208
 2.27
 16.4
 14,017
 1.77
 17.8
Consumer6,800
 3.82
 3.7
 3,897
 3.15
 2.7
 3,629
 2.96
 2.8
 55,533
 1.17
 100.0
 50,038
 1.08
 100.0
 45,618
 1.03
 100.0
Unallocated—
  
  
 —
  
  
 —
  
  
Total allowance for loan losses$55,533
  
  
 $50,038
  
  
 $45,618
  
  
December 312013 2012
(dollars in thousands)Allowance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total		 Allowance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total
Real estate 
  
  
  
  
  
Residential 1-4 family$5,534
 0.28
 48.2
 $6,068
 0.33
 49.2
Commercial real estate5,059
 1.15
 10.6
 2,965
 0.79
 9.9
Home equity line of credit5,229
 0.71
 17.8
 4,493
 0.71
 16.6
Residential land1,817
 11.23
 0.4
 4,275
 16.56
 0.7
Commercial construction2,397
 4.60
 1.3
 2,023
 4.60
 1.2
Residential construction19
 0.15
 0.3
 9
 0.15
 0.2
Total real estate20,055
 0.61
 78.6
 19,833
 0.67
 77.8
Commercial15,803
 2.02
 18.8
 15,931
 2.21
 19.0
Consumer2,367
 2.18
 2.6
 4,019
 3.32
 3.2
 38,225
 0.92
 100.0
 39,783
 1.05
 100.0
Unallocated1,891
  
  
 2,202
  
  
Total allowance for loan losses$40,116
  
  
 $41,985
  
  
In 2016, ASB's allowance for loan losses increased by $5.5 million primarily due to growth in the commercial real estate and consumer loan portfolios and increases in reserves for the commercial real estate and unsecured consumer loan portfolios. Total delinquencies of $23.1 million at December 31, 2016 was $3.0 million lower than total delinquencies of $26.1 million at December 31, 2015 primarily due to the movement of $6 million of residential loans to held-for-sale. The ratio of delinquent loans to total loans decreased from 0.57% of total loans outstanding at December 31, 2015 to 0.49% of total loans outstanding at December 31, 2016. Net charge-offs for 2016 were $11.3 million, an increase of $9.4 million compared to $1.9 million for 2015 primarily due to charge-offs of specific commercial loans and an increase in consumer loan charge-offs as a result of the strategic expansion of ASB's unsecured consumer loan product offering with risk-based pricing. ASB's provision for loan losses was $16.8 million for 2016, an increase of $10.5 million compared to the provision for loan losses of $6.3 million for 2015. The increase in provision for loan losses was driven by growth in the commercial real estate and consumer loan portfolios as well as specific reserves for a few commercial loans.
In 2015, ASB's allowance for loan losses increased by $4.4 million primarily due to growth in the commercial real estate loan portfolio ($159 million or 29.8% growth in outstanding balances) and increases in reserves for commercial loans. Overall loan quality remained strong as total delinquencies of $26.1 million at December 31, 2015 was a slight increase of $0.6 million


compared to total delinquencies of $25.5 million at December 31, 2014 primarily due to an increase in delinquent consumer loans. The ratio of delinquent loans to total loans decreased slightly from 0.58% of total loans outstanding at December 31, 2014 to 0.57% of total loans outstanding at December 31, 2015. Net charge-offs for 2015 were $1.9 million, an increase of $1.3 million compared to $0.6 million for 2014 primarily due to an increase in consumer loan charge-offs as result of the strategic expansion of ASB's unsecured consumer loan product offering with risk-based pricing. ASB's provision for loan losses was $6.3 million for 2015, an increase of $0.2 million compared to the provision for loan losses of $6.1 million for 2014.
In 2014, ASB’s allowance for loan losses increased by $5.5 million primarily due to growth in the loan portfolio ($282 million or 6.8% growth in outstanding balances) and increases in the loss rates of loan portfolios with higher risk such as commercial real estate and unsecured personal loans. Overall loan quality continued to improve as total delinquencies of $25.5 million at December 31, 2014 was a decrease of $8.3 million compared to total delinquencies of $33.8 million at December 31, 2013 due to a decrease in delinquent commercial, commercial real estate and residential land loans. The ratio of delinquent loans to total loans decreased from 0.81% of total loans outstanding at December 31, 2013 to 0.58% of total loans outstanding at December 31, 2014. Net charge-offs for 2014 were $0.6 million, a decrease of $2.8 million compared to $3.4 million for 2013 primarily due to a decrease in commercial, HELOC and residential land loan charge-offs as a result of the strong economic growth in Hawaii and partially due to the sale of the credit card portfolio in 2013. ASB’s provision for loan losses was $6.1 million for 2014, an increase of $4.6 million compared to provision for loan losses of $1.5 million for 2013 primarily due to growth in the loan portfolio.
In 2013, ASB’s allowance for loan losses decreased by $1.9 million, despite the increase in the loan portfolios (9.7% growth or $368.1 million increase in outstanding balances) primarily due to the release of reserves as a result of repayments in the higher risk purchased loan and residential land loan portfolios and the sale of the credit card portfolio. Overall loan quality has improved as delinquencies decreased significantly in 2013, primarily in the residential 1-4 family, residential land and commercial real estate portfolios. Net loan charge-offs for 2013 were $3.4 million compared to $8.8 million in 2012 as the Hawaii economy in general and the housing market in particular continued to improve. ASB’s provision for loan losses was $1.5 million in 2013, compared to $12.9 million in 2012.
Investment activities.  Currently, ASB’s investment portfolio consists of U.S. Treasury and federal agency obligations, mortgage-related securities, stock of the FHLB of Des Moines and a mortgage revenue bond. ASB owns mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA). The weighted-average yield on investments during 2016, 2015 and 2014 was 1.99%, 2.06% and 1.91%, respectively. ASB did not maintain a portfolio of securities held for trading during 2016, 2015 and 2014.
As of December 31, 2016, 2015 and 2014, ASB’s stock in FHLB amounted to $11 million, $11 million and $69 million, respectively. The amount that ASB is required to invest in FHLB stock is determined by FHLB requirements. With the merger of the FHLB of Seattle and the FHLB of Des Moines in the second quarter of 2015, all of ASB's excess stock was repurchased. The amount of stock repurchased in 2016, 2015 and 2014 was nil, $59 million and $23 million, respectively. See “Stock in FHLB” in HEI’s MD&A. Also, see “Regulation–Federal Home Loan Bank System” below.
ASB does not have any exposure to securities backed by subprime mortgages. See “Investment securities” in Note 5 of the Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.
The following table summarizes the current amortized cost of ASB’s investment portfolio (excluding stock of the FHLB of Des Moines, which has no contractual maturity) and weighted average yields as of December 31, 2016. Mortgage-related securities are shown separately because they are typically paid in monthly installments over a number of years.
 
In 1 year
or less
 
After 1 year
through 5 years
 
After 5 years
through 10 years
 
After
10 years
 Mortgage-Related Securities 
Total1
(dollars in millions) 
  
  
  
  
  
U.S. Treasury and federal agency obligations$10
 $77
 $82
 $25
 $—
 $194
Mortgage-related securities - FNMA, FHLMC and GNMA—
 —
 —
 —
 909
 909
Mortgage revenue bond2
—
 —
 —
 15
 —
 15
 $10
 $77
 $82
 $40
 $909
 $1,118
Weighted average yield1.13% 1.78% 2.32% 2.77% 1.99% 2.02%
1
As of December 31, 2016, no investment exceeded 10% of shareholder's equity.
2
Weighted average yield on the mortgage revenue bond is computed on a tax equivalent basis using a federal statutory tax rate of 35%.




Deposits and other sources of funds.
General. Deposits traditionally have beencontinue to be the principallargest source of ASB’s funds for ASB for use in lending, meeting liquidity requirements and making investments. ASB also derives funds frominvestments, and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the receiptcurrent environment due to competition for deposits and the low level of short-term interest and principal on outstanding loans receivable and mortgage-related securities, borrowings from the FHLB of Des Moines, securities sold under agreements to repurchase and other sources.rates. ASB borrows on a short-term basis to compensate for seasonal or other reductions in deposit flows. ASB also may borrow on a longer-term basis to support expanded lending or investment activities. Advances from the FHLB of Des Moines and securities sold under agreements to repurchase continue to be a sourceadditional sources of funds, but they are a higher cost source than deposits.
Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow or outflow, measured as the year-over-year difference in year-end deposits, was an inflow of $524 million in 2016, compared to an inflow of $402 million in 2015 and $251 million in 2014.
The following table presents the average deposits and average rates by type of deposit. Average balances have been calculated using the average daily balances.
Years ended December 312016 2015 2014
(dollars in thousands)
Average
balance

 
% of
total
deposits

 
Weighted
average
rate %

 
Average
balance

 
% of
total
deposits

 
Weighted
average
rate %

 
Average
balance

 
% of
total
deposits

 
Weighted
average
rate %

Interest-bearing deposit liabilities                
Savings$2,117,186
 57.5% 0.07% $1,980,151
 58.6% 0.06% $1,879,373
 58.3% 0.06%
Checking839,339
 22.8
 0.02
 782,811
 23.2
 0.02
 738,651
 22.9
 0.02
Money market160,700
 4.4
 0.13
 164,568
 4.9
 0.12
 171,889
 5.3
 0.12
Certificate565,135
 15.3
 0.95
 449,179
 13.3
 0.83
 434,934
 13.5
 0.83
Total interest-bearing deposit liabilities$3,682,360
 100.0% 0.19% $3,376,709
 100.0% 0.16% $3,224,847
 100.0% 0.16%
Total noninterest-bearing demand deposit liabilities1,559,132
     1,426,962
     1,285,964
    
Total deposit liabilities$5,241,492
     $4,803,671
     $4,510,811
    
The following table presents the amount of time certificates of deposit of $100,000 or more, segregated by time remaining until maturity:
(in thousands)Amount
Three months or less$99,452
Greater than three months through six months54,795
Greater than six months through twelve months37,888
Greater than twelve months136,002
 $328,137
Deposit-insurance premiums and regulatory developments.  For a discussion of changes to the deposit insurance system, premiums and Financing Corporation (FICO) assessments, see “Regulation–Deposit insurance coverage” below.
Other borrowings. See “Other borrowings” in Note 5 of the Consolidated Financial Statements. ASB may obtain advances from the FHLB of Des Moines provided that certain standards related to creditworthiness have been met. Advances are collateralized by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Des Moines, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Des Moines or at an approved third-party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Des Moines.
The decrease in other borrowings in 2016 was due to a decrease in public and business repurchase agreements and the maturity of a repurchase agreement with a broker/dealer. The increase in other borrowings in 2015 compared to 2014 was due to an increase in public repurchase agreements. The increase in other borrowings in 2014 compared to 2013 was due to an increase in repurchase agreements with the State of Hawaii. The increase in other borrowings in 2013 compared to 2012 was due to $50 million of additional FHLB advances taken out in 2013.


Competition. See “Bank—Executive overview and strategy” and “Bank—Certain factors that may affect future results and financial condition—Competition” in HEI’s MD&A.
The banking industry in Hawaii is highly competitive. At December 31, 2016,2019, there were 8 financial institutions insured by the FDIC headquartered in the State of Hawaii. While ASB is one of the largest financial institutions in Hawaii, based on total assets, ASB faces vigorous competition for deposits and loans from two larger banking institutions based in Hawaii and from smaller institutions that heavily promote their services in niche areas, such as providing financial services to small and medium-sized businesses, as well as national financial services organizations. Competition for loans and deposits comes primarily from other savings institutions, commercial banks, credit unions, securities brokerage firms, money market and mutual funds and other investment alternatives. ASB faces additional competition in seeking deposit funds from various types of corporate and government borrowers, including insurance companies. Competition for origination of mortgage loans comes primarily from mortgage banking and brokerage firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts. See also “Bank—Executive overview and strategy” in HEI’s MD&A.


To remain competitive and continue building core franchise value, ASB continues to develop and introduce new products and services to meet the needs of its consumer and commercial customers. Additionally, the banking industry is constantly changing and ASB is making the investment in its people and technology necessary to adapt and remain competitive. ASB competes for deposits primarily on the basis of the variety of types of savings and checking accounts it offers at competitive rates, the quality of the services it provides, the convenience of its branch locations and business hours, and convenient automated teller machines.
The primary factors in ASB’s competition for mortgage and other loans are the competitive interest rates and loan origination fees it charges, the wide variety of loan programs it offers and the quality and efficiency of the services it provides to borrowers and the business community. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.
The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation, other non-branch channels such as online and mobile banking and perceptions of the institution’s financial soundness and safety. To compete effectively, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch, convenient automated teller machines and an upgrade of ASB’s electronic banking platform. ASB also conducts advertising and promotional campaigns.
ASB has been diversifying its loan portfolio from single-family home mortgages to higher-spread, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for residential mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its consumer, commercial and commercial real estate loans.
Regulation.  ASB, a federally chartered savingssaving bank, is subject to examination and itscomprehensive regulation by the Department of Treasury, OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OCC. In addition, ASB’s holding companies are subject to the regulatory supervision of the FRB. See “HEI Consolidated–Regulation” above.
Capital requirements.  The OCC, ASB’s principal regulator, administers two sets of capital standards — minimum regulatory capital requirements and FRB, respectively, and in certain respects, the FDIC. See “HEI–Regulation” above and “Bank–Certain factors that may affect future results and financial condition–Regulation” in HEI’s MD&A. In addition, ASB must comply with FRB reserveprompt corrective action requirements.
Deposit insurance coverage. The Federal Deposit Insurance Act, as amended, and regulations promulgated by the FDIC governs insurance coverage of deposit accounts. In July 2010, the Dodd-Frank Act permanently raised the current standard maximum deposit insurance amount to $250,000. Generally, the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) is aggregated for purposes of applying the insurance limit.
See “Federal Deposit Insurance Corporation assessment” in Note 5 of the Consolidated Financial Statements for a discussion of FDIC deposit insurance assessment rates. FICO will continue to impose an assessment on average total assets minus average tangible equity to service the interest on FICO bond obligations.also has prompt corrective action capital requirements. As of December 31, 2016, ASB’s annual FICO assessment was 0.56 cents per $100 of average total assets minus average tangible equity.
Federal thrift charter.  See “Bank–Certain factors that may affect future results and financial condition—Regulation—Unitary savings and loan holding company” in HEI’s MD&A, including the discussion of previously proposed legislation that would abolish the charter.
Recent legislation and issuances. See “Bank–Legislation and regulation” in HEI’s MD&A.
Capital requirements.  The OCC has set four capital requirements for financial institutions. As of December 31, 2016,2019, ASB was in compliance with allOCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of theOCC prompt corrective action regulations and FDIC capital regulations, as follows:
ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2019 with a Tier 1 leverage ratio of 8.6% (compared to a 4.0% requirement)9.1% (4.0%), a common equity Tier 1 capital ratio of 12.2% (compared to a 4.5% requirement)13.2% (4.5%), a Tier 1 capital ratio of 12.2% (compared to a 6.0% requirement)13.2% (6.0%) and a total capital ratio of 13.4% (compared14.3% (8.0%).
ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2019 with a 8.0% requirement)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 purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (typically acquired by foreclosure). The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to HEI (through ASB Hawaii) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI currently could be required to contribute to ASB up to an additional $28.3 million of capital, if necessary, to maintain ASB’s capital position.
In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, a financial institution must hold a buffer of common equity tier 1 capital above its minimum capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer) which is phased-in through 2019. As of December 31, 2016,2019, ASB met the applicable capital requirements, including the fully phased-in capital conservation buffer.
See “Bank-Legislation“Bank—Legislation and regulation” in HEI’s MD&A for the final capital rules under the Basel III regulatory capital framework.


Examinations.  ASB is subject to periodic “safety and soundness” examinations and other examinations by the OCC. In conducting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OCC’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as an officer, director, employee, attorney or auditor, except as provided by regulation. The OCC also regularly examines ASB’s information technology practices and its performance under Community Reinvestment Act measurement criteria.
The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders).
Deposit insurance coverage.  The Federal Deposit Insurance Act, as amended, and regulations promulgated by the FDIC, govern insurance coverage of deposit accounts. In July 2010, the Dodd-Frank Act permanently raised the current standard maximum deposit insurance amount to $250,000. Generally, the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) is aggregated for purposes of applying the insurance limit.
See “Federal Deposit Insurance Corporation assessment” in Note 4 of the Consolidated Financial Statements for a discussion of FDIC deposit insurance assessment rates.
Recent legislation and issuances. See “Bank–Legislation and regulation” in HEI’s MD&A.
Affiliate transactions.  Significant restrictions apply to certain transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. For example, ASB is prohibited from making any loan or other extension of credit to an entity affiliated with ASB unless the affiliate is engaged exclusively in activities which the FRB has determined to be permissible for bank holding companies. There are also various other restrictions which apply to certain transactions between


ASB and certain executive officers, directors and insiders of ASB. ASB is also barred from making a purchase of or any investment in securities issued by an affiliate, other than with respect to shares of a subsidiary of ASB.
Financial Derivativesderivatives and Interest Rate Riskinterest rate risk. ASB is subject to OCC rules relating to derivatives activities, such as interest rate swaps, interest rate lock commitments and forward commitments. See “Derivative financial instruments” in Note 54 of the Consolidated Financial Statements for a description of interest rate lock commitments and forward commitments used by ASB. Currently ASB does not use interest rate swaps to manage interest rate risk (IRR), but may do so in the future. Generally speaking, the OCC rules permit financial institutions to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The rules require ASB to have certain internal procedures for handling financial derivative transactions, including involvement of the ASB Board of Directors.
With the transfer of the regulatory jurisdiction from the OTS to the OCC, ASB has adopted terminology and IRR assessment, measurement and management practices consistent with OCC guidelines. Management believes ASB’s IRR processes are aligned with the Interagency Advisory on Interest Rate Risk Management and appropriate with earnings and capital levels, balance sheet complexity, business model and risk tolerance.
Liquidity.  OCC regulations require ASB to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are customer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s principal sources of borrowings are advances from the FHLB of Des Moines and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB of Des Moines to borrow an amount of up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB of Des Moines stock. As of December 31, 2016,2019, ASB’s unused FHLB of Des Moines borrowing capacity was approximately $1.8$2.3 billion. ASB utilizes growth in deposits, advances from the FHLB of Des Moines and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. As of December 31, 2016,2019, ASB had loan commitments, undisbursed loan funds and unused lines and letters of credit of $1.8$1.9 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
Supervision.  Pursuant to the  The Federal Deposit Insurance Corporation Improvement Act of 1991 (the FDICIA), the federal banking agencies promulgated regulations which apply to the operations of ASB and its holding companies. Such regulations address, for example, standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders.
Prompt corrective action. The FDICIA establishes a statutory framework that is triggered by the capital level of a financial institution and subjects it to progressively more stringent


restrictions and supervision as capital levels decline. The OCC rules implement the system of prompt corrective action. In particular, the rules define the relevant capital measures for the categories of “well capitalized”,capitalized,” “adequately capitalized”, “undercapitalized”,capitalized,” “undercapitalized,” “significantly undercapitalized” and “critically undercapitalized.”
A financial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OCC determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the Deposit Insurance Fund. A financial institution that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OCC and the FDIC concur that other action would be more appropriate. As of December 31, 2016,2019, ASB was “well-capitalized.”
Interest rates. FDIC regulations restrict the ability of financial institutions that are undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2016,2019, ASB was “well capitalized” and thus not subject to these interest rate restrictions.
Qualified thrift lender test. InASB is a “qualified thrift lender” (QTL) under its federal thrift charter and, in order to satisfy the QTL test,maintain this status, ASB mustis required to maintain at least 65% of its assets in “qualified thrift investments”investments,” measured on a monthly average basis in 9 out of the previous 12 months. Failuremonths, which include housing-related loans (including mortgage-backed securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Institutions that fail to satisfy themaintain QTL test wouldstatus are subject ASB to various penalties, including limitations on its activities, and would also bring into operation restrictions ontheir activities. In ASB’s case, the activities that may be engaged in byof HEI, ASB Hawaii and theirHEI’s other subsidiaries whichwould also be subject to restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. AtAs of December 31, 2019, and at all times during 2016,2019, ASB was in compliance with the QTL test. See “HEI Consolidated–Regulation.”a qualified thrift lender.
Federal Home Loan Bank System. ASB is a member of the FHLB System, which consists of 11 regional FHLBs, and ASB’s regional bank is the FHLB of Des Moines. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have served as the central liquidity facilities for savings associations and sources of long-term funds for financing housing. At such time as an advance is made to ASB or renewed, it must be collateralized by collateral from one of the following categories: (1) fully disbursed, whole first mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related collateral that has a readily ascertainable value and with respect to which a


security interest can be perfected. The aggregate amount of outstanding advances collateralized by such other real estate-related collateral may not exceed 300% of ASB’s capital.
As mandated by the Gramm Act, the Federal Housing Finance Board (Board) regulations require each FHLB to maintain three capital ratios: (1) risk-based capital greater than or equal to the sum of its credit, market and operational risk capital requirements; (2) a minimum capital-to-assets ratio of 4%; and (3) a minimum total capital leverage ratio of 5% of total assets. At September 30, 2016, the FHLB of Des Moines was in compliance with all three of the regulatory capital requirements. ASB'sASB’s required holding in the stock of the FHLB is both membership and activity-based. Membership is based on a percentage of total assets (0.12%) while the portion related to activity is based on a percentage of outstanding activity, mainly advances (4%). As of December 31, 2016,2019, ASB was required and owned capital stock in the FHLB of Des Moines in the amount of $11$8.4 million. See “Stock in FHLB” in HEI’s MD&A section for recent developments regarding the FHLB of Des Moines.
Community Reinvestment. The Community Reinvestment Act (CRA) requires financial institutions to help meet the credit needs of their communities, including low- and moderate-income areas, consistent with safe and sound lending practices. The OCC will consider ASB’s CRA record in evaluating an application for a new deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition of an interest in another bank. ASB currently holds an “outstanding”a “satisfactory” CRA rating.
Other laws. ASB is subject to federal and state consumer protection laws which affect deposit and lending activities, such as the Truth in Lending Act (TILA), the Truth in Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act (RESPA), the Home Mortgage Disclosure Act and several federal and state financial privacy acts intended to protect consumers’ personal information and prevent identity theft, such as the Gramm Act and the Fair and Accurate Transactions Act. ASB is also subject to federal laws regulating certain of its lending practices, such as the Flood Disaster Protection Act, and laws requiring reports to regulators of certain customer transactions, such as the Currency and Foreign Transactions Reporting Act and the International Money Laundering Abatement and Anti-Terrorist Financing Act. ASB’s relationship with LPL Financial LLPCetera Investment Services LLC and Cetera Investment Advisers LLC is also governed by regulations adopted by the FRB under the Gramm Act, which regulate “networking” relationships under which a financial institution refers customers to a broker-dealer for securities services and employees of the financial institution are permitted to receive a nominal fee for the referrals. These laws may provide for substantial penalties in the event of noncompliance.
The TILA-RESPA Integrated Disclosure rule became effective on October 3, 2015. The rule requires easier-to-use mortgage disclosure forms that clearly lay out the terms of a mortgage for a homebuyer. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd Frank Act) mandated that the Bureau of Consumer Financial Protection (the Bureau) establish a single disclosure scheme for use by lenders and creditors in complying with the disclosure requirements of both RESPA and TILA. The Dodd-Frank Act amended RESPA to require that the Bureau publish a single, integrated disclosure for mortgage loan transactions. The first new form - the Loan Estimate - is designed to provide disclosures that will be helpful to consumers in understanding the key features, costs, and risks of the mortgage for which they are applying. This form is provided to consumers within three business days after they submit a loan application. The second form - the Closing Disclosure - is designed to provide disclosures that will be helpful to consumers in understanding all of the costs of the transaction. This form is provided to consumers three business days before they close on the loan. The rule applies to most closed-end consumer mortgages.
ASB believes that it currently is in compliance with these laws and regulations in all material respects.
Proposed legislation. See the discussion of proposed legislation in “Bank–Legislation and regulation” in HEI’s MD&A.
Environmental regulation.  ASB may be subject to the provisions of Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), Hawaii Environmental Response Law (ERL) and regulations promulgated thereunder, which impose liability for environmental cleanup costs on certain categories of responsible parties. CERCLA and ERL exempt persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in the management of the facility. Although there may be some risk of liability for ASB for environmental cleanup costs in the event ASB forecloses on, and becomes the owner of, property with environmental problems, the Company believes the risk is not as great for ASB as it may be for other depository institutions that have a larger portfolio of commercial loans.


Additional information. For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of theHEI’s Consolidated Financial Statements, including Note 4 thereto.
Properties. ASB owns or leases several office buildings in downtown Honolulu owns land and an operations center in the Mililani Technology Park on the island of Oahu and owns land on which a number of its branches are located.


The following table sets forth the number of bank branches owned and leased by ASB by island:
Number of branchesNumber of branches
December 31, 2016Owned Leased 
Total1
December 31, 2019Owned Leased Total
Oahu7
 29
 36
9
 25
 34
Maui3
 4
 7
2
 4
 6
Hawaii3
 2
 5
3
 2
 5
Kauai2
 1
 3
2
 1
 3
Molokai—
 1
 1
—
 1
 1
15
 37
 52
16
 33
 49
1In January 2017, a branch on the island of Maui was closed, reducing the total number of Maui branches to 6 and the total branch count to 51.
During 2016, three branches were closed on Oahu and one branch on Kauai. ASB had other branches in close proximity to the closed branches and customer accounts were consolidated into those branches.
As of December 31, 2016,2019, the net book value (NBV) of branches and office facilities was $68$182 million ($62175 million represents the NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements). As of December 31, 2018, the NBV of branches and office facilities of $190 million ($184 million represents the NBV of the land and improvements for the branches and office facilities owned by ASB and $6 million represents the NBV of ASB’s leasehold improvements) compared to the NBV of branches and office facilities of $68 million ($61 million NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements) as of December 31, 2015.. The leases expire on various dates through February 2033,December 2040, but many of the leases have extension provisions.
As of December 31, 2016,2019, ASB owned 114111 automated teller machines.
Construction of New Headquarters. In the first quarter of 2017,2019, ASB will begin construction ofmoved into its new headquarters, which it owns, in downtown Honolulu. The project will cost an estimated $100 million and is expected to take twenty months to complete. The headquarters will havehas approximately 370,000 square feet of space on eleven floors and consolidateconsolidated five separate offices into one building where approximately 600 employees will work.are working. In fourth quarter of 2019, ASB sold two office facilities as a result of the consolidation of employees into the new headquarters and recognized a pretax gain of $10.8 million.

16


ITEM 1A.RISK FACTORS
The businesses of HEI and its subsidiaries involve numerous risks which, if realized, could have a material and adverse effect on the Company’s financial statements. For additional information for certain risk factors enumerated below and other risks of the Company and its operations, see “Cautionary Note Regarding Forward-Looking Statements” above and HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk”,Risk,” the Notes to the Consolidated Financial Statements, Hawaiian Electric’s MD&A and Hawaiian Electric’s “Quantitative and Qualitative Disclosures About Market Risk.”
Holding Companycompany and Company-Wide Risks.company-wide risks.
HEI is a holding company that derives its income from its operating subsidiaries and depends on the ability of those subsidiaries to pay dividends or make other distributions to HEI and on its own ability to raise capital. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s cash flows and consequent ability to service its obligations and pay dividends on its common stock is dependent upon its receipt of dividends or other distributions from its operating subsidiaries and its ability to issue common stock or other equity securities and to incur additional debt. The ability of HEI’s subsidiaries to pay dividends or make other distributions to HEI, in turn, is subject to the risks associated with their operations and to contractual and regulatory restrictions, including:
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, 2016)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 to the OCCOCC’s and FRB'sFRB’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.
The Company, and its credit rating, is subject to risks associated with the Hawaii economy (in the aggregate and on an individual island basis), volatile U.S. capital markets and changes in the interest rate and credit market environment that have and/or could result in


higher retirement benefit plan funding requirements, declines in ASB’s interest rate margins and investment values, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money or issue securities. The two largest components of Hawaii’s economy are tourism and the federal government (including the military). Because the core businesses of HEI’s subsidiaries are providing local public electric utility services (through Hawaiian Electric and its subsidiaries) and banking services (through ASB) in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates on the construction and real estate industries and by the impact of world conditions (e.g., U.S. withdrawal of troops from Afghanistan) on federal government spending in Hawaii. For example,Hawaii, which can be affected by world conditions and, from time to time, the turmoil in the financial markets and declines in the national and global economies had a negative effect onexpiration of federal government appropriations bills. In addition, the Hawaii economy in 2009. In 2009, declines in the Hawaii,could be directly or indirectly affected by implications and potential impacts of U.S. and Asian economiesforeign 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 pandemics, or other crisis; the effects of changes that have or may occur in part ledU.S. policy, such as with respect to declines in HEI's share price, an increase in uncollected billingsimmigration and trade).
The recent outbreak of the Utilities, higher delinquenciescoronavirus, COVID-19, first identified in ASB’s loan portfolio, declinesWuhan, Hubei Province, China, has the potential to impact economic conditions in Hawaii, for example, through a reduction of tourism and business travel to Hawaii. Further, a prolonged outbreak could potentially impact the Company's pension plan asset valuesability of the Company’s customers, contractors, suppliers, IPPs, and other adverse effectsbusiness partners to perform or fulfill their obligations, which could adversely affect the Company’s businesses. For instance, restrictions on business activities due to COVID-19 may disrupt the global renewable energy supply chain that relies on Chinese manufacturing capacity for key components (such as solar modules, inverters, wind turbine components) creating project delays or material price increases for Hawaii renewable projects and procurement processes, which could potentially jeopardize the Company’s ability to achieve its RPS goals. While the Company has not been materially impacted by COVID-19 to date, the extent of the outbreak and its future impact on the Company’s businesses and its business partners is uncertain and cannot be reasonably estimated at this time.



HEI’s businesses.
If Fitch, Moody's or S&P were to downgrade HEI’s orand Hawaiian Electric’s long-term debtsecurities ratings becauseonly reflect the view, at the time the ratings are issued, of the applicable rating agency. There is no assurance that any such credit rating will remain in effect for any given period of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances, such as current, past adverseor future effects or if future events were to adversely affectso warrant. Any such lowering, suspension or withdrawal of any rating may have an adverse effect on the availability of capital to the Company or the market price or marketability of HEI’s and/or Hawaiian Electric’s securities, which could increase the cost of capital of HEI and Hawaiian Electric, and such increased costs, including interest charges, under HEI’s and/or Hawaiian Electric’s ability to borrowdebt securities and raise capital could be constrained and their future borrowing costscredit facilities, would likely increase with resultingresult in reductions in HEI’s consolidated net income in future periods. Further, if HEI’s or Hawaiian Electric’s commercial paper ratings were to be downgraded, HEI and Hawaiian Electric might not be able to sell commercial paper and might be required to draw on more expensive bank lines of credit or to defer capital or other expenditures. Neither HEI nor Hawaiian Electric management can predict future rating agency actions or their effects on the future cost of capital of HEI or Hawaiian Electric. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust maintained for pension plans, and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obligations. The Utilities’ pension tracking mechanisms help moderate pension expense; however, the significant decline in 2008 in the value of the Company’s defined benefit pension plan assets resulted in a substantial gap between the projected benefit obligations under the plans and the value of plan assets, resulting in increases in funding requirements. The increases have moderated in recent years as investment performance has improved.
Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. HEI and the Utilities are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.
Interest rate risk also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in the fair values of those instruments, respectively. Disruptions in the credit markets, a liquidity crisis in the banking industry or increased levels of residential mortgage delinquencies and defaults may result in decreases in the fair value of ASB’s investment securities and an impairment that is other-than-temporary, requiring ASB to write down its investment securities. As of December 31, 2016,2019, ASB’s investment in U.S. Treasury, federal agency obligations, and mortgage-relatedmortgage-backed securities have an implicit guarantee from the U.S. government.
HEI and Hawaiian Electric and their subsidiaries may incur higher retirement benefits expenses and have and will likely continue to recognize substantial liabilities for retirement benefits. Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including, but not limited to, the performance of the U.S. equity markets, trends in interest rates and health care costs, plan amendments, mortality improvements, new laws relating to pension funding and changes in accounting principles. For the Utilities, however, retirement benefits expenses, as adjusted by the pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, have been an allowable expense for rate-making purposes.
The Company is subject to the risks associated with the geographic concentration of its businesses and current lack of interconnections that could result in service interruptions at the Utilities or higher default rates on loans held by ASB. The business of the Utilities is concentrated on the individual islands they serve in the State of Hawaii. Their operations are more vulnerable to service interruptions than are many U.S. mainland utilities because none of the systems of the Utilities are interconnected with the systems on the other islands they serve. Because of this lack of interconnections, it is necessary to maintain higher generation reserve margins than are typical for U.S. mainland utilities to help ensure reliable service. Service interruptions, including in particular extended interruptions that could result from a natural disaster or terrorist activity, could adversely impact the KWH salesrevenues and costs of some or all of the Utilities.


Substantially all of ASB’s consumer loan customers are Hawaii residents. A significant portion of the commercial loan customers are located in Hawaii. While a majority of customers are on Oahu, ASB also has customers on the neighbor islands (whose economies have been weaker than Oahu during the recentlast economic downturn). Substantially all of the real estate underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a greater risk of default than other comparable assets held by financial institutions with other geographic concentrations in the event of


adverse economic, political or business developments or natural disasters affecting Hawaii and affect the ability of ASB’s customers to make payments of principal and interest on their loans.
Increasing competition and technological advances could cause HEI’s businesses to lose customers or render their operations obsolete. The banking industry in Hawaii, and certain aspects of the electric utility industry, are competitive. The success of HEI’s subsidiaries in meeting competition and responding to technological advances will continue to have a direct impact on HEI’s consolidated financial performance. For example:
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. SignificantNew 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 setsets 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.
New technological developments, such as the commercial development of energy storage and microgrids, may render the operations of the Utilities less competitive or outdated.
The Company may be subject to information technology and operational system failures, network disruptions, cyber attacks and breaches in data security that could adversely affect its businesses and reputation. The Company and its subsidiaries rely on information technology systems, some of which are managed or hosted by third party service providers, to manage its business data, communications, and other business processes. Such information technology systems may be vulnerable to cyberattacks or other security incidents, which could result in unauthorized access to confidential data or disruptions to operations. If the Company is unable to prevent or adequately respond to and resolve an incident, it may have a material impact on the Company’s operations or business reputation.
Utilities. The Utilities rely on networks,evolving and increasingly complex operational and information systems, networks and other technologies, includingwhich are interconnected with the Internetsystems and third-party hosted servicesnetwork infrastructure owned by third parties to support a variety of business processes and activities, including procurement and supply chain, invoicing and collection of payments, customer relationship management, human resource management, the acquisition, generation and delivery of electrical service to customers, and to process financial information and results of operations for internal reporting purposes and to comply with regulatory financial reporting and legal and tax requirements. The Utilities use their systems and infrastructure to create, collect, store, and process sensitive information, including personal information regarding customers, employees and their dependents, retirees, and other individuals. Despite the Utilities security measures, all of their systems are vulnerable to disability, failures or unauthorized access caused by natural disasters, cybersecurity incidents, security breaches, user error, unintentional defects created by system changes, military or terrorist actions, power or communication failures or similar events. Any such failure could have a material adverse impact on the Utilities’ ability to process transactions and provide service, as well the Utilities’ financial condition and results of operations. Further, a data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject the Utilities to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. A data breach could also reduce the value of proprietary information, and harm the reputation of the Utilities.
As noted by the U.S. Department of Homeland Security, the utility industry is continuing to experience an increase in the frequency and sophistication of cybersecurity incidents. The Utilities’ systems have been, and will likely continue to be, a target of attacks. Further, the Utilities’ operational networks may be subject to new cybersecurity risks due to modernizing and interconnecting existing infrastructure with new technologies and control systems, including those owned by third parties. Although the Utilities have not experienced a material cybersecurity breach to date, such incidents may occur and may have a material adverse effect on the Utilities and the Company in the future. In order to address cybersecurity risks to their information systems, the Utilities maintain security measures designed to protect their information technology systems, network infrastructure and other assets. The Utilities actively monitor developments in the area of cybersecurity and are involved in various related government and industry groups, and brief the Company’s Board quarterly on relevant cybersecurity issues. Although the Utilities continue to make investments in their cybersecurity program, including personnel, technologies, cyber insurance and training of Utilities personnel, there can be no assurance that these systems or their expected functionality will be implemented, maintained, or expanded effectively; nor can security measures completely eliminate the possibility of a


cybersecurity breach. The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates. If the Utilities’ cybersecurity measures were to be breached, the Utilities could suffer financial loss, business disruptions, liability to customers, regulatory intervention or damage to their reputation.
Due to the size, scope and complexity of the Utilities’ business, the development and maintenance of information technology systems to process and track information is critical and challenging. The Utilities often rely on third-party vendors to host, maintain, modify, and update its systems and these third-party vendors could cease to exist, fail to establish adequate processes to protect the Utilities systems and information, or experience internal or external security incidents. In addition, the Utilities are pursuing complex business transformation initiatives, which include establishing common processes across Hawaiian Electric, Hawaii Electric Light and Maui Electric and the upgrade or replacement of existing systems. Significant system changes increase the risk of system interruptions. Although the Utilities maintain change managementcontrol processes to mitigate this risk, system interruptions may occur. Further, delay or failure to complete the integration of information systems and processes may result in delays in regulatory cost recovery, increased service interruptions of aging legacy systems, or the failure to realize the cost savings anticipated to be derived from these initiatives.
As notedIn the fourth quarter of 2018, the Utilities’ new ERP/EAM system was placed into service. One of the conditions imposed by the U.S. DepartmentPUC’s approval of Homeland Security, the utility industrysystem is continuing to experience an increasethe requirement that the Utilities achieve cost savings consistent with a minimum of $246 million in the frequency and sophistication of cyber security incidents. The Utilities’ systems have been, and will likely continueERP/EAM project-related benefits to be a target of attacks. Althoughdelivered to customers over the system’s 12-year service life. If the Utilities haveare not experiencedable to achieve such minimum savings, the PUC could impose financial penalties, such as a material cyber security breach to date, such incidents may occur and mayreduction of revenue requirements that could have a material adverse effect on the Company in the future. In order to address cyber security risks to their information systems, the Utilities maintain security measures designed to protect their information technology systems, network infrastructure and other assets. The Utilities actively monitor developments in the area of cyber security and are involved in various related government and industry groups. Although the Utilities continue to make investments in their cyber security program, including personnel, technologies, cyber insurance and training of Utilities personnel, there can be no assurance that these systems or their expected functionality will be implemented, maintained, or expanded effectively; nor can security measures completely eliminate the possibility of a cyber security breach. Ifimpact the Utilities’ cyber security measures were to be breached, the Utilities could sufferand Company’s results of operations and financial loss, business disruptions, liability to customers, regulatory intervention or damage to their reputation.condition.


The Utilities are in the process of replacing their existing ERP system. Although the Utilities have in place measures, including redundant systems and recovery capabilities to mitigate system interruptions to their systems, until the new system is put into service the Utilities face elevated operational risk from reliance on old and no longer fully supported software, including the possibility of increased frequency, duration and impact of interruptions.
The Utilities have disaster recovery plans in place to protect their businesses from information technology service interruptions caused by natural disasters, security breaches, user error, unintentional defects created by system changes, military or terrorist actions, power or communication failures or similar events.interruptions. The disaster recovery plans, however, may not be successful in preventing the loss of customer data, service interruptions and disruptions to operations or damage to important facilities. If any of these systems fail to operate properly or becomes disabled and the Utilities’ disaster recovery plans do not effectively resolve the issues in a timely manner, the Utilities could suffer financial loss, business disruptions, liability to customers, regulatory intervention or damage to their reputations.reputations, any of which could have a material adverse effect on the Utilities’ and the Company’s financial condition and results of operations.
ASB. ASB is highly dependent on its ability to process, on a daily basis, a large number of transactions and relies heavily on communication and information systems, including those of third partythird-party vendors and other service providers. Communication and information system failures can result from a variety of risks including, but not limited to, events that are wholly or partially out of ASB’s control, such as communication line integrity, weather, terrorist acts, natural disasters, accidental disasters, unauthorized breaches of security systems, energy delivery systems, cyber-attackscyberattacks and other events.
ASB is under continuous threat of loss due to cyber-attacks,cyberattacks, especially as the BankASB continues to expand customer capabilities to utilize the Internet and other remote channels to transact business. Two of the most significant cyber-attackcyberattack risks that ASB faces are e-fraud and loss of sensitive customer data. Loss from e-fraud occurs when cybercriminals extract funds directly from customers’ or ASB'sASB’s accounts using fraudulent schemes that may include Internet-based funds transfers. The BankASB has been subject to e-fraud incidents historically. Loss of sensitive customer data are attempts to steal sensitive customer data, such as account numbers and social security numbers, through unauthorized access to our computer systems, including computer hacking. Such attacks are less frequent, but could present significant reputational, legal and regulatory costs if successful. Intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls have been put in place to detect and prevent cyber-attackscyberattacks or information system breaches. A disaster recovery plan has been developed in the event of a natural disaster, security breach, military or terrorist action, power or communication failure or similar event. The disaster recovery plan, however, may not be successful in preventing the loss of customer data, service interruptions, disruptions to operations or damage to important facilities. Although ASB devotes significant resources to maintain and regularly upgrade its systems and processes that are designed to protect the security of the Bank’sASB’s computer systems, software, networks and other technology assets and the confidentiality, integrity and availability of information belonging to the BankASB and its customers, there can be no assurance that such failures, interruptions or security breaches will not occur or, if they do occur, that they will be adequately corrected by ASB or its vendors.
To date, ASB has not experienced any material losses relating to cyber-attacks or other information security breaches, but there can be no assurance that the Bank will not suffer such losses in the future. If any of these systems fail to operate properly or become disabled even for a brief period of time, ASB could suffer financial loss, business disruptions, liability to customers, regulatory intervention or damage to its reputation, any of which could have a material adverse effect on ASB’s and the Company’s financial condition and results of operations.
HEI’s businesses could suffer losses that are uninsured due to a lack of affordable insurance coverage, unavailability of insurance coverage or limitations on the insurance coverage the Company does have. In the ordinary course of business, HEI


and its subsidiaries purchase insurance coverages (e.g., property and liability coverages) to protect against loss of, or damage to, their properties and against claims made by third parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. CertainSome of the insurance hascoverages have substantial deductibles or has limits on the maximum amounts that may be recovered. For example,In common with other companies in its line of business, the Utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents), which have a replacement value roughly estimated at $7$8 billion, and are largely not insured against loss or damage because the amount of transmission and distribution system insurance availablecapacity is limited and the premiums are cost prohibitive. Similarly, the Utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the Utilities are not interconnected to other systems. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC weredid not to allow the affected Utilities to recover from ratepayers restoration costs and revenues lost from business interruption, the lost revenues and repair expenses could result in a significant decrease in HEI’s consolidated net income or in significant net losses for the affected periods.

ASB generally does not obtain credit enhancements, such as mortgagor bankruptcy insurance, but does require standard hazard and hurricane insurance and may require flood insurance for certain properties. ASB is subject to the risks of borrower defaults and bankruptcies, special hazard losses not covered by the required insurance and the insurance company’s inability to pay claims on existing policies.


Increased federal and state environmental regulation will require an increasing commitment of resources and funds and could result in construction delays or penalties and fines for non-compliance. HEI and its subsidiaries are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, hazardous substances, waste management, natural resources and health and safety, which regulate, among other matters, the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous and toxic wastes and substances. These laws and regulations could result in increased capital, operating, and other costs. HEI or its subsidiaries are currently involved in investigatory or remedial actions at current, former or third-party sites and there is no assurance that the Company will not incur material costs relating to these sites. In addition, compliance with these legal requirements requires the Utilities to commit significant resources and funds toward, among other things, environmental monitoring, installation of pollution control equipment and payment of emission fees. These laws and regulations, among other things, require that certain environmental permits be obtained in order to construct or operate certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expensecost of compliance. For example, emission and/or discharge limits may be tightened, more extensive permitting requirements may be imposed and additional substances may become regulated. In addition, significant regulatory uncertainty exists regarding the impact of federal or state greenhouse gas (GHG) emission limits and reductions.
If HEI or its subsidiaries fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in civil or criminal penalties and fines or the cessation of operations that could have a material adverse on the Company’s financial condition or results of operations.
Adverse tax rulings or developments or changes in tax legislation could result in significant increases in tax payments and/or expense.Governmental taxing authorities could challenge a tax return position taken by HEI or its subsidiaries and, if the taxing authorities prevail, HEI’s consolidated tax payments and/or expense, including applicable penalties and interest, could increase significantly. Additionally, changes in tax legislation or IRS interpretations could increase the Company’s tax burden and adversely affect the Company's financial position, results of operations, and cash flows.
The Company could be subject to the risk of uninsured losses in excess of its accruals for litigation matters. HEI and its subsidiaries are involved in routine litigation in the ordinary course of their businesses, most of which is covered by insurance (subject to policy limits and deductibles). However, other litigation may arise that is not routine or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation against HEI or its subsidiaries, even if vigorously defended, could result in costs of defense and judgment or settlement amounts not covered by insurance and in excess of reserves established in HEI’s consolidated financial statements.
Changes in accounting principles and estimates could affect the reported amounts of the Company’s assets and liabilities or revenues and expenses. HEI’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the U.S. Changes in accounting principles (including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards), or changes in the Company’s application of existing accounting principles, could materially affect the financial statement presentation of HEI’s or the Utilities’ consolidated results of operations and/or financial condition. Further, in preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.


Material estimates that are particularly susceptible to significant change include the amounts reported for electric utility revenues; allowance for loan losses; income taxes; investment securities, property, plant and equipment; regulatory assets and liabilities; derivatives; goodwill; pension and other postretirement benefit obligations; contingencies;and contingencies and litigation.
The Utilities'Utilities’ financial statements reflect assets and costs based on cost-based rate-making regulations. Continued accounting in this manner requires that certain criteria relating to the recoverability of such costs through rates be met. If events or circumstances should change sosuch that the criteria are no longer satisfied, the Utilities’ expect that their regulatory assets (amounting to $957$715 million as of December 31, 2016)2019), net of regulatory liabilities (amounting to $411$972 million as of December 31, 2016)2019), would be charged to the statement of income in the period of discontinuance.
Changes in accounting principles can also impact HEI’s consolidated financial statements. For example, if management determines that a PPA requires the consolidation of the IPP in the Consolidated Financial Statements,financial statements, the consolidation could have a material effect on Hawaiian Electric’s and HEI’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. Also, if management determines that a PPA requires the classification of the agreement as a capital lease, a material effect on HEI’s consolidated balance sheet may result, including the recognition of significant capital assets and lease obligations.
Changes in the accounting principles for expected credit losses were issued by the FASB to replace existing impairment models, including replacing an “incurred loss” model for loans with a “current expected credit loss” model based on historical experience, current conditions and reasonable and supportable forecasts. The changes also require enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. The Company plans towill adopt the new accounting principle


changes using an effective date of January 1, 2020, and is in the first quarterprocess of 2020 and has not yet determinedfinalizing its analysis. The Company estimates that the impactincrease in the allowance for credit losses as of the adoption. adoption date will be between $18 million to $22 million.
Electric utility risks.
The new impairment modelfollowing risks are generally specific to Hawaiian Electric, but could have a material adverse impact on ASB’s results of operations.
Standards on accounting for revenues from contracts with customers were issued by the FASB in 2014 and 2016. The core principle of the guidance in Accounting Standards Update (ASU) No. 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. As of December 31, 2016, the Company has identified its revenue streams from, and performance obligations to, customers, and is currently evaluating the impacts of the new guidance on its ability to recognize revenue for certain contracts where there is uncertainty regarding collection and accounting for contributions in aid of construction.  In addition, the Company will separately present sales from electricity and revenues from decoupling eithereffect on the financial statements or in the notes. The Company plans to adopt ASU No. 2014-09 (and subsequently issued revenue-related ASUs, as applicable) in the first quarter of 2018, but has not determined the method of adoption (full or modified retrospective application). The Company expects to present more revenue disclosures, but the full impact of adoption of ASU No. 2014-09 on itsCompany’s consolidated results of operations, financial condition and liquidity cannot be determined until its evaluation process is complete.liquidity.
Electric Utility Risks.
Actions of the PUC are outside the control of the Utilities and could result in inadequate or untimely rate increases, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects. The rates the Utilities are allowed to charge for their services and the timeliness of permitted rate increases are among the most important items influencing the Utilities’ results of operations, financial condition and liquidity. The PUC has broad discretion over the rates that the Utilities charge their customers. As part of the decoupling mechanism that the Utilities have implemented, each of the Utilities will file a rate case once every three years. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts that may be included in rate base, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on Hawaiian Electric’s consolidated results of operations, financial condition and liquidity.
To improve the timing and certainty of the recovery of their costs, the Utilities have proposed andand/or received approval of various cost recovery mechanisms including an ECRC (changed from ECAC in 2019), a PPAC, and pension and OPEB tracking mechanisms, as well as a decoupling mechanism, a PPAC,major project interim recovery (MPIR) adjustment mechanism, and a renewable energy infrastructure program (REIP) surcharge. A change in, or the elimination of, any of these cost recovery mechanisms, including in the current proceeding in which the PUC is examining the decoupling mechanism, could have a material adverse effect on the Utilities. See “Regulatory mechanisms” in Electric Utility’s Business.
On April 18, 2018, the PUC issued an order, instituting a proceeding to investigate performance-based regulation (PBR). The PUC’s implementation of performance-based ratemaking for the Utilities pursuant to Act 005, Session Laws 2018, could include, but is not limited to, the potential addition of new performance incentive mechanisms, the adoption of third-party proposals by the PUC in its implementation of PBR, and penalties for not achieving performance incentive goals. The impacts of the implementation of PBR cannot be predicted and these impacts could have a material adverse effect on the Utilities. See “Performance-based regulation proceeding” in Note 3 of the Consolidated Financial Statements.
The Utilities could be required to refund to their customers, with interest, revenues that have been or may be received under interim rate orders in their rate case proceedings integrated resource plan cost recovery dockets and other proceedings, if and to the extent they exceed the amounts allowed in final orders.
Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of a project, or if project costs exceed caps imposed by


the PUC in its approval of the project, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income. For example, in January 2013, the Utilities and the Consumer Advocate signed a settlement agreement to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects.
Energy cost adjustmentrecovery clauses. The rate schedules of each of the Utilities include ECRCs (changed from ECACs in 2019—see below) under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power.
ECACsECRCs are subject to periodic review by the PUC. In the most recent rate cases, the PUC allowed the current ECAC to continue. However, in the decoupling reexamination proceeding, certain parties recommended modifying the ECAC to allow only partial pass-through of fuel costs and eventual phasing out of the ECAC. On March 31, 2015, the PUC issued an Order (the March Order) related to the Schedule B portion of the proceeding. As required by the March Order, the parties filed initial and reply briefs related to the following issue: What are the appropriate steps, processes and timing to further consider the merits of the proposed changes to the ECAC identified in this proceeding. In identifying the issue on possible changes to the ECAC, the PUC stated that changes to the ECAC should be made with great care to avoid unintended consequences. In its briefs, the Consumer Advocate stated that there should be no significant change to the existing ECAC without first undertaking


a new regulatory proceeding that would provide time and resources for the careful study of the potential effects of each ECAC change considered, but that there should be significantly greater ECAC audit and regulatory review of the Utilities’ incurred fuel costs should be implemented to encourage cost control and to identify and deny recovery of any imprudently incurred energy costs through the ECAC. In their briefs, the Utilities suggested ways of improving the ECAC but stated that permitting only the partial pass through of fuel costs would not be proper regulatory policy since the Utilities have no control over world oil markets, 42 of the 50 states provide dollar-for-dollar pass through of market-driven changes in fuel or purchase power costs and modifying the ECAC to allow only partial pass-through of fuel costs could severely impact the Utilities’ credit rating.
In approving Hawaii Electric Light’s request to file a rate case by the end of December 30, 2016, the PUC required Hawaii Electric Light to propose for PUC consideration potential modifications to its ECAC mechanism in order to provide appropriate economic incentives to accelerate reductions in fuel and purchased power expenses.
Hawaii Electric Light and Hawaiian Electric proposed modifications to their ECAC provisions in their rate cases filed in 2016. The two utilities proposed an expansion of the range of fuel usage efficiencies under which fuel costs would be fully passed through to customers, andhas approved an additional trigger that would allow a re-establishment of fuel usage efficiency targets under certain conditions. In addition, Hawaii Electric Light proposed an equal sharingconditions and annual automatic adjustments of fuel usage efficiency targets for all Utilities. In the most recent rate cases for the Utilities, the PUC approved revised ECRCs for the Utilities, which transferred the remaining fuel and purchased energy expenses outsiderecovery from base rates to the ECRCs. Effective January 1, 2019, ECRC for Hawaiian Electric provides for a 98/2% risk-sharing split between ratepayers and Hawaiian Electric, of fossil fuel prices above or below a baseline price and the fuel usage efficiency target range.pass-through within a range, with an annual maximum exposure cap of $2.5 million. Effective September 1, 2019, the ECRC for Maui Electric reflects 98/2% risk-sharing split between ratepayers and Maui Electric, with an annual maximum exposure cap of $0.6 million. Hawaii Electric Light’s ECRC does not have a risk-sharing split. See “Most recent rate proceedings” in Note 3 of the Consolidated Financial Statements.
A change in, or the elimination of, the ECACECRC could have a material adverse effect on the Utilities.
Electric utility operations are significantly influenced by weather conditions. The Utilities’ results of operations can be affected by the weather.weather and natural disasters. Weather conditions, particularly temperature and humidity, directly influence the demand for electricity. In addition, severe weather and natural disasters, such as hurricanes, earthquakes, tsunamis, lava flows and lightning storms, some of which may become more severe or frequent as a result of global climate changes, can cause outages and property damage and require the Utilities to incur significant additional expenses that may not be recoverable.
Electric utility operations may be significantly influenced by climate change. While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods, hurricanes, heat waves or drought conditions, the latter of which could increase wildfire risk), sea levels, and water availability and quality, all have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather and its related impacts could cause significant harm to the Utilities’ physical facilities.
Electric utility operations depend heavily on third-party suppliers of fuel and purchased power. The Utilities rely on fuel oil suppliers and shippers, and IPPs to deliver fuel oil and power, respectively, in accordance with contractual agreements. Approximately 68%72% of the net energy generated or purchased by the Utilities in 20162019 was generated from the burning of fossil fuel oil, and purchases of power by the Utilities provided about 47%46% of their total net energy generated and purchased for the same period. Failure or delay by oilfuel suppliers and shippers to provide fuel pursuant to existing contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could disrupt the ability of the Utilities to deliver electricity and require the Utilities to incur additional expenses to meet the needs of their customers that may not be recoverable. In addition, as the 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. Also, as these contractual agreements end, the Utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agreements.
The capacity provided by the Utilities’ generating resources and third-party purchased power may not be sufficient to meet customers’ energy requirements. The Utilities rely upon their generating resources and purchased power from third parties to meet their customers’ energy requirements. The Utilities update their generation capacity evaluation each year to determine the Utilities’ ability to meet reasonably expected demands for service and provide reasonable reserves for emergencies. These evaluations are impacted by a variety of factors, including customer energy demand, energy conservation and efficiency initiatives, economic conditions, and weather patterns. If the capacity provided by the Utilities’ generating resources and third-party purchased power is not adequate relative to customer demand, the Utilities may have to contract to buy more power from third parties, invest in additional generating facilities over the long-term, or extend the operating life of existing utility units. Any failure to meet customer energy requirements could negatively impact the satisfaction of the Utilities’ customers, which could have an adverse impact on the Utilities’ business and results of operations.
Electric utility and third-party purchased power projects may be significantly impacted by stakeholder activism. The potential impact of stakeholder activism could increase total utility project costs, and delay the permitting, construction and overall timing or preclude the completion of third-party or utility projects that are required to meet electricity demand,


resilience and reliability objectives, and RPS goals. If a utility project cannot be completed, the project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.
Electric utility generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated and/or increased operation and maintenance expenses and increased power purchase costs. Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are facility shutdowns or power interruptions due to insufficient generation or a breakdown or failure of equipment or processes. In addition, operations could be negatively impacted by interruptions in fuel supply, inability to negotiate satisfactory collective bargaining agreements when existing agreements expire or other labor disputes, inability to comply with regulatory or permit requirements, disruptions in delivery of electricity, operator error and catastrophic events such as earthquakes, tsunamis, hurricanes, fires, explosions, floods or other similar occurrences affecting the Utilities’ generating facilities or transmission and distribution systems.
The Utilities may be adversely affected by new legislation or administrative actions. Congress, the Hawaii legislature and governmental agencies periodically consider legislation and other initiatives that could have uncertain or negative effects on the Utilities and their customers. Congress, the Hawaii legislature and governmental agencies have adopted, or are considering adopting, a number of measures that will significantly affect the Utilities, as described below.
Renewable Portfolio Standards law.  In 2015, Hawaii’s RPS law was amended to require electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045 respectively. Energy savings resulting from energy efficiency programs do not count toward the RPS after 2014. The Utilities are committed to achieving these goals and met the 2015 RPS; however, due to the exclusion of energy savings in calculating RPS after 2014 and risks such as potential delays in IPPs being able to deliver contracted renewable energy, it is possible the Utilities may not attain the required renewable percentages in the future, and management cannot predict the future consequences of failure to do so (including potential penalties to be assessed by the PUC). On December 19, 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the


event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in an RPS framework adopted by the PUC. In addition, the PUC ordered that the Utilities will be prohibited from recovering any RPS penalty costs through rates.
Renewable energy.  In 2007, a measure was passed by the Hawaii legislature stating that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source is more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source, resulting in higher costs.
Global climate change and greenhouse gas emissions reduction.  National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to climate change have led to federal legislative and regulatory proposals and action by the state of Hawaii to reduce GHG emissions.
In July 2007, the State Legislature passed Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. On June 20, 2014, the Governor signed the final rules required to implement Act 234 and these rules went into effect on June 30, 2014. In general, Act 234 and the GHG rule require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce their GHG emissions by 16% below 2010 emission levels by 2020. In accordance with State requirements, the Utilities submitted an Emissions Reduction Plan (EmRP)(ERP) to the DOH on June 30, 2015. Hawaiian Electric, Maui Electric,The Utilities submitted a revised ERP on October 17, 2018 and Hawaii Electric Light have a total of 11 facilities affected bysubsequent revisions on May 15, 2019 and July 26, 2019, to reflect the state GHG rule. Hawaiian Electric made use ofpartnership established between the partnering provisions in the GHG rule to prepare one EmRP for all 11 of the Utilities’ affected facilities.Utilities and several IPPs. In this plan, the Utilities havepartnership has committed to a 16% reduction in GHG emissions company-wide. Pursuantin accordance with the rule. As of December 31, 2019, the permits that were pending that would have incorporated the ERP have not been approved, and are subject to additional public review and potential challenge. Additionally, the loss of the PGV facility on Hawaii Island, unseasonable weather and the delay of additional renewable projects will make these goals more challenging in the immediate future. It is expected that with the advent of additional renewable projects and the application to the State’s GHG rule, the DOH will incorporate the proposed facility-specific GHG emission limits into each facility’s covered source permit based on the 2020 levels specified in Hawaiian Electric’s EmRP. The State GHG rule requires affected sources to pay an annual fee that is based on tons per year of GHG emissions. The Utilities’ GHG emissions fee is approximately $0.5 million annually. The latest assessment of the proposed federal and final state GHG rules is that the continued growth in renewable power generation will significantly reduce the compliance costs and risk for the Utilities.
On June 3, 2010, the EPA’s final GHG Tailoring Rule was published. It created a new threshold for GHG emissions from new and existing facilities and required certain facilities to obtain Prevention of Significant Deterioration (PSD) and Title V operating permits. The U.S. Supreme Court upheld that the EPA can apply the Best Available Control Technology (BACT) requirement to GHG for new or modified sources that trigger PSD permitting for air pollutants other than GHG. Any Hawaiian Electric, Hawaii Electric Light, and Maui Electric new or modified emission sources that trigger PSD permitting will be required to comply with BACT requirements. On August 26, 2016, the EPA proposed revisions to the PSD and Title V permitting regulations to fully implement the 2014 U.S. Supreme Court decision including the establishment of a threshold below which BACT is not required for GHG emissions for new or modified emission sources that trigger PSD permitting.
As part of President Obama’s Climate Action Plan, the EPA issued the final federal rule for GHG emission reductions from existing EGUs on August 3, 2015. This rule is also known as the Clean Power Plan. This rule sets interim state-wide emissions limits for existing EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029; final limits will apply from 2030. The EPA did not issue final guidelines for Alaska, Hawaii, Puerto Rico, or Guam because the Best System of Emission Reduction established for the contiguous states is not appropriate for these locations. The EPA has said it will work with the state and territorial governments for Alaska, Hawaii, Puerto Rico, and Guam and other stakeholders to gather additional information regarding the emissions reduction measures available in these jurisdictions, particularlyPUC with respect to renewable generation. Hawaiian Electric plans to participate in this process. The Utilities’ latest assessment of the Clean Power Plan is thatPGV project, the continued growth of renewable power generation in the future will significantly reduce the compliance costs and risk for the Utilities. To date, no timetable has been established by the EPA to develop GHG emission limits for Alaska, Hawaii, Puerto Rico, or Guam.
While the timing, extent and ultimate effects of climate change cannotgoals should be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.attainable.
The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSMdemand-side management programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, and burning renewable biodiesel in


Hawaiian Electric’s CIP CT-1, using biodiesel for startup and shutdown ofat selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. Management is unable


Performance-based regulation legislation. On April 24, 2018, Act 005, Session Laws 2018 was signed into law, which establishes performance metrics that the PUC shall consider while establishing performance incentives and penalty mechanisms under a performance-based ratemaking model. The law requires that the PUC establish these performance-based ratemaking mechanisms on or before January 1, 2020. The PUC opened a proceeding on April 18, 2018 to evaluateinvestigate performance-based regulation for the ultimate impact onUtilities. See “Performance-based regulation proceedings” in Note 3 of the Utilities of these various measures to reduce GHG emissions.Consolidated Financial Statements. 
The foregoing legislation or legislation that now is, or may in the future be, proposed present risks and uncertainties for the Utilities.
The Utilities may be subject to increased operational challenges and their results of operations, financial condition and liquidity may be adversely impacted in meeting the commitments and objectives of clean energy initiatives and Renewable Portfolio Standards (RPS). The far-reaching nature of the Utilities'Utilities’ renewable energy commitments and the RPS goals present risks to the Company. Among such risks are: (1) the dependence on third partythird-party suppliers of renewable purchased energy, which if the Utilities are unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity and/or energy in its purchased power agreement, could impact the Utilities’ achievement of their commitments to RPS goals and/or the Utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the Utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the Utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the Utilities depending on their design and implementation. These initiatives include, but are not limited to, programs to enable more customer-sited generation. The implementation of these or other programs may adversely impact the results of operations, financial condition and liquidity of the Utilities.
Bank Risks.risks.
The following risks are generally specific to ASB, but could have a material adverse effect on the Company’s consolidated results of operations, financial condition and liquidity.
Fluctuations in interest rates could result in lower net interest income, impair ASB’s ability to originate new loans or impair the ability of ASB’s adjustable-rate borrowers to make increased payments or cause such borrowers to repay their adjustable-rate loans.  Interest rate risk is a significant risk of ASB’s operations. ASB’s net interest income consists primarily of interest income received on fixed-rate and adjustable-rate loans, mortgage-relatedmortgage-backed securities and investments, andless interest expense consisting primarily of interest paid on deposits and other borrowings. Interest rate risk arises when earning assets mature or when their interest rates change in a time frame different from that of the costing liabilities. Changes in market interest rates, including changes in the relationship between short-term and long-term market interest rates (e.g., a flat or an inverted yield curve) or between different interest rate indices, and the duration and severity of the changes in market interest rates can impact ASB’s net interest margin. See “Quantitative and Qualitative Disclosures about Market Risk.”
Although ASB pursues an asset-liability management strategy designed to mitigate its risk from changes in market interest rates, unfavorable movements in interest rates could result in lower net interest income. Residential 1-4 family fixed-rate mortgage loans comprised about 40% of ASB’s loan portfolio as of December 31, 20162019 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. Although the Federal Open Market Committee increased the federal funds rate at its meetings in December 2015 and 2016, the interest rate enviroment remained relatively low in 2016 and new loan production rates remained at low levels and generally below ASB's loan portfolio yields. This placed additional pressure on ASB's asset yields and net interest margin. The degree to which compression of ASB's margin continues is uncertain if interest rates rise.
Increases in market interest rates could have an adverse impact on ASB’s cost of funds. Higher market interest rates could lead to higher interest rates paid on deposits and other borrowings. Significant increases in market interest rates, or the perception that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market interest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borrowers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperforming assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of maturities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-relatedmortgage-backed securities and impact ASB’s ability to reinvest its liquidity in similar yielding assets.
Changes in the method for determining London Interbank Offered Rate (LIBOR) and the potential replacement of LIBOR may affect our loan portfolio and interest income on loans.On July 27, 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 whether or not LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee composed of large U.S. financial institutions, announced replacement of U.S. dollar LIBOR with a new index calculated by short-term repurchase agreements, backed by U.S. Treasury securities called the Secured Overnight Financing


Rate (SOFR). The potential effect of the elimination of LIBOR on ASB’s LIBOR-indexed loan portfolio and interest income on loans cannot yet be determined.
ASB’s operations are affected by factors that are beyond its control, that could result in lower revenues, higher expenses or decreased demand for its products and services. ASB’s results of operations depend primarily on the income generated by the supply of, and demand for, its products and services, which primarily consist of loans and deposit services. ASB’s revenues and expenses may be adversely affected by various factors, including:
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’ sASB’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.
Banking and related regulations could result in significant restrictions being imposed on ASB’s business or in a requirement that HEI divest ASB. ASB is subject to examination and comprehensive regulation by the Department of Treasury, the OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. In addition, the FRB is responsible for regulating ASB’s holding companies, HEI and ASB Hawaii. The regulatory authorities have extensive discretion in connection with their supervisory and enforcement activities and examination policies to address not only ASB’s compliance with applicable banking laws and regulations, but also capital adequacy, asset quality, management ability and performance, earnings, liquidity and various other factors.
Under certain circumstances, including any determination that ASB’s relationship with HEI results in an unsafe and unsound banking practice, these regulatory authorities have the authority to restrict the ability of ASB to transfer assets and to make distributions to its shareholders (including payment of dividends to HEI), or they could seek to require HEI to sever its relationship with or divest its ownership of ASB. Payment by ASB of dividends to HEI may also be restricted by the OCC and FRB under its prompt corrective action regulations or its capital distribution regulations if ASB’s capital position deteriorates. In order to maintain its status as a QTL, ASB is required to maintain at least 65% of its assets in “qualified thrift investments.” Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. Federal legislation has also been proposed in the past that could operate to eliminate the thrift charter or the grandfathered status of HEI as a unitary thrift holding company, which in turn would result in a required divestiture of ASB. In the event of a required divestiture, federal law substantially limits the types of entities that could potentially acquire ASB.
Recent legislative and regulatory initiatives could have an adverse effect on ASB’s business. The Dodd-Frank Act, which became law in July 2010, has had a substantial impact on the financial services industry. The Dodd-Frank Act establishes a framework through which regulatory reform will be written and changes to statutes, regulations or regulatory policies could affect HEI and ASB in substantial and unpredictable ways. A major component of the Dodd-Frank Act is the creation of the Consumer Financial Protection Bureau that has the responsibility for setting and enforcing clear, consistent rules relating to consumer financial products and services and has the authority to prohibit practices it finds to be unfair, deceptive or abusive.


Compliance with any such directives could have adverse effects on ASB’s revenues or operating costs. Failure to comply with laws, regulations or policies could result in sanctions by regulatory agencies, civil money penalties and/or reputation damage, which could have a material adverse effect on ASB’s business, results of operations, financial condition and liquidity.
A large percentage of ASB’s loans and securities are collateralized by real estate, and adverse changes in the real estate market and/or general economic or other conditions may result in loan losses and adversely affect the Company’s profitability. As of December 31, 20162019 approximately 82% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was concentrated in the State of Hawaii. Growth has been in the commercial real estateDuring 2019, ASB’s HELOC and commercial construction loanresidential 1-4 family portfolios whichgrew by 12% and 2%, respectively, and now comprise approximately 24%78% of total real estate loans. ASB’s financial results may be adversely affected by changes in prevailing economic conditions, either nationally or in the state of Hawaii, including decreases in real estate values, adverse employment conditions, the monetary and fiscal policies of the federal and state government and other significant external events. Adverse changes in the economy may have a negative effect on the ability of borrowers to make timely repayments of their loans. A deterioration of the economic environment in Hawaii, including a material decline in the real estate market, further declines in home resales, or a material external shock, or any environmental clean-up obligation, may also significantly impair the value of ASB’s collateral and ASB’s ability to sell the collateral upon foreclosure. In the event of a default, amounts received upon sale of the collateral may be insufficient to recover outstanding principal and interest. In addition, if poor economic conditions result in decreased demand for real estate loans, ASB’s profits may decrease if its alternative investments earn less income than real estate loans.


ASB’s strategy to expand itsExpanding commercial, commercial real estate and consumer lending activities may result in higher costs and greater credit risk than residential lending activities due to the unique characteristics of these markets. ASB hashad been aggressively pursuing a strategy that includesincluded expanding its commercial, commercial real estate and consumer lines of business. ASB's commercial real estate and commercial construction loan portfolios grew by 16% and 26%, respectively, during 2016 and now comprise 20% of total loans. The commercial loan portfolio, after several years of growth, decreased by 9% during 2016 and now comprises 15% of total loans. The decrease was primarily due to the sale of a portion of ASB's syndicated national credit loan portfolio. Commercial and commercial real estate loans have a higher risk profile than residential loans. Though both commercial and commercial real estate loans have shorter terms and earn higher spreads than residential mortgage loans, these loan types generally entail higher underwriting and other service costs and present greater credit risks than traditional residential mortgages. The growth in the consumer loan portfolio was primarily due to growth in personal loans as ASB began offering a personal loan product with risk-based pricing. This loan product is unsecured and repayment is based on the borrower’s financial stability. PersonalCommercial loans are charged off when they become 120 days delinquent.
Generally, both commercial and commercial real estate loans have shorter terms to maturity and earn higher spreads than residential mortgage loans. Onlysecured by the assets of the business typically secure commercial loans. In such cases,and, upon default, any collateral repossessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s continuing financial stability and, thus, are more likely to be affected by current economic conditions and adverse business developments. Commercial real estate properties tend to be unique and are more difficult to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meaning that they have a significant principal balance or “balloon” payment due at maturity. In addition, commercial real estate properties, particularly industrial and warehouse properties, are generally subject to relatively greater environmental risks than noncommercial properties and to the corresponding burdens and costs of compliance with environmental laws and regulations. Also, there may be costs and delays involved in enforcing rights of a property owner against tenants in default under terms of leases with respect to commercial properties. For example, a tenant may seek protection under bankruptcy laws, which could result in termination of the tenant’s lease.
ASB also has a national syndicated lending portfolio where ASB is a participant in credit facilities agented by established and reputable national lenders. Management selectively chooses each deal based on conservative credit criteria to ensure a high quality,high-quality, well diversified portfolio. In the event the borrower encounters financial difficulties and ASB is unable to sell its participation interest in the loan in the secondary market, the bankASB is typically reliant on the originating lender for managing any loan workout or foreclosure proceedings that may become necessary. Accordingly, ASB has less control over such proceedings than loans it originates and may be required to accommodate the interests of other participating lenders in resolving delinquencies or defaults on participated loans, which could result in outcomes that are not fully consistent with ASB'sASB’s preferred strategies. In addition, a significant proportion of ASB'sASB’s syndicated loans are originated in states other than Hawaii and are subject to the local regional and regulatory risks specific to those states.
Similar to the national syndicated lending portfolio, ASB does not service commercial loans in which it has participation interests rather than being the lead or agent lender and is subject to the policies and practices of the agent lender, who is the loan servicer, in resolving delinquencies or defaults on participated loans.
Commercial real estate properties tendThe consumer loan portfolio primarily consists of personal unsecured loans with risk-based pricing. Repayment is based on the borrower’s financial stability as these loans have no collateral and there is less assurance that ASB will be able to be unique and are more difficultcollect all payments due under these loans or have sufficient collateral to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meaning that they may have a significant principal balance or “balloon” payment due at maturity. In addition, commercial real estate properties, particularly industrial and warehouse properties, are generally subject to relatively greater environmental risks than noncommercial properties and to the corresponding burdens and costs of compliance with environmental laws and regulations. Also, there may be costs and delays involved in enforcing rights of a property owner against tenants in default under the terms of leases with respect to commercial properties. For example, a tenant may seek the protection of bankruptcy laws, which could result in termination of the tenant’s lease.cover all outstanding loan balances.
ASB'sASB’s allowance for loan losses may not cover actual loan losses.ASB'sASB’s allowance for loan losses is the bank'sASB’s estimate of probable losses inherent in its loan portfolio and is based on a continuing assessment of:
•existing risks in the loan portfolio;
•historical loss experience with ASB'sASB’s loans;
•changes in collateral value; and
•current conditions (for example, economic conditions, real estate market conditions and interest rate environment).


If ASB'sASB’s actual loan losses exceed its allowance for loan losses, it may incur losses, its financial condition may be materially and adversely affected, and additional capital may be required to enhance its capital position. In addition, various regulatory agencies, as an integral part of their examination process, regularly review the adequacy of ASB'sASB’s allowance. These agencies may require ASB to establish additional allowances based on their judgment of the information available at the time of their examinations. No assurance can be given that ASB will not sustain loan losses in excess of present or future levels of its allowance for loan losses.
ITEM 1B.UNRESOLVED STAFF COMMENTS
HEI: None.
Hawaiian Electric: Not applicable.


ITEM 2.PROPERTIES
HEI and Hawaiian Electric: See the “Properties” sections under “HEI,” “Electric utility” and “Bank” in Item 1. Business above.
ITEM 3.LEGAL PROCEEDINGS
HEI and Hawaiian Electric: HEI subsidiaries (includingand Hawaiian Electric (including their direct and its subsidiaries and ASB)indirect subsidiaries) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigation incidental to their respective businesses. See the descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” in HEI’s MD&A and in the Notes 43 and 54 of the Consolidated Financial Statements. The outcomes of litigation and administrative proceedings are necessarily uncertain and there is a risk that the outcome of such matters could have a material adverse effect on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular period in the future.
ITEM 4.MINE SAFETY DISCLOSURES
HEI and Hawaiian Electric: Not applicable.



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INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)
The executive officers of HEI are listed below. Messrs. OshimaSeu and Wacker are officers of HEI subsidiaries rather than of HEI, but are deemed to be executive officers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive officers serve from the date of their initial appointment until the annual meeting ofand are reappointed annually by the HEI Board at which officers are appointed (or the next annual appointment of officersannually by the applicable HEI subsidiary board), and thereafter are appointed for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or removal. HEI executive officers may also hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.
Name Age Business experience for last 5 years and prior positions with the Company
Constance H. Lau 6467 
HEI President and Chief Executive Officer since 5/06

HEI Director, 6/01 to 12/04 and since 5/06

Hawaiian Electric Chairman of the Board, since 5/06 to 5/19
ASB Hawaii Director since 5/06
ASB Chairman of the Board since 5/06, Risk Committee member since 2012 and Director since 1999
    ·   ASB Chief Executive Officer, 6/01 to 11/10, and President, 6/01 to 1/08
·   ASB Senior Executive Vice President and Chief Operating Officer and Director, 12/99 to 5/01
·   HEI Power Corp. Financial Vice President and Treasurer, 5/97 to 8/99
·   HEI Treasurer, 4/89 to 10/99, and HEI Assistant Treasurer, 12/87 to 4/89
·   Hawaiian Electric Treasurer 12/87 to 4/89 and Assistant Corporate Counsel, 9/84 to 12/87
James A. Ajello*Gregory C. Hazelton 6355 
HEI Executive Vice President and Chief Financial Officer since 8/134/17
ASB Hawaii Director since 8/09
·    HEI Executive Vice President, Chief Financial Officer and Treasurer, 5/113/18 to 8/1311/19
·    HEI Senior Financial Vice President, Treasurer and Chief Financial Officer, 1/09 to 5/11
Gregory C. Hazelton*52
HEI Senior Vice President, Finance, since 10/16 to 4/17
·    Prior to rejoining the Company in 2016: Northwest Natural Gas Company, Senior Vice President, Chief Financial Officer and Treasurer, 2/16 to 9/16, and Northwest Natural Gas Company, Senior Vice President and Chief Financial Officer, 6/15 to 2/16
·    HEI Vice President, Finance, Treasurer and Controller, 8/13 to 6/15
· Prior to joining the Company in 2013: UBS Investment Bank, Managing Director, Global Power & Utilities Group 3/11 to 5/13
Alan M. OshimaScott W. H. Seu 6954 
Hawaiian Electric President and Chief Executive Officer since 10/14
2/20
Hawaiian Electric Director 2008 to 10/11 and since 10/14
HEI Charitable Foundation President since 10/112/20
·   Hawaiian Electric Senior Executive Officer on loan from HEI,Vice President, Public Affairs, 1/17 to 2/20
·   Hawaiian Electric Vice President, System Operation, 5/14 to 9/141/17
·   HEI ExecutiveHawaiian Electric Vice President, CorporateEnergy Resources and Community Advancement, 10/11Operations, 1/13 to 5/14
·   Hawaiian Electric Vice President, Energy Resources, 8/10 to 12/12
·   Hawaiian Electric Manager, Resource Acquisition Department, 3/09 to 8/10
·   Hawaiian Electric Manager, Energy Projects Department, 5/04 to 3/09
·   Hawaiian Electric Manager, Customer Installations Department, 1/03 to 5/04
·   Hawaiian Electric Manager, Environmental Department, 4/98 to 12/02
·   Hawaiian Electric Principal Environmental Scientist, 1/97 to 4/98
·   Hawaiian Electric Senior Environmental Scientist, 5/96 to 12/96
·   Hawaiian Electric Environmental Scientist, 8/93 to 5/96
Richard F. Wacker 5457 
ASB President and Chief Executive Officer since 11/10
ASB Director since 11/10
*As disclosed in HEI's Form 8-K dated February 13, 2017, Mr. Ajello plans to retire from HEI effective April 2, 2017 and upon such retirement Mr. Hazelton will succeed Mr. Ajello as HEI's Executive Vice President and Chief Financial Officer.
Family relationships; executive arrangements
There are no family relationships between any HEI executive officer and any other HEI executive officer or any HEI director or director nominee. There are no arrangements or understandings between any HEI executive officer and any other person pursuant to which such executive officer was selected.

29


PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
HEI:
Certain of the information required by this item is incorporated herein by reference to Note 14, “Regulatory restrictions on net assets” and Note 18,17, “Quarterly information (unaudited)” of the Consolidated Financial Statements and "Item“Item 6. Selected Financial Data” and “Equity compensation plan information” under "Item“Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters"Matters” of this Form 10-K. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—HEI—Regulation—Restrictions on dividends and other distributions” and that description is incorporated herein by reference.
HEI’s common stock is traded on the New York Stock Exchange andunder the ticker symbol “HE.” The total number of holders of record of HEI common stock (i.e., registered shareholders)holders) as of February 13, 2017,2020, was 6,429.5,564. On February 11, 2020, the HEI Board of Directors approved a 1 cent increase in the quarterly dividend from $0.32 per share to $0.33 per share, starting with the dividend in the first quarter of 2020. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation including, but not limited to, the Company’s results of operations, the long-term prospects for the Company, and the current and expected future economic conditions.
Purchases of HEI common shares were made during the fourth quarter to satisfy the requirements of certain plans as follows:


ISSUER PURCHASES OF EQUITY SECURITIES
Period*
(a)
Total Number
of Shares Purchased **
 
 (b)
Average
Price Paid
per Share **
 (c)
 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
 (d)
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to 31, 2016—
 $—
—
 NA
November 1 to 30, 2016—
 $—
—
 NA
December 1 to 31, 2016207,373
 $32.28
—
 NA
Period*

Total Number
of Shares Purchased **
 
 
Average
Price Paid
per Share **

 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 

Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to 31, 201923,372
 $44.80
—
 NA
November 1 to 30, 201911,248
 $43.55
—
 NA
December 1 to 31, 2019148,516
 $44.48
—
 NA
Total183,136
 $44.47
—
 NA
NA Not applicable.
* Trades (total number of shares purchased) are reflected in the month in which the order is placed.
** The purchases were made to satisfy the requirements of the DRIP, the HEIRSP and the ASB 401(k) Plan for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP, the HEIRSP and the ASB 401(k) Plan. Of the “Total number of shares listed in column (a), 184,673purchased,” 154,786 of the 207,373183,136 shares were purchased for the DRIP; 19,10023,287 of the 207,373183,136 shares were purchased for the HEIRSP; and 3,600the remaining of the 207,373the183,136 shares were purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.
The dividends declared and paid on HEI's common stock for the quarters of 2016 and 2015 were as follows:
Quarters ended2016
 2015
(in thousands)   
March 31$33,367
 $31,840
June 3033,481
 33,300
September 3033,550
 33,312
December 3133,652
 33,313
Also see Note 18, “Quarterly information (unaudited)” of the Consolidated Financial Statements.
Hawaiian Electric:
Since a corporate restructuring on July 1, 1983, all the common stock of Hawaiian Electric has been held solely by its parent, HEI, and is not publicly traded. Accordingly, information required with respect to “Market information” and “holders” is not applicable to Hawaiian Electric.
The dividends declared and paid on Hawaiian Electric’s common stock for the quarters of 20162019 and 20152018 were as follows:
Quarters ended2016
 2015
2019
 2018
(in thousands)      
March 31$23,400
 $22,601
$25,313
 $25,826
June 3023,400
 22,602
25,313
 25,826
September 3023,399
 22,601
25,313
 25,827
December 3123,400
 22,601
25,313
 25,826
Also, see “Liquidity and capital resources” in HEI’s MD&A.
See the discussion of regulatory and other restrictions on dividends or other distributions under “Item 1. Business—HEI—Regulation—Restrictions on dividends and other distributions” and in Note 14 of the Consolidated Financial Statements.

30




ITEM 6.SELECTED FINANCIAL DATA
HEI:
Selected Financial Data                  
Hawaiian Electric Industries, Inc. and SubsidiariesHawaiian Electric Industries, Inc. and Subsidiaries  
  
  
  
Hawaiian Electric Industries, Inc. and Subsidiaries  
  
  
  
Years ended December 312016
 2015
 2014
 2013
 2012
2019
 2018
 2017
 2016
 2015
(dollars in thousands, except per share amounts)(dollars in thousands, except per share amounts)  
  
  
  
(dollars in thousands, except per share amounts)  
  
  
  
Results of operations 
  
  
  
  
 
  
  
  
  
Revenues$2,380,654
 $2,602,982
 $3,239,542
 $3,238,470
 $3,374,995
$2,874,601
 $2,860,849
 $2,555,625
 $2,380,654
 $2,602,982
Net income for common stock$248,256
 $159,877
 $168,129
 $161,709
 $138,705
217,882
 201,774
 165,297
 248,256
 159,877
Basic earnings per common share$2.30
 $1.50
 $1.65
 $1.63
 $1.43
2.00
 1.85
 1.52
 2.30
 1.50
Diluted earnings per common share$2.29
 $1.50
 $1.63
 $1.62
 $1.42
1.99
 1.85
 1.52
 2.29
 1.50
Return on average common equity12.4% 8.6% 9.6% 9.7% 8.9%9.8% 9.5% 7.9% 12.4% 8.6%
Financial position *         
         
Total assets$12,425,506
 $11,782,018
 $11,177,143
 $10,331,921
 $10,139,569
$13,745,251
 $13,104,051
 $12,534,160
 $11,881,981
 $11,275,931
Deposit liabilities5,548,929
 5,025,254
 4,623,415
 4,372,477
 4,229,916
6,271,902
 6,158,852
 5,890,597
 5,548,929
 5,025,254
Other bank borrowings192,618
 328,582
 290,656
 244,514
 195,926
115,110
 110,040
 190,859
 192,618
 328,582
Long-term debt, net1,619,019
 1,578,368
 1,498,547
 1,483,960
 1,412,386
Long-term debt, net—other than bank1,964,365
 1,879,641
 1,683,797
 1,619,019
 1,578,368
Preferred stock of subsidiaries – not subject to mandatory redemption34,293
 34,293
 34,293
 34,293
 34,293
34,293
 34,293
 34,293
 34,293
 34,293
Common stock equity2,066,753
 1,927,640
 1,790,573
 1,726,406
 1,593,008
2,280,260
 2,162,280
 2,097,386
 2,066,753
 1,927,640
Common equity ratio51% 52% 53% 56% 53%
Common stock     
  
  
       
  
Book value per common share *$19.05
 $17.94
 $17.46
 $17.05
 $16.27
$20.92
 $19.86
 $19.28
 $19.03
 $17.94
Market price per common share         
High34.98
 34.86
 35.00
 28.30
 29.24
Low27.30
 27.02
 22.71
 23.84
 23.65
December 3133.07
 28.95
 33.48
 26.06
 25.14
Dividends per common share1.24
 1.24
 1.24
 1.24
 1.24
Dividends declared per common share1.28
 1.24
 1.24
 1.24
 1.24
Dividend payout ratio54% 82% 75% 76% 87%64% 67% 82% 54% 82%
Market price to book value per common share *174% 161% 192% 153% 155%224% 184% 188% 174% 161%
Price earnings ratio **14.4x
 19.3x
 20.3x 16.0x 17.6x23.5x
 19.8x
 23.8x
 14.4x
 19.3x
Common shares outstanding (thousands) *108,583
 107,460
 102,565
 101,260
 97,928
108,973
 108,879
 108,788
 108,583
 107,460
Weighted-average108,102
 106,418
 101,968
 98,968
 96,908
Weighted-average-basic (thousands)108,949
 108,855
 108,749
 108,102
 106,418
Shareholders ***26,831
 27,927
 29,415
 30,653
 31,349
24,766
 25,369
 26,064
 26,831
 27,927
Employees *3,796
 3,918
 3,965
 3,966
 3,870
3,841
 3,898
 3,880
 3,796
 3,918
*At December 31.
**Calculated using December 31 market price per common share divided by basic earnings per common share. The principal trading market for HEI’s common stock is the New York Stock Exchange (NYSE).
***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, 2017,2020, HEI had 6,4295,564 registered shareholders (i.e., holders of record of HEI common stock), 23,72322,060 DRIP participants and total shareholders of 26,753.24,651.
2019 results includes $10.8 million of gains ($7.9 million after-tax at ASB’s statutory tax rate of 26.8%) on sales of real estate associated with ASB’s transition to its new campus. The gains were partially offset by $3.2 million ($2.4 million after-tax at ASB’s statutory tax rate of 26.8%) of exit costs associated with the move to the new campus. 2018 and 2019 results include the impact of the lower federal corporate tax rate as a result of the Tax Act. 2018 also reflects certain tax return adjustments relating to the benefit associated with additional tax deductions taken in the Company’s 2017 tax returns in conjunction with the rate differential provided in the Tax Act. The lower tax rate in 2018 and 2019 was partially offset by other Tax Act changes, including the non-deductibility of excess executive compensation and various fringe benefit costs. 2017 results include a $14 million adjustment, primarily to reduce deferred tax net asset balances (not accounted for under Utility regulatory ratemaking) to reflect the lower rates enacted by the Tax Act and $20 million ($11 million, net of tax impacts) lower in RAM revenues than prior year due to the expiration of the 2013 settlement agreement that allowed the accrual of RAM revenues on January 1 (vs. June 1) for years 2015 to 2016 at Hawaiian Electric. Results for 2016 2015 and 20142015 include merger- and spin-off-related income/(expenses), net of tax impacts, of $60 million and ($16 million), and ($2 million), respectively (see Note 2 of the Consolidated Financial Statements).
Financial data for prior periods has been updated to reflect the retrospective application of Accounting Standards Update (ASU) No. 2015-03 (Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs). See “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations.
For 2014, 2013 and 2012, under the two-class method of computing basic earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.41, $0.39 and $0.19 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2014, 2013 and 2012, under the two-class method of computing diluted earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.40, $0.38 and $0.18 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. There were no restricted stock awards outstanding during 2015 and 2016.respectively.



Hawaiian Electric:
Selected Financial Data
Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 312016201520142013201220192018201720162015
(in thousands)  
Results of operations  
Revenues$2,094,368
$2,335,166
$2,987,323
$2,980,172
$3,109,439
$2,545,942
$2,546,525
$2,257,566
$2,094,368
$2,335,166
Net income for common stock142,317
135,714
137,641
122,929
99,276
156,840
143,653
119,951
142,317
135,714
  
Financial position *  
Utility plant$6,870,627
$6,543,799
$6,220,397
$5,896,991
$5,567,346
$7,485,178
$7,092,483
$6,717,311
$6,327,102
$6,037,712
Accumulated depreciation(2,369,282)(2,266,004)(2,175,510)(2,111,229)(2,040,789)(2,690,157)(2,577,342)(2,476,352)(2,369,282)(2,266,004)
Net utility plant$4,501,345
$4,277,795
$4,044,887
$3,785,762
$3,526,557
$4,795,021
$4,515,141
$4,240,959
$3,957,820
$3,771,708
Total assets$5,975,428
$5,672,210
$5,550,021
$5,058,065
$5,099,101
$6,388,682
$5,967,503
$5,630,613
$5,431,903
$5,166,123
Current portion of long-term debt$—
$—
$—
$11,383
$—
$95,953
$—
$49,963
$—
$—
Short-term borrowings from non-affiliates88,987
25,000
4,999
—
—
Long-term debt, net1,319,260
1,278,702
1,199,025
1,198,200
1,138,180
1,401,714
1,418,802
1,318,516
1,319,260
1,278,702
Common stock equity1,799,787
1,728,325
1,682,144
1,593,564
1,472,136
2,047,352
1,957,641
1,845,283
1,799,787
1,728,325
Cumulative preferred stock-not
subject to mandatory redemption
34,293
34,293
34,293
34,293
34,293
34,293
34,293
34,293
34,293
34,293
Capital structure$3,153,340
$3,041,320
$2,915,462
$2,837,440
$2,644,609
$3,668,299
$3,435,736
$3,253,054
$3,153,340
$3,041,320
Capital structure ratios (%)  
Debt (short-term debt, which is nil, and long-term debt, net, including current portion)41.8
42.1
41.1
42.6
43.0
Debt (short-term borrowings, and long-term debt, net, including current portion)43.3
42.0
42.2
41.8
42.1
Cumulative preferred stock1.1
1.1
1.2
1.2
1.3
0.9
1.0
1.1
1.1
1.1
Common stock equity57.1
56.8
57.7
56.2
55.7
55.8
57.0
56.7
57.1
56.8


*At December 31.

HEI owns all of Hawaiian Electric’s common stock. Therefore, per share data is not meaningful.
Financial data2018 and 2019 results include the impact of the lower federal corporate tax rate as a result of the Tax Act, the benefits of which were returned to customers through a reduction in revenue requirements. 2018 also reflects certain tax return adjustments relating to the benefit associated with additional tax deductions taken in the Company’s 2017 tax returns in conjunction with the rate differential provided in the Tax Act. The lower tax rate in 2018 and 2019 was partially offset by other Tax Act changes, including the non-deductibility of excess executive compensation and various fringe benefit costs. 2017 results include $20 million ($11 million, net of tax impacts) lower in RAM revenues than prior year due to: 1) the expiration of the 2013 settlement agreement that allowed the accrual of RAM revenues on January 1 (vs. June 1) for prior periods has been updatedyears 2015 to 2016 at Hawaiian Electric, and 2) a $9 million adjustment, primarily to reduce deferred tax net asset balances (not accounted for under regulatory ratemaking) to reflect the retrospective application of ASU No. 2015-03 (Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs).lower rates enacted by Tax Act.
See "Cautionary“Cautionary Note Regarding Forward-Looking Statements"Statements” above, the “electric utility” sections and all information related to, or including, Hawaiian Electric and its subsidiaries in HEI’s MD&A and “Commitments and contingencies” in Note 43 of the Consolidated Financial Statements for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.



32




ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries):
The following discussion should be read in conjunction with the Consolidated Financial Statements.Statements and the related Notes that appear in Item 8 of this report. For information on factors that may cause HEI’s and Hawaiian Electric’s actual future results to differ from those currently contemplated by the relevant forward-looking statements, see “Cautionary Note Regarding Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A. The general discussion of HEI’s consolidated results should be read in conjunction with the electricElectric utility and bankBank segment discussions that follow.
HEI Consolidated
Executive overview and strategy. HEI is a holding company overseeing operating subsidiaries inwith operations primarily focused on Hawaii’s electric utility and banking sectors. In 2017, HEI formed Pacific Current to make investments in non-regulated renewable energy and sustainable infrastructure projects. HEI has three reportable segments—Electric utility, Bank, and Other.
Electric utility. Hawaiian Electric, Hawaii Electric Light and Maui Electric (Utilities) are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively.
Bank. ASB is a full-service community bank serving both consumer and commercial customers in the State of Hawaii and has 49 branches on branches on the islands of Oahu (34), Maui (6), Hawaii (5), Kauai (3), and Molokai (1).
Other. The Other segment comprises HEI’s corporate-level operating, general and administrative expenses and the results of Pacific Current.
A primarymajor focus of HEI’s financial strategy is to grow core earnings and earnings/profitability of its Utilities and Bank in a controlled risk manner and improve operating, capital and tax efficiencies in order to support its dividend and deliver shareholder value. In addition, HEI and its subsidiaries from time to time consider various strategies designed to enhance their competitive positions and maximize shareholder value.
HEI, through its electric utility subsidiaries (Hawaiian Electric and its subsidiaries, Hawaii Electric Light and Maui Electric), provides the only electric public utility service to approximately 95% of Hawaii’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, ASB, one of Hawaii’s largest financial institutions based on total assets. Together, HEI’s unique combination of electric utilitiespower and a bank continues to providefinancial services companies provides the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries, while providing an attractive dividend for investors.
Environmental, social and governance risks and opportunities. Environmental, social and governance (ESG) considerations have long been an integral part of HEI’s strategy to be a “catalyst for a better Hawaii” for the benefit of all stakeholders. The Company firmly believes that effective management of its ESG risks and opportunities creates a strategic business advantage; improves the lives of our employees, through focus on employee health, wellness, safety, empowerment and increased engagement; improves the sustainability, well-being and resilience of our communities, the state and the environment; and ultimately leads to sustained long-term value creation for our investors.
The HEI Board of Directors is responsible for the oversight of the Company’s enterprise risk management (ERM) programs, which are designed to address all material risks and opportunities, including ESG considerations. The Board of Directors has delegated the day-to-day responsibility to execute on these action plans to management. The Company believes ESG considerations are embedded in our daily actions and drive how we engage with our employees, communities, and shareholders.
The Company intends to leverage the frameworks developed by the Task Force on Climate-related Financial Disclosure (TCFD) and the Sustainability Accounting Standards Board (SASB) to communicate our approach and progress on ESG matters in future filings.
We are committed to achieving a renewable, sustainable energy future, providing leadership in corporate social responsibility, and adhering to governance best practices.
To learn more about our ESG initiatives please visit www.hawaiianelectric.com/clean-energy-hawaii/sustainability-report and www.asbhawaii.com/corporate-social-responsibility. Later this year, HEI will be issuing a consolidated sustainability report, which will be posted on our website at www.hei.com. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K.


HEI consolidated results of operations.
(dollars in millions, except per share amounts)2019
 % change
 2018
 % change
 2017
Revenues$2,875
 —
 $2,861
 12
 $2,556
Operating income349
 5
 333
 (4) 346
Net income for common stock218
 8
 202
 22
 165
Net income (loss) by segment:     
  
  
Electric utility$157
 9
 $144
 20
 $120
Bank89
 8
 83
 23
 67
Other(28) (15) (24) (13) (22)
Net income for common stock$218
 8
 $202
 22
 $165
Basic earnings per share$2.00
 8
 $1.85
 22
 $1.52
Diluted earnings per share$1.99
 8
 $1.85
 22
 $1.52
Dividends per share$1.28
 3
 $1.24
 —
 $1.24
Weighted-average number of common shares outstanding (millions)108.9
 —
 108.9
 —
 108.7
Dividend payout ratio64%  
 67%  
 82%
In 2016,2019, net income for HEI common stock was $248increased 8% to $218 million up 55% from $160($1.99 diluted earnings per share), compared to $202 million ($1.85 diluted earnings per share) in 2015 primarily2018, due to the merger termination fee from NEE (and related lower merger-related costs$13 million and tax benefits on previously non-deductible merger and spin-off expenses) and both the Utilities’ and ASB’s 5% higher net incomes. Basic earnings per share were $2.30 per share in 2016, up 53% from $1.50 per share in 2015. Excluding merger and spin-off-related income and costs ($60$6 million after-tax, see “Other” segment results below) and costs related to the terminated LNG contract, which required PUC approval of the merger with NEE, net income for HEI common stock would have been $190 million, up 8% from $176 million in 2015 primarily due to the Utilities’ 6% higher net income at the Utilities and ASB’s 5%ASB, respectively, partially offset by $4 million higher net income and lower lossesloss at HEI corporate.
the “other” segment. The increase in the Utilities’ strategic focus has been to meet Hawaii’s energy needs by modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy generation and taking the necessary steps to secure regulatory support for their plans. Electric utility2019 net income for common stock in 2016 of $142 million, increased from the prior year by 5%compared to 2018 was principally due to the recovery of additional investments for clean energyhigher RAM and reliability and lower O&M expenses compared to 2015 (which included higher O&M expenses from the write off of ERP software costs, additional reserves for environmental costsrate increases and higher storm weather repair expenses)MPIR revenues, partially offset by higher depreciation expense (as a result of increasing investments for the integration of more renewable energy, improved service reliabilityO&M expenses and greater system efficiency) and higher consulting expenses related to LNG and PSIPs.
ASB continues to develop and introduce new products and servicesdepreciation. The increase in order to meet the needs of both consumer and commercial customers. Additionally, ASB has made investments in electronic banking platforms, data and risk management capabilities and process improvements to deliver a continuously better experience for its customers, healthy growth and a more efficient bank. ASB’s earnings in 2016 of $57 million increased $2 million compared to prior year net income was primarily due primarily to gains on sale of properties exited in connection with ASB’s move to its new campus andhigher net interest income partlyas a result of an increase in earning asset balances and yields, partially offset by a higher provision for loan losses and higher noninterest expensescompensation and occupancy expenses. See “Electric utility,” “Bank,” and “HEI Consolidated—Other segment” sections below for additional information on year-to-year fluctuations.
The Company’s effective tax rate (combined federal and state income tax rates) was lower noninterest income. In 2016, ASB earnings benefited from higher net interest income as interest income from loan and investment growth were funded primarily by low cost deposit liabilities. These increases were partly offset by a higher provision for loan losses which wasat 19% in 2019, compared to 20% in 2018, primarily due to growthtax benefits of bank owned life insurance and increases in tax credit investments.
For a discussion of 2017 results, please refer to the “HEI consolidated results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—HEI Consolidated,” in the commercial real estate and consumer loan portfolios and additional reserves for specific commercial credits, as well as higher noninterest expenses due primarily to costs related to replacement and upgrade of ASB's electronic banking platform. ASB’s future financialCompany’s 2018 Form 10-K.
Other segment. The “other” business segment (loss)/income includes results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio.
HEI’s “other” segment had net income in 2016 of $49 million, compared to a net loss of $31 million in 2015. In 2016, HEI’s “other” segment included $60 million of net income related to the merger- and spin-off [comprised of the termination fee ($55 million)stand-alone corporate operations of HEI, ASB Hawaii, Inc. (ASB Hawaii), reimbursements of expenses from NEE and insurance ($3 million), additional tax benefits on the previously non-tax-deductible merger- and spin-off-related expenses incurred through June 30, 2016 ($8 million), partly offset by merger- and spin-off-related expenses ($6 million) (all net of tax impacts)]. In 2015, HEI’s “other” segment included $15 million of expenses relatedPacific Current, LLC.
(in millions) 2019 2018 
Increase
(decrease)
 Primary reason(s)
Operating loss1
 $(17) $(16) $(1) Lower Pacific Current operating income ($3 million in 2019 vs $4 million in 2018) due to higher Pacific Current administrative and general expenses. HEI corporate expenses were comparable year-over-year ($19 million in 2019 and 2018).
Interest expense & other (21) (16) (5) Increase due to higher average borrowings and higher average interest rates. Average borrowings increased due primarily to $100 million tranche B private placement drawn in December 2018 to fund a contribution of utility equity.
Income tax benefit 10
 8
 2
 Higher tax benefit due to an increase in pretax losses
Net loss $(28) $(24) $(4)  

1 Hamakua Energy’s sales to the merger- and spin-off (net of taxes). Excluding these merger- and spin-off-related income items andHawaii Electric Light (a regulated affiliate) are eliminated in consolidation.


expenses (after-tax), HEI’s “other” segment net loss was 24% lower ($12 million in 2016 and $15 million in 2015) primarily due to lower interest and other tax benefits recognized as a result of moving out of a federal net operating loss position.
Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, Hawaiian Electric, have paid dividends continuously since 1901. The dividend has been stable at $1.24 per share annually since 1998. The indicated dividend yield as of December 31, 2016 was 3.7%. The dividend payout ratios based on net income for common stock for 2016, 2015 and 2014 were 54%, 82% and 75%, respectively. The HEI Board of Directors considers many factors in determining the dividend quarterly, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.
Economic conditions.
Note: The statistical data in this section is from public third-party sources that management believes to be reliable (e.g., Department of Business, Economic Development and Tourism (DBEDT);, University of Hawaii Economic Research Organization;Organization, U.S. Bureau of Labor Statistics;Statistics, Department of Labor and Industrial Relations (DLIR);, Hawaii Tourism Authority (HTA);, Honolulu Board of REALTORS® and national and local newspapers).
Hawaii’s tourism industry, a significant driver of Hawaii’s economy, ended 20162019 with record highsgrowth in both visitor spending and arrivals for the fourth consecutive year.arrivals. Visitor expenditures increased 5.1%1.4% and arrivals increased 3.6%5.4% compared to 2015. Looking ahead,2018, although the average length of


stay decreased by -2.3% over 2018. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the first quarterreported an increase in total trans-Pacific air seat capacity of 2017 to decrease by 1.2% over the first quarter of 2016 driven primarily by a 4.1% decrease2.9% in domestic seats from the West coast.2019 compared 2018.
Hawaii’s unemployment rate continued to decline to 2.9%remained steady at 2.6% in December 2016,2019, which was the same as the 2.6% rate a year ago in December 2018 and lower than the state’s 3.3% rate in December 2015 and the December 2016 national unemployment rate of 4.7%3.5%.
Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices for condominiums and decrease in 2016.median sale prices for single family homes in 2019. Median sales prices for single family residential homes were lower by 0.1% and were higher by 1.2% for condominiums on Oahu increased 5.0% and 8.3%, respectively,through December 2019 over 2015.the same time period in 2018. The number of closed sales also increased from 2015. Closed sales for both single family residential homes was up by 3.9% and for condominiums were upwas down 4.8% through December of 2019 compared to 2015, 6.5% and 8.4% respectively.same time period of 2018.
Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. InFollowing price increases throughout the first quarterhalf of 2016,2019, the price of crude oil continued its decline to levels not seen for over ten years. The price of crude oilhas dropped slightly recovered and stabilizedremained fairly stable in the second and third quarters, while continuing to marginally increase in the fourth quarter.half of 2019.
At its December 20162019 meeting, the Federal Open Market Committee (FOMC) increaseddecided to maintain the federal funds rate target range of 1.5% to 1.75% to encourage maximum employment and price stability. The FOMC will continue to will continue to monitor the implications of incoming information for the second time in a decade. The FOMC raisedeconomic outlook, including global developments and muted inflation pressures.
Hawaii’s economy slowed toward the target rangeend of “0.25%2019 as the population continued to 0.5%”decline, which impacted nonfarm payroll growth. However, the construction industry continues to “0.5%perform well and visitor arrivals continue to 0.75%”. Overall, Hawaii’s economyincrease, which is expected to see positive growth in 2017. Tourism had another record year in 2016. Forecasts continue visitor arrivals and visitor expenditure growth in 2017 of 1.8% and 4.0% respectively. Military troop reductions in Hawaii could negatively impact the economy. Reductions in the military are planned in 2017 and 2018, but it is not yet known if those reductions will negatively impact Hawaii bases. Any impacts onhelp support the economy by troop reductions may be offset byin maintaining a positive, but subdued, growth path. It is unknown at this time what effects, if any, the large military construction projects recently funded in the 2017 National Defense Authorization Act (NDAA).coronavirus COVID-19 will have on Hawaii’s visitor industry or its economy.
Additional risks to local economic growth include volatility to global economies and their impact on the local real estate and construction markets.



Results of operations.
(dollars in millions, except per share amounts)2016
 % change
 2015
 % change
 2014
Revenues$2,381
 (9) $2,603
 (20) $3,240
Operating income349
 8
 323
 (3) 333
Merger termination fee90
 NM
 —
 —
 —
Net income for common stock248
 55
 160
 (5) 168
Net income (loss) by segment:     
  
  
Electric utility$142
 5
 $136
 (1) $138
Bank57
 5
 55
 7
 51
Other49
 NM
 (31) NM
 (21)
Net income for common stock$248
 55
 $160
 (5) $168
Basic earnings per share$2.30
 53
 $1.50
 (9) $1.65
Diluted earnings per share$2.29
 53
 $1.50
 (8) $1.63
Dividends per share$1.24
 —
 $1.24
 —
 $1.24
Weighted-average number of common shares outstanding (millions)108.1
 2
 106.4
 4
 102.0
Dividend payout ratio54%  
 82%  
 75%
NMNot meaningful.
See “Executive overview and strategy” above and the “Other segment,” “Electric utility” and “Bank” sections below for discussions of results of operations.
Other segment. HEI corporate-level operating, general and administrative expenses were $19 million in 2016 compared to $34 million in 2015 and $21 million in 2014. In 2016, 2015 and 2014, HEI had approximately $1 million (expenses, net of reimbursements of expenses from NEE and insurance), $17 million and $5 million, respectively, of expenses related to the previously proposed merger with NEE.
The “other” segment’s interest expenses were $9 million in 2016, $11 million in 2015 and $12 million in 2014. In each of 2016, 2015 and 2014, HEI had lower average interest rates and borrowings when compared to the prior year. In 2016, a 4.41% senior note was refinanced to a lower rate Eurodollar term loan. In 2015, a $125 million Eurodollar term loan was amended at improved pricing.
The “other” segment’s income (taxes) benefits were $(9 million) in 2016, $16 million in 2015 and $13 million in 2014. In 2016, HEI’s other segment included $25 million of tax expense relating to merger- and spin-off (net of taxes) [comprised of taxes on merger termination fee and reimbursements of expenses from NEE and insurance ($34 million), partly offset by additional tax benefits on the previously non-tax-deductible merger- and spin-off-related expenses incurred in previous years ($6 million) and tax on 2016 merger-related expenses ($3 million)]. In 2016, HEI’s results also included other tax benefits recognized as a result of moving out of a federal net operating loss position.
Liquidity and capital resources. As a result of the Tax Act, utility property is no longer eligible for bonus depreciation. Consequently, the initial cash requirement for future capital projects will generally increase approximately 10% because of the loss of the immediate tax benefit from bonus depreciation. The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements for the foreseeable future.
The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:
December 312016 20152019 2018
(dollars in millions) 
  
  
  
   
  
  
Short-term borrowings—other than bank$—
 —% $103
 3%$186
 4% $74
 2%
Long-term debt, net—other than bank1,619
 43
 1,578
 43
1,964
 44
 1,880
 45
Preferred stock of subsidiaries34
 1
 34
 1
34
 1
 34
 1
Common stock equity2,067
 56
 1,928
 53
2,280
 51
 2,162
 52
$3,720
 100% $3,643
 100%$4,464
 100% $4,150
 100%
HEI’s short-termcommercial paper borrowings and HEI’s line of credit facility were as follows:
Year ended
December 31, 2016
  
Year ended
December 31, 2019
  
(in millions)
Average
balance
 
End-of-period
balance
 
December 31,
2015
Average
balance
 
End-of-period
balance
 
December 31,
2018
Short-term borrowings 1
     
Commercial paper$43
 $—
 $103
$41
 $97
 $49
Line of credit draws—
 —
 —
—
 —
 —
Undrawn capacity under HEI’s line of credit facility150
 150
 150
—
 150
 150
1
Note: This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Liquidity and capital resources” below. The maximum amount of HEI’s short-term borrowings in 2019 was $102 million.
This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” At February 13, 2017, HEI had no outstanding commercial paper and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2016 was $103 million.
HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements.requirements, including short-term financing needs of its subsidiaries. HEI also periodically makes short-term loans to Hawaiian Electric to meet Hawaiian Electric’s cash requirements, including the funding of loans by Hawaiian Electric to Hawaii Electric Light and Maui Electric, but no such short-term loans to Hawaiian Electric were outstanding as of December 31, 2016.2019. HEI periodically utilizes long-term debt, historically consisting of medium-term notes and other unsecured


indebtedness, to fund investments in and loans to its subsidiaries to support their capital improvement or other requirements, to repay long-term and short-term indebtedness and for other corporate purposes.
In March 2013, HEI entered into equity forward transactions in which a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties See Notes 5 and such borrowed shares were sold pursuant to an HEI registered public offering. See Note 9 of the Consolidated Financial Statements. In March 2015, HEI issued the 4.7 million shares remaining under the equity forward transaction for proceeds of $104.5 million.
In October 2015, HEI amended and extended a two-year $125 million term loan agreement that it entered into on May 2, 2014, which extended term loan now matures on October 6 2017. In March 2016, HEI entered into a $75 million term loan agreement with Bank of America, N.A., which matures on March 23, 2018. See Note 8 of the Consolidated Financial Statements for a brief description of the loan agreements.
In December 2014, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities.Company’s loans.
HEI has a $150 million line of credit facility with no amounts outstanding as amended and restated on April 2, 2014, of $150 million.December 31, 2019. See Note 75 of the Consolidated Financial Statements.
The rating of HEI’s commercial paper and debt securities could significantly impact the ability of HEI to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities.
In August 2016, Moody’s downgraded HEI’s short-term commercial paper rating to P-3 from P-2 and revised HEI's outlook to stable. In December 2016, S&P affirmed HEI’s long-term and short-term issuer credit rating of BBB- and A-3, respectively, with a stable outlook. In January 2017, Fitch affirmed HEI’s long-term issuer default rating at BBB with a stable outlook.


As of February 13, 2017,20, 2020, the Fitch, Moody'sMoody’s and S&P ratings of HEI were as follows:
 FitchMoody’sS&P&P**
Long-term issuer default, long-term and senior unsecured; senior unsecured*; and long-term issuer credit;credit, respectivelyBBB*WR*BBB-
Commercial paperF3P-3A-3
OutlookStableStablePositiveStablePositive
*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.
* Not rated.
Note: The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
Management believes that, if HEI’s commercial paper ratingsThere were to be downgraded, or if credit markets for commercial paper with HEI’s ratings or in general were to tighten, it could be more difficult and/or expensive for HEI to sell commercial paper or HEI might not be able to sell commercial paper in the future. Such limitations could cause HEI to draw on its syndicated credit facility instead, and the costsno new issuances of such borrowings could increase under the terms of the credit agreement as a result of any such ratings downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it could be more difficult and/or expensive for HEI to issue long-term debt. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of HEI and its subsidiaries.
From March 6, 2014common stock through January 5, 2016, HEI satisfied the share purchase requirements of the Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan (DRIP), Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) andor the ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances. From January 6, 2016 through December 6, 2016, HEI satisfied its share purchase requirements for the plans through new issuances, except that from June 2, 2016 through August 9, 2016,in 2019, 2018, or 2017 and HEI satisfied the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock. From December 7, 2016 to date, HEI satisfied the share purchase requirements of these three plans through open market purchases of its common stock rather than through new issuances. In 2016, the Company raised $30 million through the new issuances of approximately 1 million shares of common stock under the DRIP, HEIRSP and ASB 401(k) Plan. In 2014, the Company raised $3 million through the new issuances of approximately 0.1 million shares of common stock under the DRIP, HEIRSP and ASB 401(k) Plan.
Operating activities provided net cash of $495$512 million in 2016, $3562019 and $499 million in 2015 and $325 million in 2014.2018. Investing activities used net cash of $736$542 million in 2016, $7062019 and $792 million in 2015 and $592 million in 2014.2018. In 2016,2019, net cash used in investing activities was primarily due to a Hawaiian Electric’s consolidated capital expenditures, (net of contributions in aid of construction) and ASB's net increase in loans held for investment, and purchases of available-for-sale and held-to-maturity investment securities and stock from Federal Home Loan Bank and contributions to low-income housing investments, partly offset by thereceipt of repayments offrom available-for-sale and held-to-maturity investment securities, redemption of stock from Federal Home Loan Bank and proceeds from sale of available-for-sale investment securities and real estate held for sale. In 2018, net cash used in investing activities was primarily due to capital expenditures, purchases of available-for-sale investment securities, net increase in loans held for investment, purchases of held-to-maturity investment securities, purchase of stock from Federal Home Loan Bank and contributions to low-income housing investments, partly offset by receipt of repayments from available-for-sale investment securities, proceeds from the sale of commercial loans, redemption of stock from Federal Home Loan Bank and repayments from held-to-maturity investment securities.
Financing activities provided net cash of $219$88 million in 2016, $4752019 and $200 million in 2015 and $223 million in 2014.2018. In 2016,2019, net cash provided by financing activities included proceeds from issuance of long-term debt and short-term debt, net increases in deposits and long-term debt and net proceeds from the issuance of common stock,short-term borrowings, partly offset by a net decreases in short-term borrowings, ASB’s retail repurchase agreements and other borrowings and payment of common and preferred stock dividends. dividends, repayment of long-term debt and funds transferred for redemption of long -term debt and repayment of short-term debt. In 2018, net cash provided by financing activities included proceeds from issuance of long-term debt, net increases in deposits and retail repurchase agreements, partly offset by payment of common and preferred stock dividends, long-term debt maturities and net decreases in short-term debt and other bank borrowings.
For a discussion of 2017 operating, investing and financing activities, please refer to the “Liquidity and capital resources” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—HEI Consolidated,” in the Company’s 2018 Form 10-K.
Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition-Liquidity“Liquidity and capital resources” sections below.) During 2016,2019, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $94$101 million and $36$56 million, respectively.
A portion of the net assets of Hawaiian Electric and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. One of the conditions to the PUC’s approval of the corporate restructuring of Hawaiian Electric and HEI requires that Hawaiian Electric maintain a consolidated common equity to total capitalization ratio of not less than 35% (actual ratio of 57% at December 31, 2016), and restricts Hawaiian Electric from making distributions to HEI to the extent it would result in that ratio being less than 35%. In the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay


dividends on its common stock or its ability to meet its debt or other cash obligations. See Note 14 of the Consolidated Financial Statements.
Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 20172020 through 20192022 consists primarily of the net capital expenditures of the Utilities.Utilities, estimated to range from $1.1 billion to $1.3 billion over the next three years. In addition to the funds required for the Utilities’ construction programs and debt maturities (see “Electric utility–Liquidity and capital resources”) below), approximately $200$50 million will be required


during 2017 through 2019 in 2021 and $150 million in 2022 to repay HEI’s $125 million and $75 million two-year term loansHEI-issued private placement notes maturing in October 2017March 2021 and March 2018, respectively,November 2022, which are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, other medium- or long-term debt, common stock and/or dividends from subsidiaries. Additional debt and/or equity financing may be utilized to invest in the Utilities, and bank;bank or Pacific Current; to pay down commercial paper or other short-term borrowings; or to fund unanticipated expenditures not included in the 20172020 through 20192022 forecast, such as increases in the costs of, or an acceleration of, the construction of capital projects of the Utilities or unanticipated utility capital expenditures that may be required by the HCEI or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if certain tax positions taken by the Company do not prevail or if taxes are increased by federal or state legislation.expenditures. In addition, existing debt may be refinanced prior to maturity with additional debt or equity financing (or both).
Selected contractual obligations and commitments. Information about payments under the specified contractual obligations and commercial commitments of HEI and its subsidiaries was as follows:
December 31, 2016 
December 31, 2019 
(in millions)
Less than
1 year
 
1-3
years
 
3-5
years
 
More than
5 years
 Total
Less than
1 year
 
1-3
years
 
3-5
years
 
More than
5 years
 Total
Contractual obligations 
  
  
  
  
 
  
  
  
  
Investment in qualifying affordable housing projects$13
 $—
 $—
 $1
 $14
$13
 $9
 $—
 $1
 $23
Time certificates323
 176
 156
 3
 658
503
 200
 64
 3
 770
Short-term borrowings186
 —
 —
 —
 186
Other bank borrowings143
 50
 —
 —
 193
115
 —
 —
 —
 115
Long-term debt125
 125
 146
 1,231
 1,627
102
 267
 159
 1,446
 1,974
Interest on certificates of deposit, other bank borrowings and long-term debt82
 151
 140
 800
 1,173
Operating leases, service bureau contract, maintenance and ASB construction-related agreements35
 40
 27
 18
 120
Interest on CDs, other bank borrowings, short-term loan and long-term debt86
 158
 130
 718
 1,092
Operating leases         
PPAs classified as leases63
 105
 —
 —
 168
Other operating leases12
 16
 9
 9
 46
Service bureau contract, maintenance agreements and other20
 18
 4
 1
 43
Hawaiian Electric open purchase order obligations1
56
 114
 —
 —
 170
54
 19
 1
 —
 74
Hawaiian Electric fuel oil purchase obligations (estimate based on December 31, 2016 fuel oil prices)125
 238
 —
 —
 363
Hawaiian Electric power purchase obligations–minimum fixed capacity charges121
 188
 189
 388
 886
Liabilities for uncertain tax positions—
 4
 —
 —
 4
Hawaiian Electric fuel oil purchase obligations (estimate based on fuel oil price at December 31)7
 15
 —
 —
 22
Hawaiian Electric power purchase–minimum fixed capacity charges not classified as leases51
 76
 76
 241
 444
Total (estimated)$1,023
 $1,086
 $658
 $2,441
 $5,208
$1,212
 $885
 $443
 $2,419
 $4,959
1
Includes contractual obligations and commitments for capital expenditures and expense amounts.
The tablestable above dodoes not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, obligations that may arise under indemnities provided to purchasers of discontinued operations,and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism) and as. As of December 31, 2016,2019, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables above; however, see Note 10 toof the Consolidated Financial Statements for 2020 estimated contributions for 2017.contributions. There were no material uncertain tax positions as of December 31, 2019.
See Note 43 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments. See Note 54 of the Consolidated Financial Statements for a further discussion of ASB'sASB’s commitments.
The Company adopted ASU No. 2016-02 on January 1, 2019, which had a material effect on its balance sheet as of January 1, 2019 due to the recognition of lease liabilities and right-of-use assets. See Note 1, “Summary of Significant Accounting Policies—Recent accounting pronouncements—Leases,” and Note 8, “Leases,” of the Consolidated Financial Statements.
Off-balance sheet arrangements.  Although the Company and the Utilities have off-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s and the Utilities'Utilities’ financial condition, changes in financial condition, revenues or expenses,


results of operations, liquidity, capital expenditures or capital resources that are material to investors, including the following types of off-balance sheet arrangements:
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.
Certain factors that may affect future results and financial condition.  The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors. Also see “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” above and “Certain factors that may affect future results and financial condition” in each of the electric utility and bank segment discussions below.
Economic conditions, U.S. capital markets and credit and interest rate environment.  Because the core businesses of HEI’s subsidiaries are providing local electric public utility services and banking services in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates, particularly on the construction and real estate industries and by the impact of world conditions on federal government spending in Hawaii. The two largest components of Hawaii’s economy are tourism and the federal government (including the military).
If Fitch, Moody's or S&P were to downgrade HEI’s or Hawaiian Electric’s debt ratings or if future events were to adversely affect the availability of capital to the Company, HEI’s and Hawaiian Electric’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase.
Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obligations. The Utilities’ pension tracking mechanisms help moderate pension expense; however, a decline in the value of the Company’s defined benefit pension plan assets may increase the unfunded status of the Company’s pension plans and result in increases in future funding requirements.
Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. Changes in interest rates and credit spreads also affect the fair value of ASB’s investment securities. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return and overall economic activity. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.
Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. The Utilities’ transmission and distribution systems (excluding substation buildings and contents) have a replacement value roughly estimated at $7 billion and are largely uninsured. Similarly, the Utilities have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the Utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers also have exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to an insurance deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur uninsured losses in amounts that would have a material adverse effect on the Company’s results of operations, financial condition and liquidity.
Environmental matters.  HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, may require that certain environmental permits be obtained and maintained as a condition to constructing or operating certain facilities. Obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance.


Material estimates and critical accounting policies.  In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
Material estimates that are particularly susceptible to significant change include the amounts reported for pension and other postretirement benefit obligations; contingencies and litigation; income taxes; property, plant and equipment; regulatory assets and liabilities; electric utility unbilled revenues; allowance for loan losses; nonperforming loans; troubled debt restructurings;fair value; and fair value.asset retirement obligations. Management considers an accounting estimate to be material if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of operations or financial condition.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements--thatstatements—that is, management believes that the policies discussed below are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments. The policies affecting both of the Company’s two principal segments are discussed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and critical accounting policies.” Management has reviewed the material estimates and critical accounting policies with the HEI Audit & Risk Committee and, as applicable, the Hawaiian Electric Audit & Risk Committee.
For additional discussion of the Company’s accounting policies, see Note 1 of the Consolidated Financial Statements and for additional discussion of material estimates and critical accounting policies, see the electric utility and bank segment discussions below under the same heading.
Pension and other postretirement benefits obligations. The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, plus earnings and realized and unrealized gains and losses on plan assets, and changes made to the provisions of the plans. Costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on plan assets, the discount rate and mortality. The Company’s accounting for retirement benefits under the plans in which the employees of the Utilities participate is also adjusted to account for the impact of decisions by the Public Utilities Commission of the State of Hawaii (PUC).PUC. Changes in obligations associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.
Based on various assumptions in Note 10 of the Consolidated Financial Statements, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2016,2019, associated with a change in certain actuarial assumptions, were as follows and constitute “forward-looking statements”:
Actuarial assumption
Change in assumption
in basis points
Impact on HEI Consolidated
PBO or APBO
 
Impact on Consolidated Hawaiian Electric
PBO or APBO
(dollars in millions)    
Pension benefits    
Discount rate
‘+/- 50
$(140)(177)/$158202 $(130)(167)/$148190
Other benefits    
Discount rate
'‘+/- 50
(15)$(14)/17$15 (14)$(13)/16
Health care cost trend rate
'+/- 100
4/(4)3/(4)$15
Also, see Notes 1 and 10 of the Consolidated Financial Statements.


Contingencies and litigation.  The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the likelihood of any adverse judgments in or outcomes of these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.
In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also,


environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale.
See Notes 41, 3 and 54 of the Consolidated Financial Statements.
Income taxes.  Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities using tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from its tax advisors. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.
See Note 12 of the Consolidated Financial Statements.
Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 32 of the Consolidated Financial Statements. The discussion concerning Hawaiian Electric should be read in conjunction with its consolidated financial statements and accompanying notes.


Electric utility
Executive overview and strategy. The Utilities provide electricity on all the principal islands in the state, other than Kauai, to approximately 95% of the state’s population, and operate five separate grids. The Utilities’ mission is to provide innovative energy leadership for Hawaii, to meet the needs and expectations of customers and communities, and to empower them with affordable, reliable and clean energy. The goal is to create a modern, resilient, flexible, and dynamic electric grid that enables an optimal mix of distributed energy resources, (suchsuch as private rooftop solar),solar, demand response, and grid-scale resources to enable the creation of smart, sustainable, resilient communities and achieve the statutory goal of 100% renewable energy by 2045.
Transition to renewable energy.energy. The Utilities are fully committed to assistinga 100 percent renewable energy future for Hawaii and are partnering with the State of Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy by 2045. Hawaii’s RPS law was revised in the 2015 Legislature and requires electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045, respectively. Energy savings resulting from DSM
The Utilities have made significant progress on the path to clean energy efficiency programs and solar water heating do not count toward these RPS. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems and exceeded the 2015 RPS goal.goal two years early. The Utilities'Utilities’ RPS for 20162019 was about 25%, continuingapproximately 28% and the Utilities are on track to exceed the 2015 RPS goal on its way to achievingachieve the 2020 RPS goal of 30%,. The Utilities will continue to actively procure additional renewable energy post-2020 and expect to meet or exceed the Utilities lednext statutory RPS goal of 40% in advance of the nation in 2015 in the percentage of its customers who have installed PV systems.2030 compliance year. (See "Developments“Developments in renewable energy efforts” below).
In 2014, Hawaiian Electric, Also, since the Hawaii Electric Light and Maui Electric filed proposed Power Supply Improvement Plans (PSIPs) with the PUC, as required by PUC orders issuedClean Energy initiative was launched in April 2014 (see “April 2014 regulatory orders” in Note 4 of the Consolidated Financial Statements). Updated PSIPs were filed in April 2016 providing plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045. Under these plans,2008, the Utilities will support sustainable growth of private rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, and offer new products and serviceshave continued to customers (e.g., community solar, microgrids and voluntary “demand response” programs). In December 2016,reduce the Utilities filed a PSIP Update Report as ordered by the PUC. The updated plans describe greater and faster expansion of the Utilities’ renewable energy portfolio than in the plans filed in April 2016, and emphasize work that is in progress or planned over the next five years on each of the five islands the Utilities serve. The plans include the continued growth of private rooftop solar and describe the grid and generation modernization work needed to reliably integrate an estimated total of 165,000 private systems by 2030, more than double today’s total of 79,000, and additional grid-scale renewable energy resources. The Utilities already have the highest percentage of customers using private rooftop solar of any utility in the U.S. and customer-sited resources are seen as a key contributor to the growth of the renewable portfolio on every island. In addition, the plans forecast the addition of 360 MW of grid scale solar and 157 MW of grid scale wind, with 32 MW derived from community-based renewable energy (CBRE). The plans also include 115 MW from Demand Response (DR) programs, which can shift customer use of electricity to times when more renewable energy is available, potentially making room to add even more renewable resources. Unlike the April 2016 updated PSIPs, this update does not include the use of liquefied natural gas (LNG) to generate power in the near-term or the Kahe 3x1 Combined Cycle Plant. While LNG remains a potential lower-cost bridge fuel to be evaluated, the Utilities’ priority is to continueproduce electricity. The fuel consumption in 2019 was approximately 82.5 million gallons less than that consumed in 2008. The combination of replacing fossil fuel generation with renewables, overcustomer conservation efforts, and energy efficiency actions has allowed the next five yearsUtilities to achieve its 2020 greenhouse gas emissions reduction target of 16% (compared to a 2010 baseline) ahead of schedule in 2014. As of the end of 2019, the Utilities have achieved a 18% decrease in greenhouse gas emissions compared to 2010.
If the Utilities are not successful in meeting the RPS targets as federal tax incentivesmandated by law, the PUC could assess a penalty of $20 for renewables beginevery MWh that an electric utility is deficient. Based on the level of electricity sales in 2019, a 1% shortfall in meeting the 2020 RPS requirement of 30% would translate into a penalty of approximately $1.75 million. The PUC has the discretion to phase out. An interisland cable isreduce the penalty due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated. In addition to penalties under the RPS law, failure to meet the


mandated RPS targets would be expected to result in a higher proportion of fossil fuel-based generation than if the near-term plan,RPS target had been achieved, which states that its costs and benefits should continuein turn would be expected to be evaluated.
On October 1, 2015,subject Hawaiian Electric Hawaii Electric Light and Maui Electric to limited commodity fossil fuel price exposure under a fuel cost risk-sharing mechanism. Currently, the fuel cost risk-sharing mechanism apportions 2% of the fuel cost risk to the two utilities (and 98% to ratepayers) and has a maximum exposure (or benefit) of $3.1 million.
The Utilities are fully aligned with, and supportive of, state policy to achieve a 100% renewable energy future and have made significant progress in its transformation. This alignment with state policy is reflected in management compensation programs and the Utilities’ long-range plans, which include aspirational targets in order to catalyze action and accelerate the transition away from fossil fuels at a pace more rapid than dictated by current law. The long-range plans, including aspirational targets, serve as guiding principles in the Utilities’ continued transformation, and are updated regularly to adapt to changing technology, costs and other factors. While there is no financial penalty for failure to achieve the Utilities’ long-range aspirational objectives, the Utilities recognize that there is an environmental and social cost from the continued use of fossil fuels.
The state’s policy is supported by the regulatory framework and includes a number of mechanisms designed to provide utility financial stability during the transition toward the state’s 100% renewable energy future. Under the sales decoupling mechanism, the Utilities are allowed to recover from customers, target test year revenues, independent of the level of kWh sales, which have generally declined (with the exception of 2019), as privately-owned distributed energy resources have been added to the grid and energy efficiency measures have been put into place. Other regulatory mechanisms reduce regulatory lag, such as the rate adjustment mechanism to provide revenues for escalation in certain O&M expenses and rate base changes between rate cases, and the major project interim recovery mechanism, which allow the Utilities to recover and earn on certain approved major capital projects placed into service in between rate cases. See “Decoupling” in Note 3 of the Consolidated Financial Statements.
Integrated Grid Planning. Achieving 100% renewable energy will require modernizing the grid through coordinated energy system planning in partnership with local communities and stakeholders. To accomplish this, the Utilities filed its Integrated Grid Planning (IGP) Report with the PUC on March 1, 2018, which provides an innovative systems approach to energy planning intended to yield the most cost-effective renewable energy pathways that incorporates customer and stakeholder input.
The PUC opened a docket to review the IGP process that the Utilities had proposed, and the resulting plans. In March 2019, the PUC accepted the Utilities’ IGP Work plan submitted on December 14, 2018, which describes the timing and scope of major activities that will occur in the IGP process. The IGP utilizes an inclusive and transparent Stakeholder Engagement model to provide an avenue for interested parties to engage with the Companies and contribute meaningful input throughout the IGP process. The IGP Stakeholder Council, Technical Advisor Panel and Working groups have been established and meet regularly to provide feedback and input on specific issues and process steps in the IGP.
Demand response programs. Pursuant to PUC orders, the Utilities are developing an integrated Demand Response (DR) Portfolio Plan that will enhance system operations and reduce costs to customers. The reduction in cost for the customer will take the form of either rates or incentive-based programs that will compensate customers for their participation individually, or by way of engagements with turnkey service providers that contract with the Utilities to aggregate and deliver various grid services on behalf of participating customers and their distributed assets.
In October 2017, the PUC approved the Utilities’ request made in December 2015 to defer and recover certain computer software and software development costs for a DR Management System in an amount not to exceed $3.9 million, exclusive of allowance for funds used during construction, through the Renewable Energy Infrastructure Program (REIP) Surcharge. The Utilities placed the DR Management System in service in the first quarter of 2019. On October 30, 2019, the Utilities filed the final cost report, reflecting total project costs of $3.7 million. On February 27, 2020, the PUC approved the Utilities’ request to recover deferred and other related costs of DR Management System through REIP Surcharge effective March 1, 2020 until such costs are included in determining base rates.
On January 25, 2018, the PUC approved the Utilities’ revised DR Portfolio tariff structure. The PUC supported the approach of working with aggregators to implement the DR portfolio. In 2019, the Utilities signed a multi-year Grid Services Purchase Agreement with a third party aggregator. These contracts pay service providers to aggregate grid-supporting capabilities from customer-sited Distributed Energy Resources. The first of these five-year contracts in a not-to exceed amount of $22 million has been executed (PUC approval obtained on August 9, 2019) and is expected to not only deliver benefit through efficient grid operations but also avoided fuel costs over that 5-year period. The Utilities will select the next set of aggregators in the first quarter of 2020. As the PUC considers Performance-based Regulation, demonstrated savings resulting from these contracts could results in shared savings for the Utilities. This complements the Utilities’ transformation and supports customer choice.
Grid modernization. The overall goal of the Grid Modernization Strategy is to deploy modern grid investments at an appropriate priority, sequence and pace to cost-effectively maximize flexibility, minimize the risk of redundancy and


obsolescence, deliver customer benefits and enable greater DER and renewable energy integration. Under the Grid Modernization Strategy, new technology will help triple private rooftop solar and make use of rapidly evolving products, including storage and advanced inverters. The Utilities have begun work to implement the Grid Modernization Strategy Phase 1, which received PUC approval on March 25, 2019. The estimated cost for this initial phase is approximately $86 million and is expected to be incurred over five years. The Utilities filed an application with the PUC on September 30, 2019 for an Advanced Distribution Management System as part of the second phase of their Grid Modernization implementation. The estimated cost for the implementation over five years of the Advanced Distribution Management System, which includes capital, deferred and O&M costs, is $46 million. Additional applications will be filed later to implement subsequent phases of the strategy. On December 30, 2019, the PUC suspended the Utilities’ application for the Advanced Distribution Management System pending the Utilities’ filing of a supplemental application for the broad deployment of field devices.
Community-based renewable energy. In December 2017, the PUC adopted a community-based renewable energy (CBRE) program and tariff with the PUC that will allowframework which allows customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. The program if approved byhas two phases.
The first phase, which commenced in July 2018, totals 8 MW of solar photovoltaic (PV) only with one credit rate for each island. The Utilities’ role is limited to administrative only during the first phase. As administrators, the Utilities will work with subscriber organizations to allocate capacity, answer general program questions, verify subscriber eligibility and process bill credits for subscribers. The Utilities are in the process of verifying the projects and awarding the capacity to interested subscriber organizations.
The second phase will commence after review of the first full year of the first phase. The second phase is contemplated to be a larger capacity and include multiple credit rates (e.g., time of day) and various technologies. The Utilities will have the opportunity to develop self-build projects; however 50% of utility capacity will be reserved for low to moderate income customers.
The PUC would allow customersheld an informal technical conference on July 5, 2019 to buy an interest in electricity generated by community renewable projects onreview progress and status to the first phase and to solicit recommendations for the second phase. On August 19, 2019, the Utilities and the Joint Parties submitted their island without installing systems on their own roofs or property. In November 2015, the PUC suspended the tariff submittal and opened an investigatory docket. In February 2017, the PUC issued a proposed CBRE Program Framework, a Proposed Model Tariff Language, and requested comments and feedback from the parties by March 1, 2017. Under the proposed CBRE Program Framework, the CBRE program will utilize a phased approach. The Program Framework proposes a Phase 1 with an 80 MW capacity statewide with 73 MW allocated to the Utilities' service territories. During the two year initial phase, the Utilities' primary role is to serve as the program administrator. In addition, the Framework requires a minimum allocation of 7.5 MW to develop CBRE targeting low-to-moderate income subscribers with 6.75 MW allocated to the Utilities' service territories.
After launching a smart grid customer engagement plan duringrecommendations for the second quarter of 2014, Hawaiian Electric replaced approximately 5,200 residential and commercial meters with smart meters, 160 direct load control switches, fault circuit indicators and remote controlled switches in selected areas across Oahu as part of the Smart Grid Initial Phase implementation. Also under the Initial Phase a grid efficiency measure called Volt/Var Optimization (or Conservation Voltage Reduction) was enabled, customer energy portals were launched and are available for customer use and a PrePay Application was launched. The Initial Phase implementation was completed in 2015. The smart grid provides benefits such as customer tools to manage their electric bills, potentially shortening outages and enabling the Utilities to integrate more low-cost renewable energy, like wind and solar, which will reduce Hawaii’s dependence on imported oil.phase.
Microgrid services tariff proceeding. In March 2016, the Utilities sought PUC approval to commit


funds for an expansion of the smart grid project. The proposed smart grid project was estimated to cost $340 million and be implemented over 5 years (beginning in 2017 for Oahu andJuly 2018, for Hawaii Island and Maui County). On January 4, 2017, the PUC issued an order dismissinginstituting a proceeding to investigate establishment of a microgrid services tariff, pursuant to Act 200 of 2018. The PUC granted motions to intervene in the application without prejudicedocket by eight parties (there are currently six parties) and directing the Utilities to submit a Grid Modernization Strategy.
Decoupling.completed its initial procedural schedule in March 2019. In 2010,August 2019, the PUC issued an order approving decoupling, which was implementedstating that the focus for the remainder of the docket is to facilitate the ability of microgrids to disconnect from the grid and provide backup power to customers and critical energy uses during contingency events.
The PUC also required the parties to form two Working Groups: (1) a Market Facilitation Working Group to recommend draft tariff language for the Microgrid Services Tariff; and (2) an Interconnection Standards Working Group to develop a new section of Rule 14H specific to interconnection and islanding/reconnection of microgrids. The Utilities are to file a Draft Microgrid Services Tariff and Rule 14H Updates by the Utilities in 2011 and 2012. The decoupling model implemented delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers and are in the public interest. On February 7, 2014 and March 31, 2015, the PUC issued orders to make certain modifications to the decoupling mechanism.30, 2020.
Decoupling. See "Decoupling"“Decoupling” in Note 43 of the Consolidated Financial Statements for a discussion of changes to the RAM mechanism.decoupling.
As part of decoupling, the Utilities also track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility'sutility’s rate-making ROACE is compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. Annual earnings of a utility over and above the ROACE allowed by the PUC are shared between the utility and its ratepayers on a tiered basis. The earnings sharing mechanism was not triggered for any of the utilities in 2016 or 2015. For 2014, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric credited $0.5 million to its customers for their portion of the earnings sharing during the period between June 2015 to May 2016. Earnings sharing credits are included in the annual decoupling filing for the following year. Results for 2019, 2018 and 2017 did not trigger the earnings sharing mechanism for the Utilities.
Annual decoupling filingsRegulated returns. See “Decoupling” in Note 4 of the Consolidated Financial Statements for a discussion of the 2016 annual decoupling filings.
Regulated Returns. Actual and PUC-allowed (asreturns, as of December 31, 2016) returns2019, were as follows:
% Rate-making Return on rate base (RORB)* ROACE** Rate-making ROACE***
Year ended December 31, 2019 Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric
Utility returns 6.90
 5.97
 6.37
 8.02
 7.00
 7.79
 8.80
 6.72
 7.95
PUC-allowed returns 7.57
 7.52
 7.43
 9.50
 9.50
 9.50
 9.50
 9.50
 9.50
Difference (0.67) (1.55) (1.06) (1.48) (2.50) (1.71) (0.70) (2.78) (1.55)

% Return on rate base (RORB)* ROACE** Rate-making ROACE***
Year ended December 31, 2016 Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric
Utility returns 7.48
 6.73
 6.99
 8.26
 7.28
 8.08
 9.46
 7.61
 8.34
PUC-allowed returns 8.11
 8.31
 7.34
 10.00
 10.00
 9.00
 10.00
 10.00
 9.00
Difference (0.63) (1.58) (0.35) (1.74) (2.72) (0.92) (0.54) (2.39) (0.66)
*       Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.
**     Recorded net income divided by average common equity.
***   ROACE adjusted to remove items not included by the PUC in establishing rates, such as incentive compensation and certain advertising.compensation.


The 2016 gap between PUC-allowed ROACEs and the ROACEs actually achieved is primarily due to: the consistent exclusion of certain expenses from rates (for example, incentive compensation and charitable contributions), the low RBA interest rate (currently a short-term debt raterecognition of annual RAM revenues on June 1 annually rather than the actual cost of capital),on January 1, and O&M increases and return on capital additions since the last rate case in excess of indexed escalations, and the portion of the pension regulatory asset not earning a return due to pension contributions and pension costs in excess of the pension amount in rates.




escalations.
Results of operations.
20162019 vs. 2015
2018
2016 2015 Increase (decrease) (dollars in millions, except per barrel amounts)
$2,094
 $2,335
 $(241)  
 
Revenues. Net decrease largely due to:
     
 $(198) 
lower fuel prices1
     
 (33) 
lower purchased power expense2
     
 (25) lower KWH generated
      15
 higher RAM revenues
455
 655
 (200)   
Fuel oil expense. Decrease due to lower fuel cost and lower KWH generated
563
 594
 (31)  
 
Purchased power expense. Decrease due to lower purchased power energy prices, largely due to lower fuel prices2
406
 413
 (7)  
 
Operation and maintenance expense. Net decrease due to:
     
 (5) write off of ERP software costs in 2015, as a result of a PUC ERP/EAM decision
     
 (4) 
additional reserve for environmental costs in 20153
      (1) lower storm weather repairs
      3
 higher PSIP consulting costs incurred in 2016, in order to complete the PSIP update in April 2016 and December 2016
      1
 higher LNG consulting costs to negotiate LNG contract, which was subsequently terminated following HEI/Nextera merger termination
387
 399
 (12)  
 
Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
284
 274
 10
  
 
Operating income. Increase due to an overall decrease in expenses
142
 136
 6
  
 
Net income for common stock. Increase due to higher operating income
8.1% 8.0% 0.1%   Return on average common equity
53.49
 74.71
 (21.22)   
Average fuel oil cost per barrel 1
8,845
 8,957
 (112)   
Kilowatthour sales (millions) 4
4,788
 5,082
 (294)   Cooling degree days (Oahu)
2,662
 2,727
 (65)   Number of employees (at December 31)
2019 2018 Increase (decrease) (dollars in millions, except per barrel amounts)
$2,546
 $2,547
 $(1)  
 
Revenues. Net decrease largely due to:
      $(45) 
net of lower fuel prices and higher kWh generated11
      (6) 
net of lower purchased power energy costs and higher kWh purchased2
      26
 higher electric rates
      16
 MPIR for Schofield Generating Station
      3
 higher PIM award due to low-cost variable renewable procurement, better reliability and call center performance
      2
 billing to a third party for mutual assistance work reimbursement
      2
 higher state refundable credit due to reduction in amortization period
      1
 pole attachment revenues
721
 761
 (40)   
Fuel oil expense.1  Net decrease due to lower fuel oil prices offset in part by higher kWh generated
633
 639
 (6)  
 
Purchased power expense1,2. Net decrease largely due to lower purchased power energy price offset in part by higher kWh purchased
482
 461
 21
  
 
Operation and maintenance expense. Increase largely due to:
     
 7
 higher outside services for system support (Asset management, Energy Management, Enterprise Resources and Grid Modernization systems)
      7
 higher generation overhaul costs
      3
 reset of pension costs included in rates as part of rate case decisions
      2
 higher preventive/corrective maintenance expense for generation facilities
      2
 higher medical premium costs
456
 444
 12
  
 
Other expenses. Increase due to higher depreciation expense for plant investments in 2018
254
 242
 12
  
 
Operating income. Increase due to higher electric rates, offset in part by higher operation and maintenance, and depreciation expenses
197
 180
 17
   
Income before income taxes. Increase due to higher electric rates, lower interest expense related to the hybrid securities redemption replaced with lower cost debt and refinancing of revenue bonds and higher AFUDC, offset in part by higher operation and maintenance and depreciation expense
157
 144
 13
  
 
Net income for common stock. Increase due to higher electric rates and MPIR revenues, offset in part by higher operating expenses
7.8% 7.6% 0.2%   Return on average common equity
82.17
 87.90
 (5.73)   Average fuel oil cost per barrel
8,740
 8,689
 51
   
Kilowatthour sales (millions) 3
2,670
 2,704
 (34)   Number of employees (at December 31)
1 
The rate schedules of the electric utilities currently contain energy cost adjustment clauses (ECACs)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 scheduleschedules of the electric utilities currently contain purchase power adjustment clauses (PPAC)PPACs through which changes in purchase power expenses (except purchased energy costs) are passed on to customers.
3 
Costs to complete Waiau Power Plant's onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment in 2015.
4
KWHkWh sales were lowerhigher in 20162019 when compared to the prior year due largely to continued energy efficiency and conservation efforts by customers and increasing levels of private customer-sited renewable generation.warmer humid weather in 2019 than 2018.

Hawaiian Electric’s effective tax rate (combined federal and state income tax rates) in 2019 and 2018 was comparable at 19%. Income tax expense for 2019 reflects higher amortization in 2019 versus 2018 of the Utilities’ regulatory liability related to certain excess deferred income taxes resulting from the Tax Act’s decrease in federal income tax rate, while 2018 income tax expense reflects certain tax return adjustments recorded in 2018 relating to the benefit associated with additional tax deductions taken in the Company’s 2017 tax returns in conjunction with the rate differential provided in the Tax Act.
For a discussion of 2017 results, please refer to the “Results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Electric utility,” in the Company’s 2018 Form 10-K.




The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of December 31, 2019 amounted to $4 billion, of which approximately 29% related to generation PPE, 62% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 9% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission.
2015 vs. 2014
2015 2014 Increase (decrease) (dollars in millions, except per barrel amounts)
$2,335
 $2,987
 $(652)  
 
Revenues. Decrease largely due to:
     
 $(520) 
lower fuel prices1
     
 (134) 
lower purchased power energy costs2
     
 2
 higher KWH purchased
655
 1,132
 (477)  
 
Fuel oil expense. Decrease largely due to lower fuel costs and lower KWH generated
594
 722
 (128)  
 
Purchased power expense. Decrease due to lower purchased power energy
prices, largely due to lower fuel prices, offset by higher KWH purchased
413
 411
 2
  
 
Operation and maintenance expense. Net increase due to:
     
 5
 ERP software costs write off resulting from PUC ERP/EAM decision in 2015
     
 4
 
additional reserves for environmental costs3
      3
 higher employee benefit costs due to affordable care act costs and higher health insurance premiums
      (9) higher 2014 smart grid initial phase costs
399
 447
 (48)  
 
Other expenses. Decrease in revenue taxes due to lower revenue, offset by higher
depreciation expense for plant investments
274
 276
 (2)  
 
Operating income. Decrease due to lower revenues
136
 138
 (2)  
 
Net income for common stock. Decrease due to lower operating income
8.0% 8.4% (0.4)%   Return on average common equity
74.71
 129.65
 (54.94)   
Average fuel oil cost per barrel 1
8,957
 8,976
 (19)   
Kilowatthour sales (millions) 4
5,082
 4,909
 173
   Cooling degree days (Oahu)
2,727
 2,759
 (32)   Number of employees (at December 31)
1
The rate schedules of the electric utilities currently contain energy cost adjustment clauses (ECACs) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.
2
The rate schedule of the electric utilities currently contain purchase power adjustment clauses (PPAC) through which changes in purchase power expenses (except purchased energy costs) are passed on to customers.
3
Costs to complete Waiau Power Plant's onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment in 2015.
4
KWH sales were lower in 2015 when compared to the prior year due largely to continued energy efficiency and conservation efforts by customers and increasing levels of private customer-sited renewable generation.

Most recent rate proceedings.  Unless otherwise agreed or ordered, each electric utility is currently required by PUC order to initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and to allow the utility to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability.reliability and integrate more renewable energy. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O.decision and order (D&O). The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.




Hawaiian Electric filed for a rate increase based on a 2020 test year in August 2019. Hawaii Electric Light filed its 2019 test year rate case in December 2018. Interim rates for Hawaii Electric Light’s 2019 rate case became effective on January 1, 2020, based on an interim order issued in November 2019 maintaining revenues at current effective rates. Final rates for Maui Electric’s 2018 rate case were effective on June 1, 2019 based on ruling in a D&O issued on March 18, 2019. Rates resulting from the March 2019 D&O were lower than what had been allowed in the interim order and Maui Electric refunded approximately $0.5 million to customers in June and July 2019.
Test year
(dollars in millions)
 
Date
(filed/
implemented)
 Amount 
% over 
rates in 
effect
 
ROACE
(%)
 
RORB
(%)
 
Rate
 base
 
Common
equity
%
 
Stipulated 
agreement 
reached with
Consumer
Advocate
 
Date
(filed/
implemented)
 Amount 
% over 
rates in 
effect
 
ROACE
(%)
 
RORB
(%)
 
Rate
 base
 
Common
equity
%
 
Stipulated 
agreement 
reached with
Consumer
Advocate
Hawaiian Electric    
  
  
  
  
  
      
  
  
  
  
  
  
2011 (1)
    
  
  
  
  
  
  
20171
20171
  
  
  
  
  
  
Request 7/30/10 $113.5
 6.6
 10.75
 8.54
 $1,569
 56.29
 Yes 12/16/16 $106.4
 6.9
 10.60
 8.28
 $2,002
 57.36
 Yes
Interim increase 7/26/11 53.2
 3.1
 10.00
 8.11
 1,354
 56.29
   2/16/18 36.0
 2.3
 9.50
 7.57
 1,980
 57.10
 
Interim increase (adjusted) 4/2/12 58.2
 3.4
 10.00
 8.11
 1,385
 56.29
  
Interim increase (adjusted) 5/21/12 58.8
 3.4
 10.00
 8.11
 1,386
 56.29
  
Interim increase with Tax Act 4/13/18 (0.6) —
 9.50
 7.57
 1,993
 57.10
 
Final increase 9/1/12 58.1
 3.4
 10.00
 8.11
 1,386
 56.29
   9/1/18 (0.6) —
 9.50
 7.57
 1,993
 57.10
 
2014 (2)
             
Request 6/27/14             
2017 (3)
  
  
  
  
  
  
2020    
  
  
  
  
  
  
Request
 12/16/16 $106.4
 6.9
 10.60
 8.28
 2,002
 57.36
  8/21/19 $77.6
 4.1
 10.50
 7.97
 $2,477
 57.15
 
Hawaii Electric Light    
  
  
  
  
  
               
2010 (4)
    
  
  
  
  
  
  
20162
             
Request 12/9/09 $20.9
 6.0
 10.75
 8.73
 $487
 55.91
 Yes 9/19/16 $19.3
 6.5
 10.60
 8.44
 $479
 57.12
 Yes
Interim increase 1/14/11 6.0
 1.7
 10.50
 8.59
 465
 55.91
   8/31/17 9.9
 3.4
 9.50
 7.80
 482
 56.69
 
Interim increase (adjusted) 1/1/12 5.2
 1.5
 10.50
 8.59
 465
 55.91
  
Interim increase with Tax Act 5/1/18 1.5
 0.5
 9.50
 7.80
 481
 56.69
 
Final increase 4/9/12 4.5
 1.3
 10.00
 8.31
 465
 55.91
   10/1/18 —
 —
 9.50
 7.80
 481
 56.69
 
2013 (5)
    
  
  
  
  
  
  
20193
             
Request 8/16/12 $19.8
 4.2
 10.25
 8.30
 $455
 57.05
   12/14/18 $13.4
 3.4
 10.50
 8.30
 $537
 56.91
 
Closed 3/27/13  
  
  
  
  
  
  
2016 (6)
           
Request 9/19/16 $19.3
 6.5
 10.60
 8.44
 $479
 57.12
 
Interim increase 1/1/20 0.0
 0.0
 9.50
 7.52
 534
 56.83
 
Maui Electric    
  
  
  
  
  
      
  
  
  
  
  
  
2012 (7)
    
  
  
  
  
  
  
20184
             
Request 7/22/11 $27.5
 6.7
 11.00
 8.72
 $393
 56.85
 Yes 10/12/17 $30.1
 9.3
 10.60
 8.05
 $473
 56.94
 Yes
Interim increase 6/1/12 13.1
 3.2
 10.00
 7.91
 393
 56.86
   8/23/18 12.5
 3.8
 9.50
 7.43
 462
 57.02
 
Final increase 8/1/13 5.3
 1.3
 9.00
 7.34
 393
 56.86
   6/1/19 12.2
 3.7
 9.50
 7.43
 454
 57.02
 
2015 (8)
             
Request 12/30/14             
Note:  The “Request Date”“Request” date reflects the application filing date for the rate proceeding. All other line items reflectThe “Interim increase” and “Final increase” date reflects the effective datesdate of the revised schedules and tariffs as a result of the PUC-approved increases.
(1)   Hawaiian Electric filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by Hawaiian Electric in a separate depreciation proceeding. Hawaiian Electric’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.
The $53.2 million, $58.2 million and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.
(2)   See “Hawaiian Electric 2014 test year rate case” below.
(3)   See “Hawaiian Electric 2017 test year rate case” below.
(4)
1
Hawaii Electric Light’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses. On February 8, 2012, the PUC issued a finalFinal D&O which reflected the approval of decoupling and cost-recovery mechanisms, andwas issued on February 21, 2012, Hawaii Electric Light filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. Hawaii Electric Light implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. Hawaii Electric Light also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.June 22, 2018.

2 Final D&O was issued on June 29, 2018.
3 The Interim D&O issued on November 13, 2019 approved an adjustment to base rates to maintain revenues at current effective rates.
4 A D&O issued on May 16, 2019 approved Maui Electric’s revised revenue requirements filed based on the March 2019 D&O and final rates which took effect on June 1, 2019.


(5)   Hawaii Electric Light’s request was to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. As a result of a 2013 agreement with the Consumer Advocate, which was approved by the PUC in March 2013, the
See also “Most recent rate case was withdrawn and the docket was closed.
(6)See “Hawaii Electric Light 2016 test year rate case” below.
(7)   Maui Electric’s request was to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. See discussion on final D&O, including the refund to customers in September and October 2013 required as a result of the final D&O,proceedings” in Note 43 of the Consolidated Financial Statements.
(8)See “Maui Electric 2015 test year rate case” below.
Hawaiian Electric 2014 test yearThe effects of the Tax Act on the Utilities’ regulated operations accrued to the benefit of customers from the effective date of January 1, 2018 and were addressed in the Utilities’ rate case.  On October 30, 2013 Hawaiian Electric filed withcases summarized above. Generally, the PUC a Notice of Intent to file an application for a generallower corporate income tax rate case (on or after January 2, 2014, but before June 30, 2014, using a 2014 test year)lowers the Utilities’ revenue requirements through lower income tax expense and a motion, which was subsequently recommended bythrough the Consumer Advocate, for approval of test period waiver. Hawaiian Electric’s filingamortization of a 2014 rate case would be in accordance with a PUC order which callsregulatory liability for a mandatory triennial rate case cycle. On March 7, 2014, the PUC issued an order granting Hawaiian Electric’s motion to waive the requirement to utilize a split test year, and authorized a 2014 test year.
On June 27, 2014, Hawaiian Electric submitted an abbreviated rate case filing (abbreviated filing), stating that it intends to forgo the opportunity to seek a general rate increase in base rates, and if approved, this filing would result in no change in base rates. Hawaiian Electric stated that it is foregoing a rate increase request in recognition that its customers are already in a challenging high electricity bill environment, and further explained its view that the abbreviated filing satisfies the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O.
On December 27, 2016, the PUC issued an order consolidating the filings for this rate case with the Hawaiian Electric 2017 test year rate case and closed the docket.
Maui Electric 2015 test year rate case.  On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby foregoing the opportunity to seek a general rate increase. If Maui Electric were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 RAM revenues. The normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%. Management cannot predict any actions by the PUC as a result of this filing.
Management cannot predict whether the PUC will accept this abbreviated filing to satisfy Maui Electric’s obligation to file a rate case in 2015, whether additional material will be required or whether Maui Electric will be required to proceed with a traditional rate proceeding.
Hawaii Electric Light 2016 test year rate case. On September 19, 2016, Hawaii Electric Light filed an application with the PUC for a general rate increase of $19.3 million over revenues at current effective rates (for a 6.5% increase in revenues), based on an 8.44% rate of return (which incorporates a return on equity of 10.60%). The last rate increase in base rates for Hawaii Electric Light was in January 2011. The $19.3 million requested is to cover higher operating costs (including expanded vegetation management focusing on albizia tree removal and increased pension costs) and system upgrades to increase reliability, improve customer service and integrate more renewable energy. As part of this case, Hawaii Electric Light is also taking steps towards innovative ratemaking by proposing implementation of performance based regulation (PBR) mechanisms to measure and link certain revenues to its performance in areas of customer service, reliability and communication relating to the private rooftop solar interconnection process. Hawaii Electric Light pointed out that it has increased its use of renewables from 34.6% Renewable Portfolio Standards (RPS) in 2010 to 48.7% RPS in 2015, using wind, hydroelectricity, solar and geothermal resources to generate electricity. Hawaii Electric Light also proposed revenue adjustments to recover costs associated with the acquisition and operation of the power plant currently owned by Hamakua Energy Partners, L.P. Hawaii Electric Light requested approval of the acquisition of this power plant in a separate application filed on February 12, 2016.
The PUC held public hearings for this rate case in December 2016. Four parties filed motions to intervene or participate. Decisionsexcess accumulated deferred income taxes (ADIT) resulting from the PUC on these motions are pending.
Hawaiian Electric 2017 test year rate case. On December 16, 2016, Hawaiian Electric filed an application withrecording of ADIT in prior years at the PUC for a general rate increase of $106.4 million overhigher income tax rate. The revenues at current effective rates (for a 6.9% increase in revenues), for a 2017 test year. The request is based on an 8.28% rate of return (which incorporates a return on equity of 10.6% and a capital structure that includes a 57.4% common equity capitalization) on a $2.0 billion rate base. The $106.4 million request is primarily to pay for operating costs and for system upgrades to increase reliability, improve customer service and integrate


more renewable energy. The application is also proposing a step adjustment to increase base rates by $20.6 million when the Schofield Generation Station is placed in service, which is expectedcollected in the first and a portion of the second quarters of 2018 reflected income taxes at the old 35% rate and consequently, the Utilities reduced revenues to the extent the income taxes collected revenue exceeded the taxes accrued at the new 21% rate. This reduction was recorded to a regulatory liability and electric rates were adjusted in the second quarter of 2018. Similar2018 to initiate the application in Hawaii Electric Light’s rate increase application filed in September 2016, as partreturn of the proceeding, Hawaiian Electric is taking steps toward innovative ratemaking2018 excess to customers over various amortization periods. In addition, rates were adjusted in 2018 to begin returning the excess ADIT that was accumulated as of December 31, 2017. The Tax Act also excludes the Utilities’ asset additions from qualifying for bonus depreciation (except for certain grandfathered utility property), which has the offsetting effect of increasing revenue requirement by proposing implementation of performance basedlowering ADIT and thereby increasing rate base on a prospective basis.
Performance-based regulation (PBR) mechanisms related to its performance in areas of customer service, reliability. See “Performance incentive mechanisms” and communication relating to the private rooftop solar interconnection process.
On December 27, 2016, the PUC issued an order consolidating the Hawaiian Electric filings for the 2014 test year abbreviated rate case and the 2017 test year rate case. The order also found and concluded that Hawaiian Electric's abbreviated 2014 rate case filing did not comply with: (1) the Mandatory Triennial Rate Case Cycle requirement that Hawaiian Electric file an application for a general rate case every three years, and (2) the requirement that Hawaiian Electric file its 2014 calendar test year rate case application by June 27, 2014. The order then stated that: “[T]he determination and disposition of any rates, accounts, adjustment mechanisms, and practices that would have been subject to review in the context of a 2014 test year rate case proceeding are subject to appropriate adjustment based on evidence and findings in the consolidated rate case proceeding.” On January 4, 2017, Hawaiian Electric filed a motion for clarification and/or partial reconsideration, stating that the finding of violations without a hearing raises issues regarding the due process right to a hearing, and that it contests the findings of violation, stating that the abbreviated rate case filing was comprehensive and satisfied the applicable requirements of the PUC’s rules. Hawaiian Electric requested clarification that it will be afforded the opportunity to a full and fair hearing on the violations and potential remedies alleged in the order. Hawaiian Electric also requested clarification that the PUC does not intend to make any retroactive or single issue rate adjustments to Hawaiian Electric's rates prior to 2017, but instead intended to reserve the right to use the information filed in the 2014 test year rate case to inform its decision about the reasonableness of Hawaiian Electric's 2017 test year rate increase prospectively.
Integrated resource planning and April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively provide certain key policy, resource planning, and operational directives to the Utilities. See “April 2014 regulatory orders”“Performance-based regulation proceeding” in Note 4 to3 of the Consolidated Financial Statements.
Developments in renewable energy efforts.efforts.  Developments in the Utilities’ efforts to further their renewable energy strategy include renewable energy projects discussed in Note 3 of the Consolidated Financial Statements and the following:
New renewable PPAs.
In August 2012,December 2014, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for construction of a 50-MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu. In September 2015, the PUC approved Hawaiian Electric's application with conditions and limitations. See "Schofield Generating Station Project" in Note 4 of the Consolidated Financial Statements. Once online, biodiesel currently delivered to Hawaiian Electric's Campbell Industrial Park Combustion Turbine 1 (CIP CT-1) will be diverted to the Schofield Generating Station at no additional cost.
In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s (NPM) proposed 24-MW wind farm located in the Kahuku area on Oahu from the competitive bidding process and the PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and NPMNa Pua Makani Power Partners, LLC (NPM) for thea proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA. On September 15, 2016, Hawaiian Electric filed the Amended and Restated PPA, dated August 12, 2016, which reflects the completion of the interconnection requirements study, including, among other things, amendments related to the final design of the facility, scope of work, cost, schedule and reporting milestones.farm on Oahu. The PUC conducted a public hearing on February 2, 2017, regarding the request for PUC approval to construct an overhead 46 sub-transmission line to accommodate the interconnection of the NPM wind farm. This project isfarm 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 2015,2017, the PUC approved, the PPAwith certain modifications and conditions, three PPAs for the 27.6solar energy on Oahu with Waipio PV, LLC for 45.9 MW, WaianaeLanikuhana Solar, project thatLLC 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 being developed by Eurus Energy America. The projectGlobal Infrastructure Partners. On September 19, 2019, Lanikuhana Solar and Waipio PV projects achieved commercial operations in January 2017 and is now the largest solar project in Hawaii.operations. On November 20, 2019, Kawailoa Solar, LLC achieved commercial operations.
In July 2015, Maui Electric signed two PPAs, with Kuia Solar and South Maui Renewable Resources (which subsequently assigned its PPA to SSA Solar of HI 3, LLC), each for a 2.87-MW solar facility. In February 2016,2018, the PUC approved both PPAs, subjectMaui Electric’s PPA with Molokai New Energy Partners to certain conditions and modifications.purchase solar energy from a PV plus battery storage project. The guaranteed commercial operations date for4.88 MW project will deliver no more than 2.64 MW at any time to the facilities was December 31, 2016, however both projects are experiencing delays and areMolokai system. The project is expected to be completed by mid-2017.in service in 2020.
In September 2015, the PUC approved Hawaiian Electric’s 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC to supply 2 million to 3 million gallons of biodiesel at CIP CT-1 and the Honolulu International


Airport Emergency Power Facility beginning in November 2015. The Pacific Biodiesel contract was set to expire on November 2, 2017 with possible 1 year extensions. Currently, the contract has been extended to November 2, 2018. Renewable Energy Group has a contingency supply contract with Hawaiian Electric to also supply biodiesel to CIP CT-1 in the event Pacific Biodiesel Technologies, LLC is not able to supply necessary quantities. This contingency contract was set to expire November 2016, but has been extended to November 2017, and will continue with no volume purchase requirements.
In October 2015, the Utilities filed with the PUC a proposal for a Community-Based Renewable Energy program and tariff that would allow customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. In November 2015, the PUC suspended the filing and opened a docket to investigate the matter. In February 2017, the PUC issued a proposed CBRE Program Framework, a Proposed Model Tariff Language, and requested comments and feedback from the parties by March 1, 2017. Under the proposed CBRE Program Framework, the CBRE program will utilize a phased approach. The Program Framework proposes a Phase 1 with an 80 MW capacity statewide with 73 MW allocated to the Utilities' service territories. During the two year initial phase, the Utilities' primary role is to serve as the program administrator. In addition, the Framework requires a minimum allocation of 7.5 MW to develop CBRE targeting low-to-moderate income subscribers with 6.75 MW allocated to the Utilities' service territories.
On May 5, 2016, Maui Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Maui Electric Dispatchable Firm Generation Request for Proposals. The solicitation intends to seek approximately 20 MW of new renewable generation capacity and approximately 20 MW of fuel flexible firm generation resources on the island of Maui by 2022, as proposed in the PSIP Update Report.
On June 6, 2016, Hawaiian Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Hawaiian Electric Renewable Energy Request for Proposals. The solicitation intends to seek new renewable energy generation on the island of Oahu to be placed into service by the end of 2020, consistent with the Five-Year Action Plan proposed in the PSIP Update Report.
In July 2016, Hawaiian Electric announced plans to build, own and operate a 20-MW solar facility in conjunction with the Department of the Navy at a Navy/Air Force joint base, subject to PUC approval. On October 3, 2016,2018, Hawaiian Electric filed with the PUC a requestPPA 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 waivePUC approval. On September 6, 2019, the $67 millionPUC issued an order dismissing without prejudice Hawaiian Electric’s application for a waiver of the proposed Palehua wind project from the Competitive Bidding FrameworkPUC’s framework for competitive bidding and approval of the PPA. Due to approve expenditures for the project. If approved byforegoing, the PUC, the solar facility would generate renewable energy that will feed into Oahu's electrical grid at a very reasonable cost of 9.54 cents per KWH.PPA has been declared null and void.
The Utilities began accepting energy from feed-in tariff projects in 2011. As ofOn December 31, 2016, there were 24 MW, 3 MW and 4 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric,2019, Hawaii Electric Light and Maui Electric, respectively.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.


Tariffed renewable resources.
As of December 31, 2016,2019, there were approximately 305471 MW, 71104 MW and 81118 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 NEM,Standard Interconnection Agreement, Net Energy Metering, Net Energy Metering Plus, Customer Grid Supply, (CGS) and Customer Self Supply, (CSS).Customer Grid Supply Plus and Interim Smart Export. As of December 31, 2016,2019, an estimated 26%29% of single familysingle-family homes on the islands the Utilities serveof Oahu, Hawaii and Maui have installed private rooftop solar systems, and an estimated 29% of single family homes have installed private rooftop solar systems or have been approved to install systems. As of December 31, 2016, approximately 15%18% of the Utilities'Utilities’ total customers have solar systems.   
On JanuaryThe Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2019, there were 34 MW, 3 MW and 5 2017,MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, issued an Onshore Wind ExpressionHawaii Electric Light and Maui Electric, respectively.
Biofuel sources.
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 Interest requestingbiodiesel 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.
Requests for renewable proposals, expressions of interest, fromand information.
Under a request for proposal process governed by the PUC and monitored by independent power producers that are capable of developing utility scale onshore wind projects that are eligible to capture the federal Investment Tax Credit for Large Wind on the island of Oahu. Responses have been accepted and are being evaluated.
On December 12, 2016,observers, in February 2018, the Utilities issued a RequestRFPs for Information asking interested landowners to provide information about properties220 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 Molokai, and Lanai, availableOahu in September 2018.
In December 2018, the Utilities executed a total of seven renewable generation PPAs utilizing photovoltaic technology paired with a battery storage system for utility-scale renewable energy projects ora total of 262MW, of which six PPAs were approved by the PUC in March 2019 and one PPA for growing biofuel feedstock. Responses have been accepted and are being evaluated.
HawaiianMaui Electric had PPAs to purchase solar energy with three affiliates of SunEdison—Waipio PV, LLC (formerly known as Waiawa PV, LLC), Lanikuhana Solar, LLC and Kawailoa Solar, LLC.is still under PUC review. In February 2016, as a result of the project entities missing contract milestones, Hawaiian Electric terminated the original PPAs for the three projects.  SunEdison filed Chapter 11 bankruptcy proceedings and during those proceedings the three SunEdison affiliates were acquired by an affiliate of NRG Energy, Inc. (NRG). Hawaiian Electric then negotiated with NRG and its newly acquired affiliates and has entered into amended and restated PPAs with two of the former SunEdison affiliates,


Waipio PV, LLC for 45.9 MW of solar energy on Oahu and Lanikuhana Solar, LLC for 14.7 MW of solar energy on Oahu. On January 31, 2017,2019, Hawaiian Electric filed an additional PPA for a proposed 12.5 MW PV plus battery storage project, which was approved by the PUC on August 20, 2019. Summarized information for a total of 8 PPAs, including one for Maui Electric that is pending PUC approval, is as follows:
Utilities Number of contracts Total photovoltaic size (MW) BESS Size (MW/MWh) Guaranteed commercial operation dates Contract term (years) 
Total projected annual payment
(in millions)
Hawaiian Electric 4 139.5 139.5/558 9/30/21 & 12/31/21 20 & 25 $30.9
Hawaii Electric Light 2 60 60/240 7/20/21 & 6/30/22 25 14.1
Maui Electric 2 75 75/300 7/20/21 & 6/30/22 25 17.6
Total 8 274.5 274.5 /1,098     $62.6
In March 2019 and August 2019, the Utilities received PUC approval to recover the total projected annual payment of $57.8 million for 7 PPAs through the PPAC to the extent such costs are not included in base rates. The remaining $4.8 million of total projected annual payments for the remaining PPA is pending PUC approval.
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 PUC requestsplanned retirement of the Kahului Power Plant on Maui and the upcoming expiration of the agreement for approvals of these amended and restated PPAs. Hawaiian Electric is continuing to negotiate an amended PPAthe AES Hawaii facility on Oahu. For the Grid Services RFP, the targets had been expanded in alignment with the Renewable RFPs.


Utility proposals were submitted on November 4, 2019. Proposals from third NRG affiliate, Kawailoa Solar, LLC,parties for a 49-MW solar facility, alsothese RFPs were submitted on Oahu.
Other regulatory matters.  In addition to the items below, also see Note 4 of the Consolidated Financial Statements.
Adequacy of supply.
Hawaiian Electric. In January 2017, Hawaiian Electric filed its 2017 Adequacy of Supply (AOS) letter, which indicated that based on its October 2016 sales and peak forecastNovember 5, 2019. Final awards for the 2017 - 2021 time period, Hawaiian Electric’s generation capacity willrenewable projects are scheduled to be sufficient to meet reasonably expected demandsmade in May 2020. Final awards for service and provide reasonable reserves for emergencies through 2018, but may have shortfalls in meeting the Utilities' generating system reliability guideline. The calculated reliability guideline shortfalls are relatively small and Hawaiian Electric can implement mitigation measures.
In accordance to its planning criteria, Hawaiian Electric deactivated two fossil fuel generating units from active service at its Honolulu Power Plantgrid services projects were made starting in January 2014 and anticipates deactivating two additional fossil fuel units at its Waiau Power Plant in2020.
On November 27, 2019, the 2022 timeframe. Hawaiian Electric is proceedingUtilities issued RFPs for renewable generation paired with future firm capacity additions in coordination with the State of Hawaii Department of Transportation in 2016, and with the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, including black start capabilities, generation security projectenergy storage on federal lands, which is expected to be in service in the first quarter of 2018. Hawaiian Electric is continuing negotiations with firm capacity IPPs on Oahu. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution. The PPA with AES Hawaii, Inc. is scheduled to expire in 2022.
Hawaii Electric Light.  In January 2017, Hawaii Electric Light filed its 2017 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2019 is sufficient to meet reasonably expected demands for service and provide for reasonable reserves for emergencies.
Additional generation from other renewable resources could be added in the 2020-2025 timeframe.
Maui Electric. In January 2017, Maui Electric filed its 2017 AOS letter, which indicated that Maui Electric’s generation capacity for 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 next three years is sufficiently largeMolokai 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 meet all reasonably expected demands for service and provide reasonable reserves for emergencies. The 2017 AOS letter also indicated that without the peak reduction benefits of demand response but with the equivalent firm capacity value of wind generation, Maui Electric expects to have a small reserve capacity shortfall from 2017 to 2022 on the island of Maui. Maui Electric is evaluating several measures to mitigate the anticipated reserve capacity shortfall. Maui Electric anticipates needing a significant amount of additional firm capacity on Maui in the 2022 timeframe after the planned retirement of Kahului Power Plant.
In February 2014, Maui Electric deactivated two fossil fuel generating units, with a combined rating of of 11.4 MW-net, at its Kahului Power Plant. Due to various system conditions including lack of wind generation, approaching storms and scheduled and unscheduled outages of generating units, transmission lines and independent power producers, the two deactivated units at Kahului Power Plant were reactivated for several days in 2015 and 2016. Dueissue an update to the recent frequency of reactivations of Kahului Units 1 and 2 to meet system requirements, these units were removed from deactivated status and designated as reactivated in September 2016. Considering the time needed to acquire replacement firm generating capacity, Maui Electric now anticipates the retirement of all generating units at the Kahului Power Plant, which have a combined rating of 32.3 MW, in the 2022 timeframe. A capacity planning analysis is in progress to better define needs and timing. Maui Electric plans to issue one or more RFPs for energy storage, demand response and firm generating capacity, and to make system improvements needed to ensure reliability and voltage support in this timeframe. In May 2016, Maui Electric requested that the PUC open a new docket for Maui Electric’s competitive bidding process for additional firm capacity resources. In September 2016, Maui Electric submitted an application to purchase and install three temporary mobile distributed generation diesel engines to address increasing reserve capacity shortfalls on the island of Maui. In February 2017, Maui Electric requested the PUC suspend the proceeding until the progress in the demand response programs and the DR portfolio proceeding can be further evaluated.  Lanai RFP no later than March 10, 2020.
Legislation and regulation.  Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the Utilities and their customers. Also see “Environmental regulation” in “Item 1. Business” and Note 43, and “Recent“Major tax developments” in Note 12 of the Consolidated Financial Statements.
RenewableImpact of lava flows. In May 2018, a lava eruption occurred within the Leilani Estates subdivision and resulted in the shutdown of independent power producer PGV’s geothermal facilities. The financial impact to Hawaii Electric Light has not been material. In March 2019, Hawaii Electric Light and PGV entered into a Rebuild Agreement, which sets forth the parties’ respective responsibilities associated with restoration of facilities and reconnection of the PGV facility to the electric grid.
In June 2019, Hawaii Electric Light filed an application requesting approval to reconstruct the necessary transmission lines. In December 2019, Hawaii Electric Light filed an application for approval of an amended and restated PPA with PGV. See “New renewable PPAs” in the “Developments in renewable energy.  In 2011, efforts” section above for additional information on the amended and restated PPA.
Army privatization. On September 27, 2019, Hawaiian Electric was awarded a Hawaii law was enacted that gives50-year contract to own, operate and maintain the electric distribution system serving the U.S. Army’s 12 installations on Oahu, including Schofield Barracks, Wheeler Army Airfield, Tripler Army Medical Center, Fort Shafter, and Army housing areas. Hawaiian Electric will acquire, subject to PUC approval, the Army’s existing distribution system for a purchase price of $16.3 million and will pay the Army in the form of a monthly credit against the monthly utility services charge over the 50-year term of the contract. Hawaiian Electric filed an application with the PUC for approval of the authorityArmy privatization contract on October 25, 2019.
If approved by the PUC in 2020, Hawaiian Electric would take ownership and all responsibilities for operation and maintenance of the system in late 2021 for a 50-year term, which would start after the mutually agreed upon one-year transition period. Under the contract, Hawaiian Electric will make initial capital upgrades over the first six years of the contract and replacements of aging infrastructure over the 50-year term. In addition to allow those electric utilities (includingits regular monthly electricity bill, the Utilities) that aggregate their renewable portfoliosArmy will pay Hawaiian Electric a monthly utility services charge to cover operations and maintenance expenses and provide recovery for capital upgrades, capital replacements, and the existing distribution system based on a rate of return determined by the PUC for regulated utility investments, as well as depreciation expense. A preliminary assessment estimated the capital needs of approximately $40 million in measuring whether they achieve the renewable portfoliofirst six years of the contract. The annual impact on Hawaiian Electric’s earnings is not expected to be material and will depend on a number of factors, including the amount and timing of capital upgrades and capital replacement.

Fuel contracts.  The fuel contract entered into in January 2019, by the Utilities and PAR Hawaii Refining, LLC (PAR Hawaii), for the Utilities’ low sulfur fuel oil (LSFO), high sulfur fuel oil (HSFO), No. 2 diesel, and ultra-low sulfur diesel (ULSD) requirements was approved by the PUC, and became effective on April 28, 2019 and terminates on December 31, 2022. This contract is a requirement contract with no minimum purchases. If PAR is unable to provide LSFO, HSFO, diesel and/or ULSD the contract allows the Utilities to purchase LSFO, HSFO, diesel and/or ULSD from another supplier. The contract will automatically renew upon the conclusion of the original term for successive terms of 1 year beginning on January 1, 2023 unless a party gives written termination notice at least 120 days before the beginning of an extension.

The previous fuel contracts with Island Energy Services, LLC, terminated on April 27, 2019, as agreed with IES under a mutual termination and release agreement entered into in November 2018.
standardsThe costs incurred under the contract with PAR Hawaii RPS law discussed above under "Renewable energy strategy" to distribute the costs and expenses of renewable energy projects among those utilities. The bill also allows the PUC to establish a surcharge for such costs and expenses without a rate case filing. Also passed in 2011, Act 10 provides for continued inclusion of customer-sited, grid-connected renewable energy generationare recovered in the RPS calculations after 2015. This is the current practice in calculating RPS levels, which provides electric utility ratepayers with a clear value from a program such as net energy metering.Utilities’ respective ECRCs.
Liquidity and capital resources.  Management believes that Hawaiian Electric’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities and commercial paper and draws on lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures, and investments, and to cover debt repayments, retirement benefitsbenefit plan contributions and other cash requirements in the foreseeable future.


Hawaiian Electric’s consolidated capital structure was as follows:
December 312016 20152019 2018
(dollars in millions) 
  
  
  
 
  
  
  
Short-term borrowings1
$89
 2% $25
 1%
Long-term debt, net$1,319
 42% $1,279
 42%1,498
 41
 1,419
 41
Preferred stock34
 1
 34
 1
34
 1
 34
 1
Common stock equity1,800
 57
 1,728
 57
2,047
 56
 1,958
 57
$3,153
 100% $3,041
 100%$3,668
 100% $3,436
 100%
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).
Information about Hawaiian Electric’s short-termcommercial paper borrowings, (other thanborrowings from Hawaii Electric LightHEI, and Maui Electric) and Hawaiian Electric’s line of credit facility were as follows:
Year ended
December 31, 2016
  Year ended December 31, 2019  
(in millions)
Average
balance
 
End-of-period
balance
 
December 31,
2015
Average
balance
 
End-of-period
balance
 
December 31,
2018
Short-term borrowings1
          
Commercial paper$13
 $—
 $—
$44
 $39
 $—
Line of credit draws—
 —
 —
—
 —
 —
Borrowings from HEI4
 —
 —
—
 —
 —
Undrawn capacity under line of credit facility200
 200
 200
—
 200
 200
1 
The maximum amount of external short-term borrowings in 2016by Hawaiian Electric during 2019 was $61$158 million. At December 31, 2016,2019, Hawaiian Electric had short-term borrowings from Hawaii Electric Light of $8 million and Maui Electric had short-term borrowings from Hawaiian Electric of $3.5$27.7 million, and $10 million, respectively, which intercompany borrowings are eliminated in consolidation. At February 13, 2017,In addition to the short-term borrowings above, Hawaiian Electric had no outstanding commercial paper, its linedrew $50 million on December 23, 2019 on a 364-day term loan facility (see Note 5 of credit facility was undrawn, it had no borrowings from HEI and it had short-term borrowings from Hawaii Electric Light and Maui Electric of $3.5 million and $3 million, respectively.the Consolidated Financial Statements).
Hawaiian Electric utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. Hawaiian Electric also borrows short-term from HEI for itself and on behalf of Hawaii Electric Light and Maui Electric, and Hawaiian Electric may borrow from or loan to Hawaii Electric Light and Maui Electric short-term.on a short-term basis. The intercompany borrowings among the Utilities, but not the borrowings from HEI, are eliminated in the consolidation of Hawaiian Electric’s financial statements. The Utilities periodically utilize long-term debt, borrowings of the proceeds of special purpose revenue bonds (SPRBs) issued by the Department of Budget and Finance of the State of Hawaii (DBF)DBF and the issuance of privately placed unsecured senior notes bearing taxable interest, to finance the Utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by the Utilities.
Hawaiian Electric has a $200 million line of credit facility as amended and restated on April 2, 2014, of $200 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2,with no amounts outstanding at December 31, 2019. See Note 75 of the Consolidated Financial Statements.
TheCredit ratings of Hawaiian Electric’s commercial paper. Moody’s and debt securities could significantly impact the ability of Hawaiian Electric to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (e.g., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of Hawaiian Electric securities.
In August 2016, Moody’s downgraded Hawaiian Electric’s senior unsecured debt rating from Baa1 to Baa2, downgraded other ratings andS&P (Rating Agencies) revised Hawaiian Electric’s rating outlook to stable. In December 2016, S&P affirmed Hawaiian Electric’s BBB-“positive” from “stable” on October 21, 2019 and February 20, 2020, respectively. The revision to the rating outlook was primarily based on the progress of regulatory reform for the Utilities. The Rating Agencies indicated that future upgrades or downgrades in ratings action are dependent on a variety of factors, including changes in its cash flow from operations ratios and improvements in the regulatory environment, specifically, a credit-supportive decision in the performance-based regulation proceeding. See “Performance-based regulation proceeding” in Note 3 of the Consolidated Financial Statements.



corporate credit rating and stable outlook. In January 2017, Fitch affirmed Hawaiian Electric’s long-term issuer default rating at BBB+ with a stable outlook.
As of February 13, 2017,20, 2020, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:
 FitchMoody’sS&P&P**
Long-term issuer default, long-term issuer and corporateissuer credit, respectivelyBBB+Baa2BBB-
Commercial paperF2P-2A-3
Senior unsecured debt/special purpose revenue bondsA-Baa2BBB-
Hawaiian Electric-obligated preferred securities of trust subsidiary*Baa3BB
Cumulative preferred stock (selected series)*Ba1*
Subordinated debtBBB**
OutlookStableStablePositiveStablePositive
*    Not rated.
**On February 20, 2020, S&P revised Utilities’ outlook to positive and affirmed Utilities’ issuer credit and commercial paper ratings.
Note: The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
Management believes that, if Hawaiian Electric’s commercial paper ratings were to be downgraded or if credit markets were to further tighten, it could be more difficult and/or expensive to sell commercial paper or secure other short-term borrowings. Similarly, management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded or further downgraded, or if credit markets further tighten, it could be more difficult and/or expensive for DBF and/or the Utilities to sell SPRBs and other debt securities, respectively, for the benefit of the Utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of the Utilities.
. SPRBs have been issued by the DBF to finance (and refinance) capital improvement projects of Hawaiian Electric and its subsidiaries, but the sources of their repayment are the non-collateralized obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment
On February 26, 2019, the PUC approved Hawaiian Electric and Hawaii Electric Light’s request to issue refunding SPRBs prior to December 31, 2020 to refinance their outstanding Series 2009 SPRBs in the amount of principalup to $90 million and interest due$60 million, respectively. Pursuant to this approval, on July 18, 2019, the Series 2007ADepartment of Budget and Refunding Series 2007B SPRBs are insured by Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding inFinance of the State of New YorkHawaii (DBF) issued, at par, Refunding Series 2019 SPRBs in June 2012. On August 19, 2013 FGIC's planthe aggregate principal amount of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings$150 million with a maturity of FGIC, which at the time the insured obligations were issued were higher than the ratingsJuly 1, 2039. See Note 6 of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings wereConsolidated Financial Statements.
On May 24, 2019, the PUC approved the Utilities’ request to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bondsissue SPRBs in the future.
In May 2015,amounts of up to $80$70 million, of SPRBs ($70$2.5 million and $7.5 million for Hawaiian Electric, $2.5 million for Hawaii Electric Light and $7.5 million for Maui Electric) were authorized by the Hawaii legislature for issuance, with PUC approval,Electric, respectively, prior to June 30, 2020, to finance the Utilities’ capital improvement programs.
In June 2015, Pursuant to this approval, on October 10, 2019, the DBF issued, at par, Series 2019 SPRBs in the aggregate principal amount of $80 million with a maturity of October 1, 2049. As of December 31, 2019, Hawaiian Electric and Hawaii Electric Light had $30.8 million and $0.1 million of undrawn funds remaining with the trustee, respectively. Maui Electric filed an application with the PUC for approval to issuereceived all bond proceeds at closing and sell each utility’s common stock in one or more sales in 2016 (Hawaiian Electric’s sale to HEIhad no undrawn funds as of up to $330 million and Hawaii Electric Light’s and Maui Electric’s sales to Hawaiian Electric of up to $15 million and $45 million, respectively), and the purchase of the Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric in 2016. In June 2016, the PUC issued a D&O approving the issue and sale of each utility’s common stock in 2016 up to the amounts requested in the application. In December 2016, Hawaiian Electric sold $24 million of its common stock to HEI, pursuant to this approval. Hawaii Electric Light and Maui Electric did not issue common stock in 2016.
In August 2016, Hawaiian Electric and Maui Electric obtained PUC approval to issue in 2016, unsecured obligations bearing taxable interest (Hawaiian Electric up to $70 million and Maui Electric up to $20 million). On December 15, 2016, Hawaiian Electric issued through a private placement, $40 million of unsecured senior notes bearing taxable interest.31, 2019. See Note 86 of the Consolidated Financial Statements.
On November 2, 2016,June 10, 2019, the Hawaii legislature authorized the issuance of up to $700 million of SPRBs ($400 million for Hawaiian Electric, $150 million for Hawaii Electric Light and $150 million for Maui Electric), with PUC approval, prior to June 30, 2024, to finance the Utilities’ multi-project capital improvement programs.
Bank loans. On December 23, 2019, Hawaiian Electric filed an application withentered into a 364-day, $100 million term loan credit agreement that matures on December 21, 2020. Hawaiian Electric drew the first $50 million on December 23, 2019 and has until March 23, 2020 to draw the remaining $50 million, if needed.
Taxable debt. On January 31, 2019, the Utilities received PUC approval (January 2019 Approval) to issue the remaining authorized amounts under the PUC for approval to issue unsecured obligations bearing taxable interest and/or refunding SPRBs prior to December 31,received in April 2018 (April 2018 Approval) in 2019 through 2020 to refinance three series of outstanding revenue bonds up to $252 million, $88 million and $75 million, respectively.
On January 26, 2017, Hawaiian Electric, Hawaii Electric Light and Maui Electric obtained PUC approval to issue, on or before December 31, 2017, unsecured obligations bearing taxable interest (Hawaiian Electric up to $100$205 million and Hawaii


Electric Light up to $10$15 million and Maui Electric upof taxable debt), as well as a supplemental increase to $30 million), withauthorize the proceeds expected to be used, as applicable,issuance of additional taxable debt to finance capital expenditures, repay long-term and/or short term debt used to finance or refinance capital expenditures, and/or to reimburse funds used for payment of capital expenditures.expenditures, and to refinance the Utilities’ 2004 junior subordinated deferrable interest debentures (QUIDS) prior to maturity. In addition, the January 2019 Approval authorized the Utilities to extend the period to issue additional taxable debt from December 31, 2021 to December 31, 2022. The new total “up to” amounts of taxable debt requested to be issued through December 31, 2022 are $410 million, $150 million and $130 million for Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.


Pursuant to the January 2019 Approval, on May 13, 2019, the Utilities issued through a private placement, $50 million of unsecured senior notes bearing taxable interest ($30 million for Hawaiian Electric, $10 million for Hawaii Electric Light and $10 million for Maui Electric) to refinance the Utilities’ 2004 QUIDS. See Note 6 of the Consolidated Financial Statements. See summary table below.
(in millions)Hawaiian ElectricHawaii Electric LightMaui Electric
Total “up to” amounts of taxable debt authorized through 2022$410
$150
$130
Less:   
Taxable debt authorized and issued in 2018 under April 2018 Approval75
15
10
Taxable debt issuance to refinance the 2004 QUIDS30
10
10
Remaining authorized amounts$305
$125
$110
Equity. In October 2018, the Utilities received PUC approval for the supplemental increase to issue and sell additional common stock in the amounts of up to $280 million for Hawaiian Electric and up to $100 million each for Hawaii Electric Light and Maui Electric, with the new total “up to” amounts of $430 million for Hawaiian Electric and $110 million each for Hawaii Electric Light and Maui Electric, and to extend the period authorized by the PUC to issue and sell common stock from December 31, 2021 to December 31, 2022. In December 2019, Hawaiian Electric sold $35.5 million of its common stock to HEI and Maui Electric sold $4.9 million of its common stock to Hawaiian Electric. Hawaii Electric Light did not issue common stock in 2019. See summary table below.
(in millions)Hawaiian ElectricHawaii Electric LightMaui Electric
Total “up to” amounts of common stock authorized to issue and sell through 2021$150.0
$10.0
$10.0
Supplemental increase authorized280.0
100.0
100.0
Total “up to” amounts of common stock authorized to issue and sell through 2022430.0
110.0
110.0
Common stock authorized and issued in 2017, 2018 and 2019120.2
—
11.2
Remaining authorized amounts$309.8
$110.0
$98.8
Cash flows.
Years ended December 31Years ended December 31
(in thousands)2016 Change 2015 Change 20142019 2018 Change
Net cash provided by operating activities$369,917
 $36,511
 $333,406
 $26,411
 $306,995
$423,956
 $393,613
 $30,343
Net cash used in investing activities(288,199) 20,583
 (308,782) (15,073) (293,709)(408,524) (405,182) (3,342)
Net cash used in financing activities(31,881) (17,944) (13,937) 48,412
 (62,349)
Net cash provided by (used in) financing activities(9,415) 34,929
 (44,344)
20162019 Cash Flows Compared to 2015:2018:
Net cash provided by operating activities:Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from ) net income.
The increase in net cash provided by operating activities in 2016 over 2015 was impactedprimarily driven by the following:
Higherhigher cash receipts from a refund of federal income taxes in 2016customers due to the extension of bonus depreciation enacted in the fourth quarter of 2015 and lower revenue taxes paid resulting from lower revenues due largely to lower fuel prices.higher electric rates.
Lower unbilled revenues due to timing and lower fuel prices.
Net cash used in investing activities: The decrease in net cash used in investing activities in 2016 from 2015 was driven primarily by decreased capital expenditures, offset by lower proceeds from contributions in aid of construction.
Net cash used in financing activities: The increase in net cash used in financing activities was driven primarily by decreased proceeds from issuance of long-term debt, partially offset by proceeds from issuance of common stock.
2015 Cash Flows Compared to 2014:
Net cash provided by operating activities:Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from ) net income.
The increase in net cash provided by operating activities in 2015 over 2014 was impacted by the following:
Higher unbilled revenues due to timing and lower fuel prices.
Lower revenue taxes paid resulting from lower revenues due largely to lower fuel prices.
Net cash used in investing activities: The increase in net cash used in investing activities was primarily driven by an increase in 2015 over 2014 was driven primarily by increased capital expenditures.expenditures related to construction activities.
Net cash used inprovided by financing activities: The decrease in net cash used inprovided by financing activities was primarily driven primarily by lower proceeds from issuance of long-term debt.common stock issuance.
For a discussion of 2017 operating, investing and financing activities, please refer to the “Liquidity and capital resources” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Electric utility,” in the Company’s 2018 Form 10-K.
Forecast capital expenditures. For the three-year period 2020 through 2022, the Utilities forecast $470 millionup to $1.3 billion of net capital expenditures, (including the purchase of HEP), which could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and timing of PUC decisions. Proceeds from the issuance of equity and long-term debt, cash flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the forecasted $470 millionfunds needed for the net capital expenditures, in 2017 as well as to pay down commercial paper or other short-term borrowings, as well as to fund any unanticipated expenditures not included in the 20172020 to 2022 forecast such(such as increases in the costs or acceleration of the construction of capital projects, or unanticipated capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements.regulations).


Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWHkWh sales and peak load, the availability of purchased power and changes in expectations concerning the construction and


ownership of future generation units, the availability of generating sites and transmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.
Selected contractual obligations and commitments. The following table presents aggregated information about total payments due from the Utilities during the indicated periods under the specified contractual obligations and commitments:
December 31, 2016Payments due by period
December 31, 2019Payments due by period
(in millions)Less than 1 year 
1-3
years
 
3-5
years
 
More than
5 years
 TotalLess than 1 year 
1-3
years
 
3-5
years
 
More than
5 years
 Total
         
Short-term borrowings$89
 $—
 $—
 $—
 $89
Long-term debt$—
 $50
 $96
 $1,181
 $1,327
96
 52
 100
 1,257
 1,505
Interest on long-term debt66
 132
 130
 797
 1,125
61
 121
 111
 691
 984
Operating leases9
 11
 9
 7
 36
         
Open purchase order obligations ¹56
 114
 —
 —
 170
Fuel oil purchase obligations (estimate based on December 31, 2016 fuel oil prices)125
 238
 —
 —
 363
Purchase power obligations-minimum fixed capacity charges121
 188
 189
 388
 886
Liabilities for uncertain tax positions—
 4
 —
 —
 4
PPAs classified as leases63
 105
 —
 —
 168
Other leases7
 8
 3
 2
 20
Open purchase order obligations 1
54
 19
 1
 —
 74
Fuel oil purchase obligations (estimate based on fuel oil price at December 31)7
 15
 —
 —
 22
Purchase power obligations-minimum fixed capacity charges not classified as leases51
 76
 76
 241
 444
Total (estimated)$377
 $737
 $424
 $2,373
 $3,911
$428
 $398
 $291
 $2,191
 $3,308
¹ 1Includes contractual obligations and commitments for capital expenditures and expense amounts.
The table above does not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2016,2019, the fair value of the assets held in trusts to satisfy the obligations of the Utilities’ retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above. See Note 10 of the Consolidated Financial Statements for retirement benefit plan obligations and estimated contributions for 2017.2020. There were no material uncertain tax positions as of December 31, 2019.
See Note 4“Biofuel sources” in the “Developments in renewable energy efforts” section above for additional information for fuel oil purchase obligation. See Notes 3 and 8 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments.
Certain factors that may affect future results and financial condition.  Also see “Cautionary Note Regarding Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.
Clean energy initiatives and Renewable Portfolio Standards (RPS).The far-reaching nature of the Utilities’ renewable energy commitments and the RPS goals presents risks to the Utilities. Among such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the Utilities are unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the Utilities’ achievement of their commitments to RPS goals and/or the Utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the Utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the Utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the Utilities depending on their design and implementation. These initiatives include, but are not limited to, removing the system-wide caps on net energy metering (but studying distributed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. The implementation of these or other programs may adversely impact the results of operations, financial condition and liquidity of the Utilities.operating leases obligations, respectively.
Regulation of electric utility rates. The rates the electric utilities are allowed to charge for their services, and the timeliness of permitted rate increases, are among the most important items influencing their results of operations, financial condition and liquidity. The PUC has broad discretion over the rates the electric utilities charge and other matters. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts permitted to be included in rate base, the authorized returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on the Company’s and Hawaiian Electric’s consolidated results of operations, financial condition and liquidity. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing


is not completed). There is no time limit for rendering a final D&O and interim rate increases are subject to refund with interest if the interim increase is greater than the increase approved in the final D&O.
Fuel oil and purchased power.  The electric utilities rely on fuel oil suppliers and IPPs to deliver fuel oil and power, respectively. See “Fuel contracts” and “Power purchase agreements” in Note 4 of the Consolidated Financial Statements. The Utilities estimate that 65% of the net energy the Utilities generate and purchase in 2017 will be from the burning of fossil fuel oil as compared to 67% in 2016. Purchased KWHs provided approximately 47%, 46% and 46% of the total net energy generated and purchased in 2016, 2015 and 2014, respectively.
Failure or delay by the electric utilities’ oil suppliers and shippers to provide fuel pursuant to existing supply contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could interrupt the ability of the electric utilities to deliver electricity, thereby materially adversely affecting the Company’s and the Utilities' results of operations and financial condition. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an inventory level equivalent to one month’s supply of both medium sulfur fuel oil and diesel fuel. Some, but not all, of the Utilities’ PPAs require that the IPPs maintain minimum fuel inventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties for failure to produce the firm capacity anticipated by those agreements.
Other regulatory and permitting contingencies.  Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company and the Utilities. Significant write-offs of this type were made in 2007, 2011 and 2012. See Note 4 of the Consolidated Financial Statements for a discussion of additional regulatory contingencies.
Competition.Competition.  Although competition in the generation sector in Hawaii is moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, the PUC has promoted a more competitive electric industry environment through its decisions concerning competitive bidding and distributed generation (DG). An increasing amount of generation is provided by IPPs and customer distributed generation.
Competitive bidding.bidding.  In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.
Environmental matters. The Utilities' generating stations operate under air pollution control permits issued by the Hawaii Department of Health (DOH) and, in a limited number of cases, by the federal Environmental Protection Agency (EPA). Hawaii law requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. Meeting this requirement for environmental assessments results in increased project costs.
The 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone and adoption of a NAAQS for fine particulate matter resulted in substantial changes for the electric utility industry such as the installation of additional emissions controls, retirements of older generating units and switches to lower-emissions fuels. Further, significant impacts may occur under newly adopted rules (e.g., one-hour NAAQS for sulfur dioxide and nitrogen dioxide; control of GHGs under the PSD and Title V permitting rules; under rules deemed applicable to the Utilities’ facilities (e.g., the Regional Haze Rule); or if new legislation, rules or standards are adopted in the future. Similarly, the rules governing cooling water intakes may significantly impact Hawaiian Electric’s steam generating facilities on Oahu.
Management believes that the recovery through rates of most, if not all, of any costs incurred by the Utilities in complying with environmental requirements would be allowed by the PUC, but no assurance can be given that this will in fact be the case. In addition, there can be no assurance that a significant environmental liability will not be incurred by the Utilities or that the related costs will be recoverable through rates. See “Environmental regulation” in Note 4 of the Consolidated Financial Statements.


Technological developments.  New emerging and breakthrough technological developments (e.g., the commercial development of energy storage, grid support utility interactive inverters, fuel cells, DG,distributed generation, grid modernization,


electrification of transportation, implement predictive analytics using artificial intelligence machine learning algorithms to help assess the state of health of utility assets and prevent premature failure, and the diversification of generation from renewable sources) may impact the Utilities’ future competitive position, results of operations, financial condition and liquidity. The Utilities continue to seek prudent opportunities to develop and implement advanced technologies that align with its technical and business plans and will support a more reliable, flexible and resilient utility grid.
Environmental matters.See “Electric utility—Regulation—Environmental regulation” under “Item 1. Business” and “Environmental regulation” in Note 3 of the Consolidated Financial Statements.
Commitments and contingencies. See Item 1A. Risk Factors, and Note 3 of the Consolidated Financial Statements for a discussion of important commitments and contingencies.
Off-balance sheet arrangements. See “Off-balance sheet arrangements” above in HEI Consolidated section.
Material estimates and critical accounting policies.  Also see “Material estimates and critical accounting policies” forabove in HEI Consolidated HEI above.section.
Property, plant and equipment. The Utilities have significant investments in electric generation, transmission and distribution assets. For financial reporting purposes, the depreciation of these assets is calculated using the straight-line, remaining life method, which applies a depreciation rate to the depreciable base of each asset account. The Utilities perform depreciation studies to determine the depreciation rates, which are based on historical data (e.g., retired asset lives and past removal costs), plans for the future and other factors. These depreciation studies are performed periodically, but a new study must be filed with the PUC within five years from the date of the last PUC-approved study. Changes to the estimated remaining service lives could have a significant impact on the amount of depreciation expense recorded.
Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.
The Utilities evaluate the impact of applying lease accounting standards to their new PPAs, PPA amendments and other arrangements they enter into. A possible outcome of the evaluation is that an arrangement results in its classification as a capital lease, which could have a material effect on Hawaiian Electric’s consolidated balance sheet if a significant amount of capital assets of the IPP and lease obligations needed to be recorded.
Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion under “Utility projects” in Note 4 of the Consolidated Financial Statements concerning costs of major projects that have not yet been approved for inclusion in the applicable utility’s rate base.
Regulatory assets and liabilities. The Utilities are regulated by the PUC. In accordance with accounting standards for regulatory operations, the Company’s and the Utilities’ financial statements reflect assets, liabilities, revenues and costs of the Utilities based on current cost-based rate-making regulations. The actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities.
Regulatory liabilities represent amounts collected from customers for costs that are expected to be incurred in the future.future, or amounts collected in excess of costs incurred that are refundable to customers. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rates is probable. As of December 31, 2016,2019, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $411$972 million and $957$715 million, respectively, compared to $372$950 million and $897$833 million as of December 31, 2015,2018, respectively. Regulatory liabilities and regulatory assets are itemized in Note 43 of the Consolidated Financial Statements. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the Utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 20162019 is probable. This determination assumes continuation of the current political and regulatory climate in Hawaii and is subject to change in the future.
Management believes that the operations of the Utilities currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company’s and the Utilities’ results of operations, financial condition and liquidity.
Revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to estimated energy consumed in the accounting period, but not yet billed to customers (Unbilled revenues), and RBA revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthourkWh sales. Unbilled revenues represent an estimate of energy consumed by customers subsequent to the date of the last meter reading to the end of the current reporting period. As of December 31, 2016,2019, Unbilled revenues applicable to energy consumed, but not yet billed to customers, amounted to $92$117 million and the RBA revenuesrefunds recognized in 20162019 amounted to $63$11 million.
The rate schedules of the Utilities include ECRCs (changed from ECACs in 2019) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated


power and purchased power. The rate schedules of the Utilities also include PPACs under which electric rates are more closely aligned with purchase power costs incurred. Management believes thatIf the ECRCs, PPACs or RBAs were lost or adversely modified, it could result in a material adverse effect on the Company’s and the Utilities’ results of operations, financial condition and liquidity may result if the ECACs, PPACs or RBAs were lost or adversely modified.liquidity.
Consolidation of variable interest entities.  A business enterprise must evaluate whether it should consolidate a variable interest entity (VIE).Asset retirement obligations. The Utilities evaluaterecognize asset retirement obligations (AROs), which represent the present value of expected costs to retire long-lived assets from service, provided a legal obligation exists and a reasonable estimate of the fair value and the settlement date can be made. The Utilities’ recognition of AROs have no impact on earnings, as the cost of applying accounting standards for consolidation to its relationships with IPPs with whomthe AROs are recovered over the life of the asset through depreciation. AROs recognized by the Utilities execute new PPAsrelate to legal obligations with the retirement of plant and equipment, including removal of asbestos and other hazardous materials.
The Utilities estimate the ARO using a discounted cash flow model that relies on significant estimates and assumptions about future decommissioning costs, inflationary rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate to reflect the risk associated with decommissioning the assets. The


Utilities have not recorded AROs for assets that are expected to operate indefinitely or execute amendmentswhere the Utilities cannot estimate a settlement date (or range of existing PPAs. A possible outcomepotential settlement dates.) As such, ARO liabilities are not recorded for certain asset retirement activities, including various Utility-owned generating facilities and certain electric transmission, distribution and telecommunication assets resulting from easements over property not owned by the Utilities.
Changes in estimated costs, timing of the analysis is that Hawaiian Electricdecommissioning or its subsidiaries may be found to meet the definition of a primary beneficiary of a VIE which finding may resultother assumptions used in the consolidation of the IPP in the Consolidated Financial Statements. The consolidation of IPPscalculation could have acause material effectrevision on the Consolidated Financial Statements, includingrecorded liabilities. As of December 31, 2019 and December 31, 2018, the recognition of a significant amount of assetsUtilities’ AROs totaled $10 million and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. The Utilities do not know how the consolidation of IPPs would be treated for regulatory or credit ratings purposes. See Notes 1 and 6 of the Consolidated Financial Statements.$8 million, respectively.


52


Bank
Executive overview and strategy.  When  ASB, was acquired by HEIheadquartered in 1988, it was a traditional thrift with assets of $1 billion and net income of about $13 million. Since then, ASB has grown by both acquisition and internal growth. Over the last several years the focus has been on efficient growth to maximize profitability and capital efficiency. ASB ended 2016 with assets of $6.4 billion and net income of $57 million, compared to assets of $6.0 billion as of December 31, 2015 and net income of $55 million in 2015.
ASBHonolulu, Hawaii, is a full-service community bank serving both consumer and commercial customers. InASB is one of the largest financial institutions in Hawaii and ended 2019 with assets of $7.2 billion and net income of $89 million, compared to assets of $7.0 billion and net income of $83 million in 2018.
ASB provides a wide range of financial products and services, and in order to remain competitive and continue building core franchise value, ASB continues to developis focused on making banking easier for the customer and introducedeveloping and introducing new products and services in order to meet the needs of those markets such as mobile banking.market needs. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive.competitive, facilitate process improvements in order to deliver a continuously better experience for its customers, and be a more efficient bank. ASB’s ongoing challenge iscontinued focus has been on efficient growth to continuemaximize profitability and capital efficiency, as well as control expenses. Key strategies to increase revenues and control expenses.drive organic growth include:
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.
The interest rate environment and the quality of ASB’s assets will continue to impactinfluence its financial results.
ASB continues to face a challenging interest rate environment. The relatively low level A lowering of interest rates and excess liquidityacross the yield curve as a result of the Federal Reserve Board’s decreases in the financial systemshort-term interest rates have impacted new loan production rates and made it challenging to find investments with adequate risk-adjusted returns, which resulted in downward pressure onmaintain ASB’s asset yields and net interest margin. The potential for compression of ASB’s margin whenif interest rates risecontinue to decrease is a risk that is actively managed.
As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Quantitative“Item 7A. Quantitative and Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies to manage interest rate risk include:
1.attracting and retaining low-cost core deposits, particularly those in non-interest bearing transaction accounts;
2.reducing the overall exposure to fixed-rate residential mortgage loans and diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable-rate loans such as commercial real estate and consumervariable rate loans;
3.managing interest-bearing liabilities to optimize costfocusing investment growth in securities that exhibit less extension risk (i.e., risk of funds and managing interest rate sensitivity; and
4.focusing new investments on shorter duration or variable rate securities.longer average lives) as rates rise.
ASB’s loan quality benefited in 2016 from stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the state of Hawaii. ASB’s annualized net charge-offs as a percentage of total average loans was 0.24% for 2016 compared to 0.04% for 2015. The higher net charge-off ratio was primarily due to charge offs of specific commercial credits and unsecured consumer loans. ASB’s provision for loan losses increased from $6.3 million for 2015 to $16.8 million for 2016, primarily due to loan loss reserves needed for growth in the commercial real estate and consumer loan portfolios as well as reserves for specific commercial credits.
Effective July 2013, ASB became non-exempt from the Durbin Amendment to the Dodd-Frank Act which resulted in lower debit card interchange fees. For 2016, 2015 and 2014, the estimated net income impact of the lower debit card interchange fees was $6 million per year.




Results of operations.
20162019 vs. 20152018
(in millions) 2016 2015 
Increase
(decrease)
 Primary reason(s)
Interest income $219
 $200
 $19
 Higher interest income was due to higher average earning asset balances and higher loan yields. ASB’s average loan portfolio balance for 2016 was $223 million higher than 2015 as the average commercial real estate, HELOC and consumer loan balances increased by $204 million, $32 million and $30 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix targets and loan growth strategy. The commercial loan average balance decreased $55 million due to the strategic reduction of the nationally syndicated loan portfolio. The loan portfolio yield benefited from a shift in the mix of the loan portfolio and the repricing of the adjustable rate loans with the increase in the prime rate. The average investment and mortgage-related securities portfolio balance increased by $248 million as ASB purchased investments with liquidity in excess of loan growth funding.
Noninterest income 67
 67
 —
 Noninterest income was flat as higher gains on sale of investment securities and insurance proceeds in 2016 were offset by lower gains on sales of real estate and mortgage servicing rights.
Revenues 286
 267
 19
  
Interest expense 13
 12
 1
 Higher interest expense was due to an increase in average interest-bearing liabilities. Average deposit balances for 2016 increased by $438 million compared to 2015 due to an increase in core deposits and term certificates of $322 million and $116 million, respectively. The other borrowings average balance decreased by $48 million due to a decrease in repurchase agreements.
Provision for loan losses 17
 6
 11
 Higher provision for loan losses for 2016 was primarily due to growth in the commercial real estate and consumer loan portfolios and additional reserves for specific commercial credits. The provision for loan losses in 2015 were used primarily to establish loan loss reserves for the growth in the loan portfolio and additional reserve levels for the commercial and unsecured consumer loan portfolios.
Noninterest expense 169
 166
 3
 Higher noninterest expense was primarily due to costs related to replacement and upgrade of ASB's electronic banking platform in mid 2016 to enhance the Bank's online and mobile banking services to consumer and business customers as well as expand its distribution channels.
Expenses 199
 184
 15
  
Operating income 87
 83
 4
 Higher interest income, partly offset by higher provision for loan losses and noninterest expenses.
Net income 57
 55
 2
 Higher operating income, partly offset by higher taxes.
Return on average common equity 1
 9.9% 9.9% —%  
(in millions) 2019 2018 
Increase
(decrease)
 Primary reason(s)
Interest income $266
 $258
 $8
 Higher interest income was due to higher average loan portfolio balances and yields, partly offset by a decrease in balances and yields in the investment securities portfolio. ASB’s average loan portfolio balance for 2019 was $231 million higher than 2018’s average loan portfolio balance primarily due to increases in the average HELOC, residential, commercial and consumer loan portfolio balances of $99 million, $59 million, $40 million and $30 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix targets and loan growth strategy. The 2019 loan portfolio yield increased 5 basis points compared to the prior year loan portfolio yield due to the repricing of adjustable rate loans in the latter part of 2018 and early 2019. The average investment securities portfolio balance decreased by $86 million and the portfolio yield decreased 14 basis points. The decrease in the portfolio balance was due to ASB’s decision to use investment portfolio repayments to fund the growth in the loan portfolio rather than redeploy it into investment securities. The decrease in the investment yields was due to an increase in the amortization of premiums in the investment portfolio.



2015 vs. 2014
(in millions) 2015 2014 
Increase
(decrease)
 Primary reason(s) 2019 2018 
Increase
(decrease)
 Primary reason(s)
Interest income $200
 $191
 $9
 The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for 2015 was $213 million higher than 2014 as the average commercial real estate, residential, HELOC and commercial loan balances increased by $111 million, $40 million, $37 million and $15 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix targets and loan growth strategy. The loan portfolio yield continued to be impacted by the interest rate environment as new loan production yields were lower than the average portfolio yield. The average investment and mortgage-related securities portfolio balance increased by $150 million as ASB purchased investments with liquidity in excess of loan growth funding.
Noninterest income 67
 61
 6
 Higher noninterest income was due to an increase in gain on sale of loans as loan sales increased by $119 million as a result of ASB's decision to sell a larger portion of its low rate residential loan production, higher deposit related fee initiatives and gains on sales of real estate and mortgage servicing rights. 2014 noninterest income included the gain on sale of the municipal bond portfolio with no similar security sales in 2015. 73
 56
 17
 Noninterest income was higher in 2019 compared to 2018 primarily due to a gain on sale of real estate, an increase in mortgage banking income and higher bank-owned life insurance payouts. ASB sold two office facilities that were no longer needed when ASB moved into its new campus headquarters, which resulted in a gain on sale of real estate of $10.8 million. There were no such sales in 2018. The increase in mortgage banking income was due to an increase in loan sales into the secondary market as a result of higher residential mortgage loan production in 2019 compared to 2018. The higher bank-owned life insurance income was due to higher proceeds from life insurance policies received in 2019 compared to the previous year.
Revenues 267
 252
 15
   339
 314
 25
 The increase in revenues was due to higher interest and noninterest income.
Interest expense 12
 11
 1
 Higher interest expense was due to an increase in average interest-bearing liabilities. Average deposit balances for 2015 increased by $293 million compared to 2014 due to an increase in core deposits and term certificates of $279 million and $14 million, respectively. The other borrowings average balance increased by $64 million due to an increase in public repurchase agreements. 18
 15
 3
 Higher interest expense was primarily due to an increase in term certificate balances and increased deposit rates. Average deposit balances for 2019 increased by $155 million compared to 2018 due to an increase in core deposits and time certificates of $134 million and $21 million, respectively. Average cost of deposits for 2019 was 27 basis points, or 4 basis points above the average cost of deposits for 2018. The other borrowings average balance decreased by $28 million primarily due to a decrease in repurchase agreements. Average cost of other borrowings for 2019 was 1.42%, or 32 basis points above the average cost of borrowings for 2018.
Provision for loan losses 6
 6
 —
 The provision for loan losses for 2015 and 2014 were used primarily to establish loan loss reserves for the growth in the loan portfolio and cover net loan charge-offs. The provision for loan losses in 2015 also included higher reserve levels for the commercial loan portfolio. 24
 15
 9
 The provision for loan losses for 2019 increased by $8.7 million compared to the provision for loan losses in 2018. The provision for loan losses in 2019 was primarily for additional loss reserves for the consumer and credit scored loan portfolios to cover net charge-offs, and reserves for an impaired commercial credit, partly offset by the release of reserves resulting from recoveries of previously charged-off loans. The provision for loan losses for 2018 was primarily for additional loss reserves for the consumer loan portfolio as a result of growth and increased net charge-offs, partly offset by the release of reserves for the commercial, commercial real estate and HELOC loan portfolios as a result of improved credit trends.
Noninterest expense 166
 156
 10
 Higher noninterest expense was primarily due to higher compensation and benefits expense as a result of an increase in retail delivery compensation cost, higher performance-based incentive cost and higher benefits expenses related to the frozen defined benefit plan and medical insurance premium costs. 185
 177
 8
 Higher noninterest expense was primarily due to higher compensation and employee benefit costs, and increases in occupancy and equipment expenses. The increase in compensation and employee benefits was due to an increase in the minimum pay rate for employees, annual merit increases and higher employee benefit costs. Occupancy and equipment expenses for 2019 included occupancy, depreciation and equipment expenses for the new campus while still including the costs of properties being vacated.
Expenses 184
 173
 11
   227
 207
 20
 The increase in expenses was primarily due to higher provision for loan losses, and increases in interest and noninterest expenses.
Operating income 83
 79
 4
 Higher interest and noninterest income, partly offset by higher noninterest expenses. 112
 107
 5
 Higher interest and noninterest income was partly offset by higher provision for loan losses, higher interest expense and higher noninterest expenses.
Net income 55
 51
 4
 Higher operating income, partly offset by higher taxes. 89
 83
 6
 The increase in net income was the result of higher operating income and lower income tax expense.
Return on average common equity 1
 9.9% 9.6% 0.3%  
Return on average equity 1
 13.5% 13.5% —%  

1 Calculated using the average daily balance
1
For a discussion of 2017 results, please refer to the “Results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Bank,” in the Company’s 2018 Form 10-K.
Calculated using the average daily balances.
See Note 54 of the Consolidated Financial Statements for a discussion of guarantees and further information about ASB.



Average balance sheet and net interest margin.  The following table provides a summary of our consolidated average balances, including major categories of interest-earning assets and interest-bearing liabilities:
2016 2015 20142019 2018 2017
(dollars in thousands)
Average
balance
 
Interest1
income/
expense
 
Yield/
rate
(%)
 Average
balance		 
Interest1
income/
expense
 Yield/
rate
(%)		 Average
balance		 
Interest1income/
expense
 Yield/
rate
(%)
Average
balance
 
Interest
income/
expense
 
Yield/
rate
(%)
 Average
balance		 
Interest
income/
expense
 Yield/
rate
(%)		 Average
balance		 
Interest
income/
expense
 Yield/
rate
(%)
Assets:             
  
  
                 
Interest-earning deposits$75,092
 $383
 0.51
 $124,874
 $323
 0.26
 $88,089
 $222
 0.25
$16,618
 $320
 1.92
 $50,658
 $940
 1.86
 $79,927
 $898
 1.12
FHLB stock11,153
 191
 1.72
 32,140
 148
 0.46
 83,053
 88
 0.11
9,716
 350
 3.60
 9,726
 351
 3.60
 10,770
 208
 1.93
Securities purchased under resale agreements—
 —
 —
 —
 —
 —
 5,096
 20
 0.39
Available-for-sale investment securities                 
Investment securities                 
Taxable934,469
 18,592
 1.99
 687,215
 14,649
 2.13
 525,949
 11,336
 2.16
1,406,564
 31,178
 2.22
 1,503,036
 35,862
 2.39
 1,265,240
 27,291
 2.16
Non-taxable717
 28
 3.87
 —
 —
 —
 11,600
 429
 3.69
27,512
 1,360
 4.94
 17,485
 771
 4.41
 15,427
 655
 4.24
Total available-for-sale investment securities935,186
 18,620
 1.99
 687,215
 14,649
 2.13
 537,549
 11,765
 2.19
Total investment securities1,434,076
 32,538
 2.27
 1,520,521
 36,633
 2.41
 1,280,667
 27,946
 2.18
Loans                                  
Residential 1-4 family2,074,564
 88,274
 4.26
 2,064,170
 89,933
 4.36
 2,023,816
 90,591
 4.48
2,181,554
 89,956
 4.12
 2,122,895
 86,936
 4.10
 2,077,705
 86,934
 4.18
Commercial real estate872,694
 35,940
 4.12
 669,184
 26,558
 3.97
 557,924
 23,904
 4.28
863,468
 40,324
 4.67
 860,155
 39,579
 4.60
 887,890
 37,806
 4.26
Home equity line of credit859,955
 28,249
 3.28
 828,129
 26,511
 3.20
 790,701
 25,716
 3.25
1,043,479
 38,826
 3.72
 944,065
 34,634
 3.67
 889,360
 30,001
 3.37
Residential land18,850
 1,118
 5.93
 17,304
 1,101
 6.36
 16,276
 1,106
 6.79
14,065
 774
 5.50
 14,935
 823
 5.51
 16,837
 1,011
 6.00
Commercial743,586
 29,743
 4.00
 798,182
 29,282
 3.67
 783,670
 29,294
 3.74
620,206
 27,950
 4.51
 579,765
 26,689
 4.60
 631,170
 27,405
 4.34
Consumer149,287
 16,450
 11.02
 119,267
 11,397
 9.56
 110,440
 8,730
 7.90
270,340
 35,864
 13.27
 240,414
 31,802
 13.23
 205,334
 24,098
 11.74
Total loans 2,3
4,718,936
 199,774
 4.23
 4,496,236
 184,782
 4.11
 4,282,827
 179,341
 4.19
Total interest-earning assets5,740,367
 218,968
 3.81
 5,340,465
 199,902
 3.74
 4,996,614
 191,436
 3.83
Total loans 1,2
4,993,112
 233,694
 4.68
 4,762,229
 220,463
 4.63
 4,708,296
 207,255
 4.40
Total interest-earning assets 3
6,453,522
 266,902
 4.14
 6,343,134
 258,387
 4.07
 6,079,660
 236,307
 3.89
Allowance for loan losses(54,338)  
  
 (46,881)  
  
 (42,242)  
  
(54,640)  
   (53,593)  
   (55,629)  
  
Non-interest-earning assets507,850
  
  
 490,187
  
  
 459,513
  
  
Noninterest-earning assets696,270
  
   606,304
  
   546,523
  
  
Total Assets$6,193,879
  
  
 $5,783,771
  
  
 $5,413,885
  
  
$7,095,152
  
   $6,895,845
  
  
 $6,570,554
  
  
Liabilities and Shareholder’s Equity: 
  
  
  
  
  
  
  
  
 
  
    
  
  
  
  
  
Savings$2,117,186
 1,402
 0.07
 $1,980,151
 1,257
 0.06
 $1,879,373
 1,134
 0.06
$2,340,671
 1,904
 0.08
 $2,334,681
 1,639
 0.07
 $2,278,396
 1,567
 0.07
Interest-bearing checking839,339
 173
 0.02
 782,811
 139
 0.02
 738,651
 126
 0.02
1,044,315
 1,298
 0.12
 1,006,839
 706
 0.07
 902,678
 238
 0.03
Money market160,700
 202
 0.13
 164,568
 205
 0.12
 171,889
 214
 0.12
145,939
 953
 0.65
 140,225
 602
 0.43
 142,068
 168
 0.12
Time certificates565,135
 5,390
 0.95
 449,179
 3,747
 0.83
 434,934
 3,603
 0.83
810,749
 12,675
 1.56
 789,926
 11,044
 1.40
 696,799
 7,687
 1.10
Total interest-bearing deposits3,682,360
 7,167
 0.19
 3,376,709
 5,348
 0.16
 3,224,847
 5,077
 0.16
4,341,674
 16,830
 0.39
 4,271,671
 13,991
 0.33
 4,019,941
 9,660
 0.24
Advances from Federal Home Loan Bank101,597
 3,160
 3.11
 100,438
 3,146
 3.13
 100,389
 3,146
 3.13
33,652
 843
 2.50
 41,855
 845
 2.02
 79,374
 2,245
 2.83
Securities sold under agreements to repurchase169,730
 2,428
 1.43
 219,351
 2,832
 1.29
 155,012
 2,585
 1.67
79,647
 767
 0.96
 99,162
 703
 0.71
 97,535
 251
 0.26
Total interest-bearing liabilities3,953,687
 12,755
 0.32
 3,696,498
 11,326
 0.31
 3,480,248
 10,808
 0.31
4,454,973
 18,440
 0.41
 4,412,688
 15,539
 0.35
 4,196,850
 12,156
 0.29
Non-interest bearing liabilities: 
  
  
  
  
  
  
  
  
Noninterest bearing liabilities: 
  
  
  
  
  
  
  
  
Deposits1,559,132
  
  
 1,426,962
  
  
 1,285,964
  
  
1,848,336
  
  
 1,763,331
  
  
 1,672,780
  
  
Other102,302
  
  
 109,386
  
  
 113,401
  
  
131,691
  
  
 108,976
  
  
 102,789
  
  
Shareholder’s equity578,758
  
  
 550,925
  
  
 534,272
  
  
660,152
  
  
 610,850
  
  
 598,135
  
  
Total Liabilities and Shareholder’s Equity$6,193,879
  
  
 $5,783,771
  
  
 $5,413,885
  
  
$7,095,152
  
  
 $6,895,845
  
  
 $6,570,554
  
  
Net interest income 
 $206,213
  
  
 $188,576
  
  
 $180,628
  
 
 $248,462
    
 $242,848
  
  
 $224,151
  
Net interest margin (%)4
 
  
 3.59
  
  
 3.53
  
  
 3.62
 
  
 3.85
  
  
 3.83
  
  
 3.69
1 
Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.01 million, nil and $0.2 million for 2016, 2015 and 2014, respectively.
2
Includes loans held for sale, at lower of cost or fair value, of $5.4$6.3 million, $5.6$2.3 million and $3.1$7.4 million as of December 31, 2016, 20152019, 2018 and 2014,2017, respectively.
32 
Includes recognition of net deferred loan fees of $2.8$0.2 million, $2.7$0.1 million and $3.7$1.7 million for 2016, 20152019, 2018 and 2014,2017 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.



The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a pro rata basis.
 2019 vs. 2018 2018 vs. 2017
(in thousands)Rate Volume Total Rate Volume Total
Interest income 
  
  
  
  
  
Interest-earning deposits$31
 $(651) $(620) $455
 $(413) $42
FHLB stock—
 (1) (1) 165
 (22) 143
Investment securities           
Taxable(2,462) (2,222) (4,684) 3,100
 5,471
 8,571
Non-taxable102
 487
 589
 27
 89
 116
Total investment securities(2,360) (1,735) (4,095) 3,127
 5,560
 8,687
Loans     
      
Residential 1-4 family454
 2,566
 3,020
 (1,768) 1,770
 2
Commercial real estate595
 150
 745
 2,972
 (1,199) 1,773
Home equity line of credit481
 3,711
 4,192
 2,740
 1,893
 4,633
Residential land(1) (48) (49) (79) (109) (188)
Commercial(539) 1,800
 1,261
 1,587
 (2,303) (716)
Consumer96
 3,966
 4,062
 3,284
 4,420
 7,704
Total loans1,086
 12,145
 13,231
 8,736
 4,472
 13,208
Total increase (decrease) in interest income(1,243) 9,758
 8,515
 12,483
 9,597
 22,080
Interest expense 
  
  
  
  
  
Savings(261) (4) (265) —
 (72) (72)
Interest-bearing checking(563) (29) (592) (431) (37) (468)
Money market(325) (26) (351) (436) 2
 (434)
Time certificates(1,325) (306) (1,631) (2,253) (1,104) (3,357)
Advances from Federal Home Loan Bank(181) 183
 2
 528
 872
 1,400
Securities sold under agreements to repurchase(219) 155
 (64) (448) (4) (452)
Total decrease (increase) in interest expense(2,874) (27) (2,901) (3,040) (343) (3,383)
Increase (decrease) in net interest income$(4,117) $9,731
 $5,614
 $9,443
 $9,254
 $18,697
Earning assets, costing liabilities, contingencies and other factors.  Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The interest rate environment


has been impacted by disruptions in the financial markets over a period of several years and these conditions are beginning to moderate with the interest rate increases in the past year which resulted in an increase in net interest income and net interest margin.years.
Loan originations and mortgage-relatedmortgage-backed securities are ASB’s primary earning assets.


Loan portfolio.  ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. See Note 5 of the Consolidated Financial Statements forThe following table sets forth the composition of ASB’s loans receivable.held for investment:
December 312019 2018 2017 2016 2015
(dollars in thousands)Balance 
% of
total

 Balance % of
total
 Balance % of
total
 Balance % of
total
 Balance % of
total
Real estate: 1 
 
  
  
  
  
  
  
  
  
  
Residential 1-4 family$2,178,135
 42.6
 $2,143,397
 44.3
 $2,118,047
 45.3
 $2,048,051
 43.2
 $2,069,665
 44.8
Commercial real estate824,830
 16.1
 748,398
 15.4
 733,106
 15.7
 800,395
 16.9
 690,561
 14.9
Home equity line of credit1,092,125
 21.3
 978,237
 20.2
 913,052
 19.6
 863,163
 18.2
 846,294
 18.3
Residential land14,704
 0.3
 13,138
 0.3
 15,797
 0.3
 18,889
 0.4
 18,229
 0.4
Commercial construction70,605
 1.4
 92,264
 1.9
 108,273
 2.3
 126,768
 2.7
 100,796
 2.2
Residential construction11,670
 0.2
 14,307
 0.3
 14,910
 0.3
 16,080
 0.3
 14,089
 0.3
Total real estate4,192,069
 81.9
 3,989,741
 82.4
 3,903,185
 83.5
 3,873,346
 81.7
 3,739,634
 80.9
Commercial670,674
 13.1
 587,891
 12.1
 544,828
 11.7
 692,051
 14.6
 758,659
 16.4
Consumer257,921
 5.0
 266,002
 5.5
 223,564
 4.8
 178,222
 3.7
 123,775
 2.7
Total loans5,120,664
 100.0
 4,843,634
 100.0
 4,671,577
 100.0
 4,743,619
 100.0
 4,622,068
 100.0
Less: Deferred fees and discounts512
  
 (613)  
 (809)  
 (4,926)  
 (6,249)  
Allowance for loan losses(53,355)  
 (52,119)  
 (53,637)  
 (55,533)  
 (50,038)  
Total loans, net$5,067,821
  
 $4,790,902
  
 $4,617,131
  
 $4,683,160
  
 $4,565,781
  
1
Includes renegotiated loans.
The increase in the loans balance in 2019 was primarily due to growth in the HELOC, commercial, commercial real estate and residential 1-4 family loan portfolios, which were the portfolios targeted as ASB continued its loan growth strategy of diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable rate loans.
The increase in the totalloans balance in 2018 was primarily due to growth in the HELOC, consumer, commercial and residential 1-4 family loan portfolios, which were portfolios targeted in ASB’s loan growth strategy.
The decrease in the loans balance in 2017 was primarily due to decreases in the commercial, commercial real estate, and commercial construction loan portfolios, partly offset by growth in the residential 1-4 family, HELOC, and consumer loan portfolios. The decrease in the commercial loan portfolio from $4.6 billion atwas primarily due to the endstrategic reductions in the portfolio, including a $75 million reduction in ASB’s nationally syndicated loan portfolio. The decrease in the commercial real estate loan portfolio was primarily due to paydown of 2015 to $4.7 billion ata large commercial real estate credit. The growth in the end ofresidential 1-4 family, HELOC and consumer loan portfolios were consistent with ASB’s loan growth strategy.
The increase in the loans balance in 2016 was primarily due to growth in the commercial real estate, home equity line of credit (HELOC),consumer, commercial construction and consumerHELOC loan portfolios whichas a result of demand for these loan types, partly offset by a decrease in the commercial and residential 1-4 family loan portfolios. The growth in the commercial real estate, consumer, commercial construction and HELOC loan portfolios was consistent with ASB’s loan growth strategy. The decrease in the commercial loan portfolio mix targetswas due to the strategic reduction of ASB’s nationally syndicated loan portfolio by $93 million. The decrease in the residential loan portfolio was due to ASB’s decision to sell a portion of its loan production with low interest rates to control its interest rate risk.
The increase in the loans balance in 2015 was primarily due to growth in commercial real estate, HELOC and residential 1-4 family loan portfolios, partly offset by a decrease in the commercial loan portfolio. The growth in the commercial real estate, HELOC and residential loan portfolios was driven by demand for this loan type and was consistent with ASB’s loan growth strategy.


The following table summarizes loans held for investment based upon contractually scheduled principal payments allocated to the indicated maturity categories:
December 312019
Due
In
1 year
or less

 
After 1 year
through
5 years

 
After
5 years

 Total
(in millions) 
  
  
  
Commercial – Fixed$73
 $135
 $37
 $245
Commercial – Adjustable163
 247
 16
 426
Total commercial236
 382
 53
 671
Commercial construction – Fixed—
 —
 —
 —
Commercial construction – Adjustable26
 27
 18
 71
Total commercial construction26
 27
 18
 71
Residential construction – Fixed12
 —
 —
 12
Residential construction – Adjustable—
 —
 —
 —
Total residential construction12
 —
 —
 12
Total loans – Fixed85
 135
 37
 257
Total loans – Adjustable189
 274
 34
 497
Total loans$274
 $409
 $71
 $754
Home equity— key credit statistics.Attention has been given by regulators and rating agencies to the potential for increased exposure to credit losses associated with HELOCs that were originated during the period of rapid home price appreciation between 2003 and 2007 as they have reached the end of their 10-year, interest-only payment periods. Once the interest only payment period has ended, payments are reset to include principal repayments along with interest. ASB does not have a large exposure to HELOCs originated between 2003 and 2007. Nearly all of ASB’s HELOC originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older equity lines represent 1% of the HELOC portfolio and are included in the amortizing balances identified in the loan portfolio table below.
December 31 2016 2015 2019
 2018
Outstanding balance (in thousands) $863,163
 $846,294
Outstanding balance of home equity loans (in thousands) $1,092,125
 $978,237
Percent of portfolio in first lien position 45.1% 42.9% 53.7% 49.2%
Net charge-off ratio 0.01% 0.02% 0.01% 0.01%
Delinquency ratio 0.35% 0.25% 0.27% 0.46%
      End of draw period – interest only Current
December 31, 2019 Total Interest only 2019-2020 2021-2023 Thereafter amortizing
Outstanding balance (in thousands) $1,092,125
 $814,174
 $42,694
 $118,153
 $653,327
 $277,951
% of total 100% 75% 4% 11% 60% 25%
 
      End of draw period – interest only Current
December 31, 2016 Total Interest only 2017 2018-2020 Thereafter amortizing
Outstanding balance (in thousands) $863,163
 $678,348
 $8,524
 $122,966
 $546,858
 $184,815
% of total 100% 79% 1% 14% 64% 21%
The HELOC portfolio makes up 18%21% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable ratevariable-rate term loan with a 20-year amortization period. This product type comprises 78%76% of the total HELOC portfolio and is the current product offering. Borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed ratefixed-rate loan with level principal and interest payments. As of December 31, 2016,2019, approximately 19%23% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option.
Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of real estate secured loans. In a foreclosure action, the property securingcollateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold. As of December 31, 2019 and 2018, ASB had nil and $0.1 million, respectively, of real estate acquired in settlement of loans.
In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured loans). ASB loans that were 90 days or


more past due on which interest was being accrued as of December 31, 2019, 2018, 2017, 2016 and 2015 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured (TDR) loans:
December 312019
 2018
 2017
 2016
 2015
(dollars in thousands) 
  
  
  
  
Nonaccrual loans— 
  
  
  
  
Real estate: 
  
  
  
  
Residential 1-4 family$11,395
 $12,037
 $12,598
 $11,154
 $20,554
Commercial real estate195
 —
 —
 223
 1,188
Home equity line of credit6,638
 6,348
 4,466
 3,080
 2,254
Residential land448
 436
 841
 878
 970
Commercial construction  —
 —
 —
 —
Residential construction  —
 —
 —
 —
Total real estate18,676
 18,821
 17,905
 15,335
 24,966
Commercial5,947
 4,278
 3,069
 6,708
 20,174
Consumer5,113
 4,196
 2,617
 1,282
 895
Total nonaccrual loans$29,736
 $27,295
 $23,591
 $23,325
 $46,035
Troubled debt restructured loans not included above— 
  
  
  
  
Real estate: 
  
  
  
  
Residential 1-4 family$9,869
 $10,194
 $10,982
 $14,450
 $13,962
Commercial real estate853
 915
 1,016
 1,346
 —
Home equity line of credit10,376
 11,597
 6,584
 4,934
 2,467
Residential land2,644
 1,622
 425
 2,751
 4,713
Commercial construction—
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
Total real estate23,742
 24,328
 19,007
 23,481
 21,142
Commercial2,614
 1,527
 1,741
 14,146
 1,104
Consumer57
 62
 66
 10
 —
Total troubled debt restructured loans$26,413
 $25,917
 $20,814
 $37,637
 $22,246
In 2019, nonaccrual loans increased $2.4 million primarily due to increases in commercial and consumer nonaccrual loans of $1.7 million and $0.9 million, respectively. ASB evaluates a restructured loan transaction to determine if the borrower is in financial difficulty and if the restructured terms are considered concessions—typically terms that are out of market, beyond normal or reasonable standards, or otherwise not available to a non-troubled borrower in the normal marketplace. A loan classified as TDR must meet both criteria of financial difficulty and concession. Accruing TDR loans increased by $0.5 million primarily due to increases of $1.1 million and $1.0 million of commercial and residential land loans, respectively, classified as TDR, partially offset by a $1.2 million decrease in HELOC loans classified as TDR.
In 2018, nonaccrual loans increased $3.7 million primarily due to increases in HELOC, consumer, and commercial nonaccrual loans of $1.9 million, $1.6 million and $1.2 million, respectively. Accruing TDR loans increased by $5.1 million primarily due to a $5.0 million increase in HELOC loans classified as TDR.
In 2017, nonaccrual loans increased slightly by $0.3 million primarily due to higher nonaccrual residential 1-4 family, HELOC and consumer loans of $1.4 million, $1.4 million and $1.3 million, respectively. Nonaccrual commercial loans decreased by $3.6 million. Accruing TDR loans decreased by $16.8 million in 2017 primarily due to decreases of $12.4 million, $3.5 million, and $2.3 million of commercial, residential 1-4 family, and residential land loans, respectively, classified as TDRs.
In 2016, nonaccrual loans decreased $22.7 million primarily due to upgrades of specific commercial and commercial real estate loans, payoff of a troubled commercial loan and a segment of residential mortgages transferred to held-for-sale. Nonaccrual commercial and residential loans decreased by $13.5 million and $9.4 million, respectively. Accruing TDR loans increased $15.4 million in 2016 primarily due to increases of $13.0 million and $2.5 million of commercial and HELOC loans, respectively, classified as TDR. The increase in commercial loans classified as TDR was primarily due to two commercial credits being classified as TDR.


Impact of nonperforming loans on interest income. The following table presents the gross interest income for both nonaccrual and restructured loans that would have been recognized if such loans had been current in accordance with their original contractual terms, and had been outstanding throughout the period or since origination if held for only part of the period. The table also presents the interest income related to these loans that was actually recognized for the period.
(dollars in millions)Year ended December 31, 2019
Gross amount of interest income that would have been recorded if the loans had been current in accordance with original contractual terms, and had been outstanding throughout the period or since origination, if held for only part of the period 1
$3
Interest income actually recognized2
Total interest income foregone$1
1
Based on the contractual rate that was being charged at the time the loan was restructured or placed on nonaccrual status.
See “Allowance for loan losses” in Note 54 of the Consolidated Financial Statements for information with respect to nonperforming assets. The level of nonperforming loans has continued to decrease with the improving Hawaii economy.
Allowance for loan losses. See “Allowance for loan losses” in Note 54 of the Consolidated Financial Statements for the tables which sets forth the allocation of ASB’s allowance for loan losses. ForUsing an effective date of January 1, 2020, ASB will adopt ASU 2016-13, Financial Instruments - Measurement of Current Expected Credit Losses on Financial Instruments, which will modify the accounting for the allowance for loan losses from an incurred loss model to an expected loss model (see Note 1, “Summary of Significant Accounting Policies” of the Consolidated Financial Statements).
The following table presents the changes in the allowance for loan losses:
(dollars in thousands)2019
 2018
 2017
 2016
 2015
Allowance for loan losses, January 1$52,119
 $53,637
 $55,533
 $50,038
 $45,618
Provision for loan losses23,480
 14,745
 10,901
 16,763
 6,275
Charge-offs         
Real estate:         
Residential 1-4 family26
 128
 826
 639
 356
Commercial real estate—
 —
 —
 —
 —
Home equity line of credit144
 353
 14
 112
 205
Residential land4
 18
 210
 138
 —
Commercial construction—
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
Total real estate174
 499
 1,050
 889
 561
Commercial6,811
 2,722
 4,006
 5,943
 1,074
Consumer21,677
 17,296
 11,757
 7,413
 4,791
Total charge-offs28,662
 20,517
 16,813
 14,245
 6,426
Recoveries 
  
  
  
  
Real estate:         
Residential 1-4 family854
 74
 157
 421
 226
Commercial real estate—
 —
 —
 —
 —
Home equity line of credit17
 257
 308
 59
 80
Residential land229
 179
 482
 461
 507
Commercial construction—
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
Total real estate1,100
 510
 947
 941
 813
Commercial2,351
 2,136
 1,852
 1,093
 2,773
Consumer2,967
 1,608
 1,217
 943
 985
Total recoveries6,418
 4,254
 4,016
 2,977
 4,571
Net charge-offs22,244
 16,263
 12,797
 11,268
 1,855
Allowance for loan losses, December 31$53,355
 $52,119
 $53,637
 $55,533
 $50,038
Ratio of allowance for loan losses to loans held for investment1.04% 1.08% 1.15% 1.17% 1.08%
Ratio of provision for loan losses during the year to average total loans0.47% 0.31% 0.23% 0.36% 0.14%
Ratio of net charge-offs during the year to average total loans0.45% 0.34% 0.27% 0.24% 0.04%


The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans:
December 312019 2018 2017
(dollars in thousands)Allow-ance balance 
Allowance
to loan
receivable
%
 
Loan
receivable
% of
total
 Allow-ance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total		 Allow-ance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total
Real estate: 
  
  
  
  
  
  
  
  
Residential 1-4 family$2,380
 0.11
 42.6
 $1,976
 0.09
 44.3
 $2,902
 0.14
 45.3
Commercial real estate15,053
 1.82
 16.1
 14,505
 1.94
 15.4
 15,796
 2.15
 15.7
Home equity line of credit6,922
 0.63
 21.3
 6,371
 0.65
 20.2
 7,522
 0.82
 19.6
Residential land449
 3.05
 0.3
 479
 3.65
 0.3
 896
 5.67
 0.3
Commercial construction2,097
 2.97
 1.4
 2,790
 3.02
 1.9
 4,671
 4.31
 2.3
Residential construction3
 0.03
 0.2
 4
 0.03
 0.3
 12
 0.08
 0.3
Total real estate26,904
 0.64
 81.9
 26,125
 0.65
 82.4
 31,799
 0.81
 83.5
Commercial10,245
 1.53
 13.1
 9,225
 1.57
 12.1
 10,851
 1.99
 11.7
Consumer16,206
 6.28
 5.0
 16,769
 6.30
 5.5
 10,987
 4.91
 4.8
Total allowance for loan losses$53,355
 1.04
 100.0
 $52,119
 1.08
 100.0
 $53,637
 1.15
 100.0
December 312016 2015
(dollars in thousands)Allowance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total		 Allowance balance Allowance
to loan
receivable
%		 Loan
receivable
% of
total
Real estate: 
  
  
  
  
  
Residential 1-4 family$2,873
 0.14
 43.2
 $4,186
 0.20
 44.8
Commercial real estate16,004
 2.00
 16.9
 11,342
 1.64
 14.9
Home equity line of credit5,039
 0.58
 18.2
 7,260
 0.86
 18.3
Residential land1,738
 9.20
 0.4
 1,671
 9.17
 0.4
Commercial construction6,449
 5.09
 2.7
 4,461
 4.43
 2.2
Residential construction12
 0.07
 0.3
 13
 0.09
 0.3
Total real estate32,115
 0.83
 81.7
 28,933
 0.77
 80.9
Commercial16,618
 2.40
 14.6
 17,208
 2.27
 16.4
Consumer6,800
 3.82
 3.7
 3,897
 3.15
 2.7
Total allowance for loan losses$55,533
 1.17
 100.0
 $50,038
 1.08
 100.0
In 2019, ASB’s allowance for loan losses increased by $1.2 million primarily due to an increase in loan loss reserves for the commercial, commercial real estate and HELOC loan portfolios as a result of loan growth in those loan portfolios. Total delinquencies of $19.8 million at December 31, 2019 was a decrease of $6.2 million compared to total delinquencies of $26.0 million at December 31, 2018 primarily due to decreases in delinquent residential 1-4 family and HELOC loans. The ratio of delinquent loans to total loans decreased from 0.54% of total outstanding loans at December 31, 2018 to 0.39% of total outstanding loans at December 31, 2019. Net charge-offs for 2019 were $22.2 million, an increase of $5.9 million compared to $16.3 million at December 31, 2018 primarily due to an increase in consumer loan portfolio charge-offs as result of ASB’s unsecured consumer loan portfolio product offering with risk-based pricing and net charge-offs for an impaired commercial credit. ASB’s provision for loan losses was $23.5 million, an increase of $8.7 million compared to the provision for loan losses of $14.7 million for 2018. The increase was due to additional reserves for the consumer and credit scored loan portfolios, and an impaired commercial credit.
In 2018, ASB’s allowance for loan losses decreased by $1.5 million primarily due to lower loan loss reserves required for the commercial, commercial construction, commercial real estate and HELOC loan portfolios as a result of improving credit trends, partly offset by additional loan loss reserves for the consumer loan portfolio. Total delinquencies of $26.0 million at December 31, 2018 was an increase of $2.4 million compared to total delinquencies of $23.6 million at December 31, 2017 primarily due to increases in delinquent consumer, HELOC and residential 1-4 family loans, partly offset by decreases in delinquent commercial loans. The ratio of delinquent loans to total loans increased slightly from 0.51% of total outstanding loans at December 31, 2017 to 0.54% of total outstanding loans at December 31, 2018. Net charge-offs for 2018 were $16.3 million, an increase of $3.5 million compared to $12.8 million at December 31, 2017 primarily due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan portfolio product offering with risk-based pricing. ASB’s


provision for loan losses was $14.7 million, an increase of $3.8 million compared to the provision for loan losses of $10.9 million for 2017. The increase was due to additional reserves for the consumer loan portfolio, partly offset by lower reserves required for the commercial, commercial construction, commercial real estate and HELOC loan portfolios as result of improved credit quality in those loan portfolios.
In 2017, ASB’s allowance for loan losses decreased by $1.9 million primarily due to lower loan loss reserves required for the commercial, commercial construction, and commercial real estate loan portfolios as a result of a decrease in the portfolio balances and improving credit trends, partly offset by additional loan loss reserves for the consumer and HELOC loan portfolios. Total delinquencies of $23.6 million at December 31, 2017 was a slight increase of $0.5 million compared to total delinquencies of $23.1 million at December 31, 2016 primarily due to increases in delinquent commercial and consumer loans, offset by decreases in delinquent residential 1-4 family and commercial real estate loans. The ratio of delinquent loans to total loans increased slightly from 0.49% of total loans outstanding at December 31, 2016 to 0.51% of total loans outstanding at December 31, 2017. Net charge-offs for 2017 were $12.8 million, an increase of $1.5 million compared to $11.3 million for 2016 primarily due to an increase in consumer loan portfolio charge-offs as a result of the strategic expansion of ASB’s unsecured consumer loan product offering with risk-based pricing. ASB’s provision for loan losses was $10.9 million, a decrease of $5.9 million compared to the provision for loan losses of $16.8 million for 2016. The decrease was primarily due to the release of reserves for commercial real estate and commercial loan portfolios due to lower outstanding balances and improved credit quality, partly offset by an increase in loss reserves for the consumer loan portfolio.
In 2016, ASB’s allowance for loan losses increased by $5.5 million primarily due to growth in the commercial real estate and consumer loan lossportfolios and increases in reserves for the commercial real estate and unsecured consumer loan portfolios. Total delinquencies of $23.1 million at December 31, 2016 was $3.0 million lower than total delinquencies of $26.1 million at December 31, 2015 primarily due to the movement of $6 million of residential loans to held-for-sale. The ratio of delinquent loans to total loans decreased from 0.57% of total loans outstanding at December 31, 2015 to 0.49% of total loans outstanding at December 31, 2016. Net charge-offs for 2016 were $11.3 million, an increase of $9.4 million compared to $1.9 million for 2015 primarily due to charge-offs of specific commercial loans and an increase in consumer loan charge-offs as a result of the strategic expansion of ASB’s unsecured consumer loan product offering with risk-based pricing. ASB’s provision for loan losses was $16.8 million for 2016, an increase of $10.5 million compared to the provision for loan losses of $6.3 million for 2015. The increase in provision for loan losses was driven by growth in the commercial real estate and consumer loan portfolios as well as specific reserves for a few commercial loans.
In 2015, ASB’s allowance for loan losses increased by $4.4 million primarily due to growth in the commercial real estate loan portfolio ($159 million or 29.8% growth in outstanding balances) and increases in reserves for commercial andloans. Overall loan quality remained strong as total delinquencies of $26.1 million at December 31, 2015 was a slight increase of $0.6 million compared to total delinquencies of $25.5 million at December 31, 2014 primarily due to an increase in delinquent consumer loans. The ratio of delinquent loans to total loans decreased slightly from 0.58% of total loans outstanding at December 31, 2014 to 0.57% of total loans outstanding at December 31, 2015. Net charge-offs for 2015 were $1.9 million, an increase of $1.3 million compared to $0.6 million for 2014 primarily due to an increase in consumer loan loss reserves.charge-offs as result of the strategic expansion of ASB’s unsecured consumer loan product offering with risk-based pricing. ASB’s provision for loan losses was $6.3 million for 2015, an increase of $0.2 million compared to the provision for loan losses of $6.1 million for 2014.
Available-for sale investmentInvestment securities.  ASB’s investment portfolio was comprised as follows:
December 31 2016 2015 2019 2018 2017
(dollars in thousands) Balance % of total Balance % of total Balance % of total Balance % of total Balance % of total
U.S. Treasury and federal agency obligations $192,281
 18% $212,959
 26% $117,787
 9% $154,349
 10% $184,298
 13%
Mortgage-related securities — FNMA, FHLMC and GNMA 897,474
 81
 607,689
 74
Mortgage revenue bond 15,427
 1
 —
 —
Total available-for-sale investment securities $1,105,182
 100% $820,648
 100%
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies 1,165,836
 85
 1,303,291
 85
 1,245,988
 86
Corporate bonds 60,057
 4
 49,132
 3
 —
 —
Mortgage revenue bonds 28,597
 2
 23,636
 2
 15,427
 1
Total investment securities $1,372,277
 100% $1,530,408
 100% $1,445,713
 100%


PrincipalCurrently, ASB’s investment portfolio consists of U.S. Treasury and interest on mortgage-relatedfederal agency obligations, mortgage-backed securities, corporate bonds and mortgage revenue bonds. ASB owns mortgage-backed securities issued or guaranteed by the U.S. government agencies or sponsored agencies, including the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and, Government National Mortgage Association (GNMA) and Small Business Administration (SBA). The weighted-average yield on investments during 2019, 2018 and 2017 was 2.27%, 2.41% and 2.18%, respectively. ASB did not maintain a portfolio of securities held for trading during 2019, 2018 and 2017.


As of December 31, 2019, 2018 and 2017, ASB had $139.5 million, $141.9 million and $44.5 million, respectively, of investment securities that were purchased and classified as held-to-maturity. The investment securities were classified as held-to-maturity to enhance ASB’s capital management in a rising rate environment. ASB considers the held-to-maturity classification of these investment securities to be appropriate as ASB has the positive intent and ability to hold these securities to maturity.
Principal and interest on mortgage-backed securities issued by FNMA, FHLMC, GNMA and SBA are guaranteed by the issuer and, in the case of GNMA and SBA, backed by the full faith and credit of the U.S. government. U.S. Treasury securities are also backed by the full faith of the U.S. government. The increase in investment securities was due to the purchase of agency mortgage-relatedmortgage-backed and credit securities, corporate bonds, and a mortgage revenue bond with excess liquidity.
The net unrealized losses on ASB’s investment securities were primarily caused by movements in interest rates. All contractual cash flows of those investments are guaranteed by an agency of the U.S. government. Based upon ASB'sASB’s evaluation at December 31, 20162019, 2018, and 2015,2017 there was no indicated impairment as the bankASB expects to collect the contractual cash flows for these investments. See “Investment securities” in Note 1 of the Consolidated Financial Statements for a discussion of securities impairment assessment.
As of December 31, 2016, 20152019, 2018, and 2014,2017, ASB did not have any private-issue mortgage-relatedmortgage-backed securities. ASB does not have any exposure to securities backed by subprime mortgages. See “Investment securities” in Note 4 of the Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.
The following table summarizes the current amortized cost of ASB’s investment portfolio (excluding stock of the FHLB of Des Moines, which has no contractual maturity) and weighted average yields as of December 31, 2019. Mortgage-backed securities are shown separately because they are typically paid in monthly installments over a number of years.
(dollars in millions)
In 1 year
or less
 
After 1 year
through 5 years
 
After 5 years
through 10 years
 
After
10 years
 Mortgage-backed securities 
Total1
U.S. Treasury and federal agency obligations$47
 $41
 $29
     $117
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies        1,164
 1,164
Corporate bonds  35
 24
     59
Mortgage revenue bonds2
13
     16
   29
 $60
 $76
 $53
 $16
 $1,164
 $1,369
Weighted average yield2.26% 2.75% 2.44% 3.17% 2.44% 2.54%
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%.

Stock in FHLB. As of December 31, 2019, 2018 and 2017, ASB’s stock in FHLB of Des Moines ($8 million, $10 million and $10 million, respectively) was carried at cost because it can only be redeemed at par. The amount that ASB is required to invest in FHLB stock is determined by FHLB requirements. In 2019, 2018 and 2017, ASB received cash dividends of $349,000, $350,000 and $208,000, respectively, on its FHLB Stock.
Deposits and other borrowings.  Deposits continue to be the largest sourceAs of funds for ASBDecember 31, 2019 and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the current environment due to competition for2018, ASB’s costing liabilities consisted of 98% deposits and 2% other borrowings.
ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow or outflow, measured as the low levelyear-over-year difference in year-end deposits, was an inflow of short-term interest rates. Advances$113 million in 2019, compared to an inflow of $268 million in 2018 and $342 million in 2017.


The following table presents the average deposits and average rates by type of deposit. Average balances have been calculated using the average daily balances.
Years ended December 312019 2018 2017
(dollars in thousands)
Average
balance

 
% of
total interest-bearing
deposits

 
Weighted
average
rate %

 
Average
balance

 % of
total interest-bearing
deposits
 
Weighted
average
rate %

 Average
balance
 % of
total interest-bearing
deposits
 Weighted
average
rate %
Interest-bearing deposit liabilities                
Savings$2,340,671
 53.9% 0.08% $2,334,681
 54.6% 0.07% $2,278,396
 56.7% 0.07%
Checking1,044,315
 24.0
 0.12
 1,006,839
 23.6
 0.07
 902,678
 22.5
 0.03
Money market145,939
 3.4
 0.65
 140,225
 3.3
 0.43
 142,068
 3.5
 0.12
Certificate810,749
 18.7
 1.56
 789,926
 18.5
 1.40
 696,799
 17.3
 1.10
Total interest-bearing deposit liabilities$4,341,674
 100.0% 0.39% $4,271,671
 100.0% 0.33% $4,019,941
 100.0% 0.24%
Total noninterest-bearing demand deposit liabilities1,848,336
     1,763,331
     1,672,780
    
Total deposit liabilities$6,190,010
     $6,035,002
     $5,692,721
    
The following table presents the amount of time certificates of deposit of $100,000 or more, segregated by time remaining until maturity:
(in thousands)Amount
Three months or less$204,100
Greater than three months through six months72,436
Greater than six months through twelve months64,370
Greater than twelve months115,604
 $456,510
Other borrowings consist of advances from the FHLB and securities sold under agreements to repurchases. See “Other borrowings” in Note 4 of the Consolidated Financial Statements. ASB may obtain advances from the FHLB of Des Moines provided that certain standards related to creditworthiness have been met. Advances are collateralized by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Des Moines, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Des Moines or at an approved third-party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Des Moines. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. ASB pledges investment securities as collateral for securities sold under agreements to repurchase. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase continueon a gross basis in the balance sheet.
The increase in other borrowings in 2019 was due to be additional sourcesan increase in business repurchase agreements, partly offset by the payoff of funds. FHLB advances.
The decrease in other borrowings in 2018 was due to the payoff of a maturing FHLB advance and a decrease in business repurchase agreements. The decrease in other borrowings in 2017 was due to the payoff of a maturing FHLB advance, offset by an increase in business repurchase agreements.
As of December 31, 2016, ASB’s costing liabilities consisted of 97% deposits and 3% other borrowings compared to costing liabilities of 94% deposits and 6% other borrowings as of December 31, 2015. See Note 5 of the Consolidated Financial Statements for the composition of ASB’s deposit liabilities and other borrowings.
Federal Home Loan Bank of Des Moines. As of December 31, 2016 and 2015, ASB had $100 million of advances outstanding at the FHLB of Des Moines. As of December 31, 2016,2019, the unused borrowing capacity with the FHLB of Des Moines was $1.8$2.3 billion. The FHLB of Des Moines will continuecontinues to be aan important source of liquidity for ASB. See “Liquidity and capital resources” below for changes in the unused borrowing capacity with the FHLB of Des Moines.
Other factors.  Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in the fair value of the investment securities, respectively. In addition, changes in credit spreads also impact the fair values of the investment securities.


As of December 31, 2016,2019, ASB had an unrealized loss,gain, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $7.9$2.5 million compared to an unrealized loss, net of taxes, of $1.9$24.4 million as of December 31, 2015.2018. See “Quantitative and qualitative disclosures about market risk.Qualitative Disclosures About Market Risk.”
Legislation and regulation.  ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC)OCC and the Federal Deposit Insurance Corporation (FDIC).FDIC. Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.” Also see “Federal Deposit Insurance Corporation Assessment” in Note 54 of the Consolidated Financial Statements.
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act).  Regulation of the financial services industry, including regulation of HEI, ASB Hawaii and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASB Hawaii and ASB, under the Dodd-Frank Act on July 21, 2011, all of the functions of the Office of Thrift Supervision (OTS)OTS transferred on July 21, 2011 to the OCC, the FDIC, the Federal Reserve Board (FRB)FRB and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASB Hawaii, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, the OCC and the Bureau. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposed new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.
More stringent affiliate transaction rules now apply to At all times during 2019, ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewingwas a potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.”
The Dodd-Frank Act established the Bureau. It has authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and


(iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower. qualified thrift lender.
ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and allows federal law to preempt a state consumer financial law on a “case by case” basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state, (2) the state law prevents or significantly interferes with a bank’s exercise of its power or (3) the state law is preempted by another federal law.
The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms.
Also, the Dodd-Frank Act directs the Bureau to publish rules and forms that combine certain disclosures that consumers receive in connection with applying for and closing on a mortgage loan under the Truth in Lending Act and the Real Estate Settlement Procedures Act. Consistent with this requirement, the Bureau amended Regulation X (Real Estate Settlement Procedures Act) and Regulation Z (Truth in Lending) to establish new disclosure requirements and forms in Regulation Z for most closed-end consumer credit transactions secured by real property. In addition to combining the existing disclosure requirements and implementing new requirements, the final rule provides extensive guidance regarding compliance with those requirements. This rule was effective October 3, 2015.
The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. Financial institutions and their affiliates that have less than $10 billion in assets are exempt from this Amendment; however, on July 1, 2013, ASB became non-exempt as the consolidated assets of HEI exceeded $10 billion. The debit card interchange fees received by ASB have been lower as a result of the application of this Amendment.
Final Capital Rules.  On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies (such as ASB Hawaii). The FRB indicated that it would release a proposal on intermediate holding companies that would specify the criteria for establishing and transferring activities to intermediate holding companies and propose to apply the FRB’s capital requirements to such intermediate holding companies. The FRB has not yet issued such a proposal, or a proposal on how to apply the Basel III capital rules to SLHCs that are substantially engaged in commercial or insurance underwriting activities, such as grandfathered unitary SLHCs like HEI.
Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would initially be subject to the following minimum regulatory capital requirements: a common equity Tier 1 capital ratio of 4.5%, a Tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a tier 1 leverage ratio of 4%, and these requirements would increase in subsequent years. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization’s total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies’ calculation of risk-weighted assets and addressaddresses shortcomings in capital requirements identified by the agencies. The phased-in effective dates of the capital requirements under the final rule are:



Minimum Capital Requirements
Effective dates 1/1/2015 1/1/2016 1/1/2017 1/1/2018 1/1/2019
Capital conservation buffer  
 0.625% 1.25% 1.875% 2.50%
Common equity Tier 1 ratio + conservation buffer 4.50% 5.125% 5.75% 6.375% 7.00%
Tier 1 capital ratio + conservation buffer 6.00% 6.625% 7.25% 7.875% 8.50%
Total capital ratio + conservation buffer 8.00% 8.625% 9.25% 9.875% 10.50%
Tier 1 leverage ratio 4.00% 4.00% 4.00% 4.00% 4.00%
Countercyclical capital buffer — not applicable to ASB  
 0.625% 1.25% 1.875% 2.50%
The final rule was effective January 1, 2015 for ASB. As of December 31, 2016,2019, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.2%13.2%, a Tier-1 capital ratio of 12.2%13.2%, a Total capital ratio of 13.4%14.3% and a Tier-1 leverage ratio of 8.6%9.1%.
Subject to the timing and final outcome of the FRB’s SLHC intermediate holding company proposal, HEI anticipates that the capital requirements in the final rule will eventually be effective for HEI or ASB Hawaii as well. If the fully phased-in capital requirements were currently applicable to HEI, management believes HEI would satisfy the capital requirements, including the fully phased-in capital conservation buffer. Management cannot predict what final rule the FRB may adopt concerning intermediate holding companies or their impact on ASB Hawaii, if any.
Military Lending Act. The DepartmentCovered Savings Associations.On May 24, 2019, the OCC issued a final rule to allow federal savings associations with total consolidated assets of Defense (DOD) amended$20 billion or less, as reported by the association to the OCC on its regulationcall report as of December 31, 2017, to elect to operate as covered savings associations. A covered savings association generally has the same rights and privileges as a national bank that implementshas its main office situated in the Military Lending Act (MLA), which became effective on October 3, 2016. The DOD amended its regulation primarily forsame location as the purpose of extending the protectionshome office of the MLA to a broader range of closed-end and open-end credit products.covered savings association, with some exceptions. It initially applied to three narrowly-defined “consumer credit” products: closed-end payday loans; closed-end auto title loans; and closed-end tax refund anticipation loans. The DOD revised the scope of the definition of ‘‘consumer credit’’ to be generally consistent with the credit products that have beenis subject to the requirements of the Regulation Z, namely: credit offered or extendedsame duties, restrictions, penalties, liabilities, conditions, and limitations that apply to a national bank, with some exceptions, and must comply with certain rules and regulations applicable to the powers and investments of a national bank. A covered borrower primarily for personal, family, or household purposes and thatsavings association is (i) subjectnot required to a finance charge or (ii) payable by a written agreement in more than four installments.
Additionally, the DOD elected to exercise its discretion by generally requiring any fees for credit insurance products or for credit-related ancillary products to be included in the Military Annual Percentage Rate. The DOD also modified the disclosures that a creditor must provide to a covered borrower and implemented the enforcement provisions of the MLA. ASB has modified certain products, practices and associated training to conform to these changes.

Overtime Rules. The Secretary of Labor updated the overtime regulations of the Fair Labor Standards Act to simplify and modernize them. The Department of Labor issued final rules that will raise the salary threshold indicating eligibility from $455/week to $913/week ($47,476 per year), and update automatically the salary threshold every three years, based on wage growth over time, increasing predictability. The final rule was to become effective on December 1, 2016. In late-November 2016 however, the U.S. District Court in the Eastern District of Texas granted a nationwide preliminary injunction that blocked the final rule, saying the Department of Labor's rule exceeds the authority the agency was delegated by Congress. Despite this block, ASB modified its salaries in the fourth quarter of 2016 such that it is in voluntary compliancecomply with the final rule.
Stocklending and investment limits in FHLB.In the second quarter of 2015, the FHLB of Des MoinesHOLA and the FHLB of Seattle successfully completed the merger of the two banks and operated as one under the name FHLB of Des Moines as of June 1, 2015. The FHLB of Des Moines will continueis not required to be a sourcequalified thrift lender under HOLA. Finally, a covered savings association is not permitted to retain or engage in any subsidiaries, assets, or activities that are not permissible for a national bank. ASB has initiated a preliminary examination of liquidity for ASB.the benefits and disadvantages of such an election with the preservation of being held by a unitary thrift holding company in mind. ASB is awaiting official FRB commentary, and has not reached a decision on the election.
As of December 31, 2016, ASB’s stock in FHLB of Des Moines of $11.2 million was carried at cost because it can only be redeemed at par. There is a minimum required investment in such stock based on measurements of ASB’s capital, assets and/or borrowing levels. In 2016, 2015 and 2014, ASB received cash dividends of $191,000, $147,000 and $88,000, respectively, on its FHLB Stock.
Mortgage Servicing Rights. As of December 31, 2016 and 2015, ASB's mortgage servicing rights had a net carrying amount of $9.4 million and $8.9 million, respectively. The increase in the net carrying amount was due to the servicing rights retained from the residential loan sales during the year.



Liquidity and capital resources.
December 312016
 % change
 2015
 % change
2019
 % change
 2018
 % change
(dollars in millions) 
  
  
  
 
  
  
  
Total assets$6,421
 7
 $6,015
 8
$7,233
 3
 $7,028
 3
Available-for-sale investment securities1,105
 35
 821
 49
Loans receivable held for investment, net4,683
 3
 4,566
 4
Investment securities1,372
 (10) 1,530
 6
Loans held for investment, net5,068
 6
 4,791
 4
Deposit liabilities5,549
 10
 5,025
 9
6,272
 2
 6,159
 5
Other bank borrowings193
 (41) 329
 13
115
 5
 110
 (42)
As of December 31, 2016,2019, ASB was one of Hawaii’s largest financial institutions based on assets of $6.4$7.2 billion and deposits of $5.5$6.3 billion.
ASB’s principal sources of liquidity are customer deposits, borrowings and the maturity and repayment of portfolio loans and securities. ASB’s deposits as of December 31, 20162019 were $524$113 million higher than December 31, 2015.2018. ASB’s principal sources of borrowings areinclude advances from the FHLB and securities sold under agreements to repurchase from broker/dealers and commercial account holders. As of December 31, 2016,2019, ASB had no FHLB borrowings totaled $100 million, representing 1.6% of assets.outstanding. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. As of December 31, 2016,2019, ASB’s unused FHLB borrowing capacity was approximately $1.8$2.3 billion with no FHLB borrowings outstanding. In February 2020, the FHLB of Des Moines notified ASB that certain assets would no longer qualify as collateral for FHLB advances, reducing ASB's total FHLB borrowing capacity to approximately $1.5 billion. The notice included high-quality home equity lines of credit and was technical in nature and unrelated to the credit quality of the home equity loans, of which approximately 54% are in first lien position. ASB is working with the FHLB to understand the nature of the disqualification of those assets as collateral and re-establishing eligibility. Although the reduction in borrowing capacity will not impact ASB’s operations, ASB is evaluating other assets to pledge as collateral to increase its reserve borrowing capacity with the FHLB. Over the past 10 years, the maximum amount outstanding as of any quarter end was $110 million. As of December 31, 2016,2019, securities sold under agreements to repurchase totaled $93$115 million, representing 1.4%1.6% of assets. ASB utilizes deposits, advances from the


FHLB and securities sold under agreements to repurchase to fund maturing and withdrawn deposits, repay maturing borrowings, fund existing and future loans and purchase investment and mortgage-relatedmortgage-backed securities. As of December 31, 2016,2019, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.8$1.9 billion, includingof which, commitments to lend $2.6 million to borrowers whose loan terms have been modified in troubled debt restructurings.restructurings were nil. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
As of December 31, 20162019 and 2015,2018, ASB had $23.3$29.7 million and $46.0$27.3 million of loans on nonaccrual status, respectively, or 0.5% and 1.0%0.6% of net loans outstanding, respectively.outstanding. As of December 31, 20162019 and 2015,2018, ASB had $1.2 millionnil and $1.0$0.4 million, respectively, of real estate acquired in settlement of loansloans.
In 2016,2019, operating activities provided cash of $64$110 million. Net cash of $448$120 million was used by investing activities primarily due to purchases of investment securities of $534 million, a net increase in loans held forreceivable of $300 million, purchases of available-for-sale investment securities of $194$108 million, capital expenditures of $9$24 million, purchases of held-to-maturity investment securities of $13 million, contributions to low-income housing investments of $7 million and the purchasepurchases of bank owned life insurance of $3$4 million, partly offset by receipt of repayments offrom available-for-sale investment securities of $220$273 million, proceeds from the sale of commercial loansreal estate of $52$21 million, proceeds from the sale of mortgage-relatedavailable-for-sale investment securities of $20 million, repayments from held-to-maturity investment securities of $16 million and proceeds from the redemption of bank owned life insurance of $3 million and proceeds from the sale of real estate held for sale of $2$6 million. Financing activities provided net cash of $352$62 million primarily due to a net increase in deposits of $524$113 million partly offset by repayments of securities sold under agreements to repurchase of $92 million,and a net decreaseincrease in retail repurchase agreements of $44$50 million, partly offset by a net decrease in FHLB advances of $45 million and the payment of common stock dividends to HEI (through ASB Hawaii) of $36$56 million.
ASB believes that maintaining a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2016,2019, ASB was well-capitalized (see “Regulation—Capital requirements” belowNote 4 of the Consolidated Financial Statements for ASB’s capital ratios).
For a discussion of ASB dividends, see “Common stock equity” in Note 54 of the Consolidated Financial Statements.
Certain factors that may affect future resultsSee “Commitments” and financial condition.  Also see “Cautionary“Contingency” in Note Regarding Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.
Competition.  The banking industry in Hawaii is highly competitive. ASB is one of Hawaii’s largest financial institutions, based on total assets, and is in direct competition for deposits and loans, not only with larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small- and medium-sized businesses, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securities brokerage firms. These competitors offer a variety of lending, deposit and investment products to retail and business customers.


The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation, other non-branch channels such as online and mobile banking and perceptions4 of the institution’s financial soundnessConsolidated Financial Statements for a discussion of commitments and safety. To meet competition, ASB offers a variety of savingscontingencies and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch, convenient automated teller machines and an upgrade of the Bank's electronic banking platform. ASB also conducts advertising and promotional campaigns.off-balance sheet arrangements.
The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.
ASB is a full-service community bank serving both consumer and commercial customers and has been diversifying its loan portfolio from single-family home mortgages to higher-spread, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for residential mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its consumer, commercial and commercial real estate loans.
U.S. capital markets and credit and interest rate environment. Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of December 31, 2016, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $1.1 billion.
Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. Persistent low levels of interest rates have made it challenging to find investments with adequate risk-adjusted returns and had a negative impact on ASB’s asset yields and net interest margin. If the current interest rate environment persists, the potential for compression of ASB’s net interest margin will continue. ASB also manages the credit risk associated with its lending and securities portfolios, but a deep and prolonged recession led by a material decline in housing prices could materially impair the value of its portfolios. See “Quantitative and Qualitative Disclosures about Market Risk” below.
Technological developments.  New technological developments (e.g., significant advances in internet banking) may impact ASB’s future competitive position, results of operations and financial condition.
Environmental matters.  Prior to extending a loan collateralized by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.
Regulation. ASB is subject to examination and comprehensive regulation by the Department of Treasury, OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OCC.
Capital requirements.  The OCC, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2016, ASB was in compliance with OCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of OCC prompt corrective action regulations and FDIC capital regulations, as follows:
ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2016 with a Tier 1 leverage ratio of 8.6% (4.0%), a common equity Tier 1 capital ratio of 12.2% (4.5%), a Tier 1 capital ratio of 12.2% (6.0%) and a total capital ratio of 13.4% (8.0%).
ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2016 with a Tier 1 leverage ratio of 8.6% (5.0%), a common equity Tier 1 capital ratio of 12.2% (6.5%), a Tier-1 capital ratio of 12.2% (8.0%) and a total capital ratio of 13.4% (10.0%).
The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent


mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (typically acquired by foreclosure). The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to HEI (through ASB Hawaii) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI currently could be required to contribute to ASB up to an additional $28.3 million of capital, if necessary, to maintain ASB’s capital position.
Examinations.  ASB is subject to periodic “safety and soundness” examinations and other examinations by the OCC. In conducting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OCC’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as an officer, director, employee, attorney or auditor, except as provided by regulation. The OCC also regularly examines ASB’s information technology practices and its performance under Community Reinvestment Act measurement criteria.
The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2016, ASB was “well-capitalized” and thus not subject to these restrictions.
Qualified Thrift Lender status.  ASB is a “qualified thrift lender” (QTL) under its federal thrift charter and, in order to maintain this status, ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, ASB Hawaii and HEI’s other subsidiaries would also be subject to restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2016, ASB was a qualified thrift lender.
Unitary savings and loan holding company.  The Gramm-Leach-Bliley Act of 1999 (Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, ASB Hawaii and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the authorized financial holding companies permitted under the Gramm Act. There have been legislative proposals in the past which would operate to eliminate the thrift charter or the grandfathered status of HEI as a unitary thrift holding company and effectively require the divestiture of ASB.
Material estimates and critical accounting policies.  Also see “Material estimates and critical accounting policies” for Consolidated HEI above.
Allowance for loan losses.  See Note 1 of the Consolidated Financial Statements and the discussion above under “Earning assets, costing liabilities and other factors.” ASB maintains an allowance for loan losses believed to be adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (for example, economic conditions, real estate market conditions and interest rate environment). The allowance for loan losses is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are


combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.
ASB disaggregates the loan portfolio into loan segments for purposes of determining the allowance for loan losses. Commercial, and commercial real estate, and commercial construction loans are defined as non-homogeneous loans. ASB utilizes a risk rating system for evaluating the credit quality of such loans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. Values are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). ASB's credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans are categorized into the regulatory asset quality classifications: Pass, Special Mention, Substandard, Doubtful, and Loss based on credit quality. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the contractual terms of the loan agreement. Onceutilizes a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans that are not considered collateral dependent, generally the discounted cash flow method is used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured (TDR) loans, the present value of the expected future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured terms. Impairment shortfalls are charged to the provision for loan losses and included in the allowance for loan losses. However, impairment shortfalls that are deemed to be confirmed losses (uncollectible) are charged off, with the loan written down by the amount of the confirmed loss.
Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products with common risk characteristics and segmented into various secured and unsecured loan product types. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB supplements performance data with an 11-risk rating retail credit model that assigns a probability of default to each borrower based primarily on the borrower's current Fair Isaac Corporation (FICO) score and for HELOC and unsecured consumer products, the bankruptcy score. Current FICO and bankruptcy data is purchased and appended to all homogeneous loans on a quarterly basis and used to estimate the borrower’s probability of default and the loss given default.
ASB's methodology for determining the allowance for loan losses was generally based on historic loss rates using various look-back periods. During the second quarter of 2014, ASB implemented enhancements to the loss rate calculation for estimating the allowance for loan losses that included several refinements to determining the probability of default and the loss given default for the various segments of the loan portfolio that are more statistically sound than those previously employed. The result is an estimated loss rate established for each loan. ASB believes that these enhancements improve the precision in estimating the allowance for loan losses. The enhancement did not have a material effect on the total allowance for loan losses or the provision for loan losses for 2014 and did result in the full allocation of the previously unallocated portion of the allowance for loan losses.
In conjunction with the above enhancement, management also adopted an enhanced risk rating system for monitoring and managing credit risk in the non-homogenous loan portfolios that measures general creditworthiness at the borrower level. The numerical-based, risk rating “PD Model” that takes into consideration fiscal year-end financial information of the borrower and identified financial attributes including retained earnings, operating cash flows, interest coverage, liquidity and leverage that demonstrate a strong correlation with default to assign default probabilities at the borrower level. In addition, a loss given default value is assigned to each loan to measure loss in the event of default based on loan specific features such as collateral that mitigates the amount of loss in the event of default. Together the PD Model and loss given default construct provide a more quantitative, data driven and consistent framework for measuring risk within the portfolio, on a loan by loan basis and for the ultimate collectability of each loan. Additionally,
Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB supplements performance data with external credit bureau data and credit scores


such as the Fair Isaac Corporation (FICO) score on a quarterly basis. ASB has built portfolio loss models for each major segment based on the combination of internal and external data to predict the probability of default at the loan level.
ASB also considers qualitative factors may be included in determining the estimation process.allowance for loan losses. These include but are not limited to adjustments for changes in policies and procedures in underwriting, monitoring or collections, economic conditions, portfolio mix, lending and risk management personnel, results of internal audit and quality control reviews, collateral values and any concentrations of credit.
The reserve for unfunded commitments is maintained at a level believed by management to be sufficient to absorb estimated probable losses related to unfunded credit facilities and is included in accounts payable and other liabilities in the consolidated balance sheets. The determination of the adequacy of the reserve is based upon an evaluation of the unfunded credit facilities, including an assessment of historical commitment utilization experience, credit risk grading and historical loss rates. This process takes into consideration the same risk elements that are analyzed in the determination of the adequacy of the allowance for loan losses, as discussed above. Net adjustments to the reserve for unfunded commitments are included in other noninterest expense in the consolidated statements of income.


Management believes its allowance for loan losses adequately estimates actual loan losses that will ultimately be incurred. However, such estimates are based on currently available information and historical experience, and future adjustments may be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.
Nonperforming loans. Loans are generally placed on nonaccrual status when contractually past due 90 days or more, or earlier if management believes that the probability of collection is insufficient to warrant further accrual. All interest that is accrued but not collected is reversed. A loan may be returned to accrual status if (i) principal and interest payments have been brought current and ASB expects repayment of the remaining contractual principal and interest, (ii) the loan has otherwise become well-secured and collection efforts are reasonably expected to result in repayment of the debt, or (iii) the borrower has been making regularly scheduled payments in full for the prior six months and it is reasonably assured that the loan will be brought fully current within a reasonable period. Cash receipts on nonaccruing loans are generally applied to reduce the unpaid principal balance.
Loans considered to be uncollectible are charged-off against the allowance. The amount and timing of charge-offs on loans includes consideration of the loan type, length of delinquency, insufficiency of collateral value, lien priority and the overall financial condition of the borrower. Recoveries on loans previously charged-off are credited back to the allowance. Loans that have been charged-off against the allowance are periodically monitored to evaluate whether further adjustments to the allowance are necessary.
Loans in the commercial and commercial real estate portfolio are charged-off when the loan is risk rated “doubtful” or “loss”. The loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 90 days or more; (b) significant improvement in the borrower’s repayment capacity is doubtful; and/or (c) collateral value is insufficient to cover outstanding indebtedness and no other viable assets exist.
Loans in the residential mortgage and home equity portfolios are charged-off when the loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 180 days or more; (b) it is probable that collateral value is insufficient to cover outstanding indebtedness and no other viable assets exist; (c) notification of the borrower’s bankruptcy is received; or (d) in cases where ASB is in a subordinate position to other debt, the senior lien holder has foreclosed and extinguished the junior lien.
Other consumer loans are generally charged-off when the balance becomes 120 days delinquent.
See "Nonperforming loans" in Note 1 of the Consolidated Financial Statements for additional information regarding ASB's nonperforming loans.
Troubled debt restructurings.A loan modification is deemed to be a TDR when ASB grants a concession ASB would not otherwise consider if it were not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve their financial position to eventually be able to repay the loan fully, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses and maximizing recovery.
ASB may consider various types of concessions in granting a TDR, including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period or interest only payments for a period of time. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly payments. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period and temporary deferral of principal payments. ASB generally do not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.
Certain TDRs that are current in payment status are classified as nonaccrual in accordance with regulatory guidance. These nonaccruing TDRs can be returned to accrual status when principal and interest have been current for at least six months and a well-documented evaluation of the borrower’s financial condition has been performed and indicates future payments are reasonably assured.


All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment. The financial impact of the calculated impairment amount is an increase to the allowance for loan losses associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Fair value. Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent third party sources. However, in certain cases, ASB uses its own assumptions based on the best information available in certain circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if ASB were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of its financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
ASB classifies its financial assets and liabilities that are measured at fair value in accordance with the three levelthree-level valuation hierarchy outlined as follows:
hierarchy. Level 1:Inputs to the valuation methodology1 valuations are based on quoted prices, unadjusted for identical assets or liabilitiesinstruments traded in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used t measure fair value whenever available.
Level 2:Inputs to the valuation methodology include2 valuations are based on quoted prices for similar assets or liabilitiesinstruments in active markets; inputs to the valuation methodology includemarkets, quoted prices for identical or similar assets or liabilitiesinstruments in markets that are not active;active or inputs tomodel-based techniques for which all significant assumptions are observable in 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.market. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for whichvaluations are based on model-based techniques that use at least one significant assumption not observable in the determination of fair value requiresmarket or significant management judgment or estimation.
Classification See “Fair value measurements” in the hierarchy is based upon the lowest level input that is significant to the fair value measurementNote 1 of the asset or liability. For instruments classified in Level 1 and 2 where inputs are primarily based upon observable market data, there is less judgment applied in arriving at the fair value. For instruments classified in Level 3, management judgment is more significant due to the lack of observable market data.Consolidated Financial Statements).
Significant assets measured at fair value on a recurring basis include ASB's mortgage-relatedASB’s mortgage-backed securities available for sale. These instruments are priced using an external pricing service and are classified as Level 2 within the fair value hierarchy. The third-party pricing services use a variety of methods to determine fair value including quoted prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds and other observable market factors. To enhance the robustness of the pricing process, ASB compares its standard third-party vendor’s price with that of another third-party vendor. If the prices are within an acceptable tolerance range, the price of the standard vendor will be accepted. If the variance is beyond the tolerance range, an evaluation will be conducted by the investment manager and a challenge to the price may be made. Fair value in such cases will be based on the value that best reflects the data and observable characteristics of the security. In all cases, the fair value used will have been independently determined by a third-party pricing vendor or non-affiliated broker.
Fair value is also used on a nonrecurring basis to evaluate certain assets for impairment or for disclosure purposes. Examples of nonrecurring uses of fair value include mortgage servicing rights accounted for by the amortization method, loan impairments for certain loans, real estate ownedacquired in settlement of loans and goodwill.
See "Investment securities"“Investment securities” and "Derivative“Derivative financial instruments"instruments” in Note 54 and Note 16 of the Consolidated Financial Statements for additional information regarding ASB'sASB’s fair value measurements.

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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEIand Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries is applicable):
The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility and the “other” segment’s exposures to these two risks were not material as of December 31, 2016.2019.
Credit risk for ASB is the risk that borrowers or issuers of securities will not be able to repay their obligations to the bank. Credit risk associated with ASB’s lending portfolios is controlled through its underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated through investment portfolio limits, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss sensitivity analysis. See “Allowance for loan losses” in Item 7 above and in Note 54 of the Consolidated Financial Statements.
Liquidity risk for ASB is the risk that the bank will not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liability management process, on-going analytical analysis, monitoring and reporting information such as weekly cash-flow analyses and maintenance of liquidity contingency plans.
The Utilities are exposed to some commodity price risk primarily related to their fuel supply and IPP contracts. The Utilities'Utilities’ commodity price risk is substantially mitigated so long as they have their current ECACsECRCs in their rate schedules. The Utilities currently have no hedges against its commodity price risk.
The Company currently has no direct exposure to market risk from trading activities nor foreign currency exchange rate risk.
The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity, especially as it relates to ASB, but also as it may affect the discount rate used to determine retirement benefit liabilities and minimum contributions, the market value of retirement benefit plans’ assets and the Utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.
Bank interest rate risk
The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk (IRR). ASB’s interest-rate risk profile is strongly influenced by its primary business of making fixed-rate residential mortgage loans and taking in retail deposits. Large mismatches in the amounts or timing between the maturity or repricing of interest sensitive assets or liabilities could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates. Many other factors also affect ASB’s exposure to changes in interest rates, such as general economic and financial conditions, customer preferences and competition for loans or deposits.
ASB’s Asset/Liability Management Committee (ALCO), whose voting members are officers and employees of ASB, is responsible for managing interest rate risk and carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies under which management monitors and coordinates ASB’s assets and liabilities.
See Note 54 of the Consolidated Financial Statements for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.
Management of ASB measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income (NII) and the market value of interest-sensitive assets and liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanced with a mortgage prepayment model and a collateralized mortgage obligation database. The simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions for mortgage loans and mortgage-relatedmortgage-backed securities.
NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in the alternate interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next



twelve months. The alternate scenarios are created by assuming “rate ramps” or gradual interest changes and accomplished by moving the yield curve in a parallel fashion, over the next twelve monthtwelve-month period, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-relatedmortgage-backed assets, future pricing spreads for new assets and liabilities and the speed and magnitude with which deposit rates change in response to changes in the overall level of interest rates. Other NII sensitivity analysis may include scenarios such as yield curve twists or non-static balance sheet changes (such as changes to key balance sheet drivers).
Consistent with OCC guidelines, the market value or economic capitalization of ASB is measured as economic value of equity (EVE). EVE represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. Key assumptions used in the calculation of ASB’s EVE include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alternate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. EVE is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points (bp) up to + 300 bp. The change in EVE is measured as the change in EVE in a given rate scenario from the base case and expressed as a percentage. To gain further insight into the IRR profile, additional analysis is periodically performed in alternate scenarios including rate shifts of greater magnitude and changes in key balance sheet drivers.
ASB’s interest-rate risk sensitivity measures as of December 31, 20162019 and 20152018 constitute “forward-looking statements” and were as follows:
 
Change in NII
(gradual change in interest rates)
 
Change in EVE
(instantaneous change in interest rates)
 
Change in NII
(gradual change in interest rates)
 
Change in EVE
(instantaneous change in interest rates)
Change in interest rates
(basis points)
 December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018
+300 1.9% 1.6% (8.0)% (9.3)% 2.8% 2.5% 15.3% 10.0%
+200 0.8
 0.6
 (4.6) (5.3) 2.1
 1.9
 12.2
 8.1
+100 —
 (0.1) (1.6) (1.9) 1.3
 1.1
 7.5
 5.1
-100 (0.5) (0.5) (1.6) (1.2) (2.0) (2.3) (12.7) (11.0)
Management believes that
ASB’s interest rate risk position as of December 31, 2016 represents a reasonable level of risk. The NII sensitivity profile under the rising interest rate scenarios werewas more asset sensitive for all rate increases as of December 31, 2016 compared to December 31, 2015. The increase in asset sensitivity was primarily attributed to management updating its repricing assumptions of certain core deposits in the third quarter of 2016 and growth in shorter duration home equity and personal unsecured loan products. In addition, ASB reduced its exposure to repurchase agreements by $136 million, resulting in a less interest rate sensitive funding base.
ASB’s base EVE increased to $1.1 billion as of December 31, 2016 compared to $974 million as of December 31, 2015 due to the growth and mix of the balance sheet. Assets increased by $407 million with market valuation exceeding the growth and valuation of funding liabilities.
The change in EVE to rising rates became less sensitive as of December 31, 20162019 compared to December 31, 20152018. The decrease in long term market rates increased prepayment expectations, resulting in higher reinvestment into lower yielding fixed-rate mortgage and mortgage-backed investment portfolios. The increased prepayment expectations also drove higher premium amortization on existing mortgage-backed securities. In addition, the bank had more cash on the balance sheet as of December 31, 2019, which contributed to higher NII asset sensitivity.
EVE sensitivity increased as of December 31, 2019 compared to December 31, 2018 as the duration of liabilities lengthened more thanassets shortened while the duration of assets. In the third quarter of 2016, management updated its core deposit average lives assumption, which positively improved the market value of portfolio equity. However, the recentliabilities lengthened. The downward shift in the yield curve has caused mortgage ratesled to increase, leading to slowerfaster prepayment expectations and lengthening in durationshortened the durations of the residentialfixed-rate mortgage portfolio.and mortgage-backed investment portfolios, while lengthening core deposit duration.
The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicativeindications of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period


and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve monthtwelve-month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.


Other than bank interest rate risk
The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt and preferred securities. As of December 31, 2016, management believes2019, the Company was exposed to “other than bank” interest rate risk because of its periodic borrowing requirements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see “Pension and other postretirement benefits obligations” in HEI’s MD&A and “Retirement benefits” in Notes 1 and 10 of the Consolidated Financial Statements) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates”).return. Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. The Company’s long-term debt, in the form of borrowings of proceeds of revenue bonds, privately-placed senior notes and bank term loans, is predominately at fixed rates (see Note 16 of the Consolidated Financial Statements for the fair value of long-term debt, net-other than bank).

71




ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
HEI and Hawaiian Electric:
Index to Consolidated Financial StatementsPage
ReportReports of Independent Registered Public Accounting FirmFirms - HEI
8373
ReportReports of Independent Registered Public Accounting FirmFirms - Hawaiian Electric
8477
Consolidated Financial Statements
8578
HEI 
Consolidated Statements of Income for the years ended December 31, 2016, 20152019, 2018 and 20142017
8578
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 20152019, 2018 and 20142017
8679
Consolidated Balance Sheets at December 31, 20162019 and 20152018
8780
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2016, 20152019, 2018 and 20142017
8881
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 20152019, 2018 and 20142017
8982
Hawaiian Electric 
Consolidated Statements of Income for the years ended December 31, 2016, 20152019, 2018 and 20142017
9184
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 20152019, 2018 and 20142017
9184
Consolidated Balance Sheets at December 31, 20162019 and 20152018
9285
Consolidated Statements of Capitalization at December 31, 20162019 and 20152018
9386
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2016, 20152019, 2018 and 20142017
9588
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 20152019, 2018 and 20142017
9689
Notes to Consolidated Financial Statements
9790

72




Report of Independent Registered Public Accounting Firm
Tothe Shareholders and the Board of Directors and Shareholders of
Hawaiian Electric Industries, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting
In our opinion, the consolidated financial statements listed inWe have audited the accompanying index present fairly, in all material respects, the financial positionconsolidated balance sheets of Hawaiian Electric Industries, Inc. and its subsidiaries at(the "Company") as of December 31, 20162019 and December 31, 2015,2018, the related consolidated statements of income, comprehensive income, changes in shareholders' equity, and the results of their operations and their cash flows, for each of the three years in the period ended December 31, 20162019, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). We also have audited 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 (COSO).
In our opinion, the financial statements referred to above 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. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). COSO.
Basis for Opinions
The Company'sCompany’s management is responsible for these financial statements, and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Overover Financial Reporting appearing under Item 9A. Our responsibility is to express opinionsan opinion on these financial statements and an opinion on the financial statement schedules, and on the Company'sCompany’s internal control over financial reporting based on our integrated audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i)(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; (ii)(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 (iii)(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.


Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Electric utility segment - regulatory assets and liabilities - Refer to Note 3 to the financial statements
Critical Audit Matter Description
Hawaiian Electric Company, Inc. (“Hawaiian Electric,” or the “Utility”) is subject to rate regulation by the Hawaii Public Utility Commission (the “PUC”) and accounts for the effects of regulation under FASB Accounting Standards Codification (“ASC”) Topic 980, “Regulated Operations” as 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; and depreciation expense. As of December 31, 2019, regulatory assets and liabilities amounted to approximately $715,080,000 and $972,310,000, respectively. The Company’s continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third party regulator, rates are designed to recover the costs of providing service, and it is reasonable to assume that rates can be charged to, and collected from, customers.
Hawaiian Electric’s rates are subject to regulatory rate-setting processes and earnings oversight. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, Hawaiian Electric’s investment in the utility business. Any decision by the PUC could (1) impact the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) necessitate a refund or future reductions in rates that should be reported as regulatory liabilities.
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 high 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. Given that management’s accounting judgements are based on assumptions about the outcome of future decisions by the PUC, 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 rate regulators 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. 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.


Allowance for Loan Losses - Refer to Notes 1 and 4 to the financial statements
Critical Audit Matter Description
The Company maintains an allowance for loan losses (the “Allowance”) to absorb losses inherent in its loan portfolio. As of December 31, 2019, the total Allowance balance is $53.4 million. The level of Allowance is based on existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and the interest rate environment). The Allowance is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. These qualitative factors include, but are not limited to, adjustments for changes in policies and procedures in underwriting, monitoring or collections, economic conditions, portfolio mix, lending and risk management personnel, results of internal audit and quality control reviews, collateral values and any concentrations of credit.
The selection of relevant and appropriate qualitative factors in calculating the Allowance requires significant management judgment. Given the magnitude of the loan portfolio and the subjective nature of determining the Allowance, including the judgments applied by management in determining the qualitative factors, auditing the Allowance attributable to these qualitative factors involves a high degree of auditor judgment, and increased level of effort, and the need to involve more experienced audit professionals.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Allowance, included the following procedures, among others:
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.
Summary of significant accounting policies - Recent accounting pronouncements - Credit losses - Refer to Note 1 to the financial statements
Critical Audit Matter Description
On January 1, 2020, the Company will adopt ASU No. 2016-13, “Financial Instruments - Credit Losses”, which requires the measurement of all expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts) and enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. The Company and Utilities will adopt ASU No. 2016-13 using an effective date of January 1, 2020 and will apply the guidance using a modified retrospective basis with the cumulative effect of initially applying the amendments to be recognized in retained earnings as of January 1, 2020.
The allowance for credit losses (ACL) is a material estimate of the Company. As a result of the change from an incurred loss model to a methodology that considers the credit loss over the expected life of the loan, the Company expects to record, upon completing its final analysis, an adjustment between $18 million and $22 million to increase the ACL, with a corresponding adjustment to reduce retained earnings as of January 1, 2020. The ACL requires management to make estimates of the expected credit losses over the expected life of the loans, including using estimates of future economic conditions that will impact the amount of such future losses. In order to estimate the expected credit losses, existing credit loss estimation models were updated and, in certain cases, new models implemented to align with the expected loss framework.


The estimation of credit losses significantly changes under the expected loss framework, includes the application of new accounting policies, the use of new subjective judgments, and changes to loss estimation models. Accordingly, the procedures performed to audit the disclosure of the expected impact of the adoption of ASU No. 2016-13 involved a high degree of auditor judgment and required significant effort, including the need to involve our credit specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the disclosure of the expected impact of adopting ASU No. 2016-13 included the following, among others:
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.

/s/ PricewaterhouseCoopersDeloitte & Touche LLP
Los Angeles, CaliforniaHonolulu, Hawaii
February 24, 201728, 2020
We have served as the Company’s auditor since 2017.

76




Report of Independent Registered Public Accounting Firm
To the Shareholder and the Board of Directors and Shareholder
of Hawaiian Electric Company, Inc.


In our opinion,Opinion on the consolidated financial statements listed inFinancial Statements
We have audited the accompanying index present fairly, in all material respects, the financial positionconsolidated balance sheets and statements of capitalization of Hawaiian Electric Company, Inc. and its subsidiaries (the "Company") as of December 31, 20162019 and 2015,2018, the related consolidated statements of income, comprehensive income, changes in common stock equity, and the results of their operations and their cash flows, for each of the three years in the period ended December 31, 20162019, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements referred to above 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. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
Basis for Opinion
These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements and financial statement schedule based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
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 to respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.opinions.



/s/ PricewaterhouseCoopersDeloitte & Touche LLP
Los Angeles, CaliforniaHonolulu, Hawaii
February 24, 201728, 2020

We have served as the Company’s auditor since 2017.













77




Consolidated Statements of Income
Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 312016
 2015
 2014
2019
 2018
 2017
(in thousands, except per share amounts) 
  
  
 
  
  
Revenues 
  
  
 
  
  
Electric utility$2,094,368
 $2,335,166
 $2,987,323
$2,545,942
 $2,546,525
 $2,257,566
Bank285,924
 267,733
 252,497
328,570
 314,275
 297,640
Other362
 83
 (278)89
 49
 419
Total revenues2,380,654
 2,602,982
 3,239,542
2,874,601
 2,860,849
 2,555,625
Expenses 
  
  
 
  
  
Electric utility1,809,900
 2,061,050
 2,711,555
2,291,564
 2,304,864
 1,994,042
Bank198,572
 183,921
 173,202
Bank (includes $10.8 million gain on sales of properties in 2019)217,008
 206,040
 198,104
Other24,007
 35,458
 22,185
17,355
 16,589
 17,246
Total expenses2,032,479
 2,280,429
 2,906,942
2,525,927
 2,527,493
 2,209,392
Operating income (loss) 
  
  
 
  
  
Electric utility284,468
 274,116
 275,768
254,378
 241,661
 263,524
Bank87,352
 83,812
 79,295
111,562
 108,235
 99,536
Other(23,645) (35,375) (22,463)(17,266) (16,540) (16,827)
Total operating income348,175
 322,553
 332,600
348,674
 333,356
 346,233
Merger termination fee90,000
 —
 —
Retirement defined benefits expense—other than service costs(2,806) (5,962) (7,942)
Interest expense, net – other than on deposit liabilities and other bank borrowings(75,803) (77,150) (76,352)(90,899) (88,677) (78,972)
Allowance for borrowed funds used during construction3,144
 2,457
 2,579
4,453
 4,867
 4,778
Allowance for equity funds used during construction8,325
 6,928
 6,771
11,987
 10,877
 12,483
Income before income taxes373,841
 254,788
 265,598
271,409
 254,461
 276,580
Income taxes123,695
 93,021
 95,579
51,637
 50,797
 109,393
Net income250,146
 161,767
 170,019
219,772
 203,664
 167,187
Preferred stock dividends of subsidiaries1,890
 1,890
 1,890
1,890
 1,890
 1,890
Net income for common stock$248,256
 $159,877
 $168,129
$217,882
 $201,774
 $165,297
Basic earnings per common share$2.30
 $1.50
 $1.65
$2.00
 $1.85
 $1.52
Diluted earnings per common share$2.29
 $1.50
 $1.63
$1.99
 $1.85
 $1.52
Dividends per common share$1.24
 $1.24
 $1.24
Weighted-average number of common shares outstanding108,102
 106,418
 101,968
108,949
 108,855
 108,749
Net effect of potentially dilutive shares207
 303
 969
458
 291
 184
Adjusted weighted-average shares108,309
 106,721
 102,937
Weighted-average shares assuming dilution109,407
 109,146
 108,933
The accompanying notes are an integral part of these consolidated financial statements.

78




Consolidated Statements of Comprehensive Income
Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 312016
 2015
 2014
2019
 2018
 2017
(in thousands) 
  
  
 
  
  
Net income for common stock$248,256
 $159,877
 $168,129
$217,882
 $201,774
 $165,297
Other comprehensive income (loss), net of taxes: 
  
  
 
  
  
Net unrealized gains (losses) on available-for sale investment securities: 
  
  
 
  
  
Net unrealized gains (losses) on available-for sale investment securities arising during the period, net of (taxes) benefits of $3,763, $1,541 and $(3,856) for 2016, 2015 and 2014, respectively(5,699) (2,334) 5,840
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $238, nil and $1,132 for 2016, 2015 and 2014, respectively(360) —
 (1,715)
Net unrealized gains (losses) on available-for sale investment securities arising during the period, net of (taxes) benefits of $(10,024), $3,468 and $2,886 for 2019, 2018 and 2017, respectively27,382
 (9,472) (4,370)
Reclassification adjustment for net realized gains included in net income, net of taxes of $175, nil and nil for 2019, 2018 and 2017, respectively(478) —
 —
Derivatives qualified as cash flow hedges: 
  
  
 
  
  
Effective portion of foreign currency hedge net unrealized losses arising during the period, net of tax benefits of $179, nil and nil for 2016, 2015 and 2014, respectively(281) —
 —
Less: reclassification adjustment to net income, net of (taxes) benefit of $(76), $150 and $150 for 2016, 2015 and 2014, respectively(119) 235
 236
Unrealized interest rate hedging losses, net of tax benefit of $409, $151 and nil for 2019, 2018 and 2017, respectively(1,177) (436) —
Reclassification adjustment to net income, net of tax benefits of nil, nil and $289 for 2019, 2018 and 2017, respectively—
 —
 454
Retirement benefit plans: 
  
  
 
  
  
Net gains (losses) arising during the period, net of (taxes) benefits of $27,703, $(3,753) and $149,364 for 2016, 2015 and 2014, respectively(43,510) 5,889
 (234,166)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $9,267, $14,344 and $7,245 for 2016, 2015 and 2014, respectively14,518
 22,465
 11,344
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $(18,206), $16,011 and $(132,373) for 2016, 2015 and 2014, respectively28,584
 (25,139) 207,833
Net gains (losses) arising during the period, net of (taxes) benefits of $(3,892), $9,810 and $(41,129) for 2019, 2018 and 2017, respectively10,914
 (28,101) 65,531
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,512, $7,317 and $10,041 for 2019, 2018 and 2017, respectively10,107
 21,015
 15,737
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $(5,610), $2,887 and $(49,523) for 2019, 2018 and 2017, respectively
(16,177) 8,325
 (78,724)
Other comprehensive income (loss), net of taxes(6,867) 1,116
 (10,628)30,571
 (8,669) (1,372)
Comprehensive income attributable to Hawaiian Electric Industries, Inc.$241,389
 $160,993
 $157,501
$248,453
 $193,105
 $163,925
The accompanying notes are an integral part of these consolidated financial statements.

79




Consolidated Balance Sheets
Hawaiian Electric Industries, Inc. and Subsidiaries
December 31 
 2016
  
 2015
 
 2019
  
 2018
(dollars in thousands) 
  
  
  
 
  
  
  
ASSETS 
  
  
  
 
  
  
  
Cash and cash equivalents 
 $278,452
  
 $300,478
 
 $196,813
  
 $169,208
Restricted cash  30,872
   —
Accounts receivable and unbilled revenues, net 
 237,950
  
 242,766
 
 300,794
  
 325,672
Available-for-sale investment securities, at fair value 
 1,105,182
  
 820,648
 
 1,232,826
  
 1,388,533
Held-to-maturity investment securities, at amortized cost  139,451
   141,875
Stock in Federal Home Loan Bank, at cost 
 11,218
  
 10,678
 
 8,434
  
 9,958
Loans receivable held for investment, net 
 4,683,160
  
 4,565,781
Loans held for investment, net 
 5,067,821
  
 4,790,902
Loans held for sale, at lower of cost or fair value 
 18,817
  
 4,631
 
 12,286
  
 1,805
Property, plant and equipment, net 
  
  
  
 
  
  
  
Land$97,423
  
 $90,890
  
$100,161
  
 $102,925
  
Plant and equipment6,727,935
  
 6,444,214
  
7,545,083
  
 7,118,709
  
Construction in progress222,455
  
 181,873
  
229,953
  
 267,714
  
7,047,813
  
 6,716,977
  
7,875,197
  
 7,489,348
  
Less – accumulated depreciation(2,444,348) 4,603,465
 (2,339,319) 4,377,658
(2,765,569) 5,109,628
 (2,659,230) 4,830,118
Operating lease right-of-use assets  199,171
   —
Regulatory assets 
 957,451
  
 896,731
 
 715,080
  
 833,426
Other 
 447,621
  
 480,457
 
 649,885
  
 530,364
Goodwill 
 82,190
  
 82,190
 
 82,190
  
 82,190
Total assets 
 $12,425,506
  
 $11,782,018
 
 $13,745,251
  
 $13,104,051
LIABILITIES AND SHAREHOLDERS’ EQUITY 
  
  
  
 
  
  
  
Liabilities 
  
  
  
 
  
  
  
Accounts payable 
 $143,279
  
 $138,523
 
 $220,633
  
 $214,773
Interest and dividends payable 
 25,225
  
 26,042
 
 24,941
  
 28,254
Deposit liabilities 
 5,548,929
  
 5,025,254
 
 6,271,902
  
 6,158,852
Short-term borrowings—other than bank 
 —
  
 103,063
 
 185,710
  
 73,992
Other bank borrowings 
 192,618
  
 328,582
 
 115,110
  
 110,040
Long-term debt, net—other than bank 
 1,619,019
  
 1,578,368
 
 1,964,365
  
 1,879,641
Deferred income taxes 
 728,806
  
 680,877
 
 379,324
  
 372,518
Operating lease liabilities  199,571
   —
Regulatory liabilities 
 410,693
  
 371,543
 
 972,310
  
 950,236
Contributions in aid of construction 
 543,525
  
 506,087
Defined benefit pension and other postretirement benefit plans liability 
 638,854
  
 589,918
 
 513,287
  
 538,384
Other 
 473,512
  
 471,828
 
 583,545
  
 580,788
Total liabilities 
 10,324,460
  
 9,820,085
 
 11,430,698
  
 10,907,478
Preferred stock of subsidiaries - not subject to mandatory redemption 
 34,293
  
 34,293
 
 34,293
  
 34,293
Commitments and contingencies (Notes 4 and 5) 
 

  
 

Commitments and contingencies (Notes 3 and 4) 
 

  
 

Shareholders’ equity 
  
  
  
 
  
  
  
Preferred stock, no par value, authorized 10,000,000 shares; issued: none 
 —
  
 —
 
 —
  
 —
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,583,413 shares and 107,460,406 shares at December 31, 2016 and 2015, respectively 
 1,660,910
  
 1,629,136
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,973,328 shares and 108,879,245 shares at December 31, 2019 and 2018, respectively 
 1,678,257
  
 1,669,267
Retained earnings 
 438,972
  
 324,766
 
 622,042
  
 543,623
Accumulated other comprehensive loss, net of tax benefits 
  
  
  
 
  
  
  
Net unrealized losses on securities$(7,931)  
 $(1,872)  
Net unrealized gains (losses) on securities$2,481
  
 $(24,423)  
Unrealized losses on derivatives(454)  
 (54)  
(1,613)  
 (436)  
Retirement benefit plans(24,744) (33,129) (24,336) (26,262)(20,907) (20,039) (25,751) (50,610)
Total shareholders’ equity 
 2,066,753
  
 1,927,640
 
 2,280,260
  
 2,162,280
Total liabilities and shareholders’ equity 
 $12,425,506
  
 $11,782,018
 
 $13,745,251
  
 $13,104,051
The accompanying notes are an integral part of these consolidated financial statements.

80




Consolidated Statements of Changes in Shareholders’ Equity
Hawaiian Electric Industries, Inc. and Subsidiaries
Common stock Retained 
Accumulated
 other
 comprehensive
  Common stock 
Retained
earnings
 
Accumulated
 other
 comprehensive
income (loss)
  
(in thousands, except per share amounts)Shares Amount earnings income (loss) TotalShares Amount Total
Balance, December 31, 2013101,260
 $1,488,126
 $255,030
 $(16,750) $1,726,406
Balance, December 31, 2016108,583
 $1,660,910
 $438,972
 $(33,129) $2,066,753
Net income for common stock—
 —
 165,297
 —
 165,297
Other comprehensive loss, net of tax benefits—
 —
 —
 (1,372) (1,372)
Reclass of AOCI for tax rate reduction impact—
 —
 7,440
 (7,440) —
Issuance of common stock: 
  
  
  
  
Share-based plans205
 4,664
 —
 —
 4,664
Share-based expenses and other, net—
 (3,083) —
 —
 (3,083)
Common stock dividends ($1.24 per share)—
 —
 (134,873) —
 (134,873)
Balance, December 31, 2017108,788
 1,662,491
 476,836
 (41,941) 2,097,386
Net income for common stock—
 —
 168,129
 —
 168,129
—
 —
 201,774
 —
 201,774
Other comprehensive loss, net of tax benefits—
 —
 —
 (10,628) (10,628)—
 —
 —
 (8,669) (8,669)
Issuance of common stock: 
  
  
  
  
 
  
  
  
  
Partial settlement of equity forward1,000
 24,873
 —
 —
 24,873
Dividend reinvestment and stock purchase plan95
 2,461
 —
 —
 2,461
Retirement savings and other plans210
 6,816
 —
 —
 6,816
Expenses and other, net—
 (979) —
 —
 (979)
Share-based plans91
 2,650
 —
 —
 2,650
Share-based expenses and other, net—
 4,126
 —
 —
 4,126
Common stock dividends ($1.24 per share)—
 —
 (126,505) —
 (126,505)—
 —
 (134,987) —
 (134,987)
Balance, December 31, 2014102,565
 1,521,297
 296,654
 (27,378) 1,790,573
Balance, December 31, 2018108,879
 1,669,267
 543,623
 (50,610) 2,162,280
Net income for common stock—
 —
 159,877
 —
 159,877
—
 —
 217,882
 —
 217,882
Other comprehensive income, net of taxes—
 —
 —
 1,116
 1,116
—
 —
 —
 30,571
 30,571
Issuance of common stock: 
  
  
  
  
 
  
  
  
  
Partial settlement of equity forward4,700
 109,183
 —
 —
 109,183
Retirement savings and other plans195
 5,578
 —
 —
 5,578
Expenses and other, net—
 (6,922) —
 —
 (6,922)
Common stock dividends ($1.24 per share)—
 —
 (131,765) —
 (131,765)
Balance, December 31, 2015107,460
 1,629,136
 324,766
 (26,262) 1,927,640
Net income for common stock—
 —
 248,256
 —
 248,256
Other comprehensive loss, net of tax benefits—
 —
 —
 (6,867) (6,867)
Issuance of common stock: 
  
  
  
  
Dividend reinvestment and stock purchase plan859
 26,844
 —
 —
 26,844
Retirement savings and other plans264
 9,298
 —
 —
 9,298
Expenses and other, net—
 (4,368) —
 —
 (4,368)
Common stock dividends ($1.24 per share)—
 —
 (134,050) —
 (134,050)
Balance, December 31, 2016108,583
 $1,660,910
 $438,972
 $(33,129) $2,066,753
Share-based plans94
 3,092
 —
 —
 3,092
Share-based expenses and other, net—
 5,898
 —
 —
 5,898
Common stock dividends ($1.28 per share)—
 —
 (139,463) —
 (139,463)
Balance, December 31, 2019108,973
 $1,678,257
 $622,042
 $(20,039) $2,280,260
The accompanying notes are an integral part of these consolidated financial statements.

81




Consolidated Statements of Cash Flows
Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 312019
 2018
 2017
(in thousands) 
  
  
Cash flows from operating activities 
  
  
Net income$219,772
 $203,664
 $167,187
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
Depreciation of property, plant and equipment229,858
 214,036
 200,658
Other amortization48,255
 41,593
 21,340
Provision for loan losses23,480
 14,745
 10,901
Loans originated, held for sale(285,042) (109,537) (115,104)
Proceeds from sale of loans, held for sale277,119
 112,182
 127,951
Gain on sale of real estate, held for sale(10,762) —
 —
Deferred income taxes(15,085) (9,368) 37,835
Share-based compensation expense9,986
 7,792
 5,404
Allowance for equity funds used during construction(11,987) (10,877) (12,483)
Other10,822
 (4,219) (3,324)
Changes in assets and liabilities 
  
  
Decrease (increase) in accounts receivable and unbilled revenues, net26,083
 (64,321) (12,875)
Decrease (increase) in fuel oil stock(11,493) 7,054
 (20,794)
Decrease (increase) in regulatory assets71,262
 9,252
 (17,256)
Increase (decrease) in accounts, interest and dividends payable(3,054) 21,528
 34,985
Change in prepaid and accrued income taxes, tax credits and utility revenue taxes(27,538) 29,429
 20,685
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability(4,482) 20,871
 882
Change in other assets and liabilities, net(34,724) 15,488
 (25,551)
Net cash provided by operating activities512,470
 499,312
 420,441
Cash flows from investing activities 
  
  
Available-for-sale investment securities purchased(108,088) (224,335) (528,379)
Principal repayments on available-for-sale investment securities272,949
 218,930
 220,231
Proceeds from sale of available-for-sale investment securities19,810
 —
 —
Purchases of held-to-maturity investment securities(13,057) (103,184) (44,515)
Proceeds from repayments or maturities of held-to-maturity investment securities15,505
 5,720
 —
Purchase of stock from Federal Home Loan Bank(95,636) (28,292) (2,868)
Redemption of stock from Federal Home Loan Bank97,160
 28,040
 4,380
Net decrease (increase) in loans held for investment(300,210) (189,352) 15,887
Proceeds from sale of commercial loans—
 7,149
 36,760
Proceeds from sale of real estate held for sale21,060
 —
 —
Capital expenditures(457,520) (506,770) (430,454)
Contributions to low income housing investments(6,974) (14,499) (17,505)
Acquisition of business—
 —
 (76,323)
Other, net13,292
 14,534
 7,487
Net cash used in investing activities(541,709) (792,059) (815,299)
Years ended December 312016
 2015
 2014
(in thousands) 
  
  
Cash flows from operating activities 
  
  
Net income$250,146
 $161,767
 $170,019
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
Depreciation of property, plant and equipment194,273
 183,966
 172,762
Other amortization10,473
 11,619
 10,282
Provision for loan losses16,763
 6,275
 6,126
Impairment of utility assets—
 6,021
 1,866
Loans receivable originated and purchased, held for sale(236,769) (268,279) (155,755)
Proceeds from sale of loans receivable, held for sale236,062
 275,296
 155,030
Deferred income taxes47,118
 41,432
 104,225
Share-based compensation expense4,789
 6,542
 9,287
Excess tax benefits from share-based payment arrangements(404) (978) (277)
Allowance for equity funds used during construction(8,325) (6,928) (6,771)
Other(12,422) 1,672
 (280)
Changes in assets and liabilities 
  
  
Decrease (increase) in accounts receivable and unbilled revenues, net(898) 62,304
 33,089
Decrease in fuel oil stock4,786
 34,830
 28,041
Increase in regulatory assets(18,273) (24,182) (17,000)
Decrease in accounts, interest and dividends payable(9,643) (52,663) (67,189)
Change in prepaid and accrued income taxes, tax credits and utility revenue taxes39,109
 (42,596) (39,091)
Increase in defined benefit pension and other postretirement benefit plans liability1,587
 852
 22,251
Change in other assets and liabilities(23,118) (41,070) (101,195)
Net cash provided by operating activities495,254
 355,880
 325,420
Cash flows from investing activities 
  
  
Available-for-sale investment securities purchased(533,956) (429,262) (183,778)
Principal repayments on available-for-sale investment securities219,845
 153,271
 91,013
Proceeds from sale of available-for-sale investment securities16,423
 —
 79,564
Purchase of stock from Federal Home Loan Bank(7,773) (1,600) —
Redemption of stock from Federal Home Loan Bank7,233
 60,223
 23,244
Net increase in loans held for investment(194,042) (181,343) (283,810)
Proceeds from sale of commercial loans52,299
 —
 —
Proceeds from sale of real estate acquired in settlement of loans829
 1,329
 3,213
Proceeds from sale of real estate held for sale1,764
 7,283
 —
Capital expenditures(330,043) (363,804) (364,826)
Contributions in aid of construction30,100
 40,239
 41,806
Other856
 7,940
 1,125
Net cash used in investing activities(736,465) (705,724) (592,449)

(continued)



Consolidated Statements of Cash Flows (continued)
Hawaiian Electric Industries, Inc. and Subsidiaries


Years ended December 312016
 2015
 2014
2019
 2018
 2017
Cash flows from financing activities 
  
  
 
  
  
Net increase in deposit liabilities523,675
 401,839
 250,938
113,050
 165,880
 341,668
Net increase (decrease) in short-term borrowings with original maturities of three months or less(103,063) (15,909) 13,490
86,718
 (18,999) 67,992
Net increase (decrease) in retail repurchase agreements(43,601) 37,925
 (9,465)
Proceeds from other bank borrowings180,835
 50,000
 130,601
Repayments of other bank borrowings(272,902) (50,000) (75,000)
Proceeds from issuance of short-term debt75,000
 25,000
 125,000
Repayment of short-term debt(50,000) (50,000) (75,000)
Net increase in other bank borrowings with original maturities of three months or less5,070
 71,556
 61,776
Repayment of other bank borrowings—
 (50,000) (63,534)
Proceeds from issuance of long-term debt115,000
 80,000
 125,000
289,349
 250,000
 532,325
Repayment of long-term debt(75,000) —
 (111,400)
Excess tax benefits from share-based payment arrangements404
 978
 277
Net proceeds from issuance of common stock13,220
 104,435
 26,898
Repayment of long-term debt and funds transferred for repayment of long-term debt(287,285) (53,887) (465,000)
Withheld shares for employee taxes on vested share-based compensation(997) (996) (3,828)
Common stock dividends(117,274) (131,765) (126,458)(139,463) (134,987) (134,873)
Preferred stock dividends of subsidiaries(1,890) (1,890) (1,890)(1,890) (1,890) (1,890)
Other(219) (833) (456)(1,836) (1,603) (6,349)
Net cash provided by financing activities219,185
 474,780
 222,535
87,716
 200,074
 378,287
Net increase (decrease) in cash and cash equivalents(22,026) 124,936
 (44,494)
Cash and cash equivalents, January 1300,478
 175,542
 220,036
Net increase (decrease) in cash, cash equivalents and restricted cash58,477
 (92,673) (16,571)
Cash, cash equivalents and restricted cash, January 1169,208
 261,881
 278,452
Cash, cash equivalents and restricted cash, December 31227,685
 169,208
 261,881
Less: Restricted cash(30,872) —
 —
Cash and cash equivalents, December 31$278,452
 $300,478
 $175,542
$196,813
 $169,208
 $261,881


The accompanying notes are an integral part of these consolidated financial statements.

83




Consolidated Statements of Income
Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 312016
 2015
 2014
2019
 2018
 2017
(in thousands) 
  
  
 
  
  
Revenues$2,094,368
 $2,335,166
 $2,987,323
$2,545,942
 $2,546,525
 $2,257,566
Expenses 
  
  
 
  
  
Fuel oil454,704
 654,600
 1,131,685
720,709
 760,528
 587,768
Purchased power562,740
 594,096
 722,008
633,256
 639,307
 586,634
Other operation and maintenance405,533
 413,089
 410,612
481,737
 461,491
 411,907
Depreciation187,061
 177,380
 166,387
215,731
 203,626
 192,784
Taxes, other than income taxes199,862
 221,885
 280,863
240,131
 239,912
 214,949
Total expenses1,809,900
 2,061,050
 2,711,555
2,291,564
 2,304,864
 1,994,042
Operating income284,468
 274,116
 275,768
254,378
 241,661
 263,524
Allowance for equity funds used during construction8,325
 6,928
 6,771
11,987
 10,877
 12,483
Retirement defined benefits expense—other than service costs(2,836) (3,631) (6,003)
Interest expense and other charges, net(66,824) (66,370) (64,757)(70,842) (73,348) (69,637)
Allowance for borrowed funds used during construction3,144
 2,457
 2,579
4,453
 4,867
 4,778
Income before income taxes229,113
 217,131
 220,361
197,140
 180,426
 205,145
Income taxes84,801
 79,422
 80,725
38,305
 34,778
 83,199
Net income144,312
 137,709
 139,636
158,835
 145,648
 121,946
Preferred stock dividends of subsidiaries915
 915
 915
915
 915
 915
Net income attributable to Hawaiian Electric143,397
 136,794
 138,721
157,920
 144,733
 121,031
Preferred stock dividends of Hawaiian Electric1,080
 1,080
 1,080
1,080
 1,080
 1,080
Net income for common stock$142,317
 $135,714
 $137,641
$156,840
 $143,653
 $119,951
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income
Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 31 2016
 2015
 2014
2019
 2018
 2017
(in thousands)          
Net income for common stock$142,317
 $135,714
 $137,641
$156,840
 $143,653
 $119,951
Other comprehensive income (loss), net of taxes: 
  
  
 
  
  
Derivatives qualified as cash flow hedges:          
Effective portion of foreign currency hedge net unrealized losses arising during the period, net of tax benefits of $179, nil and nil for 2016, 2015 and 2014, respectively(281) —
 —
Less: reclassification adjustment to net income, net of taxes of $110, nil and nil for 2016, 2015 and 2014, respectively(173) —
 —
Reclassification adjustment to net income, net of tax benefits of nil, nil and $289 for 2019, 2018 and 2017, respectively
—
 —
 454
Retirement benefit plans: 
  
  
 
  
  
Net gains (losses) arising during the period, net of (taxes) benefits of $27,153,$(3,590) and $139,236 for 2016, 2015 and 2014, respectively(42,631) 5,638
 (218,608)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $8,442, $12,981 and $6,504 for 2016, 2015 and 2014, respectively13,254
 20,381
 10,212
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $(18,206), $16,011 and $(132,373) for 2016, 2015 and 2014, respectively28,584
 (25,139) 207,833
Net gains (losses) arising during the period, net of (taxes) benefits of $(1,821), $9,024 and $(39,587) for 2019, 2018 and 2017, respectively
5,249
 (26,019) 63,105
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,312, $6,594 and $9,221 for 2019, 2018 and 2017, respectively
9,550
 19,012
 14,477
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $(5,610), $2,887 and $(49,523) for 2019, 2018 and 2017, respectively
(16,177) 8,325
 (78,724)
Other comprehensive income (loss), net of taxes(1,247) 880
 (563)(1,378) 1,318
 (688)
Comprehensive income attributable to Hawaiian Electric Company, Inc.$141,070
 $136,594
 $137,078
$155,462
 $144,971
 $119,263
The accompanying notes are an integral part of these consolidated financial statements.

84




Consolidated Balance Sheets
Hawaiian Electric Company, Inc. and Subsidiaries
December 312016
 2015
2019
 2018
(in thousands) 
  
 
  
Assets 
  
 
  
Property, plant and equipment      
Utility property, plant and equipment 
  
 
  
Land$53,153
 $52,792
$51,816
 $49,667
Plant and equipment6,605,732
 6,315,698
7,240,288
 6,809,671
Less accumulated depreciation(2,369,282) (2,266,004)(2,690,157) (2,577,342)
Construction in progress211,742
 175,309
193,074
 233,145
Utility property, plant and equipment, net4,501,345
 4,277,795
4,795,021
 4,515,141
Nonutility property, plant and equipment, less accumulated depreciation of $1,232 as of December 31, 2016 and $1,229 as of December 31, 20157,407
 7,272
Nonutility property, plant and equipment, less accumulated depreciation of $111 and $1,255 as of December 31, 2019 and 2018, respectively6,956
 6,961
Total property, plant and equipment, net4,508,752
 4,285,067
4,801,977
 4,522,102
Current assets 
  
 
  
Cash and cash equivalents74,286
 24,449
11,022
 35,877
Restricted cash30,872
 —
Customer accounts receivable, net123,688
 132,778
152,790
 177,896
Accrued unbilled revenues, net91,693
 84,509
117,227
 121,738
Other accounts receivable, net5,233
 10,408
11,568
 6,215
Fuel oil stock, at average cost66,430
 71,216
91,937
 79,935
Materials and supplies, at average cost53,679
 54,429
60,702
 55,204
Prepayments and other23,100
 36,640
116,980
 32,118
Regulatory assets66,032
 72,231
30,710
 71,016
Total current assets504,141
 486,660
623,808
 579,999
Other long-term assets 
  
 
  
Operating lease right-of-use-assets176,809
 —
Regulatory assets891,419
 824,500
684,370
 762,410
Unamortized debt expense208
 497
Other70,908
 75,486
101,718
 102,992
Total other long-term assets962,535
 900,483
962,897
 865,402
Total assets$5,975,428
 $5,672,210
$6,388,682
 $5,967,503
Capitalization and liabilities 
  
 
  
Capitalization (see Consolidated Statements of Capitalization)
 
  
 
  
Common stock equity$1,799,787
 $1,728,325
$2,047,352
 $1,957,641
Cumulative preferred stock – not subject to mandatory redemption34,293
 34,293
34,293
 34,293
Commitments and contingencies (Note 4)

 

Commitments and contingencies (Note 3)

 

Long-term debt, net1,319,260
 1,278,702
1,401,714
 1,418,802
Total capitalization3,153,340
 3,041,320
3,483,359
 3,410,736
Current liabilities 
  
 
  
Current portion of operating lease liabilities63,707
 —
Current portion of long-term debt, net95,953
 —
Short-term borrowings from non-affiliate88,987
 25,000
Accounts payable117,814
 114,846
187,770
 171,791
Interest and preferred dividends payable22,838
 23,111
20,728
 23,215
Taxes accrued172,730
 191,084
Taxes accrued, including revenue taxes207,992
 233,333
Regulatory liabilities3,762
 2,204
30,724
 17,977
Other55,221
 54,079
67,305
 60,003
Total current liabilities372,365
 385,324
763,166
 531,319
Deferred credits and other liabilities 
  
 
  
Operating lease liabilities113,400
 —
Deferred income taxes733,659
 654,806
377,150
 383,197
Regulatory liabilities406,931
 369,339
941,586
 932,259
Unamortized tax credits88,961
 84,214
117,868
 91,522
Defined benefit pension and other postretirement benefit plans liability599,726
 552,974
478,763
 503,659
Other76,921
 78,146
113,390
 114,811
Total deferred credits and other liabilities1,906,198
 1,739,479
2,142,157
 2,025,448
Contributions in aid of construction543,525
 506,087
Total capitalization and liabilities$5,975,428
 $5,672,210
$6,388,682
 $5,967,503
 The accompanying notes are an integral part of these consolidated financial statements.

85




Consolidated Statements of Capitalization
Hawaiian Electric Company, Inc. and Subsidiaries
December 312019  2018 
(dollars in thousands, except par value)  
   
Common stock equity  
   
Common stock of $6 2/3 par value  
   
Authorized: 50,000,000 shares. Outstanding: 17,048,783 shares and  
   
16,751,488 shares at December 31, 2019 and 2018, respectively $113,678
  $111,696
Premium on capital stock 714,824
  681,305
Retained earnings 1,220,129
  1,164,541
Accumulated other comprehensive income (loss), net of taxes-retirement benefit plans (1,279)  99
Common stock equity 2,047,352
  1,957,641
Cumulative preferred stock not subject to mandatory redemption    
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value.    
Series Par Value   Shares outstanding December 31, 2019 and 2018 2019
 2018
(dollars in thousands, except par value and shares outstanding)    
C-4 1/4% $20
 (Hawaiian Electric) 150,000
 $3,000
 $3,000
D-5% 20
 (Hawaiian Electric) 50,000
 1,000
 1,000
E-5% 20
 (Hawaiian Electric) 150,000
 3,000
 3,000
H-5 1/4% 20
 (Hawaiian Electric) 250,000
 5,000
 5,000
I-5% 20
 (Hawaiian Electric) 89,657
 1,793
 1,793
J-4 3/4% 20
 (Hawaiian Electric) 250,000
 5,000
 5,000
K-4.65% 20
 (Hawaiian Electric) 175,000
 3,500
 3,500
G-7 5/8% 100
 (Hawaii Electric Light) 70,000
 7,000
 7,000
H-7 5/8% 100
 (Maui Electric) 50,000
 5,000
 5,000
   
   1,234,657
 34,293
 34,293
December 312016 2015
(dollars in thousands, except par value)   
    
Common stock equity   
    
Common stock of $6 2/3 par value   
    
Authorized: 50,000,000 shares. Outstanding: 16,019,785 shares and   
    
15,805,327 shares at December 31, 2016 and 2015, respectively  $106,818
   $105,388
Premium on capital stock  601,491
   578,930
Retained earnings  1,091,800
   1,043,082
Accumulated other comprehensive income (loss), net of taxes       
Unrealized losses on derivatives(454)   —
  
Retirement benefit plans132
 (322) 925
 925
Common stock equity  1,799,787
   1,728,325
Cumulative preferred stock not subject to mandatory redemption   
    
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value.   
    
Series Par Value 
Par
 Value
 Shares outstanding December 31, 2016 and 2015 2016 2015
(dollars in thousands, except par value and shares outstanding)    
C-4 1/4% $20
 (Hawaiian Electric) 150,000
 $3,000
 $3,000
D-5% 20
 (Hawaiian Electric) 50,000
 1,000
 1,000
E-5% 20
 (Hawaiian Electric) 150,000
 3,000
 3,000
H-5 1/4% 20
 (Hawaiian Electric) 250,000
 5,000
 5,000
I-5% 20
 (Hawaiian Electric) 89,657
 1,793
 1,793
J-4 3/4% 20
 (Hawaiian Electric) 250,000
 5,000
 5,000
K-4.65% 20
 (Hawaiian Electric) 175,000
 3,500
 3,500
G-7 5/8% 100
 (Hawaii Electric Light) 70,000
 7,000
 7,000
H-7 5/8% 100
 (Maui Electric) 50,000
 5,000
 5,000
   
   1,234,657
 34,293
 34,293
(continued)
The accompanying notes are an integral part of these consolidated financial statements.



Consolidated Statements of Capitalization (continued)
Hawaiian Electric Company, Inc. and Subsidiaries
December 31 2016 2015
(in thousands) 
  
Long-term debt 
  
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligations unconditionally guaranteed by Hawaiian Electric): 
  
Hawaiian Electric, 3.25%, refunding series 2015, due 2025$40,000
 $40,000
Hawaii Electric Light, 3.25%, refunding series 2015, due 20255,000
 5,000
Maui Electric, 3.25%, refunding series 2015, due 20252,000
 2,000
Hawaiian Electric, 6.50%, series 2009, due 203990,000
 90,000
Hawaii Electric Light, 6.50%, series 2009, due 203960,000
 60,000
Hawaiian Electric, 4.60%, refunding series 2007B, due 202662,000
 62,000
Hawaii Electric Light, 4.60%, refunding series 2007B, due 20268,000
 8,000
Maui Electric, 4.60%, refunding series 2007B, due 202655,000
 55,000
Hawaiian Electric, 4.65%, series 2007A, due 2037100,000
 100,000
Hawaii Electric Light, 4.65%, series 2007A, due 203720,000
 20,000
Maui Electric, 4.65%, series 2007A, due 203720,000
 20,000
Total obligations to the State of Hawaii462,000
 462,000
Other long-term debt – unsecured: 
  
Taxable senior notes:   
Hawaiian Electric, 4.54%, Series 2016A, due 204640,000
 —
Hawaiian Electric, 5.23%, Series 2015A, due 204550,000
 50,000
Hawaii Electric Light, 5.23%, Series 2015A, due 204525,000
 25,000
Maui Electric, 5.23%, Series 2015A, due 20455,000
 5,000
Hawaii Electric Light, 3.83%, Series 2013A, due 202014,000
 14,000
Hawaiian Electric, 4.45%, Series 2013A, due 202240,000
 40,000
Hawaii Electric Light, 4.45%, Series 2013B, due 202212,000
 12,000
Hawaiian Electric, 4.84%, Series 2013B, due 202750,000
 50,000
Hawaii Electric Light, 4.84%, Series 2013C, due 202730,000
 30,000
Maui Electric, 4.84%, Series 2013A, due 202720,000
 20,000
Hawaiian Electric, 5.65%, Series 2013C, due 204350,000
 50,000
Maui Electric, 5.65%, Series 2013B, due 204320,000
 20,000
Hawaiian Electric, 3.79%, Series 2012A, due 201830,000
 30,000
Hawaii Electric Light, 3.79%, Series 2012A, due 201811,000
 11,000
Maui Electric, 3.79%, Series 2012A, due 20189,000
 9,000
Hawaiian Electric, 4.03%, Series 2012B, due 202062,000
 62,000
Maui Electric, 4.03%, Series 2012B, due 202020,000
 20,000
Hawaiian Electric, 4.55%, Series 2012C, due 202350,000
 50,000
Hawaii Electric Light, 4.55%, Series 2012B, due 202320,000
 20,000
Maui Electric, 4.55%, Series 2012C, due 202330,000
 30,000
Hawaiian Electric, 4.72%, Series 2012D, due 202935,000
 35,000
Hawaiian Electric, 5.39%, Series 2012E, due 2042150,000
 150,000
Hawaiian Electric, 4.53%, Series 2012F, due 203240,000
 40,000
Total taxable senior notes813,000
 773,000
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 203451,546
 51,546
Total other long-term debt – unsecured864,546
 824,546
Total long-term debt1,326,546
 1,286,546
Less unamortized debt issuance costs7,286
 7,844
Long-term debt, net1,319,260
 1,278,702
Total capitalization$3,153,340
 $3,041,320
December 31 2019
 2018
(in thousands) 
  
Long-term debt 
  
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligations unconditionally guaranteed by Hawaiian Electric):   
3.50%, Series 2019, due 2049$80,000
 $—
3.20%, Refunding series 2019, due 2039150,000
 —
3.10%, Refunding series 2017A, due 2026125,000
 125,000
4.00%, Refunding series 2017B, due 2037140,000
 140,000
3.25%, Refunding series 2015, due 202547,000
 47,000
6.50%, Series 2009, due 2039 - redeemed in 2019—
 150,000
Total obligations to the State of Hawaii$542,000
 $462,000
Other long-term debt – unsecured: 
  
Taxable senior notes:   
4.21%, Series 2019A, due 2033$50,000
 $—
4.38%, Series 2018A, due 202867,500
 67,500
4.53%, Series 2018B, due 203317,500
 17,500
4.72%, Series 2018C, due 204815,000
 15,000
4.31%, Series 2017A, due 204750,000
 50,000
4.54%, Series 2016A, due 204640,000
 40,000
5.23%, Series 2015A, due 204580,000
 80,000
3.83%, Series 2013A, due 202014,000
 14,000
4.45%, Series 2013A and 2013B, due 202252,000
 52,000
4.84%, Series 2013A, 2013B and 2013C, due 2027100,000
 100,000
5.65%, Series 2013B and 2013C, due 204370,000
 70,000
4.03%, Series 2012B, due 202082,000
 82,000
4.55%, Series 2012B and 2012C, due 2023100,000
 100,000
4.72%, Series 2012D, due 202935,000
 35,000
5.39%, Series 2012E, due 2042150,000
 150,000
4.53%, Series 2012F, due 203240,000
 40,000
Total taxable senior notes963,000
 913,000
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034 - redeemed in 2019—
 51,546
Total other long-term debt – unsecured963,000
 964,546
Total long-term debt1,505,000
 1,426,546
Less unamortized debt issuance costs7,333
 7,744
Less current portion long-term debt, net of unamortized debt issuance costs95,953
 —
Long-term debt, net1,401,714
 1,418,802
Total capitalization$3,483,359
 $3,410,736
The accompanying notes are an integral part of these consolidated financial statements.

87




Consolidated Statements of Changes in Common Stock Equity
Hawaiian Electric Company, Inc. and Subsidiaries
Common stock 
Premium
on
capital
 Retained 
Accumulated
other
comprehensive
  Common stock 
Premium
on
capital
stock
 
Retained
earnings
 
Accumulated
other
comprehensive
income (loss)
  
(in thousands)Shares Amount stock earnings income (loss) TotalShares Amount Total
Balance, December 31, 201315,429
 $102,880
 $541,452
 $948,624
 $608
 $1,593,564
Balance, December 31, 201616,020
 $106,818
 $601,491
 $1,091,800
 $(322) $1,799,787
Net income for common stock—
 —
 —
 119,951
 —
 119,951
Other comprehensive loss, net of tax benefits—
 —
 —
 —
 (688) (688)
Reclass of AOCI for tax rate reduction impact—
 —
 —
 209
 (209) —
Issuance of common stock, net of expenses122
 816
 13,184
 —
 —
 14,000
Common stock dividends—
 —
 —
 (87,767) —
 (87,767)
Balance, December 31, 201716,142
 107,634
 614,675
 1,124,193
 (1,219) 1,845,283
Net income for common stock—
 —
 —
 143,653
 —
 143,653
Other comprehensive income, net of taxes—
 —
 —
 —
 1,318
 1,318
Issuance of common stock, net of expenses609
 4,062
 66,630
 —
 —
 70,692
Common stock dividends—
 —
 —
 (103,305) —
 (103,305)
Balance, December 31, 201816,751
 111,696
 681,305
 1,164,541
 99
 1,957,641
Net income for common stock—
 —
 —
 137,641
 —
 137,641
—
 —
 —
 156,840
 —
 156,840
Other comprehensive loss, net of tax benefits—
 —
 —
 —
 (563) (563)—
 —
 —
 —
 (1,378) (1,378)
Issuance of common stock, net of expenses376
 2,508
 37,486
 —
 —
 39,994
297
 1,982
 33,519
 —
 —
 35,501
Common stock dividends—
 —
 —
 (88,492) —
 (88,492)—
 —
 —
 (101,252) —
 (101,252)
Balance, December 31, 201415,805
 105,388
 578,938
 997,773
 45
 1,682,144
Net income for common stock—
 —
 —
 135,714
 —
 135,714
Other comprehensive income, net of taxes—
 —
 —
 —
 880
 880
Common stock issuance expenses—
 —
 (8) —
 —
 (8)
Common stock dividends—
 —
 —
 (90,405) —
 (90,405)
Balance, December 31, 201515,805
 105,388
 578,930
 1,043,082
 925
 1,728,325
Net income for common stock—
 —
 —
 142,317
 —
 142,317
Other comprehensive loss, net of tax benefits—
 —
 —
 —
 (1,247) (1,247)
Issuance of common stock, net of expenses215
 1,430
 22,561
 —
 —
 23,991
Common stock dividends—
 —
 —
 (93,599) —
 (93,599)
Balance, December 31, 201616,020
 $106,818
 $601,491
 $1,091,800
 $(322) $1,799,787
Balance, December 31, 201917,048
 $113,678
 $714,824
 $1,220,129
 $(1,279) $2,047,352
The accompanying notes are an integral part of these consolidated financial statements.



88




Consolidated Statements of Cash Flows
Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 312016 2015 20142019
 2018
 2017
(in thousands) 
  
  
 
  
  
Cash flows from operating activities 
  
  
 
  
  
Net income$144,312
 $137,709
 $139,636
$158,835
 $145,648
 $121,946
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
 
  
  
Depreciation of property, plant and equipment187,061
 177,380
 166,387
215,731
 203,626
 192,784
Other amortization6,935
 8,939
 9,897
29,631
 26,602
 8,498
Impairment of utility assets—
 6,021
 1,866
Deferred income taxes74,386
 75,626
 82,947
(16,284) (7,982) 38,037
Income tax credits, net231
 4,844
 6,062
27,259
 (99) (52)
State refundable credit(8,369) (6,239) (2,251)
Allowance for equity funds used during construction(8,325) (6,928) (6,771)(11,987) (10,877) (12,483)
Change in cash overdraft—
 —
 (1,038)
Other(3,931) 1,672
 758
200
 4,768
 1,237
Changes in assets and liabilities 
  
  
 
  
  
Decrease in accounts receivable8,551
 23,727
 26,743
Decrease (increase) in accounts receivable20,956
 (50,917) 2,914
Decrease (increase) in accrued unbilled revenues(7,184) 40,093
 6,750
4,511
 (14,684) (15,361)
Decrease in fuel oil stock4,786
 34,830
 28,041
Decrease (increase) in materials and supplies750
 2,821
 (72)
Increase in regulatory assets(18,273) (24,182) (17,000)
Decrease in accounts payable(10,614) (54,555) (65,527)
Decrease (increase) in fuel oil stock(12,002) 6,938
 (20,443)
Increase in materials and supplies(5,498) (807) (718)
Decrease (increase) in regulatory assets71,262
 9,252
 (17,256)
Increase in regulatory liabilities1,953
 37,358
 3,602
Increase (decrease) in accounts payable(2,051) 24,358
 25,734
Change in prepaid and accrued income taxes, tax credits and revenue taxes2,123
 (63,096) (4,036)(28,523) 25,036
 29,862
Increase (decrease) in defined benefit pension and other postretirement
benefit plans liability
484
 1,125
 (961)(4,448) 18,746
 604
Change in other assets and liabilities(11,375) (32,620) (66,687)(17,220) (17,114) (21,468)
Net cash provided by operating activities369,917
 333,406
 306,995
423,956
 393,613
 335,186
Cash flows from investing activities 
  
  
 
  
  
Capital expenditures(320,437) (350,161) (336,679)(419,898) (415,264) (376,865)
Contributions in aid of construction30,100
 40,239
 41,806
Other2,138
 1,140
 1,164
11,374
 10,082
 4,578
Net cash used in investing activities(288,199) (308,782) (293,709)(408,524) (405,182) (372,287)
Cash flows from financing activities 
  
  
 
  
  
Common stock dividends(93,599) (90,405) (88,492)(101,252) (103,305) (87,767)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,995) (1,995) (1,995)(1,995) (1,995) (1,995)
Proceeds from issuance of common stock24,000
 —
 40,000
35,500
 70,700
 14,000
Proceeds from issuance of long-term debt40,000
 80,000
 —
280,000
 100,000
 315,000
Repayment of long-term debt—
 —
 (11,400)
Repayment of long-term debt and funds transferred for repayment of long-term debt(283,546) (50,000) (265,000)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less38,987
 (4,999) 4,999
Proceeds from issuance of short-term debt75,000
 25,000
 —
Repayment of short-term debt(50,000) —
 —
Other(287) (1,537) (462)(2,109) (472) (3,905)
Net cash used in financing activities(31,881) (13,937) (62,349)
Net increase (decrease) in cash and cash equivalents49,837
 10,687
 (49,063)
Cash and cash equivalents, January 124,449
 13,762
 62,825
Net cash provided by (used in) financing activities(9,415) 34,929
 (24,668)
Net increase (decrease) in cash, cash equivalents and restricted cash6,017
 23,360
 (61,769)
Cash, cash equivalents and restricted cash, January 135,877
 12,517
 74,286
Cash, cash equivalents and restricted cash, December 3141,894
 35,877
 12,517
Less: Restricted cash(30,872) —
 —
Cash and cash equivalents, December 31$74,286
 $24,449
 $13,762
$11,022
 $35,877
 $12,517
The accompanying notes are an integral part of these consolidated financial statements.




89


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Notes to Consolidated Financial Statements


Note 1 · Summary of significant accounting policies
General
Hawaiian Electric Industries, Inc. (HEI) is a holding company with direct and indirect subsidiaries principally engaged in electric utility, banking, and bankingrenewable/sustainable infrastructure investment businesses primarilyoperating in the State of Hawaii. HEI is the parent holding company ofowns Hawaiian Electric Company, Inc. (Hawaiian Electric) and indirect parent, ASB Hawaii, Inc., an intermediate holding company ofthat owns American Savings Bank, F. S. B.F.S.B. (ASB), and Pacific Current, LLC (Pacific Current). HEI’s common stock is traded on the New York Stock Exchange.Pacific Current’s significant subsidiaries include Hamakua Energy, LLC (Hamakua Energy) and Mauo, LLC (Mauo).
Hawaiian Electric and its wholly-ownedwholly owned operating subsidiaries, Hawaii Electric Light Company, Inc. (Hawaii Electric Light) and Maui Electric Company, Limited (Maui Electric), are regulated public electric utilities (collectively, the Utilities) in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai. Hawaiian Electric also owns Renewable Hawaii, Inc. (RHI), Uluwehiokama Biofuels Corp. (UBC) and HECO Capital Trust III. See Note 3.2.
ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii.
Hamakua Energy, owns and operates a 60-megawatt (MW) combined-cycle power plant, which sells the power it produces only to Hawaii Electric Light. Mauo is a commercial-scale, solar-plus-storage project (8.6 MW of solar and 42.3 MW of storage) currently under construction on the islands of Oahu and Maui.
Basis of presentation.  In preparing the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
Material estimates that are particularly susceptible to significant change for HEI and its subsidiaries (collectively, the Company) include the amounts reported as fair value for investment securities (ASB only); property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; derivatives; regulatory assets and liabilities (Utilities only); electric utility unbilled revenues (Utilities only); asset retirement obligations (Utilities only); and allowance for loan losses (ASB only); and goodwill (ASB only).
Consolidation.  The HEI consolidated financial statements include the accounts of the Company.HEI and its subsidiaries. The Hawaiian Electric consolidated financial statements include the accounts of Hawaiian Electric and its subsidiaries. The consolidatedWhen HEI or Hawaiian Electric has a controlling financial statements exclude subsidiaries which are variable interest entities (VIEs) when the Company or the Utilities are not the primary beneficiaries.in another entity (usually, majority voting interest), that entity is consolidated. Investments in companies over which the Company or the Utilities have the ability to exercise significant influence, but not control, are accounted for using the equity method. SeeThe consolidated financial statements exclude variable interest entities (VIEs) when the Company or the Utilities are not the primary beneficiaries. In general, significant intercompany amounts are eliminated in consolidation (see Note 62 for information regarding unconsolidated VIEs.exceptions).
Cash and cash equivalents.  The Utilities consider cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and liquid investments (with original maturities of three months or less) to be cash and cash equivalents. The Company considers the same items to be cash and cash equivalents as well as ASB’s deposits with the Federal Home Loan Bank (FHLB), federal funds sold (excess funds that ASB loans to other banks overnight at the federal funds rate) and securities purchased under resale agreements.agreements with original maturities of three months or less. Additionally, ASB is required by the Federal Reserve System to maintain noninterest-bearing cash reserves equal to a percentage of certain deposits. The reserve requirement for ASB at December 31, 2019 and 2018 was $26.2 million and $28.1 million, respectively.
Equity method.  Investments in upRestricted cash.  The Utilities consider funds on deposit with trustees, which represent the undrawn proceeds from the issuance of special purpose revenue bonds to 50%-owned affiliates over which the Company or thebe restricted cash because these funds are available only to finance (or reimburse payment of) approved capital expenditures. At December 31, 2019 and 2018, total restricted cash of Utilities have the ability to exercise significant influence over the operatingwas $30.9 million and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in operating revenues. Equity method investments are also evaluated for OTTI. Also seeNaN, respectively (see Note 6 below.6).
Property, plant and equipment.  Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is


completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make utility plant more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities. See discussion regarding “Utility projects” in Note 3.


Depreciation.  Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Electric utility plant additions in the current year are depreciated beginning January 1 of the following year in accordance with rate-making. Electric utility plant has lives ranging from 2016 to 88 years for production plant, from 2510 to 6579 years for transmission and distribution plant and from 5 to 65 years for general plant. The Utilities’ composite annual depreciation rate, which includes a component for cost of removal, was 3.2% in 2019, 3.2%2018 and 3.1% in 2016, 2015 and 2014, respectively.2017.
Leases.  HEI, the Utilities and ASB have entered into lease agreements for the use of equipment and office space. The provisions of some of the lease agreements contain renewal options.
HEI's consolidated operating lease expense was $19 million, $18 million and $19 million in 2016, 2015 and 2014, respectively. The Utilities' operating lease expense was $10 million, $9 million and $9 million in 2016, 2015 and 2014, respectively. HEI's consolidated and the Utilities' future minimum lease payments are as follows:
(in millions)HEI Hawaiian Electric
2017$12
 $6
20189
 4
20197
 4
20205
 3
20214
 3
Thereafter8
 4
 $45
 $24
Retirement benefits.  Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant (in the case of the Utilities). Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary.Plans. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), including changes promulgated by the Pension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost during the year, subject to ERISA minimum and Internal Revenue Code limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the Public Utilities Commission of the State of Hawaii (PUC), the Utilities generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost.status.
Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions (except for executive life) for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantagedtax-advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Utilities must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC. Future decisions in rate cases could further impact funding amounts.
The Company and the Utilities recognize on their respective balance sheets the funded status of their defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.
Environmental expenditures.  The Company and the Utilities are subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense. Environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.
Financing costs.  Financing costs related to The Utilities review their sites and measure the registration and saleliability quarterly by assessing a range of HEI common stock are recorded in shareholders’ equity.
HEI uses the straight-line method, which approximates the effective interest method, to amortize the long-term debt financingreasonably likely costs of the holding company over the term of the related debt.
The Utilities use the straight-line method, which approximates the effective interest method, to amortize long-term debt financing costseach identified site using currently available information, including existing technology, presently enacted laws and premiums or discounts over the term of the related debt. Unamortized financing costs and premiums or


discounts on the Utilities' long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.
HEIregulations, experience gained at similar sites, and the Utilities use the straight-line method to amortize the feesprobable level of involvement and related costs paid to secure a firm commitment under their line-of-credit arrangements.financial condition of other potentially responsible parties.
Income taxes.  Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s and the Utilities'Utilities’ assets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.
The Company recognizesHEI and the Utilities’ investment tax credits as a reduction of income tax expense in the period the assets giving rise to such credits are placed in service, except for the Utilities' investment tax credits, which are deferred and amortized over the estimated useful lives of the properties to which the credits relate (and for the Utilities, this treatment is in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”Operations”).
The Utilities are included in the consolidated income tax returns of HEI. However, income tax expense has been computed for financial statement purposes as if the Utilitieseach utility filed a separate income tax return and Hawaiian Electric filed a consolidated Hawaiian Electric income tax returns.return.
Governmental tax authorities could challenge a tax return position taken by the Company. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and charged to expense or an unanticipated tax liability might be incurred.
The Company and the Utilities use a “more-likely-than-not” recognition threshold and measurement standard for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.
Fair value measurements. Fair value estimates are estimates of the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company and the Utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These

91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company or the Utilities were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s and the Utilities' financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
The Company and the Utilities group their financial assets measured at fair value in three levels outlined as follows:
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.
Classification in the hierarchy is based upon the lowest level input that is significant to the fair value measurement of the asset or liability. For instruments classified in Level 1 and 2 where inputs are primarily based upon observable market data,


there is less judgment applied in arriving at the fair value. For instruments classified in Level 3, management judgment is more significant due to the lack of observable market data.
The Company reviews and updates the fair value hierarchy classifications on a quarterly basis. Changes from one quarter to the next related to the observability of inputs in fair value measurements may result in a reclassification between the fair value hierarchy levels and are recognized based on period-end balances.
Fair value is also used on a nonrecurring basis to evaluate certain assets for impairment or for disclosure purposes. Examples of nonrecurring uses of fair value include mortgage servicing rights accounted for by the amortization method, loan impairments for certain loans, real estate owned, goodwill and asset retirement obligations (AROs).
Earnings per share (HEI only).  Basic earnings per share (EPS) is computed by dividing net income for common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that dilutive common shares for stock compensation and the equity forward transactions are added to the denominator. For 2014, HEI used the two-class method of computing EPS as restricted stock grants included non-forfeitable rights to dividends and were participating securities.
Under the two-class method of computing EPS, HEI's EPS was comprised as follows for both participating securities (i.e., restricted shares that became fully vested in the fourth quarter of 2014) and unrestricted common stock:
  2014
  Basic
 Diluted
Distributed earnings $1.24
 $1.24
Undistributed earnings 0.41
 0.39
  $1.65
 $1.63
Impairment of long-lived assets and long-lived assets to be disposed of.  The Company and the Utilities review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.
Recent accounting pronouncements.
Revenues from contracts with customers.  In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers: (Topic 606).” The core principle of the guidance in ASU No. 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should: (1) identify the contract/s with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies a performance obligation. ASU No. 2014-09 also requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
As of December 31, 2016, the Company has identified its revenue streams from, and performance obligations to, customers, and is currently evaluating the impacts of the new guidance on its ability to recognize revenue for certain contracts where there is uncertainty regarding collection and accounting for contributions in aid of construction. 
The Company plans to adopt ASU No. 2014-09 (and subsequently issued revenue-related ASUs, as applicable) in the first quarter of 2018, but has not determined the method of adoption (full or modified retrospective application). The Company expects to present more revenue disclosures, but the full impact of adoption of ASU No. 2014-09 on its results of operations, financial condition and liquidity cannot be determined until its evaluation process is complete.
Going concern.  In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.Disclosure is required if there is substantial doubt about the entity’s ability to continue as a going concern.


        The Company adopted ASU No. 2014-15 for 2016 and interim periods going forward. Since management has concluded that there are no conditions or events that raise substantial doubt about HEI’s or Hawaiian Electric’s ability to continue as a going concern through February 24, 2018, there was no impact on HEI’s and Hawaiian Electric’s consolidated financial statements.
Extraordinary and unusual items. In January 2015, the FASB issued ASU No. 2015-01, “Income Statement - Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items,” which removes the concept of extraordinary items from U.S. GAAP and eliminates the requirement for extraordinary items to be separately presented in the statement of income.
The Company adopted ASU 2015-01 prospectively on January 1, 2016 and the adoption did not have a material impact on the Company’s and Hawaiian Electric’s consolidated financial statements.
Consolidation.  In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which modifies the requirements of consolidation with respect to limited partnerships, entities that are similar in nature to limited partnerships or are VIEs. The amended guidance (1) modifies the evaluation of whether limited partnerships and similar legal entities are VIEs or voting interest entities; (2) eliminates the presumption that a general partner should consolidate a limited partnership; (3) changes the analysis related to the evaluation of servicing fees and excludes servicing fees that are deemed commensurate with the level of service required from the determination of the primary beneficiary; (4) clarifies certain consideration related to the consolidation analysis when performing a related party assessment; and (5) provides a scope exception from consolidation guidance for reporting entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Bank Act of 1940 for registered money market funds.
        The Company retrospectively adopted ASU No. 2015-02 in the first quarter 2016 and the adoption did not have a material impact on HEI’s and Hawaiian Electric’s consolidated financial statements.
Debt issuance costs. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.
The Company retrospectively adopted ASU No. 2015-03 in the first quarter 2016 and the adoption did not have a material impact on the Company’s and Hawaiian Electric’s consolidated financial statements.


The table below summarizes the impact to the prior period financial statements of the adoption of ASU No. 2015-03:
 (in thousands)
As
previously
 filed
Adjustment from adoption of ASU No. 2015-03
As
currently reported
 
 December 31, 2015   
 HEI Consolidated Balance Sheet and Note 3 - Segment financial information (Total assets)   
 Other assets$488,635
$(8,178)$480,457
 Total assets and Total liabilities and shareholders’ equity11,790,196
(8,178)11,782,018
 Long-term debt, net-other than bank1,586,546
(8,178)1,578,368
 Total liabilities9,828,263
(8,178)9,820,085
 Hawaiian Electric Consolidated Balance Sheet and Note 3 - Segment financial information (Total assets)   
 Unamortized debt expense8,341
(7,844)497
 Total other long-term assets908,327
(7,844)900,483
 Total assets and Total capitalization and liabilities5,680,054
(7,844)5,672,210
 Long-term debt, net1,286,546
(7,844)1,278,702
 Total capitalization3,049,164
(7,844)3,041,320
 Note 4 - Hawaiian Electric Consolidating Balance Sheet   
 Hawaiian Electric (parent only)   
 Unamortized debt expense5,742
(5,383)359
 Total other long-term assets662,430
(5,383)657,047
 Total assets and Total capitalization and liabilities4,481,558
(5,383)4,476,175
 Long-term debt, net880,546
(5,383)875,163
 Total capitalization2,631,164
(5,383)2,625,781
 Hawaii Electric Light   
 Unamortized debt expense1,494
(1,420)74
 Total other long-term assets130,749
(1,420)129,329
 Total assets and Total capitalization and liabilities955,935
(1,420)954,515
 Long-term debt, net215,000
(1,420)213,580
 Total capitalization514,702
(1,420)513,282
 Maui Electric   
 Unamortized debt expense1,105
(1,041)64
 Total other long-term assets115,148
(1,041)114,107
 Total assets and Total capitalization and liabilities831,201
(1,041)830,160
 Long-term debt, net191,000
(1,041)189,959
 Total capitalization459,725
(1,041)458,684
Investments in certain entities that calculate net asset value per share. In May 2015, the FASB issued ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent),” which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and limits certain disclosures to those investments.
The Company retrospectively adopted ASU No. 2015-07 in the first quarter 2016; thus, the fair value disclosures for retirement benefit plan assets have been revised.
Financial instruments.  In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which, among other things:
Requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income.
Requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes.


Requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (i.e., securities or loans and receivables).
Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost.
The Company plans to adopt ASU No. 2016-01 in the first quarter of 2018 and has not yet determined the impact of adoption.
Leases. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which requires that lessees recognize a liability to make lease payments (the lease liability) and a right-of-use asset, representing its right to use the underlying asset for the lease term, for all leases (except short-term leases) at the commencement date. 
The Company plans to adopt ASU 2016-02 in the first quarter of 2019 (using a modified retrospective transition approach for leases existing at, or entered into after, January 1, 2017) and has not yet determined the impact of adoption.
Stock compensation.  In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment transactions.
The Company adopted ASU 2016-09 in the first quarter of 2017. From January 1, 2017, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement. Also from January 1, 2017, no excess tax benefits and deficiencies are included in determining the assumed proceeds under the treasury stock method of calculating diluted EPS. As of January 1, 2017, HEI adopted an accounting policy to account for forfeitures when they occur.
From January 1, 2017, HEI retrospectively applied the guidance for taxes paid (equivalent to the value of withheld shares for tax withholding purposes) and excess tax benefits. Excess tax benefits will be classified along with other income tax cash flows as an operating activity and the cash payments made to taxing authorities on the employees’ behalf for withheld shares will be classified as financing activities on the HEI Consolidated Statements of Cash Flows for all periods that are presented.
Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. ASU No. 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts) and enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. In addition, ASU No. 2016-13 amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The other-than-temporary impairment model of accounting for credit losses on AFS debt securities will be replaced with an estimate of expected credit losses only when the fair value is below the amortized cost of the asset. The length of time the fair value of an AFS debt security has been below the amortized cost will no longer impact the determination of whether a credit loss exists. The AFS debt security model will also require the use of an allowance to record the estimated losses (and subsequent recoveries). The accounting for the initial recognition of the estimated expected credit losses for purchased financial assets with credit deterioration would be recognized through an allowance for loan losses with an offset to the cost basis of the related financial asset at acquisition (i.e., there is no impact to net income at initial recognition).
The Company plans to adopt ASU 2016-13 in the first quarter of 2020 and has not yet determined the impact of adoption.
Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides guidance on eight specific cash flow issues - debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies), distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle.
The Company plans to adopt ASU 2016-15 in the first quarter of 2018 using a retrospective transition method and has not yet determined the impact of adoption.
Intra-entity transfers of assets other than inventory.  In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which changes current guidance that prohibits the


recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party by requiring the recognition of the income tax consequences of such transfer when it occurs.
The Company plans to adopt ASU 2016-16 in the first quarter of 2018 using a modified retrospective transition method and believes the impact of adoption will be immaterial to the Company’s and Hawaiian Electric’s consolidated financial statements.
Restricted cash.  In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents.
The Company plans to adopt ASU 2016-18 in the first quarter of 2018 using a retrospective transition method and believes the impact of adoption will not be material to the Company’s and Hawaiian Electric’s consolidated statements of cash flows.
Reclassifications.  Reclassifications made to prior years’ financial statements to conform to the 2016 presentation did not affect previously reported results of operations and include additional detail of noncash items in operating activities on the Company's and Hawaiian Electric's Consolidated Statements of Cash Flows.
Electric utility
Regulation by the Public Utilities Commission of the State of Hawaii (PUC). The Utilities are regulated by the PUC and account for the effects of regulation under FASB ASC Topic 980, “Regulated Operations.” As a result, the Utilities’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to, and collected from, customers within 24 months. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance.
Accounts receivable.  Accounts receivable are recorded at the invoiced amount. The Utilities generally assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Utilities’ best estimate of the amount of probable credit losses in the Utilities existing accounts receivable. At December 31, 2016 and 2015, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $1.1 million and $1.7 million, respectively.
Contributions in aid of construction.  The Utilities receive contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 to 55 years as an offset against depreciation expense.
Electric utility revenues.  Electric utility revenues are based on rates authorized by the PUC. Revenues related to electric service are generally recorded when service is rendered and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Under decoupling, electric utility revenues also incorporate: (1) monthly revenue balancing account (RBA) revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales, (2) rate adjustment mechanism (RAM) revenues for escalation in certain operation and maintenance (O&M) expenses and rate base changes and (3) an earnings sharing mechanism, which reduces revenues between rate cases in the event the utility’s ratemaking return on average common equity (ROACE) exceeds the ROACE allowed in its most recent rate case. Under the decoupling tariff approved in 2011, the prior year accrued RBA revenues (regulatory asset) and the annual RAM amount are billed from June 1 of each year through May 31 of the following year, which is within 24 months following the end of the year in which they are recorded as required by the accounting standard for alternative revenue programs. See "Decoupling" discussion in Note 4 Electric Utility segment.
The rate schedules of the Utilities include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules also include purchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECACs and PPACs are required to be reconciled quarterly.
The Utilities’ revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, the Utilities’ revenue tax payments to the taxing authorities are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current


year’s cash collections from electric sales (in the case of franchise taxes). For 2016, 2015 and 2014, the Utilities included approximately $187 million, $209 million and $267 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.
Power purchase agreements.  If a power purchase agreement (PPA) falls within the scope of ASC Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the Utilities would recognize a capital asset and a lease obligation. Currently, none of the PPAs are required to be recorded as a capital lease.
The Utilities evaluate PPAs to determine if the PPAs are VIEs, if the Utilities are primary beneficiaries and if consolidation is required. See Note 6.
Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.
Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.
The weighted-average AFUDC rate was 7.6% in 2016, 7.6% in 2015 and 7.7% in 2014, and reflected quarterly compounding.
Bank (HEI only)
Investment securities.  Investments in debt and equity securities are classified as held-to-maturity (HTM), trading or available-for-sale (AFS). ASB determines the appropriate classification at the time of purchase. Debt securities that ASB intends to and has the ability to hold to maturity are classified as HTM securities and reported at cost. Marketable debt and equity securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable debt and equity securities not classified as either HTM or trading securities are classified as AFS and reported at fair value. Unrealized gains and losses for AFS securities are excluded from earnings and reported on a net basis in accumulated other comprehensive income (AOCI) until realized.
Interest income is recorded on an accrual basis. Discounts and premiums on securities are accreted or amortized into interest income using the interest method over the remaining contractual lives of the agency obligation securities and the estimated lives of the mortgage-related securities adjusted for anticipated prepayments. ASB uses actual prepayment experience and estimates of future prepayments to determine the constant effective yield necessary to apply the interest method of income recognition. The discounts and premiums on the agency obligations portfolio are accreted or amortized on a prospective basis using expected contractual cash flows. The discounts and premiums on the mortgage-related securities portfolio are accreted or amortized on a retrospective basis using changes in anticipated prepayments. This method requires a retrospective adjustment of the effective yield each time ASB changes the estimated life as if the new estimate had been known since the original acquisition date of the securities. Estimates of future prepayments are based on the underlying collateral characteristics and historic or projected prepayment behavior of each security. The specific identification method is used in determining realized gains and losses on the sales of securities.
For securities that are not trading securities, individual securities are assessed for impairment at least on a quarterly basis, and more frequently when economic or market conditions warrant. A security is impaired if the fair value of the security is less than its carrying value at the financial statement date. When a security is impaired, ASB determines whether this impairment is temporary or other-than-temporary. If ASB does not expect to recover the entire amortized cost basis of the security or there is a change in the expected cash flows, an OTTI exists. If ASB intends to sell the security, or will more likely than not be required to sell the security before recovery of its amortized cost, the OTTI must be recognized in earnings. If ASB does not intend to sell the security, and it is not more likely than not that ASB will be required to sell the security before recovery of its amortized cost, the OTTI must be separated into the amount representing the credit loss and the amount related to all other factors. The amount of OTTI related to the credit loss is recognized in earnings, while the remaining OTTI is recognized in AOCI. Based on ASB's evaluation as of December 31, 2016 and 2015, there was no indicated impairment as the bank expects to collect the contractual cash flows for these investments.
Stock in Federal Home Loan Bank (FHLB) is carried at cost and is reviewed at least periodically for impairment, with valuation adjustments recognized in noninterest income.
Loans receivable.  ASB carries loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method.


Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over periods not exceeding the contractual life of the loan using the interest method or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.
Loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held for sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.
Allowance for loan losses.  ASB maintains an allowance for loan losses that it believes is adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). The allowance for loan losses is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.
ASB disaggregates its portfolio loans into portfolio segments for purposes of determining the allowance for loan losses. Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a risk rating system for evaluating the credit quality of the loans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. Values are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). ASB’s credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans are categorized into the regulatory asset quality classifications-Pass, Special Mention, Substandard, Doubtful, and Loss based on credit quality. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the original contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans that are not considered collateral dependent, generally the discounted cash flow method is used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured loans, the present value of the expected future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured terms. Impairments are charged to the provision for loan losses and included in the allowance for loan losses. However, confirmed losses (uncollectible) are charged off, with the loan written down by the amount of the confirmed loss.
Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products with common risk characteristics and segmented into various secured and unsecured loan product types. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB does supplement performance data with an 11-risk rating retail credit model that assigns a probability of default to each borrower based primarily on the borrower's current Fair Isaac Corporation (FICO) score and for the home equity line of credit (HELOC) and unsecured consumer products, the bankruptcy score (BK). Current FICO and BK data is purchased and appended to all homogeneous loans on a quarterly basis and used to estimate the borrower’s probability of default and the loss given default.
ASB also considers the following qualitative factors for all loans in estimating the allowance for loan losses:
changes in lending policies and procedures;
changes in economic and business conditions and developments that affect the collectability of the portfolio;
changes in the nature, volume and terms of the loan portfolio;
changes in lending management and other relevant staff;
changes in loan quality (past due, non-accrual, classified loans);


changes in the quality of the loan review system;
changes in the value of underlying collateral;
effect of, and changes in the level of, any concentrations of credit; and
effect of other external and internal factors.
ASB’s methodology for determining the allowance for loan losses was generally based on historic loss rates using various look-back periods. During the second quarter of 2014, ASB implemented enhancements to the loss rate calculation for estimating the allowance for loan losses that included several refinements to determining the probability of default and the loss given default for the various segments of the loan portfolio that are more statistically sound than those previously employed. The result is an estimated loss rate established for each borrower. ASB also updated its measurement of the loss emergence period in the calculation of the allowance for loan losses. The loss emergence period is broadly defined as the period that it takes, on average, for the lender to identify the specific borrower and amount of loss incurred by the bank for a loan that has suffered from a loss-causing event. In most cases, as credit quality and conditions improve, management has observed that the loss emergence period has extended and has incorporated this observed change in the estimate of the allowance for loan losses. Management believes these enhancements will improve the precision in estimating the allowance for loan losses. The enhancements did not have a material effect on the total allowance for loan losses or the provision for loan losses for 2014. The enhancements did result in the full allocation of the previously unallocated portion of the allowance for loan losses.
In conjunction with the above enhancement, management also adopted an enhanced risk rating system for monitoring and managing credit risk in the non-homogenous loan portfolios, that measures general creditworthiness at the borrower level. The numerical-based, risk rating “PD Model” takes into consideration fiscal year-end financial information of the borrower and identified financial attributes including retained earnings, operating cash flows, interest coverage, liquidity and leverage that demonstrate a strong correlation with default to assign default probabilities at the borrower level. In addition, a loss given default (LGD) value is assigned to each loan to measure loss in the event of default based on loan specific features such as collateral that mitigates the amount of loss in the event of default. Together the PD Model and LGD construct provide a more quantitative, data driven and consistent framework for measuring risk within the portfolio, on a loan by loan basis and for the ultimate collectability of each loan.
The reserve for unfunded commitments is maintained at a level believed by management to be sufficient to absorb estimated probable losses related to unfunded credit facilities and is included in accounts payable and other liabilities in the consolidated balance sheets. The determination of the adequacy of the reserve is based upon an evaluation of the unfunded credit facilities, including an assessment of historical commitment utilization experience, credit risk grading and historical loss rates. This process takes into consideration the same risk elements that are analyzed in the determination of the adequacy of the allowance for loan losses, as discussed above. Net adjustments to the reserve for unfunded commitments are included in other noninterest expense in the consolidated statements of income.
Management believes its allowance for loan losses adequately estimates actual loan losses that will ultimately be incurred. However, such estimates are based on currently available information and historical experience, and future adjustments may be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.
Nonperforming loans. Loans are generally placed on nonaccrual status when contractually past due 90 days or more, or earlier if management believes that the probability of collection is insufficient to warrant further accrual. All interest that is accrued but not collected is reversed. A loan may be returned to accrual status if (i) principal and interest payments have been brought current and repayment of the remaining contractual principal and interest is expected to be made, (ii) the loan has otherwise become well-secured and in the process of collection, or (iii) the borrower has been making regularly scheduled payments in full for the prior six months and it is reasonably assured that the loan will be brought fully current within a reasonable period. Cash receipts on nonaccruing loans are generally applied to reduce the unpaid principal balance.
Loans considered to be uncollectible are charged-off against the allowance for loan losses. The amount and timing of charge-offs on loans includes consideration of the loan type, length of delinquency, insufficiency of collateral value, lien priority and the overall financial condition of the borrower. Recoveries on loans previously charged-off are credited back to the allowance for loan losses. Loans that have been charged-off against the allowance for loan losses are periodically monitored to evaluate whether further adjustments to the allowance are necessary. Loans in the commercial and commercial real estate portfolio are charged-off when the loan is risk-rated “Doubtful” or “Loss”. The loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 90 days or more; (b) significant improvement in the borrower’s repayment capacity is doubtful; and/or (c) collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist.


Loans in the residential mortgage and home equity portfolios are charged-off when the loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 180 days or more; (b) it is probable that collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist; (c) borrower’s debt is discharged in bankruptcy and the loan is not reaffirmed; or (d) in cases where ASB is in a subordinate position to other debt, the senior lien holder has foreclosed and ASB's junior lien is extinguished.
Other consumer loans are generally charged-off when the balance becomes 120 days delinquent.
Loans modified in a troubled debt restructuring. Loans are considered to have been modified in a troubled debt restructuring (TDR) when, due to a borrower’s financial difficulties, ASB makes concessions to the borrower that it would not otherwise consider for a non-troubled borrower. Modifications may include interest rate reductions, interest only payments for an extended period of time, protracted terms such as amortization and maturity beyond the customary length of time found in the normal market place, and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual loan that has been modified in a TDR remains on nonaccrual status until the borrower has demonstrated sustained repayment performance for a period of six consecutive months. However, performance prior to the modification, or significant events that coincide with the modification, are included in assessing whether the borrower can meet the new terms and may result in the loan being returned to accrual status at the time of loan modification or after a shorter performance period. If the borrower’s ability to meet the revised payment schedule is uncertain, or there is reasonable doubt over the full collectability of principal and interest, the loan remains on nonaccrual status.
Real estate acquired in settlement of loans.  ASB records real estate acquired in settlement of loans at fair value, less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. Costs related to holding real estate are charged to operations as incurred.
Goodwill. At December 31, 2016 and 2015, the amount of goodwill was $82.2 million. The goodwill is with respect to ASB and is the Company’s only intangible asset with an indefinite useful life and is tested for impairment annually at December 31 using data as of September 30.
To determine if there was any impairment to the book value of goodwill pertaining to ASB, the fair value of ASB was estimated using a valuation method based on a market approach and discounted cash flow method with each method having an equal weighting in determining the fair value of ASB. The market approach considers publicly traded financial institutions with assets of $3.5 billion to $8 billion and measures the institutions' market values as a multiple to (1) net income and (2) book equity. ASB used the median market value multiples for net income and book equity from its selection criteria and applied the multiples to its net income and book equity to calculate ASB's fair value using the market approach. In order to reflect a premium that a buyer would pay for a controlling interest in ASB, a control premium of 18.4% was included in determining the market approach fair value. The control premium was based on control premiums paid in 18 acquisitions with deal values over $500 million which were completed in 2014-2016 where 100% interests were purchased and control premium information was available. The discounted cash flow method values a company on a going concern basis and is based on the concept that the future benefits derived from a particular company can be measured by its sustainable after-tax cash flows in the future. ASB's discounted cash flow analysis was based on its income statement forecasts and a discount rate of 8.9% was applied to present value the cash flows. ASB used a Capital Asset Pricing Model analysis to determine its discount rate. For the three years ended December 31, 2016, there has been no impairment of goodwill.
Mortgage banking. Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held for sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold. ASB is obligated to subsequently repurchase a loan if the purchaser discovers a standard representation or warranty violation such as noncompliance with eligibility requirements, customer fraud or servicing violations. This primarily occurs during a loan file review. ASB considers and records a reserve for loan repurchases if appropriate.
ASB recognizes a mortgage servicing asset when a mortgage loan is sold with servicing rights retained. This mortgage servicing right (MSR) is initially capitalized at its presumed fair value based on market data at the time of sale and accounted for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing assets or liabilities are included as a component of gain on sale of loans. Under ASC Topic 860, “Transfers and Servicing,” we amortize the MSRs in proportion to and over the period of estimated net servicing income and assess for impairment at each reporting date.


ASB's MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15 and 30 year mortgages and note rate in bands primarily of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others.
ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. Because observable market prices with exact terms and conditions may not be readily available, ASB compares the fair value of MSRs to an estimated value calculated by an independent third-party on a semi-annual basis. The third-party relies on both published and unpublished sources of market related assumptions and their own experience and expertise to arrive at a value. ASB uses the third-party value only to assess the reasonableness of fair value generated by the valuation model.
Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in "Other income, net" in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.
Loan servicing fee income represents income earned for servicing mortgage loans owned by investors. It includes mortgage servicing fees and other ancillary servicing income, net of guaranty fees. Servicing fees are generally calculated on the outstanding principal balances of the loans serviced and are recorded as income when earned.
Tax Credit Investments. ASB invests in limited liability entities formed to operate qualifying affordable housing projects.
The affordable housing investments provide tax benefits to investors in the form of tax deductions from operating losses and tax credits. As a limited partner, ASB has no significant influence over the operations. These investments are initially recorded at the initial capital contribution with a liability recognized for the commitment to contribute additional capital over the term of the investment.
The Company uses the proportional amortization method of accounting for its investments. Under the proportional amortization method, the Company amortizes the cost of its investments in proportion to the tax credits and other tax benefits it receives. The amortization, tax credits and tax benefits are reported as a component of income tax expense. Cash contributions and payments made on commitments to low-income housing tax credit (LIHTC) investments are classified as operating activities in the Company’s consolidated statements of cash flows.
For these limited liability entities, ASB assesses whether it is the primary beneficiary of the limited liability entity, which is a variable interest entity (VIE). The primary beneficiary of a VIE is determined to be the party that meets both of the following criteria: (i) has the power to make decisions that most significantly affect the economic performance of the VIE; and (ii) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. Generally, ASB, as a limited partner, is not deemed to be the primary beneficiary as it does not meet the power criterion, i.e., no power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and no direct ability to unilaterally remove the general partner.
All tax credit investments are evaluated for potential impairment at least annually, or more frequently, when events or conditions indicate that it is deemed probable that ASB will not recover its investment. Potential indicators of impairment might arise when there is evidence that some or all tax credits previously claimed would be recaptured, or that expected remaining credits would no longer be available to the limited liability entities. If an investment is determined to be impaired, it is written down to its estimated fair value and the new cost basis of the investment is not adjusted for subsequent recoveries in value. As of December 31, 2016, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investments.
At December 31, 2016 and 2015, the carrying amount of qualifying affordable housing investments was $47.1 million and $37.8 million, respectively, and included in other assets in the consolidated balance sheets.
ASB’s unfunded commitments to fund to its qualifying affordable housing investments were $14.0 million and $10.1 million as of December 31, 2016 and 2015, respectively. These unfunded commitments are unconditional and legally binding and are recorded in accounts payable and other liabilities with an increase in other assets in the consolidated balance sheets.


The table below summarizes the amounts in income tax expense related to ASB's investments in qualifying affordable housing projects:
Years ended December 312016
 2015
 2014
(in millions) 
  
  
Amounts in income taxes related to investments in qualifying affordable housing projects 
  
  
   Amortization recognized in the provision for income taxes$(5.8) $(5.4) $(3.6)
   Tax credits and other tax benefits recognized in the provision for income taxes8.4
 8.0
 5.4
         Net benefit to income tax expense$2.6
 $2.6
 $1.8
2 · Termination of proposed merger and other matters
On December 3, 2014, HEI, NextEra Energy, Inc. (NEE) and two subsidiaries of NEE entered into an Agreement and Plan of Merger (the Merger Agreement), under which Hawaiian Electric was to become a subsidiary of NEE. The Merger Agreement contemplated that, prior to the Merger, HEI would distribute to its shareholders all of the common stock of ASB Hawaii, Inc. (ASB Hawaii), the parent company of ASB (such distribution referred to as the Spin-Off).
The closing of the Merger was subject to various conditions, including receipt of regulatory approval from the PUC. In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger. On July 15, 2016, the PUC dismissed the application without prejudice.
On July 16, 2016, NEE terminated the Merger Agreement. Pursuant to the terms of the Merger Agreement, on July 19, 2016, NEE paid HEI a $90 million termination fee and $5 million for the reimbursement of expenses associated with the transaction. In 2016, the Company recognized $60 million of net income ($2 million of net loss in each of the first and second quarters and $64 million of net income in the third quarter), comprised of the termination fee ($55 million), reimbursements of expenses from NEE and insurance ($3 million), and additional tax benefits on the previously non-tax-deductible merger- and spin-off-related expenses incurred through June 30, 2016 ($8 million), less merger- and spin-off-related expenses incurred in 2016 ($6 million) (all net of tax impacts). In 2015, the Company recognized $16 million of merger- and spin-off-related expenses ($5 million in the first quarter, $7 million in the second quarter and $2 million in each of the third and fourth quarters), net of tax impacts. In 2014, the Company recognized merger- and spin-off-related expenses of $5 million, net of tax impacts, primarily in the fourth quarter. The Spin-Off of ASB Hawaii was cancelled as it was cross-conditioned on the merger consummation.
In May 2016, the Utilities had filed an application for approval of an LNG supply and transport agreement and LNG-related capital equipment and two related applications, which applications were conditioned on the PUC’s approval of the proposed Merger. Subsequently, the Utilities terminated the agreement and withdrew the three applications. In 2016, Hawaiian Electric recognized expenses related to the terminated LNG agreement of $1 million, net of tax benefits, in each of the first and second quarters.
Litigation. HEI and its subsidiaries are subject to various legal proceedings that arise from time to time. Some of these proceedings may seek relief or damages in amounts that may be substantial. Because these proceedings are complex, many years may pass before they are resolved, and it is not feasible to predict their outcomes. Some of these proceedings involve claims HEI and Hawaiian Electric believe may be covered by insurance, and HEI and Hawaiian Electric have advised their insurance carriers accordingly.
Since the December 3, 2014 announcement of the Merger Agreement with NEE, several purported class action complaints were filed by alleged stockholders of HEI against HEI, the individual directors of HEI, NEE and others. All of these lawsuits (seven of which were consolidated) have been dismissed, either with or without prejudice.


3 · Segment financial information
The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described for the Company in the summary of significant accounting policies, except as otherwise indicated and except that federal and state income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on net income. Each segment accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest, rent and preferred stock dividends.
Electric utility
Hawaiian Electric and its wholly-owned operating subsidiaries, Hawaii Electric Light and Maui Electric, are public electric utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. The utility subsidiaries are aggregated within the electric utility segment because they: (1) are involved in the business of supplying electric energy in the same geographical location (i.e., the State of Hawaii), (2) have similar production processes that include electric generators (e.g., conventional oil-fired steam units and combustion turbines), (3) serve similar customers within their franchise territories (e.g., residential, commercial and industrial customers), (4) use similar electric grids to distribute the energy to their customers, (5) are regulated by the PUC and undergo similar rate-making processes, (6) have similar economic characteristics and (7) perform financial reporting oversight and management of the business at the consolidated level. Hawaiian Electric also owns the following nonregulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; HECO Capital Trust III, which is a financing entity; and Uluwehiokama Biofuels Corp. (UBC), which was formed to own a new biodiesel refining plant to be built on the island of Maui, which project has been terminated.
Bank
ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) (previously by the Department of Treasury, Office of Thrift Supervision (OTS)) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System.
Other
“Other” includes amounts for the holding companies (HEI and ASB Hawaii, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.


Segment financial information was as follows:
(in thousands)Electric utility Bank
 Other
 Total
2016 
  
  
  
Revenues from external customers$2,094,224
 $285,924
 $506
 $2,380,654
Intersegment revenues (eliminations)144
 —
 (144) —
Revenues2,094,368
 285,924
 362
 2,380,654
Depreciation and amortization193,996
 9,813
 937
 204,746
Interest expense, net66,824
 12,755
 8,979
 88,558
Income before income taxes229,113
 87,352
 57,376
 373,841
Income taxes84,801
 30,073
 8,821
 123,695
Net income144,312
 57,279
 48,555
 250,146
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income for common stock142,317
 57,279
 48,660
 248,256
Capital expenditures320,437
 9,394
 212
 330,043
Assets (at December 31, 2016)5,975,428
 6,421,357
 28,721
 12,425,506
2015 
  
  
  
Revenues from external customers$2,335,135
 $267,733
 $114
 $2,602,982
Intersegment revenues (eliminations)31
 —
 (31) —
Revenues2,335,166
 267,733
 83
 2,602,982
Depreciation and amortization186,319
 7,928
 1,338
 195,585
Interest expense, net66,370
 11,326
 10,780
 88,476
Income (loss) before income taxes217,131
 83,812
 (46,155) 254,788
Income taxes (benefit)79,422
 29,082
 (15,483) 93,021
Net income (loss)137,709
 54,730
 (30,672) 161,767
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income (loss) for common stock135,714
 54,730
 (30,567) 159,877
Capital expenditures350,161
 13,470
 173
 363,804
Assets (at December 31, 2015)5,672,210
 6,014,755
 95,053
 11,782,018
2014 
  
  
  
Revenues from external customers$2,987,299
 $252,497
 $(254) $3,239,542
Intersegment revenues (eliminations)24
 —
 (24) —
Revenues2,987,323
 252,497
 (278) 3,239,542
Depreciation and amortization176,284
 5,399
 1,361
 183,044
Interest expense, net64,757
 10,808
 11,595
 87,160
Income (loss) before income taxes220,361
 79,295
 (34,058) 265,598
Income taxes (benefit)80,725
 27,994
 (13,140) 95,579
Net income (loss)139,636
 51,301
 (20,918) 170,019
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income (loss) for common stock137,641
 51,301
 (20,813) 168,129
Capital expenditures336,679
 28,073
 74
 364,826
Assets (at December 31, 2014)5,550,021
 5,566,222
 60,900
 11,177,143
See Note 1 for the impact to prior period financial information of the adoptions of ASU No. 2015-03.
Intercompany electricity sales of the Utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by the Utilities and the profit on such sales is nominal.
Bank fees that ASB charges the Utilities and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution and the profit on such fees is nominal.


4 · Electric utility segment
Regulatory assets and liabilities.  Regulatory assets represent deferred costs and accrued decoupling revenues which are expected to be fully recovered through rates over PUC-authorized periods. Generally, the Utilities do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, the Utilities include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. In the table below, noted in parentheses are the original PUC authorized amortization or recovery periods and, if different, the remaining amortization or recovery periods as of December 31, 2016 are noted.
Regulatory assets were as follows:
December 312016
 2015
(in thousands) 
  
Retirement benefit plans (balance primarily varies with plans’ funded statuses)$745,367
 $679,766
Income taxes, net (1 to 55 years)90,100
 88,039
Decoupling revenue balancing account and RAM regulatory asset (1 to 2 years)73,485
 74,462
Unamortized expense and premiums on retired debt and equity issuances (19 to 30 years; 6 to 18 years remaining)12,299
 14,089
Vacation earned, but not yet taken (1 year)10,970
 10,420
Other (1 to 50 years; 1 to 46 years remaining)25,230
 29,955
 $957,451
 $896,731
Included in: 
  
Current assets$66,032
 $72,231
Long-term assets891,419
 824,500
 $957,451
 $896,731
Regulatory liabilities were as follows:
December 312016
 2015
(in thousands) 
  
Cost of removal in excess of salvage value (1 to 60 years)$394,072
 $357,825
Retirement benefit plans (5 years beginning with respective utility’s next rate case)10,824
 9,835
Other (5 years; 1 to 2 years remaining)5,797
 3,883
 $410,693
 $371,543
Included in:   
Current liabilities$3,762
 $2,204
Long-term liabilities406,931
 369,339
 $410,693
 $371,543
The regulatory asset and liability relating to retirement benefit plans was recorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for the Utilities in 2007 (see Note 10).
Major customers.  The Utilities received 11% ($226 million), 11% ($265 million) and 12% ($350 million) of their operating revenues from the sale of electricity to various federal government agencies in 2016, 2015 and 2014, respectively.
Cumulative preferred stock. The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:


December 31, 2016
Voluntary
liquidation price
 
Redemption
price
Series 
  
C, D, E, H, J and K (Hawaiian Electric)$20
 $21
I (Hawaiian Electric)20
 20
G (Hawaii Electric Light)100
 100
H (Maui Electric)100
 100
Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric's obligation to make payments on its own preferred stock.
Related-party transactions. HEI charged the Utilities $6.5 million, $6.5 million and $7.0 million for general management and administrative services in 2016, 2015 and 2014, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.
Hawaiian Electric’s short-term borrowings totaled nil at December 31, 2016 and 2015. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or Hawaiian Electric’s effective weighted average short-term external borrowing rate. If both HEI and Hawaiian Electric do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Wall Street Journal plus 0.15%.
Borrowings among the Utilities are eliminated in consolidation. Interest charged by HEI to Hawaiian Electric was $0.04 million in 2016 and nil in each of 2015 and 2014.
Commitments and contingencies.
Fuel contracts.  The Utilities have contractual agreements to purchase minimum quantities of low sulfur fuel oil (LSFO), medium sulfur fuel oil (MSFO), diesel fuel and biodiesel for multi-year periods, some through December 2019. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2016, the estimated cost of minimum purchases under the fuel supply contracts is $125 million in 2017, $119 million in 2018 and $119 million in 2019. The actual cost of purchases in 2017 and future years could vary substantially from this estimate of minimum purchases as a result of changes in market prices, quantities actually purchased, entry into new supply contracts and/or other factors. The Utilities purchased $0.4 billion, $0.6 billion and $1.1 billion of fuel under contractual agreements in 2016, 2015 and 2014, respectively.
On February 18, 2016, the Companies signed two fuel supply contracts with Chevron Products Company (Chevron) for: (1) Oahu’s LSFO and diesel (for purposes of blending with LSFO) to meet the Environmental Protection Agency’s Mercury and Air Toxic Standards; and (2) MSFO, diesel and ultra-low sulfur diesel for Oahu, Maui, Molokai and the island of Hawaii. The contract began on January 1, 2017, terminates on December 31, 2019, and may automatically renew for annual terms thereafter unless terminated earlier by either party. Both of these fuel contracts were recently assigned to Island Energy Services, LLC, a subsidiary of One Rock Capital Partners, L.P., who purchased Chevron’s Hawaii assets on November 1, 2016. Both of these fuel contracts replace prior fuel supply contracts with Chevron and Par Hawaii Refining, LLC (Par), which both expired on December 31, 2016.

Hawaii Electric Light also signed a contract with Chevron, now Island Energy Services, LLC, for terminalling services in Hilo, Hawaii for 2017 through 2019. The terminalling services were provided by Chevron as part of the fuel supply contract but as mentioned above, that contract expired December 31, 2016. Now Hilo terminalling services are contracted in a stand-alone contract.
The PUC approved all of the contracts with Chevron, now Island Energy Services, LLC. All of the costs incurred under these contracts are included in the Utilities’ respective Energy Cost Adjustment Clauses (ECACs) to the extent such costs are not recovered through the base rates.
Hawaiian Electric also has three contracts for biodiesel. Two of the contracts are with Pacific Biodiesel Technologies, LLC (PBT) and one contingency contract is in place with REG Marketing & Logistics, LLC (REG). PBT has agreed to supply biodiesel to Hawaiian Electric’s Campbell Industrial Park (CIP) generating facility through November 2017. The Company intends to seek a one-year extension of this contract through 2018. While fuel is delivered to CIP, the contract provides that biodiesel can be trucked to the Honolulu International Airport Emergency Facility and to any other generating facility on Oahu owned by Hawaiian Electric. Hawaiian Electric intends to shift the biodiesel supply to Schofield generating station when that


new facility comes online and as long as the PBT contract remains in effect. PBT also has a spot buy contract with Hawaiian Electric to purchase additional quantities of biodiesel at or below the price of diesel. Very few purchases of “at parity” biodiesel have been purchased, however the contract remains in effect and was recently extended through June 2018.
Hawaiian Electric also has a contingency contract with REG. REG will supply biodiesel in the event PBT is unable to supply quantities above the contract maximum volume, should something unexpected occur. Hawaiian Electric did not purchase any biofuel from REG during 2016. Regardless of no purchases, Hawaiian Electric secured a one-year extension of this contract through November 2017.
The costs incurred under the Utilities’ biodiesel contracts are included in their respective ECACs, to the extent such costs are not recovered through the Utilities’ base rates.
The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under Hawaiian Electric’s purchase power agreement (PPA) with Kalaeloa is based in part on the price Kalaeloa pays PAR (formerly known as Hawaii Independent Energy, LLC) for LSFO in a fuel contract between the two parties.
Hawaiian Electric and Kalaeloa are currently in negotiations to address the PPA term that ended on May 23, 2016. The PPA automatically extends on a month-to-month basis as long as the parties are still negotiating in good faith. The month-to-month term extensions shall end 60 days after either party notifies the other in writing that negotiations have terminated. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution.
The costs incurred for LSFO under Hawaiian Electric's fuel contract with Kalaeloa is included in Hawaiian Electric's ECAC, to the extent such costs are not recovered through base rates.
Power purchase agreements.  As of December 31, 2016, the Utilities had five firm capacity PPAs for a total of 551 megawatts (MW) of firm capacity. Purchases from these five independent power producers (IPPs) and all other IPPs totaled $0.6 billion, $0.6 billion and $0.7 billion for 2016, 2015 and 2014, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term (and as amended) and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2017 through 2021 and a total of $0.4 billion in the period from 2022 through 2033.
In general, the Utilities base their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. The Utilities pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. The Utilities do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to Hawaiian Electric or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.
Purchase power adjustment clause. The PUC has approved purchased power adjustment clauses (PPACs) for the Utilities. Purchased power capacity, O&M and other non-energy costs previously recovered through base rates are now recovered in the PPACs and, subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs outside of a rate case. Purchased energy costs continue to be recovered through the ECAC to the extent they are not recovered through base rates.
AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended (through Amendment No. 2), for a period of 30 years beginning September 1992, Hawaiian Electric agreed to purchase 180 MW of firm capacity from AES Hawaii. In August 2012, Hawaiian Electric filed an application with the PUC seeking an exemption from the PUC’s Competitive Bidding Framework to negotiate an amendment to the PPA to purchase 186 MW of firm capacity, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013, but Hawaiian Electric and AES Hawaii were not able to reach agreement on an amendment. In June 2015, AES Hawaii filed an arbitration demand regarding a dispute about whether Hawaiian Electric was obligated to buy up to 9 MW of additional capacity based on a 1992 letter. Hawaiian Electric responded to the arbitration demand and, in October 2015, AES Hawaii and Hawaiian Electric entered into a Settlement Agreement to stay the arbitration proceeding. The Settlement Agreement included certain conditions precedent which, if satisfied would have released the parties from the claims under the arbitration proceeding. Among the conditions precedent was the successful negotiation of an amendment to the existing purchase power agreement and PUC approval of such amendment.


In November 2015, Hawaiian Electric entered into Amendment No. 3 to the PPA, subject to PUC approval. The arbitration proceeding was stayed to allow for the PUC approval proceeding to proceed. In January 2017, the PUC denied  Hawaiian Electric’s request to approve Amendment No. 3 to the PPA. Approval of Amendment No. 3 would have satisfied the final condition for effectiveness of the Settlement Agreement and resolved AES Hawaii’s claims. Following the PUC’s decision, the parties have agreed to extend the stay of the arbitration proceedings for an additional four months, to allow the parties to discuss possible alternative settlement structures.
Hu Honua Bioenergy, LLC. In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy, LLC (Hu Honua) for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii. Per the terms of the PPA, the Hu Honua plant was scheduled to be in service in 2016. However, Hu Honua encountered construction delays, failed to meet its current obligations under the PPA and failed to provide adequate assurances that it could perform or had the financial means to perform. Hawaii Electric Light terminated the PPA on March 1, 2016. Hawaii Electric Light and Hu Honua were in discussions regarding the possibility of reinstating the PPA under revised terms and conditions. However, on November 30, 2016, Hu Honua filed a civil complaint in the United States District Court for the District of Hawaii which included claims purportedly arising out of the termination of Hu Honua’s PPA. The complaint named HEI, Hawaiian Electric and Hawaii Electric Light as defendants.  HEI, Hawaiian Electric and Hawaii Electric believe the allegations in the complaint are without merit and intend to defend these lawsuits vigorously.
Liquefied natural gas. On May 18, 2016, Hawaiian Electric and Fortis Hawaii Energy Inc. (Fortis Hawaii), an affiliate of Fortis, Inc. (Fortis), entered into a Fuel Supply Agreement (FSA) whereby Fortis Hawaii intended to sell to Hawaiian Electric liquefied natural gas (LNG) to be produced from the LNG facilities on Tilbury Island in Delta, British Columbia, Canada. Pursuant to the FSA, Fortis Hawaii had arranged, or planned to arrange, for the transportation of gas for delivery to, and liquefaction at, the Tilbury LNG facilities, including with respect to the transport and delivery of LNG across a jetty at such facilities, for the purchase and storage of LNG at such LNG facilities and for the transportation of LNG to delivery points in Hawaii for the benefit of Hawaiian Electric and its subsidiaries. The FSA was subject to approval by the PUC and to the satisfaction of certain conditions precedent, including the consummation of the merger between HEI and NEE. On July 16, 2016, pursuant to the terms of the Merger Agreement, NEE terminated the Merger Agreement. Accordingly, on July 19, 2016, Hawaiian Electric provided notice of termination of the FSA to Fortis Hawaii, effective immediately, and withdrew the application for PUC approval of the FSA, which included a request for approval to commit approximately $341 million to convert existing generating units to use natural gas, and to commit approximately $117 million for containers to support LNG. In addition, on July 19, 2016, Hawaiian Electric withdrew its applications to the PUC for a waiver from the competitive bidding process to allow Hawaiian Electric to construct a modern, efficient, combined cycle generation system at the Kahe power plant that would utilize LNG and to commit $859 million for such project. Hawaiian Electric will continue to evaluate all options to modernize generation using a cleaner fuel to bring price stability and support adding renewable energy for its customers.
Utility projects.  Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, or if PUC imposed caps on project costs are exceeded, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.
Renewable energy project matters. In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, Hawaii Electric Light filed an application to defer 2012 costs related to the Geothermal RFP. In November  2015, the PUC approved the deferral of $2.1 million of costs related to the Geothermal RFP, and will review the prudency and reasonableness of the deferred costs in the Hawaii Electric Light 2016 test year rate case.In February 2013, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received, but Hawaii Electric Light notified bidders that none of the submitted bids sufficiently met both the low-cost and technical requirements of the Geothermal RFP. In October 2014, Hawaii Electric Light issued Addendum No. 1 (Best and Final Offer) and Attachment A (Best and Final Offer Bidder's Response Package) directly to five eligible bidders. The submittals received in January 2015 were considered for final selection of one project to proceed with PPA negotiations. In February 2015, Ormat Technologies, Inc. was selected for an award and began PPA negotiations with Hawaii Electric Light. In February 2016, Hawaii Electric Light provided the PUC with a status update notifying the PUC that Ormat Technologies, Inc. had determined the proposed project not to be economically and financially viable, resulting in termination of PPA negotiations. On March 8, 2016, the Independent Observer issued a report on the results of the negotiation phase of the Geothermal RFP.
In February 2016, Huena Power Inc. (Huena) filed with the PUC a Petition for Declaratory Order (which the PUC later dismissed without prejudice) and a Complaint relating to the Geothermal RFP. Hawaii Electric Light filed a motion to dismiss Huena’s Petition which was granted on March 28, 2016. Hawaii Electric Light’s motion to dismiss Huena’s Complaint is still


pending. On December 15, 2016, the PUC issued Order No. 34211 in Docket No. 2016-0027 granting Hawaii Electric Light's motion to dismiss Huena’s complaint against Hawaii Electric Light with prejudice and closed the geothermal RFP docket.
Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) Implementation Project. The Utilities submitted their Enterprise Information System Roadmap to the PUC in June 2014 and refiled an application for an ERP/EAM implementation project in July 2014 with an estimated cost of $82.4 million.
In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the Utilities’ existing ERP/EAM system, (2) denying the Utilities request to defer the costs for the ERP software purchased in 2012 and (3) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under two options. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015. In April 2016, the Utilities filed additional information on the costs and benefits of the project and the Consumer Advocate submitted its reply.
On August 11, 2016, the PUC issued a second D&O approving the Utilities’ request to commence the ERP/EAM implementation project, subject to certain conditions, including a $77.6 million cap on cost recovery as well as a requirement that the Utilities pass onto customers a minimum of $244 million in savings associated with the system over its 12-year service life. Pursuant to the D&O and subsequent orders, the Utilities will be required to file: the proposed methods of passing on to customers the estimated monetary savings attributable to the project by March 31, 2017; a bottom-up, low-level analysis of the project’s benefits; performance metrics and tracking mechanism for passing the project’s benefits on to customers by September 2017; and monthly reports on the status and costs of the project starting February 2017. The project is expected to go-live by October 1, 2018.
Schofield Generating Station Project. In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for the construction of a 50 MW utility owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks. In September 2015, the PUC approved Hawaiian Electric’s application to expend $167 million for the project. In approving the project, the PUC placed a cost cap of $167 million for the project, stated 90% of the cap is allowed for cost recovery through cost recovery mechanisms other than base rates, and stated the $167 million cap will be adjusted downward due to any reduction in the cost of the engine contract due to a reduction in the foreign exchange rate. Hawaiian Electric was required to take all necessary steps to lock in the lowest possible exchange rate. On January 5, 2016, Hawaiian Electric executed a window forward agreement which lowered the cost of the engine contract by $9.7 million, resulting in a revised project cost cap of $157.3 million. Hawaiian Electric has received all of the major permits for the project, including a 35 year site lease from the U.S. Army. Construction of the facility began in October 2016, and the facility is expected to be placed in service in the first quarter of 2018.
Hamakua Energy Partners, L.P. (HEP) Asset Purchase Agreement. Hawaii Electric Light has been purchasing up to 60 MW (net) of firm capacity from HEP under a power purchase agreement (PPA) that expires on December 30, 2030. The HEP plant currently contributes about 23% of the island of Hawaii’s generating capacity. On December 22, 2015, Hawaii Electric Light entered into an agreement, subject to PUC approval, to acquire the assets of HEP for approximately $84.5 million. If approved by the PUC, the agreement to purchase the existing HEP generating assets will terminate the existing PPA. The elimination of certain required capacity payments under the PPA is expected to result in lower costs to customers. Additionally, by owning the plant, Hawaii Electric Light will be able to manage HEP’s efficient generating units more productively, providing greater flexibility to cycle HEP’s generating units to more effectively manage the Hawaii island grid. This increased operational flexibility will be essential to support and facilitate Hawaii Electric Light’s efforts to integrate more renewable energy onto the grid.
A decision on an application requesting PUC approval of Hawaii Electric Light's purchase of the HEP Facility is pending.
Environmental regulation.  The Utilities are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act and Clean Water Act (CWA), have increased significantly.
Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases into the environment associated with current or previous operations. The Utilities report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.
Clean Water Act Section 316(b). On August 14, 2014, the EPA published in the Federal Register the final regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The regulations were effective October 14, 2014 and apply to the cooling water


systems for the steam generating units at three of Hawaiian Electric’s power plants on the island of Oahu. The regulations prescribe a process, including a number of required site-specific studies, for states to develop facility-specific entrainment and impingement controls to be incorporated in each facility’s National Pollutant Discharge Elimination System (NPDES) permit. These studies must be completed before Hawaiian Electric and the State of Hawaii Department of Health (DOH) can determine what entrainment or impingement controls, if any, might be necessary at the affected facilities to comply with the new 316(b) rule. Hawaiian Electric will work with the DOH to identify the appropriate compliance methods for the 316(b) rule.
Mercury Air Toxics Standards. On February 16, 2012, EPA published the final rule establishing the National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs) in the Federal Register. The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS established the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Hawaiian Electric received a one-year extension to comply by April 16, 2016. Hawaiian Electric initially selected a MATS compliance strategy based on switching to lower emission fuels, but has since continued developing and refining its emission control strategy. Hawaiian Electric’s liquid oil-fired steam generating units that are subject to the MATS limits are able to comply with the new standards without a significant fuel switch in combination with a suite of operational changes.
Hawaiian Electric has proceeded with the implementation of the MATS Compliance Plan and has met all compliance requirements to date.
1-Hour Sulfur Dioxide National Ambient Air Quality Standard. On August 1, 2015, the EPA published the Data Requirements Rule for the 2010 1-Hour Sulfur Dioxide (SO2) Primary National Ambient Air Quality Standard (NAAQS). Hawaiian Electric is working with the DOH to gather data the EPA requires through the installation and operation of two new 1-hour SO2 air quality monitoring stations on the island of Oahu. This data will be integrated into the DOH’s statewide monitoring network and will assist the State’s development of its strategy to maintain the NAAQS and comply with the new 1-Hour SO2 Rule in its State Implementation Plan. The two new 1-hour SO2 air quality monitoring stations have been installed and were placed into operation prior to the EPA regulatory deadline of January 1, 2017.
Potential Clean Air Act Enforcement.  On July 1, 2013, Hawaii Electric Light and Maui Electric received a letter from the U.S. Department of Justice (DOJ) alleging potential violations of the Prevention of Significant Deterioration and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. In correspondence dated November 4, 2014, the DOJ also identified potential violations by Hawaiian Electric at its Kahe facility and proposed resolving the identified, potential violations by entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities continue to negotiate with the DOJ to resolve these issues, but are unable to estimate the amount or effect of a consent decree, if any, at this time.
Former Molokai Electric Company generation site.  In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since identified environmental impacts in the subsurface soil at the Site. Although Maui Electric never operated at the Site or owned the Site property, after discussions with the EPA and the DOH Maui Electric agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of environmental contamination. A 2011 assessment by a Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, residual fuel oils, and other subsurface contaminants. Maui Electric has a reserve balance of $3.6 million as of December 31, 2016 for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation.
Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is a Potentially Responsible Party responsible for cleanup of PCB contamination in sediment in the area offshore of the Waiau Power Plant as part of the Pearl Harbor Superfund Site. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to date to investigate the area. The Navy has completed a remedial investigation and a feasibility study (FS) for the remediation of contaminated sediment at several locations in Pearl Harbor and issued its Final FS Report on June 29, 2015. On February 2, 2016, the Navy released the Proposed Plan for Pearl Harbor Sediment Remediation and Hawaiian Electric submitted comments. The extent of the contamination, the appropriate remedial measures to address it and Hawaiian Electric’s potential responsibility for any associated costs have not been determined.
On March 23, 2015, Hawaiian Electric received a letter from the EPA requesting that Hawaiian Electric submit a work plan to assess potential sources and extent of PCB contamination onshore at the Waiau Power Plant. Hawaiian Electric submitted a sampling and analysis (SAP) work plan to the EPA and the DOH. Onshore sampling at the Waiau Power Plant was completed


in two phases in December 2015 and June 2016. The extent of the onshore contamination, the appropriate remedial measures to address it, and any associated costs have not yet been determined.
As of December 31, 2016, the reserve account balance recorded by Hawaiian Electric to address the PCB contamination was $4.1 million. The reserve represents the probable and reasonably estimable cost to complete the onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment. The final remediation costs will depend on the results of the onshore investigation and assessment of potential source control requirements, as well as the further investigation of contaminated sediment offshore from the Waiau Power Plant.
Global climate change and greenhouse gas emissions reduction.  National and international concerns about climate change and the contribution of greenhouse gas (GHG) emissions (including carbon dioxide emissions from the combustion of fossil fuels) to climate change have led to federal legislative and regulatory proposals and action by the State of Hawaii to reduce GHG emissions.
In July 2007, the State Legislature passed Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 (i.e., the final GHG rule), which went into effect on June 30, 2014. In general, Act 234 and the corresponding GHG rule require affected sources (that have the potential to emit GHGs in excess of established thresholds) to reduce their GHG emissions by 16% below 2010 emission levels by 2020. In accordance with the GHG rule, the Utilities submitted their Emissions Reduction Plan (EmRP) to the DOH on June 30, 2015, demonstrating how they will comply. The Utilities have committed to a 16% reduction in GHG emissions company-wide. Pursuant to the State’s GHG rule, the DOH will incorporate the proposed facility-specific GHG emission limits into each facility’s covered source permit based on the 2020 levels specified in Hawaiian Electric’s approved EmRP. The GHG rule also requires affected sources to pay an annual fee that is based on tons per year of GHG emissions starting on the effective date of the regulations. The fee for the Utilities is estimated to be approximately $0.5 million annually. The latest assessment of the proposed federal and final state GHG rules is that the continued growth in renewable power generation will significantly reduce the compliance costs and risk for the Utilities.
As part of a negotiated amendment to the Power Purchase Agreement between Hawaiian Electric and AES Hawaii, Hawaiian Electric planned to include the AES Hawaii facility on Oahu as a partner in the Utilities’ EmRP. The PUC denied the amendment to the Power Purchase Agreement in January 2017, however Hawaiian Electric and AES Hawaii continue to consider partnership options in the Utilities' EmRP. Additionally, if the proposed acquisition of the Hamakua Energy Partners (HEP) facility by Hawaii Electric Light is approved by the PUC, the GHG emissions from the HEP facility would need to be addressed in the Utilities’ EmRP. Hawaiian Electric will work with the DOH on the timing of the EmRP modifications to address these changes in the partnership, if necessary.
The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in Hawaiian Electric’s Campbell Industrial Park combustion turbine No. 1 (CIP CT-1), using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities will continue to pursue the use of cleaner fuels to replace, at least in part, petroleum. Management is unable to evaluate the ultimate impact on the Utilities’ operations of more comprehensive GHG regulations that might be promulgated; however, the various initiatives that the Utilities are pursuing are likely to provide a sound basis for appropriately managing the Utilities’ carbon footprint and thereby meet both state and federal GHG reduction goals.
While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise. This effect could potentially result in impacts to coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and result in increased flooding and storm damage due to heavy rainfall, increased rates of beach erosion, saltwater intrusion into freshwater aquifers and terrestrial ecosystems, and higher water tables in low-lying areas. The effects of climate change on the weather (for example, more intense or more frequent rain events, flooding, or hurricanes), sea levels, and freshwater availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.
Asset retirement obligations. AROs represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The Utilities’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.


Hawaiian Electric has recorded estimated AROs related to removing retired generating units at its Honolulu and Waiau power plants. These removal projects are ongoing, with activity and expenditures occurring in partial settlement of these liabilities. Both removal projects are expected to continue through 2017.
Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
(in thousands)2016 2015
Balance, January 1$26,848
 $29,419
Accretion expense10
 24
Liabilities incurred—
 —
Liabilities settled(1,269) (2,595)
Revisions in estimated cash flows—
 —
Balance, December 31$25,589
 $26,848
Decoupling.In 2010, the PUC issued an order approving decoupling, which was implemented by Hawaiian Electric on March 1, 2011, by Hawaii Electric Light on April 9, 2012 and by Maui Electric on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a rate adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. Under the decoupling tariff approved in 2011, the annual RAM is accrued and billed from June 1 of each year through May 31 of the following year.
As part of a January 2013 Settlement Agreement with the Consumer Advocate, which was approved by the PUC, for RAM years 2014 - 2016, Hawaiian Electric was allowed to record RAM revenue beginning on January 1 and to bill such amounts from June 1 of the applicable year through May 31 of the following year (current accrual method). After 2016, the RAM provisions approved in 2011 again apply to Hawaiian Electric. Applying the RAM provisions approved in 2011 again for Hawaiian Electric, is equivalent to a reduction of approximately $14 million in pro forma net earnings for Hawaiian Electric in 2017, assuming all other factors are unchanged.
On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers and are in the public interest. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. In October 2013, the PUC issued orders that bifurcated the proceeding (into Schedule A and Schedule B issues).
On February 7, 2014, the PUC issued a decision and order (D&O) on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O required:
A 90% limitation on the incremental current year Rate Base RAM Adjustment effective with the Utilities’ 2014 decoupling filing.
Effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case (ranging from 1.25% to 3.25%), instead of the 6% that had been previously approved.
On March 31, 2015, the PUC issued an Order (the March Order) related to the Schedule B portion of the proceeding to make certain further modifications to the decoupling mechanism, and to establish a briefing schedule with respect to certain issues in the proceeding. The March Order modified the RAM portion of the decoupling mechanism to be capped at the lesser of the RAM Revenue Adjustment as currently determined (adjusted to eliminate the 90% limitation on the current RAM Period Rate Base RAM adjustment that was ordered in the Schedule A portion of the proceeding) and a RAM Revenue Adjustment calculated based on the cumulative annual compounded increase in Gross Domestic Product Price Index (GDPPI) applied to the 2014 annualized target revenues (adjusted for certain items specified in the Order) (the RAM Cap). The 2014 annualized target revenues represent the target revenues from the last rate case, and RAM revenues, offset by earnings sharing credits, if any, allowed under the decoupling mechanism through the 2014 decoupling filing. The Utilities may apply to the PUC for approval of recovery of revenues for Major Projects (including related baseline projects grouped together for consideration as


Major Projects) through the RAM above the RAM cap or outside of the RAM through the Renewable Energy Infrastructure Program (REIP) surcharge or other adjustment mechanism. The RAM was amended on an interim basis pending the outcome of the PUC’s review of the Utilities’ Power Supply Improvement Plans. The triennial rate case cycle required under the decoupling mechanism continues to serve as the maximum period between the filing of general rate cases, and the amendments to the RAM do not limit or dilute the ordinary opportunities for the Utilities to seek rate relief according to conventional/traditional ratemaking procedures.
In making the modifications to the RAM Adjustment, the PUC stated the changes are designed to provide the PUC with control of and prior regulatory review over substantial additions to baseline projects between rate cases. The modifications do not deprive the Utilities of the opportunity to recover any prudently incurred expenditure or limit orderly recovery for necessary expanded capital programs.
The RBA, which is the sales decoupling component, was retained by the PUC in its March Order, and the PUC made no change in the authorized return on common equity. The PUC stated that performance-based ratemaking is not adopted at this time.
As required by the March Order, the parties filed initial and reply briefs related to the following issues: (1) whether and, if so, how the conventional performance incentive mechanisms proposed in this proceeding should be refined and implemented in this docket; (2) what are the appropriate steps, processes and timing for determining measures to improve the efficiency and effectiveness of the general rate case filing and review process; and (3) what are the appropriate steps, processes and timing to further consider the merits of the proposed changes to the ECAC identified in this proceeding. In identifying the issue on possible changes to the ECAC, the PUC stated that changes to the ECAC should be made with great care to avoid unintended consequences.
In accordance with the March Order, the Utilities and the Consumer Advocate filed on June 15, 2015, their Joint Proposed Modified REIP Framework/Standards and Guidelines regarding the eligibility of projects for cost recovery above the RAM Cap through the REIP surcharge. On the same date, the Utilities filed their proposed standards and guidelines on the eligibility of projects for cost recovery through the RAM above the RAM Cap. On June 30, 2015, the Consumer Advocate filed comments on this proposal, and the County of Hawaii filed comments on both the REIP and the RAM above the RAM Cap proposals.
The RAM Cap impacted the Utilities' recovery of capital investments as follows:
Hawaiian Electric's RAM revenues were limited to the RAM Cap in 2015 and 2016. In October 2015, Hawaiian Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $40.3 million and other associated costs for its Underground Cable Program and the 138kV Transmission and 46kV Sub-Transmission Structures Major Baseline Projects through the RAM above the 2015 RAM Cap. In April 2016, Hawaiian Electric modified its October 2015 application to reduce its request to recover revenue requirements associated with 2015 net plant additions from $40.3 million to $35.7 million as a result of the extension of bonus depreciation in 2015. In August 2016, the PUC dismissed Hawaiian Electric's October 2015 above the RAM Cap application because the application did not also request approval of the commitment of capital expenditures. Return on plant additions in excess of the amount provided by the RAM is being requested in the Hawaiian Electric 2017 test year rate case.
Maui Electric's RAM revenues were limited to the RAM Cap in 2015 and 2016. In October 2015, Maui Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $4.3 million and other associated costs for its transmission and distribution and generation plant reliability Major Baseline Project through the RAM above the 2015 RAM Cap. In March 2016, Maui Electric withdrew its October 2015 application. Maui Electric determined that the application was unnecessary because it could recover the revenue requirements associated with its 2015 net plant additions under the RAM Cap due to: (1) the extension of bonus depreciation in 2015 which resulted in an increased level of accumulated deferred income taxes as an offset to 2015 net plant additions; and (2) the recorded amount of net plant additions in 2015 was less than the estimate of net plant additions in the application. In anticipation of having plant additions in 2017 in excess of the amount provided for by the RAM. Maui Electric filed an application in August 2016, to recover the revenue requirements associated with 2017 plant additions for the Kaonoulu and Kuihelani substations in the total amount of $27.2 million and other associated costs through the RAM above the 2017 RAM Cap. In September 2016, the Consumer Advocate recommended the PUC reject the application, and Maui Electric subsequently objected to that recommendation. Maui Electric is awaiting the PUC's decision.
Hawaii Electric Light's RAM revenues were not limited to the RAM Cap in 2015 or 2016.


Annual decoupling filings.  On May 24, 2016, the PUC approved the annual decoupling filings for Hawaiian Electric and Maui Electric and, as amended on May 19, 2016, for Hawaii Electric Light, to go into effect on June 1, 2016. Annual incremental RAM adjusted revenues were $11.0 million, $2.3 million and $2.4 million for Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
Hawaiian Telcom. The Utilities each have separate agreements for the joint ownership and maintenance of utility poles with Hawaiian Telcom, Inc. (Hawaiian Telcom), the respective county or counties in which each utility operates and other third parties, such as the State of Hawaii. The agreements set forth various circumstances requiring pole removal/installation/replacement and the sharing of costs among the joint pole owners. The agreements allow for the cost of work done by one joint pole owner to be shared by the other joint pole owners based on the apportionment of costs in the agreements. The Utilities have maintained, replaced and installed the majority of the jointly-owned poles in each of the respective service territories, and have billed the other joint pole owners for their respective share of the costs. The counties and the State have been fully reimbursing the Utilities for their share of the costs. However, Hawaiian Telcom has been delinquent in reimbursing the Utilities for its share of the costs.
Hawaiian Electric has initiated a dispute resolution process to collect the unpaid amounts from Hawaiian Telcom is proceeding as specified by the joint pole agreement. For Hawaii Electric Light, the agreement does not specify an alternative dispute resolution process, and thus a complaint for payment was filed with the Circuit Court in June 2016. Maui Electric has not yet commenced any legal action to recover the delinquent amounts. As of December 31, 2016, total receivables under the joint pole agreement, including interest, from Hawaiian Telcom are $21.3 million ($14.2 million at Hawaiian Electric, $5.7 million at Hawaii Electric Light, and $1.4 million at Maui Electric). Management expects to prevail on these claims but has reserved for the accrued interest on the receivables.
April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively address certain key policy, resource planning and operational issues for the Utilities. The Utilities addressed these orders as follows:
Integrated Resource Planning. The PUC did not accept the Utilities’ Integrated Resource Plan and Action Plans submission, and, in lieu of an approved plan, has commenced other initiatives to enable resource planning. The PUC directed each of Hawaiian Electric and Maui Electric to file their respective Power Supply Improvement Plans (PSIPs), which they did in August 2014. The PUC also provided its inclinations on the future of Hawaii’s electric utilities in an exhibit to the order. The exhibit provides the PUC’s perspectives on the vision, business strategies and regulatory policy changes required to align the Utilities' business model with customers’ interests and the state’s public policy goals.
Reliability Standards Working Group. The PUC ordered the Utilities to take timely actions intended to lower energy costs, improve system reliability and address emerging challenges to integrate additional renewable energy. In addition to the PSIPs mentioned above, the PUC ordered certain filing requirements which include the following:
Distributed Generation Interconnection Plan - the Utilities’ Plan was filed in August 2014.
Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters - the Utilities’ Plan was filed in June 2014.
Action Plan for improving efficiencies in the interconnection requirements studies - the Utilities’ Plan was filed in May 2014.
The Utilities are to file monthly reports providing details about interconnection requirements studies.
Integrated interconnection queue for each distribution circuit for each island grid - the Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.
The PUC also stated it would be opening new dockets to address (1) reliability standards, (2) the technical, economic and policy issues associated with distributed energy resources (see “Distributed Energy Resources (DER) Investigative Proceeding” below) and (3) the Hawaii electricity reliability administrator, which is a third party position which the legislature has authorized the PUC to create by contract to provide support for the PUC in developing and periodically updating local grid reliability standards and procedures and interconnection requirements and overseeing grid access and operation.
Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop an integrated Demand Response (DR) Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. Subsequently, the Utilities submitted status updates and an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special adviser to guide, monitor, and review the Utility’s Plan design and implementation.


On December 30, 2015, the Utilities filed applications with the PUC (1) for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs. The Utilities filed an update to the DR Portfolio proceeding on February 10, 2017. In the DRMS proceeding, the Parties filed Statements of Position in December 2016 and are awaiting a PUC decision.
Review of PSIPs. Collectively, the PUC's April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities' strategies and plans going forward.
PSIPs for Hawaiian Electric, Maui Electric and Hawaii Electric Light were filed in August 2014. The PSIPs each include a tactical plan to transform how electric utility services will be offered to meet customer needs and produce higher levels of renewable energy. Each plan contains a diversified mix of technologies, including significant distributed and utility‑scale renewable resources, that is expected to result, on a consolidated basis, in over 65% of the Utilities’ energy being produced from renewable resources by 2030. Under these plans, the Utilities will support sustainable growth of private rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil to lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generators and lower full service residential customer bills in real dollars.
In November 2015, the PUC issued an order in the proceeding to review the PSIPs filed. The order provided observations and concerns on the PSIPs submitted. As required by the order, the Utilities submitted a Proposed Revision Plan in November 2015, which included a schedule and a work plan to supplement, amend and update the PSIPs in order to address the PUC’s observations and concerns, and submitted updated PSIPs on April 1, 2016. The parties and participants filed comments on the Utilities Proposed Revision Plan in January 2016. The updated PSIPs, filed on April 1, 2016, provide the Utilities’ assumptions, analyses and plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045.
As required by the PUC, on December 23, 2016, the Utilities filed their PSIP Update Report: December 2016. The updated plans describe greater and faster expansion of the Utilities’ renewable energy portfolio than in the plans filed in April 2016 and emphasize work that is in progress or planned over the next five years on each of the five islands the Utilities serve. The final step in the procedural schedule was the filing of the parties and participants’ respective statements of position in February 2017.

Distributed Energy Resources (DER) Investigative Proceeding. In March 2015, the PUC issued an order to address DER issues.
On June 29, 2015, the Utilities submitted their final Statement of Position in the DER proceeding, which included:
(1)new pricing provisions for future private rooftop photovoltaic (PV) systems,
(2)technical standards for advanced inverters,
(3)new options for customers including battery-equipped private rooftop PV systems,
(4)a pilot time-of-use rate,
(5)an improved method of calculating the amount of private rooftop PV that can be safely installed, and
(6)a streamlined and standardized PV application process.
On October 12, 2015, the PUC issued a D&O establishing DER reforms that: (1) promote rapid adoption of the next generation of solar PV and other distributed energy technologies; (2) encourage more competitive pricing of distributed energy resource systems; (3) lower overall energy supply costs for all customers; and (4) help to manage DER in terms of each island’s limited grid capacity.
The D&O approved a customer self-supply tariff and a customer grid supply tariff to govern customer generators connected to the Utilities’ systems. These tariffs replace the Net Energy Metering (NEM) program.
In June 2016, the PUC approved the Utilities Advanced Inverter Test Plan and the Utilities submitted the results of the testing to the PUC.
Pursuant to a PUC order, in October 2016, the Utilities submitted tariffs for a Residential Interim Time of Use program, which is limited to 2 years and 5,000 customers. The primary objective is to encourage more efficient use of the electric system and enable more cost-effective integration of renewable energy by shifting customer load from the system’s higher cost, peak demand period to the mid-day period when relatively inexpensive renewable resources are abundant.


The DER Phase 2 of this proceeding is focused on further developing competitive markets for distributed energy resources, including storage. On December 9, 2016, the PUC issued an Order, establishing the statement of issues and procedural schedule to govern Phase 2 of this proceeding. Technical track issues, including DER integration analyses and revisions to interconnection standards, will be addressed before the end of 2017. More complex market issues will be addressed in late 2018.
Derivative financial instrument. On January 5, 2016, Hawaiian Electric executed a window forward agreement to hedge the foreign currency risk associated with the anticipated purchase of engines from a European manufacturer to be included as part of the Schofield generating station. This window forward agreement has been designated as a cash flow hedge under which a single guaranteed exchange rate agreed upon on a certain date for future currency transactions scheduled to occur on specific dates with a “window” or range of plus/minus 30 days. Unrealized gains are recorded at fair value as assets in “other current assets,” and unrealized losses are recorded at fair value as liabilities in “other current liabilities,” both for the period they are outstanding. For this window forward agreement, the effective portion is reported as a component of accumulated other comprehensive income until reclassified into net income consistent with any gains or losses recognized on the engines. The generating station is expected to be placed in service in the first quarter of 2018.
December 31 2016
(dollars in thousands) Notional amount Fair value
Window forward contract $20,734
 $(743)
Consolidating financialinformation. Hawaiian Electric is not required to provide separate financial statements or other disclosures concerning Hawaii Electric Light and Maui Electric to holders of the 2004 Debentures issued by Hawaii Electric Light and Maui Electric to HECO Capital Trust III (Trust III) since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by Hawaiian Electric. Consolidating information is provided below for Hawaiian Electric and each of its subsidiaries for the periods ended and as of the dates indicated.
Hawaiian Electric also unconditionally guarantees Hawaii Electric Light’s and Maui Electric’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of Hawaii Electric Light and Maui Electric, (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder (see Hawaiian Electric and Subsidiaries' Consolidated Statements of Capitalization) and (c) relating to the trust preferred securities of Trust III (see Note 6). Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.


Consolidating statement of income
Year ended December 31, 2016
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$1,474,384
 311,385
 308,705
 —
 (106)[1] $2,094,368
Expenses            
Fuel oil305,359
 55,094
 94,251
 —
 —
  454,704
Purchased power431,009
 81,018
 50,713
 —
 —
  562,740
Other operation and maintenance273,176
 63,897
 68,460
 —
 —
  405,533
Depreciation126,086
 37,797
 23,178
 —
 —
  187,061
Taxes, other than income taxes141,615
 29,017
 29,230
 —
 —
  199,862
   Total expenses1,277,245
 266,823
 265,832
 —
 —
  1,809,900
Operating income197,139
 44,562
 42,873
 —
 (106)  284,468
Allowance for equity funds used during construction6,659
 765
 901
 —
 —
  8,325
Equity in earnings of subsidiaries42,391
 —
 —
 —
 (42,391)[2] —
Interest expense and other charges, net(45,839) (11,555) (9,536) —
 106
[1] (66,824)
Allowance for borrowed funds used during construction2,484
 294
 366
 —
 —
  3,144
Income before income taxes202,834
 34,066
 34,604
 —
 (42,391)  229,113
Income taxes59,437
 12,277
 13,087
 —
 —
  84,801
Net income143,397
 21,789
 21,517
 —
 (42,391)  144,312
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric143,397
 21,255
 21,136
 —
 (42,391)  143,397
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$142,317
 21,255
 21,136
 —
 (42,391)  $142,317

Consolidating statement of comprehensive income
Year ended December 31, 2016
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Net income for common stock$142,317
 21,255
 21,136
 —
 (42,391)  $142,317
Other comprehensive income (loss), net of taxes:            
Derivatives qualified as cash flow hedges:            
Effective portion of foreign currency hedge net unrealized losses arising during the period, net of tax benefits(281) —
 —
 —
 —
  (281)
Less: reclassification adjustment to net income, net of taxes(173) —
 —
 —
 —
  (173)
Retirement benefit plans: 
  
  
  
     
Net losses arising during the period, net of tax benefits(42,631) (5,141) (5,447) —
 10,588
[1] (42,631)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits13,254
 1,718
 1,549
 —
 (3,267)[1] 13,254
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes28,584
 3,269
 3,852
 —
 (7,121)[1] 28,584
Other comprehensive loss, net of tax benefits(1,247) (154) (46) —
 200
  (1,247)
Comprehensive income attributable to common shareholder$141,070
 21,101
 21,090
 —
 (42,191)  $141,070


Consolidating statement of income
Year ended December 31, 2015
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$1,644,181
 345,549
 345,517
 —
 (81)[1] $2,335,166
Expenses            
Fuel oil458,069
 71,851
 124,680
 —
 —
  654,600
Purchased power440,983
 97,503
 55,610
 —
 —
  594,096
Other operation and maintenance284,583
 63,098
 65,408
 —
 —
  413,089
Depreciation117,682
 37,250
 22,448
 —
 —
  177,380
Taxes, other than income taxes156,871
 32,312
 32,702
 —
 —
  221,885
   Total expenses1,458,188
 302,014
 300,848
 —
 —
  2,061,050
Operating income185,993
 43,535
 44,669
 —
 (81)  274,116
Allowance for equity funds used
   during construction
5,641
 604
 683
 —
 —
  6,928
Equity in earnings of subsidiaries42,920
 —
 —
 —
 (42,920)[2] —
Interest expense and other charges, net(45,899) (10,773) (9,779)   81
[1] (66,370)
Allowance for borrowed funds used during construction1,967
 215
 275
 —
 —
  2,457
Income before income taxes190,622
 33,581
 35,848
 —
 (42,920)  217,131
Income taxes53,828
 12,292
 13,302
 —
 —
  79,422
Net income136,794
 21,289
 22,546
 —
 (42,920)  137,709
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric136,794
 20,755
 22,165
 —
 (42,920)  136,794
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$135,714
 20,755
 22,165
 —
 (42,920)  $135,714

Consolidating statement of comprehensive income
Year ended December 31, 2015
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Net income for common stock$135,714
 20,755
 22,165
 —
 (42,920)  $135,714
Other comprehensive income (loss), net of taxes:            
Retirement benefit plans: 
  
  
  
  
   
Net gains (losses) arising during the period, net of taxes5,638
 (2,710) (1,352) —
 4,062
[1] 5,638
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits20,381
 2,728
 2,503
 —
 (5,231)[1] 20,381
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes(25,139) 104
 (1,107) —
 1,003
[1] (25,139)
Other comprehensive income, net of taxes880
 122
 44
 —
 (166)  880
Comprehensive income attributable to common shareholder$136,594
 20,877
 22,209
 —
 (43,086)  $136,594


Consolidating statement of income
Year ended December 31, 2014
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$2,142,245
 422,200
 422,965
 —
 (87)[1] $2,987,323
Expenses            
Fuel oil821,246
 117,215
 193,224
 —
 —
  1,131,685
Purchased power537,821
 123,226
 60,961
 —
 —
  722,008
Other operation and maintenance283,532
 65,471
 61,609
 —
 —
  410,612
Depreciation109,204
 35,904
 21,279
 —
 —
  166,387
Taxes, other than income taxes201,426
 39,521
 39,916
 —
 —
  280,863
   Total expenses1,953,229
 381,337
 376,989
 —
 —
  2,711,555
Operating income189,016
 40,863
 45,976
 —
 (87)  275,768
Allowance for equity funds used
   during construction
6,085
 472
 214
 —
 —
  6,771
Equity in earnings of subsidiaries40,964
 —
 —
 —
 (40,964)[2] —
Interest expense and other charges, net(44,041) (11,030) (9,773) —
 87
[1] (64,757)
Allowance for borrowed funds used during construction2,306
 182
 91
 —
 —
  2,579
Income before income taxes194,330
 30,487
 36,508
 —
 (40,964)  220,361
Income taxes55,609
 11,264
 13,852
 —
 —
  80,725
Net income138,721
 19,223
 22,656
 —
 (40,964)  139,636
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric138,721
 18,689
 22,275
 —
 (40,964)  138,721
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$137,641
 18,689
 22,275
 —
 (40,964)  $137,641
Consolidating statement of comprehensive income (loss)
Year ended December 31, 2014
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Net income for common stock$137,641
 18,689
 22,275
 —
 (40,964)  $137,641
Other comprehensive income (loss), net of taxes:            
Retirement benefit plans: 
  
  
  
  
   
Net losses arising during the period, net of tax benefits(218,608) (28,725) (29,352) —
 58,077
[1] (218,608)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits10,212
 1,270
 1,090
 —
 (2,360)[1] 10,212
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits207,833
 27,437
 28,257
 —
 (55,694)[1] 207,833
Other comprehensive loss, net of tax benefits(563) (18) (5) —
 23
  (563)
Comprehensive income attributable to common shareholder$137,078
 18,671
 22,270
 —
 (40,941)  $137,078



Consolidating balance sheet
December 31, 2016
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Assets 
  
  
  
  
   
Property, plant and equipment            
Utility property, plant and equipment 
  
  
  
  
   
Land$43,956
 6,181
 3,016
 —
 —
  $53,153
Plant and equipment4,241,060
 1,255,185
 1,109,487
 —
 —
  6,605,732
Less accumulated depreciation(1,382,972) (507,666) (478,644) —
 —
  (2,369,282)
Construction in progress180,194
 12,510
 19,038
 —
 —
  211,742
Utility property, plant and equipment, net3,082,238
 766,210
 652,897
 —
 —
  4,501,345
Nonutility property, plant and equipment, less accumulated depreciation5,760
 115
 1,532
 —
 —
  7,407
Total property, plant and equipment, net3,087,998
 766,325
 654,429
 —
 —
  4,508,752
Investment in wholly-owned subsidiaries, at equity550,946
 —
 —
 —
 (550,946)[2] —
Current assets 
  
  
  
  
   
Cash and equivalents61,388
 10,749
 2,048
 101
 —
  74,286
Advances to affiliates—
 3,500
 10,000
 —
 (13,500)[1] —
Customer accounts receivable, net86,373
 20,055
 17,260
 —
 —
  123,688
Accrued unbilled revenues, net65,821
 13,564
 12,308
 —
 —
  91,693
Other accounts receivable, net7,652
 2,445
 1,416
 —
 (6,280)[1] 5,233
Fuel oil stock, at average cost47,239
 8,229
 10,962
 —
 —
  66,430
Materials and supplies, at average cost29,928
 7,380
 16,371
 —
 —
  53,679
Prepayments and other16,502
 5,352
 2,179
 —
 (933)[3] 23,100
Regulatory assets60,185
 3,483
 2,364
 —
 —
  66,032
Total current assets375,088
 74,757
 74,908
 101
 (20,713)  504,141
Other long-term assets 
  
  
  
  
   
Regulatory assets662,232
 120,863
 108,324
 —
 —
  891,419
Unamortized debt expense151
 23
 34
 —
 —
  208
Other43,743
 13,573
 13,592
 —
 —
  70,908
Total other long-term assets706,126
 134,459
 121,950
 —
 —
  962,535
Total assets$4,720,158
 975,541
 851,287
 101
 (571,659)  $5,975,428
Capitalization and liabilities 
  
  
  
  
   
Capitalization 
  
  
  
  
   
Common stock equity$1,799,787
 291,291
 259,554
 101
 (550,946)[2] $1,799,787
Cumulative preferred stock–not subject to mandatory redemption22,293
 7,000
 5,000
 —
 —
  34,293
Long-term debt, net915,437
 213,703
 190,120
 —
 —
  1,319,260
Total capitalization2,737,517
 511,994
 454,674
 101
 (550,946)  3,153,340
Current liabilities 
  
  
  
  
   
Short-term borrowings-affiliate13,500
 —
 —
 —
 (13,500)[1] —
Accounts payable86,369
 18,126
 13,319
 —
 —
  117,814
Interest and preferred dividends payable15,761
 4,206
 2,882
 —
 (11)[1] 22,838
Taxes accrued120,176
 28,100
 25,387
 —
 (933)[3] 172,730
Regulatory liabilities—
 2,219
 1,543
 —
 —
  3,762
Other41,352
 7,637
 12,501
 —
 (6,269)[1] 55,221
Total current liabilities277,158
 60,288
 55,632
 —
 (20,713)  372,365
Deferred credits and other liabilities 
  
  
  
  
   
Deferred income taxes524,433
 108,052
 100,911
 —
 263
[1] 733,659
Regulatory liabilities281,112
 93,974
 31,845
 —
 —
  406,931
Unamortized tax credits57,844
 15,994
 15,123
 —
 —
  88,961
Defined benefit pension and other postretirement benefit plans liability444,458
 75,005
 80,263
 —
 —
  599,726
Other49,191
 13,024
 14,969
 —
 (263)[1] 76,921
Total deferred credits and other liabilities1,357,038
 306,049
 243,111
 —
 —
  1,906,198
Contributions in aid of construction348,445
 97,210
 97,870
 —
 —
  543,525
Total capitalization and liabilities$4,720,158
 975,541
 851,287
 101
 (571,659)  $5,975,428


Consolidating balance sheet
December 31, 2015
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Assets 
  
  
  
  
   
Property, plant and equipment            
Utility property, plant and equipment 
  
  
  
  
   
Land$43,557
 6,219
 3,016
 —
 —
  $52,792
Plant and equipment4,026,079
 1,212,195
 1,077,424
 —
 —
  6,315,698
Less accumulated depreciation(1,316,467) (486,028) (463,509) —
 —
  (2,266,004)
Construction in progress147,979
 11,455
 15,875
 —
 —
  175,309
Utility property, plant and equipment, net2,901,148
 743,841
 632,806
 —
 —
  4,277,795
Nonutility property, plant and equipment, less accumulated depreciation5,659
 82
 1,531
 —
 —
  7,272
Total property, plant and equipment, net2,906,807
 743,923
 634,337
 —
 —
  4,285,067
Investment in wholly-owned subsidiaries, at equity556,528
 —
 —
 —
 (556,528)[2] —
Current assets 
  
  
  
  
   
Cash and equivalents16,281
 2,682
 5,385
 101
 —
  24,449
Advances to affiliates—
 15,500
 7,500
 —
 (23,000)[1] —
Customer accounts receivable, net93,515
 20,508
 18,755
 —
 —
  132,778
Accrued unbilled revenues, net60,080
 12,531
 11,898
 —
 —
  84,509
Other accounts receivable, net16,421
 1,275
 1,674
 —
 (8,962)[1] 10,408
Fuel oil stock, at average cost49,455
 8,310
 13,451
 —
 —
  71,216
Materials and supplies, at average cost30,921
 6,865
 16,643
 —
 —
  54,429
Prepayments and other25,505
 9,091
 2,295
 —
 (251)[1], [3] 36,640
Regulatory assets63,615
 4,501
 4,115
 —
 —
  72,231
Total current assets355,793
 81,263
 81,716
 101
 (32,213)  486,660
Other long-term assets 
  
  
  
  
   
Regulatory assets608,957
 114,562
 100,981
 —
 —
  824,500
Unamortized debt expense359
 74
 64
 —
 —
  497
Other47,731
 14,693
 13,062
 —
 —
  75,486
Total other long-term assets657,047
 129,329
 114,107
 —
 —
  900,483
Total assets$4,476,175
 954,515
 830,160
 101
 (588,741)  $5,672,210
Capitalization and liabilities 
  
  
  
  
   
Capitalization 
  
  
  
  
   
Common stock equity$1,728,325
 292,702
 263,725
 101
 (556,528)[2] $1,728,325
Cumulative preferred stock–not subject to mandatory redemption22,293
 7,000
 5,000
 —
 —
  34,293
Long-term debt, net875,163
 213,580
 189,959
 —
 —
  1,278,702
Total capitalization2,625,781
 513,282
 458,684
 101
 (556,528)  3,041,320
Current liabilities 
  
  
  
  
   
Short-term borrowings-affiliate23,000
 —
 —
 —
 (23,000)[1] —
Accounts payable84,631
 17,702
 12,513
 —
 —
  114,846
Interest and preferred dividends payable15,747
 4,255
 3,113
 —
 (4)[1] 23,111
Taxes accrued131,668
 30,342
 29,325
 —
 (251)[3] 191,084
Regulatory liabilities—
 1,030
 1,174
 —
 —
  2,204
Other41,083
 8,760
 13,194
 —
 (8,958)[1] 54,079
Total current liabilities296,129
 62,089
 59,319
 —
 (32,213)  385,324
Deferred credits and other liabilities 
  
  
  
  
   
Deferred income taxes466,133
 100,681
 87,706
 —
 286
[1] 654,806
Regulatory liabilities254,033
 84,623
 30,683
 —
 —
  369,339
Unamortized tax credits54,078
 15,406
 14,730
 —
 —
  84,214
Defined benefit pension and other postretirement benefit plans liability409,021
 69,893
 74,060
 —
 —
  552,974
Other51,273
 13,243
 13,916
 —
 (286)[1] 78,146
Total deferred credits and other liabilities1,234,538
 283,846
 221,095
 —
 —
  1,739,479
Contributions in aid of construction319,727
 95,298
 91,062
 —
 —
  506,087
Total capitalization and liabilities$4,476,175
 954,515
 830,160
 101
 (588,741)  $5,672,210


Consolidating statements of changes in common stock equity
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Balance, December 31, 2013$1,593,564
 274,802
 248,771
 101
 (523,674) $1,593,564
Net income for common stock137,641
 18,689
 22,275
 —
 (40,964) 137,641
Other comprehensive loss, net of tax benefits(563) (18) (5) —
 23
 (563)
Issuance of common stock, net of expenses39,994
 —
 —
 —
 —
 39,994
Common stock dividends(88,492) (11,627) (14,349) —
 25,976
 (88,492)
Balance, December 31, 2014$1,682,144
 281,846
 256,692
 101
 (538,639) $1,682,144
Net income for common stock135,714
 20,755
 22,165
 —
 (42,920) 135,714
Other comprehensive income, net of taxes880
 122
 44
 —
 (166) 880
Common stock issuance expenses(8) —
 (1) —
 1
 (8)
Common stock dividends(90,405) (10,021) (15,175) —
 25,196
 (90,405)
Balance, December 31, 2015$1,728,325
 292,702
 263,725
 101
 (556,528) $1,728,325
Net income for common stock142,317
 21,255
 21,136
 —
 (42,391) 142,317
Other comprehensive loss, net of tax benefits(1,247) (154) (46) —
 200
 (1,247)
Issuance of common stock, net of expenses23,991
 (5) —
 —
 5
 23,991
Common stock dividends(93,599) (22,507) (25,261) —
 47,768
 (93,599)
Balance, December 31, 2016$1,799,787
 291,291
 259,554
 101
 (550,946) $1,799,787


Consolidating statement of cash flows
Year ended December 31, 2016
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$143,397
 21,789
 21,517
 —
 (42,391)[2] $144,312
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
Equity in earnings(42,491) —
 —
 —
 42,391
[2] (100)
Common stock dividends received from subsidiaries47,843
 —
 —
 —
 (47,768)[2] 75
Depreciation of property, plant and equipment126,086
 37,797
 23,178
 —
 —
  187,061
Other amortization2,979
 1,817
 2,139
 —
 —
  6,935
Deferred income taxes54,721
 7,027
 12,661
 —
 (23)[1] 74,386
Income tax credits, net177
 60
 (6) —
 —
  231
Allowance for equity funds used during construction(6,659) (765) (901) —
 —
  (8,325)
Other(2,694) (810) (427) —
 —
  (3,931)
Changes in assets and liabilities:   
      
   
Decrease (increase) in accounts receivable10,175
 (718) 1,776
 —
 (2,682)[1] 8,551
Increase in accrued unbilled revenues(5,741) (1,033) (410) —
 —
  (7,184)
Decrease in fuel oil stock2,216
 81
 2,489
 —
 —
  4,786
Decrease (increase) in materials and supplies993
 (515) 272
 —
 —
  750
Increase in regulatory assets(16,161) (1,243) (869) —
 —
  (18,273)
Increase (decrease) in accounts payable(10,247) 768
 (1,135) —
 —
  (10,614)
Change in prepaid and accrued income taxes, tax credits and revenue taxes2,933
 2,645
 (3,478) —
 23
[1] 2,123
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability599
 53
 (168) —
 —
  484
Change in other assets and liabilities(11,682) (78) (2,272) —
 2,682
[1] (11,350)
Net cash provided by operating activities296,444
 66,875
 54,366
 —
 (47,768)  369,917
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(236,425) (51,344) (32,668) —
 —
  (320,437)
Contributions in aid of construction23,611
 3,412
 3,077
 —
 —
  30,100
Advances from affiliates—
 12,000
 (2,500) —
 (9,500)[1] —
Other1,932
 175
 31
 —
 —
  2,138
Net cash used in investing activities(210,882) (35,757) (32,060) —
 (9,500)  (288,199)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(93,599) (22,507) (25,261) —
 47,768
[2] (93,599)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from issuance of common stock24,000
 —
 —
 —
 —
  24,000
Proceeds from issuance of long-term debt40,000
 —
 —
 —
 —
  40,000
Net decrease in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less(9,500) —
 —
 —
 9,500
[1] —
Other(276) (10) (1) —
 —
  (287)
Net cash used in financing activities(40,455) (23,051) (25,643) —
 57,268
  (31,881)
Net increase (decrease) in cash and cash equivalents45,107
 8,067
 (3,337) —
 —
  49,837
Cash and cash equivalents, January 116,281
 2,682
 5,385
 101
 —
  24,449
Cash and cash equivalents, December 31$61,388
 10,749
 2,048
 101
 —
  $74,286



Consolidating statement of cash flows
Year ended December 31, 2015
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$136,794
 21,289
 22,546
 —
 (42,920)[2] $137,709
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
    Equity in earnings(43,020) —
 —
 —
 42,920
[2] (100)
Common stock dividends received from subsidiaries25,296
 —
 —
 —
 (25,196)[2] 100
Depreciation of property, plant and equipment117,682
 37,250
 22,448
 —
 —
  177,380
Other amortization4,678
 2,124
 2,137
 —
 —
  8,939
Impairment of utility assets4,573
 724
 724
 —
 —
  6,021
Other4,403
 (2,476) (255) —
 —
  1,672
Deferred income taxes53,338
 8,295
 13,707
 —
 286
[1] 75,626
Income tax credits, net4,284
 527
 33
 —
 —
  4,844
Allowance for equity funds used during construction(5,641) (604) (683) —
 —
  (6,928)
Changes in assets and liabilities:   
      
   
Decrease in accounts receivable15,652
 3,420
 4,617
 —
 38
[1] 23,727
Decrease in accrued unbilled revenues29,733
 4,593
 5,767
 —
 —
  40,093
Decrease in fuel oil stock25,060
 5,490
 4,280
 —
 —
  34,830
Decrease (increase) in materials and supplies2,233
 (201) 789
 —
 —
  2,821
Decrease (increase) in regulatory assets(20,356) (3,930) 104
 —
 —
  (24,182)
Decrease in accounts payable(42,751) (6,425) (5,379) —
 —
  (54,555)
Change in prepaid and accrued income taxes, tax credits and revenue taxes(50,382) (6,166) (6,548) —
 —
  (63,096)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability870
 (161) 416
 —
 —
  1,125
Change in other assets and liabilities(24,197) (3,545) (4,554) —
 (324)[1] (32,620)
Net cash provided by operating activities238,249
 60,204
 60,149
 —
 (25,196)  333,406
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(267,621) (48,645) (33,895) —
 —
  (350,161)
Contributions in aid of construction35,955
 2,160
 2,124
 —
 —
  40,239
Advances from (to) affiliates16,100
 (15,500) (7,500) —
 6,900
[1] —
Other924
 132
 84
 —
 —
  1,140
Net cash used in investing activities(214,642) (61,853) (39,187) —
 6,900
  (308,782)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(90,405) (10,021) (15,175) —
 25,196
[2] (90,405)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from the issuance of long-term debt50,000
 25,000
 5,000
 —
 —
  80,000
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less23,000
 (10,500) (5,600) —
 (6,900)[1] —
Other(1,257) (226) (54) —
 —
  (1,537)
Net cash used in financing activities(19,742) 3,719
 (16,210) —
 18,296
  (13,937)
Net increase in cash and cash equivalents3,865
 2,070
 4,752
 —
 —
  10,687
Cash and cash equivalents, January 112,416
 612
 633
 101
 —
  13,762
Cash and cash equivalents, December 31$16,281
 2,682
 5,385
 101
 —
  $24,449



Consolidating statement of cash flows
Year ended December 31, 2014
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating
adjustments		  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$138,721
 19,223
 22,656
 —
 (40,964)[2] $139,636
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
    Equity in earnings(41,064) —
 —
 —
 40,964
[2] (100)
Common stock dividends received from subsidiaries26,076
 —
 —
 —
 (25,976)[2] 100
Depreciation of property, plant and equipment109,204
 35,904
 21,279
 —
 —
  166,387
Other amortization4,535
 2,926
 2,436
 —
 —
  9,897
Impairment of assets1,866
 —
 —
 —
 —
  1,866
Other758
 —
 —
 —
 —
  758
Deferred income taxes56,901
 12,083
 13,963
 —
 —
  82,947
Income tax credits, net4,998
 680
 384
 —
 —
  6,062
Allowance for equity funds used during construction(6,085) (472) (214) —
 —
  (6,771)
Change in cash overdraft—
 —
 (1,038) —
 —
  (1,038)
Changes in assets and liabilities: 
  
      
   
Decrease in accounts receivable16,213
 7,150
 3,483
 —
 (103)[1] 26,743
Decrease in accrued unbilled revenues4,680
 1,174
 896
 —
 —
  6,750
Decrease in fuel oil stock25,098
 378
 2,565
 —
 —
  28,041
Decrease (increase) in materials and supplies2,357
 219
 (2,648) —
 —
  (72)
Decrease (increase) in regulatory assets(14,620) (3,357) 977
 —
 —
  (17,000)
Decrease in accounts payable(56,044) (6,645) (2,838) —
 —
  (65,527)
Change in prepaid and accrued income taxes, tax credits and revenue taxes(4,166) (3,251) 3,381
 —
 —
  (4,036)
Decrease in defined benefit pension and other postretirement benefit plans liability(562) —
 (399) —
 —
  (961)
Change in other assets and liabilities(50,180) (12,907) (3,703) —
 103
[1] (66,687)
Net cash provided by operating activities218,686
 53,105
 61,180
 —
 (25,976)  306,995
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(237,970) (49,895) (48,814) —
 —
  (336,679)
Contributions in aid of construction30,021
 7,695
 4,090
 —
 —
  41,806
Advances from (to) affiliates(9,261) 1,000
 —
 —
 8,261
[1] —
Other604
 492
 68
 —
 —
  1,164
Net cash used in investing activities(216,606) (40,708) (44,656) —
 8,261
  (293,709)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(88,492) (11,627) (14,349) —
 25,976
[2] (88,492)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from the issuance of common stock40,000
 —
 —
 —
 —
  40,000
Repayment of long-term debt—
 (11,400) —
 —
 —
  (11,400)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less(1,000) 10,500
 (1,239) —
 (8,261)[1] —
Other(337) (50) (75) —
 —
  (462)
Net cash used in financing activities(50,909) (13,111) (16,044) —
 17,715
  (62,349)
Net increase (decrease) in cash and cash equivalents(48,829) (714) 480
 —
 —
  (49,063)
Cash and cash equivalents, January 161,245
 1,326
 153
 101
 —
  62,825
Cash and cash equivalents, December 31$12,416
 612
 633
 101
 —
  $13,762

Explanation of consolidating adjustments on consolidating schedules:
[1]Eliminations of intercompany receivables and payables and other intercompany transactions.
[2]Elimination of investment in subsidiaries, carried at equity.
[3]Reclassification of accrued income taxes for financial statement presentation.


5 · Bank segment (HEI only)
Selected financial information
American Savings Bank, F.S.B.
Statements of Income Data
Years ended December 312016
 2015
 2014
(in thousands) 
  
  
Interest and dividend income 
  
  
Interest and fees on loans$199,774
 $184,782
 $179,341
Interest and dividends on investment securities19,184
 15,120
 11,945
Total interest and dividend income218,958
 199,902
 191,286
Interest expense 
  
  
Interest on deposit liabilities7,167
 5,348
 5,077
Interest on other borrowings5,588
 5,978
 5,731
Total interest expense12,755
 11,326
 10,808
Net interest income206,203
 188,576
 180,478
Provision for loan losses16,763
 6,275
 6,126
Net interest income after provision for loan losses189,440
 182,301
 174,352
Noninterest income 
  
  
Fees from other financial services22,384
 22,211
 21,747
Fee income on deposit liabilities21,759
 22,368
 19,249
Fee income on other financial products8,707
 8,094
 8,131
Bank-owned life insurance4,637
 4,078
 3,949
Mortgage banking income6,625
 6,330
 2,913
Gains on sale of investment securities598
 —
 2,847
Other income, net2,256
 4,750
 2,375
Total noninterest income66,966
 67,831
 61,211
Noninterest expense 
  
  
Compensation and employee benefits90,117
 90,518
 79,885
Occupancy16,321
 16,365
 17,197
Data processing13,030
 12,103
 11,690
Services11,054
 10,204
 10,269
Equipment6,938
 6,577
 6,564
Office supplies, printing and postage6,075
 5,749
 6,089
Marketing3,489
 3,463
 3,999
FDIC insurance3,543
 3,274
 3,261
Other expense18,487
 18,067
 17,314
Total noninterest expense169,054
 166,320
 156,268
Income before income taxes87,352
 83,812
 79,295
Income taxes30,073
 29,082
 27,994
Net income$57,279
 $54,730
 $51,301


Statements of Comprehensive Income
Years ended December 312016
 2015
 2014
(in thousands) 
  
  
Net income$57,279
 $54,730
 $51,301
Other comprehensive income (loss), net of taxes: 
  
  
Net unrealized gains (losses) on available-for sale investment securities: 
  
  
Net unrealized gains (losses) on available-for sale investment securities arising during the period, net of (taxes) benefits of $3,763, $1,541 and $(3,856) for 2016, 2015 and 2014, respectively(5,699) (2,334) 5,840
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $238, nil and $1,132 for 2016, 2015 and 2014, respectively(360) —
 (1,715)
Retirement benefit plans: 
  
  
Net gains (losses) arising during the period, net of (taxes) benefits of nil, $(59) and $6,164 for 2016, 2015 and 2014, respectively—
 90
 (9,336)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $566, $1,011 and $561 for 2016, 2015 and 2014, respectively857
 1,531
 850
Other comprehensive income (loss), net of taxes(5,202) (713) (4,361)
Comprehensive income$52,077
 $54,017
 $46,940
Balance Sheets Data
December 31 2016
 2015
(in thousands)  
  
Assets  
  
Cash and due from banks $137,083
 $127,201
Interest-bearing deposits 52,128
 93,680
Restricted cash 1,764
 —
Available-for-sale investment securities, at fair value 1,105,182
 820,648
Stock in Federal Home Loan Bank, at cost 11,218
 10,678
Loans receivable held for investment 4,738,693
 4,615,819
Allowance for loan losses (55,533) (50,038)
Net loans 4,683,160
 4,565,781
Loans held for sale, at lower of cost or fair value 18,817
 4,631
Other 329,815
 309,946
Goodwill 82,190
 82,190
Total assets $6,421,357
 $6,014,755
Liabilities and shareholder’s equity  
  
Deposit liabilities–noninterest-bearing $1,639,051
 $1,520,374
Deposit liabilities–interest-bearing 3,909,878
 3,504,880
Other borrowings 192,618
 328,582
Other 101,635
 101,029
Total liabilities 5,843,182
 5,454,865
Commitments and contingencies 

 

Common stock 1
 1
Additional paid in capital 342,704
 340,496
Retained earnings 257,943
 236,664
Accumulated other comprehensive loss, net of tax benefits    
     Net unrealized losses on securities$(7,931) $(1,872) 
     Retirement benefit plans(14,542)(22,473)(15,399)(17,271)
Total shareholder’s equity 578,175
 559,890
Total liabilities and shareholder’s equity $6,421,357
 $6,014,755




December 31 2016
 2015
(in thousands)  
  
Other assets  
  
Bank-owned life insurance $143,197
 $138,139
Premises and equipment, net 90,570
 88,077
Prepaid expenses 3,348
 3,550
Accrued interest receivable 16,824
 15,192
Mortgage-servicing rights 9,373
 8,884
Low-income housing equity investments 47,081
 37,793
Real estate acquired in settlement of loans, net 1,189
 1,030
Other 18,233
 17,281
  $329,815
 $309,946
Other liabilities  
  
Accrued expenses $36,754
 $30,705
Federal and state income taxes payable 4,728
 13,448
Cashier’s checks 24,156
 21,768
Advance payments by borrowers 10,335
 10,311
Other 25,662
 24,797
  $101,635
 $101,029
Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.
Available-for-sale investment securities. The major components of investment securities were as follows:
         Gross unrealized losses
   Gross Gross Estimated Less than 12 months 12 months or longer
(dollars in thousands)
Amortized
cost
 
unrealized
gains
 
unrealized
losses
 
fair
value
 Number of issues Fair value Amount Number of issues Fair value Amount
December 31, 2016                   
Available-for-sale 
  
  
  
    
  
    
  
U.S. Treasury and federal agency obligations$193,515
 $920
 $(2,154) $192,281
 18 $123,475
 $(2,010) 1 $3,485
 $(144)
Mortgage-related securities- FNMA, FHLMC and GNMA909,408
 1,742
 (13,676) 897,474
 88 709,655
 (12,143) 13 47,485
 (1,533)
Mortgage revenue bond15,427
 —
 —
 15,427
 — —
 —
 — —
 —
 $1,118,350
 $2,662
 $(15,830) $1,105,182
 106 $833,130
 $(14,153) 14 $50,970
 $(1,677)
December 31, 2015                   
Available-for-sale 
  
  
  
    
  
    
  
U.S. Treasury and federal agency obligations$213,234
 $1,025
 $(1,300) $212,959
 13 $83,053
 $(866) 3 $17,378
 $(434)
Mortgage-related securities- FNMA, FHLMC and GNMA610,522
 3,564
 (6,397) 607,689
 38 305,785
 (2,866) 25 125,817
 (3,531)
 $823,756
 $4,589
 $(7,697) $820,648
 51 $388,838
 $(3,732) 28 $143,195
 $(3,965)
ASB does not believe that the investment securities that were in an unrealized loss position as of December 31, 2016, represent an other-than-temporary impairment. Total gross unrealized losses were primarily attributable to rising interest rates relative to when the investment securities were purchased and not due to the credit quality of the investment securities. The contractual cash flows of the U.S. Treasury, federal agency obligations and mortgage-related securities are backed by the full faith and credit guaranty of the United States government or an agency of the government. ASB does not intend to sell the securities before the recovery of its amortized cost basis and there have been no adverse changes in the timing of the contractual cash flows for the securities. ASB did not recognize OTTI for 2016, 2015 and 2014.
U.S. Treasury, federal agency obligations, and the mortgage revenue bond have contractual terms to maturity. Mortgage-related securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages.


The contractual maturities of available-for-sale investment securities were as follows:
 Amortized
 Fair
December 31, 2016Cost
 value
(in thousands)   
Due in one year or less$9,979
 $10,001
Due after one year through five years77,179
 77,126
Due after five years through ten years81,411
 81,083
Due after ten years40,373
 39,498
 208,942
 207,708
Mortgage-related securities-FNMA,FHLMC and GNMA909,408
 897,474
Total available-for-sale securities$1,118,350
 $1,105,182
The proceeds, gross gains and losses from sales of available-for-sale investment securities were as follows:
Years ended December 312016
 2015
 2014
(in millions)     
Proceeds$16.4
 $—
 $79.6
Gross gains0.6
 —
 2.8
Gross losses—
 —
 —
Interest income from taxable and non-taxable investment securities were as follows:
Years ended December 312016
 2015
 2014
(in thousands)     
Taxable$19,166
 $15,120
 $11,666
Non-taxable18
 —
 279
 $19,184
 $15,120
 $11,945
ASB pledged securities with a market value of approximately $277.1 million and $100.5 million as of December 31, 2016 and 2015, respectively, as collateral for public funds and other deposits, automated clearinghouse transactions with Bank of Hawaii, to-be-announced mortgage-backed securities settlements with JP Morgan, borrowing at the discount window of the Federal Reserve Bank of San Francisco, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2016 and 2015, securities with a carrying value of $114.9 million and $260.5 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.
Stock in FHLB.  As of December 31, 2016 and 2015, ASB’s stock in FHLB was carried at cost ($11.2 million and $10.7 million, respectively) because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and borrowing levels. In May 2015, the FHLB of Seattle and FHLB of Des Moines completed the merger of the two banks and began operating as the FHLB of Des Moines on June 1, 2015. With the merger, all of the ASB’s excess FHLB stock was repurchased. The FHLB repurchased a total of nil and $58.6 million of FHLB stock from ASB in 2016 and 2015, respectively. There was no other significant impact on ASB as a result of the merger.
Periodically and as conditions warrant, ASB reviews its investment in the stock of the FHLB for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2016, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2016 based on its evaluation of the underlying investment, including:
the net income and growth in retained earnings recorded by the FHLB in the first nine months of 2016;
compliance by the FHLB with all of its regulatory capital requirements and being classified “adequately capitalized” by the Federal Housing Finance Agency (Finance Agency);
being authorized by the Finance Agency to repurchase excess stock;
the impact of legislative and regulatory changes on institutions and, accordingly, on the customer base of the FHLB;
the liquidity position of the FHLB; and
ASB’s intent and assessment of whether it will more likely than not be required to sell the FHLB stock before recovery of its par value.


Future deterioration in the FHLB's financial position and/or negative developments in any of the factors considered in ASB's impairment evaluation above may result in future impairment losses.
Loans receivable.
The components of loans receivable were summarized as follows:
December 312016
 2015
(in thousands) 
  
Real estate: 
  
Residential 1-4 family$2,048,051
 $2,069,665
Commercial real estate800,395
 690,561
Home equity line of credit863,163
 846,294
Residential land18,889
 18,229
Commercial construction126,768
 100,796
Residential construction16,080
 14,089
Total real estate3,873,346
 3,739,634
Commercial692,051
 758,659
Consumer178,222
 123,775
Total loans4,743,619
 4,622,068
Less: Deferred fees and discounts(4,926) (6,249)
          Allowance for loan losses(55,533) (50,038)
Total loans, net$4,683,160
 $4,565,781
ASB's policy is to require private mortgage insurance on all real estate loans when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For non-owner occupied residential properties, the loan-to-value ratio may not exceed 80% of the lower of the appraised value or purchase price at origination. ASB is subject to the risk that the insurance company cannot satisfy the bank's claim on policies.
ASB services real estate loans for investors (principal balance of $1.2 billion, $1.5 billion and $1.4 billion as of December 31, 2016, 2015 and 2014, respectively), which are not included in the accompanying consolidated balance sheets data. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan servicing cost to expense as incurred.
As of December 31, 2016 and 2015, ASB had pledged loans with an amortized cost of approximately $2.4 billion and $2.3 billion, respectively, as collateral to secure advances from the FHLB.
As of December 31, 2016 and 2015, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board (FRB) Regulation O) of such individuals, was $22.9 million and $27.8 million, respectively. The $4.9 million decrease in such loans in 2016 was attributed to closed lines of credits and repayments of $4.9 million. As of December 31, 2016 and 2015, $19.0 million and $25.8 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms. Management believes these loans do not represent more than a normal risk of collection.
Allowance for loan losses.  As discussed in Note 1, ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio.


The allowance for loan losses (balances and changes) and financing receivables were as follows:
(in thousands)Residential 1-4 family Commercial
real estate		 Home equity
line of credit		 Residential land Commercial construction Residential construction Commercial Consumer Unallo- cated Total
December 31, 2016  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
Beginning balance$4,186
 $11,342
 $7,260
 $1,671
 $4,461
 $13
 $17,208
 $3,897
 $—
 $50,038
Charge-offs(639) —
 (112) (138) —
 —
 (5,943) (7,413) —
 (14,245)
Recoveries421
 —
 59
 461
 —
 —
 1,093
 943
 —
 2,977
Provision(1,095) 4,662
 (2,168) (256) 1,988
 (1) 4,260
 9,373
 —
 16,763
Ending balance$2,873
 $16,004
 $5,039
 $1,738
 $6,449
 $12
 $16,618
 $6,800
 $—
 $55,533
Ending balance: individually evaluated for impairment$1,352
 $80
 $215
 $789
 $—
 $—
 $1,641
 $6
 

 $4,083
Ending balance: collectively evaluated for impairment$1,521
 $15,924
 $4,824
 $949
 $6,449
 $12
 $14,977
 $6,794
 $—
 $51,450
Financing Receivables:  
  
  
  
  
  
  
  
  
Ending balance$2,048,051
 $800,395
 $863,163
 $18,889
 $126,768
 $16,080
 $692,051
 $178,222
 $—
 $4,743,619
Ending balance: individually evaluated for impairment$19,854
 $1,569
 $6,158
 $3,629
 $—
 $—
 $20,539
 $10
 $—
 $51,759
Ending balance: collectively evaluated for impairment$2,028,197
 $798,826
 $857,005
 $15,260
 $126,768
 $16,080
 $671,512
 $178,212
 $—
 $4,691,860
December 31, 2015  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
Beginning balance$4,662
 $8,954
 $6,982
 $1,875
 $5,471
 $28
 $14,017
 $3,629
 $—
 $45,618
Charge-offs(356) —
 (205) —
 —
 —
 (1,074) (4,791) —
 (6,426)
Recoveries226
 —
 80
 507
 —
 —
 2,773
 985
 —
 4,571
Provision(346) 2,388
 403
 (711) (1,010) (15) 1,492
 4,074
 

 6,275
Ending balance$4,186
 $11,342
 $7,260
 $1,671
 $4,461
 $13
 $17,208
 $3,897
 $—
 $50,038
Ending balance: individually evaluated for impairment$1,453
 $—
 $442
 $891
 $—
 $—
 $3,527
 $7
 

 $6,320
Ending balance: collectively evaluated for impairment$2,733
 $11,342
 $6,818
 $780
 $4,461
 $13
 $13,681
 $3,890
 $—
 $43,718
Financing Receivables:  
  
  
  
  
  
  
  
  
Ending balance$2,069,665
 $690,561
 $846,294
 $18,229
 $100,796
 $14,089
 $758,659
 $123,775
 

 $4,622,068
Ending balance: individually evaluated for impairment$22,457
 $1,188
 $3,225
 $5,683
 $—
 $—
 $21,119
 $13
 

 $53,685
Ending balance: collectively evaluated for impairment$2,047,208
 $689,373
 $843,069
 $12,546
 $100,796
 $14,089
 $737,540
 $123,762
 

 $4,568,383
Changes in the allowance for loan losses were as follows:
(dollars in thousands)2016
 2015
 2014
Allowance for loan losses, January 1$50,038
 $45,618
 $40,116
Provision for loan losses16,763
 6,275
 6,126
Charge-offs, net of recoveries 
  
  
Real estate loans(52) (252) (1,137)
Other loans11,320
 2,107
 1,761
Net charge-offs11,268
 1,855
 624
Allowance for loan losses, December 31$55,533
 $50,038
 $45,618
Ratio of net charge-offs to average total loans0.24% 0.04% 0.01%
Credit quality.  ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial, commercial real estate and commercial construction loans.


Each loan is assigned an Asset Quality Rating (AQR) reflecting the likelihood of repayment or orderly liquidation of that loan transaction pursuant to regulatory credit classifications:  Pass, Special Mention, Substandard, Doubtful, and Loss. The AQR is a function of the probability of default model rating, the loss given default, and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens and major changes in business and economic conditions. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt. Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that the Bank may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable.
The credit risk profile by internally assigned grade for loans was as follows:
December 312016 2015
(in thousands)
Commercial
real estate
 
Commercial
construction
 Commercial Total 
Commercial
real estate
 
Commercial
construction
 Commercial Total
Grade: 
  
  
    
  
  
  
Pass$701,657
 $102,955
 $614,139
 1,418,751
 $642,410
 $86,991
 $703,208
 $1,432,609
Special mention65,541
 —
 25,229
 90,770
 7,710
 13,805
 7,029
 28,544
Substandard33,197
 23,813
 52,683
 109,693
 40,441
 —
 47,975
 88,416
Doubtful—
 —
 —
 —
 —
 —
 447
 447
Loss—
 —
 —
 —
 —
 —
 —
 —
Total$800,395
 $126,768
 $692,051
 1,619,214
 $690,561
 $100,796
 $758,659
 $1,550,016
The credit risk profile based on payment activity for loans was as follows:
(in thousands)
30-59
days
past due
 
60-89
days
past due
 
Greater
than
90 days
 
Total
past due
 Current 
Total
financing
receivables
 
Recorded
investment>
90 days and
accruing
December 31, 2016 
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
Residential 1-4 family$5,467
 $2,338
 $3,505
 $11,310
 $2,036,741
 $2,048,051
 $—
Commercial real estate2,416
 —
 —
 2,416
 797,979
 800,395
 —
Home equity line of credit1,263
 381
 1,342
 2,986
 860,177
 863,163
 —
Residential land—
 —
 255
 255
 18,634
 18,889
 —
Commercial construction—
 —
 —
 —
 126,768
 126,768
 —
Residential construction—
 —
 —
 —
 16,080
 16,080
 —
Commercial413
 510
 1,303
 2,226
 689,825
 692,051
 —
Consumer1,945
 1,001
 963
 3,909
 174,313
 178,222
 —
Total loans$11,504
 $4,230
 $7,368
 $23,102
 $4,720,517
 $4,743,619
 $—
December 31, 2015 
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
Residential 1-4 family$4,967
 $3,289
 $11,503
 $19,759
 $2,049,906
 $2,069,665
 $—
Commercial real estate—
 —
 —
 —
 690,561
 690,561
 —
Home equity line of credit896
 706
 477
 2,079
 844,215
 846,294
 —
Residential land—
 —
 415
 415
 17,814
 18,229
 —
Commercial construction—
 —
 —
 —
 100,796
 100,796
 —
Residential construction—
 —
 —
 —
 14,089
 14,089
 —
Commercial125
 223
 878
 1,226
 757,433
 758,659
 —
Consumer1,383
 593
 644
 2,620
 121,155
 123,775
 —
Total loans$7,371
 $4,811
 $13,917
 $26,099
 $4,595,969
 $4,622,068
 $—


The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due, and TDR loans was as follows:
December 312016 2015
(in thousands)   
Real estate: 
  
Residential 1-4 family$11,154
 $20,554
Commercial real estate223
 1,188
Home equity line of credit3,080
 2,254
Residential land878
 970
Commercial construction—
 —
Residential construction—
 —
Commercial6,708
 20,174
Consumer1,282
 895
Total nonaccrual loans$23,325
 $46,035
Real estate:   
Residential 1-4 family$—
 $—
Commercial real estate—
 —
Home equity line of credit—
 —
Residential land—
 —
Commercial construction—
 —
Residential construction—
 —
Commercial—
 —
Consumer—
 —
Total accruing loans 90 days or more past due$—
 $—
Real estate:   
Residential 1-4 family$14,450
 $13,962
Commercial real estate1,346
 —
Home equity line of credit4,934
 2,467
Residential land2,751
 4,713
Commercial construction—
 —
Residential construction—
 —
Commercial14,146
 1,104
Consumer10
 —
Total troubled debt restructured loans not included above$37,637
 $22,246



The total carrying amount and the total unpaid principal balance of impaired loans were as follows:
December 312016 2015
(in thousands)
Recorded
investment
 
Unpaid
principal
balance
 
Related
allow-
ance
 
Average
recorded
investment
 
Interest
income
recognized*
 
Recorded
investment
 
Unpaid
principal
balance
 
Related
allow-
ance
 
Average
recorded
investment
 
Interest
income
recognized*
With no related allowance recorded 
  
  
  
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
  
  
  
Residential 1-4 family$9,571
 $10,400
 $—
 $10,136
 $324
 $10,596
 $11,805
 $—
 $11,215
 $332
Commercial real estate223
 228
 —
 1,124
 —
 1,188
 1,436
 —
 370
 74
Home equity line of credit1,500
 1,900
 —
 1,105
 23
 707
 948
 —
 484
 4
Residential land1,218
 1,803
 —
 1,518
 66
 1,644
 2,412
 —
 2,397
 137
Commercial construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial6,299
 8,869
 —
 8,694
 370
 5,671
 6,333
 —
 5,185
 157
Consumer—
 —
 —
 2
 —
 —
 —
 —
 —
 —
 18,811
 23,200
 —
 22,579
 783
 19,806
 22,934
 —
 19,651
 704
With an allowance recorded 
  
  
  
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
  
  
  
Residential 1-4 family10,283
 10,486
 1,352
 11,589
 457
 11,861
 11,914
 1,453
 11,578
 562
Commercial real estate1,346
 1,346
 80
 1,962
 15
 —
 —
 —
 1,699
 —
Home equity line of credit4,658
 4,712
 215
 3,765
 137
 2,518
 2,579
 442
 1,597
 49
Residential land2,411
 2,411
 789
 2,964
 206
 4,039
 4,117
 891
 4,337
 318
Commercial construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial14,240
 14,240
 1,641
 16,106
 456
 15,448
 16,073
 3,527
 12,507
 211
Consumer10
 10
 6
 12
 —
 13
 13
 7
 14
 —
 32,948
 33,205
 4,083
 36,398
 1,271
 33,879
 34,696
 6,320
 31,732
 1,140
Total 
  
  
  
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
  
  
  
Residential 1-4 family19,854
 20,886
 1,352
 21,725
 781
 22,457
 23,719
 1,453
 22,793
 894
Commercial real estate1,569
 1,574
 80
 3,086
 15
 1,188
 1,436
 —
 2,069
 74
Home equity line of credit6,158
 6,612
 215
 4,870
 160
 3,225
 3,527
 442
 2,081
 53
Residential land3,629
 4,214
 789
 4,482
 272
 5,683
 6,529
 891
 6,734
 455
Commercial construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial20,539
 23,109
 1,641
 24,800
 826
 21,119
 22,406
 3,527
 17,692
 368
Consumer10
 10
 6
 14
 —
 13
 13
 7
 14
 —
 $51,759
 $56,405
 $4,083
 $58,977
 $2,054
 $53,685
 $57,630
 $6,320
 $51,383
 $1,844
* Since loan was classified as impaired.
Troubled debt restructurings.  A loan modification is deemed to be a TDR when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.
ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period, and temporary deferral or


reduction of principal payments. ASB generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.
All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment:  (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Loan modifications that occurred during 2016 and 2015 and the impact on the allowance for loan losses were as follows:
Years ended December 312016 2015
 Number Outstanding recorded investment Net increase in ALLL Number Outstanding recorded investment Net increase in ALLL
(dollars in thousands)of
contracts		 Pre-modification Post-modification  
of
contracts
 Pre-modification Post-modification 
Troubled debt restructurings  
  
    
  
  
  
Real estate: 
  
  
    
  
  
  
Residential 1-4 family14
 $3,131
 $3,245
 $337
 19
 $3,594
 $3,668
 $87
Commercial real estate—
 —
 —
 —
 1
 1,500
 1,500
 —
Home equity line of credit36
 3,337
 3,337
 554
 39
 2,441
 2,441
 370
Residential land2
 203
 204
 —
 1
 218
 218
 —
Commercial construction—
 —
 —
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
 —
 —
Commercial15
 20,266
 20,266
 865
 8
 2,267
 2,267
 486
Consumer—
 —
 —
 —
 —
 —
 —
 —
 67
 $26,937
 $27,052
 $1,756
 68
 $10,020
 $10,094
 $943
Loans modified in TDRs that experienced a payment default of 90 days or more in 2016 and 2015, and for which the payment default occurred within one year of the modification, were as follows:
Years ended December 312016 2015
(dollars in thousands)
Number of
 contracts
 
Recorded
 investment
 
Number of
 contracts
 
Recorded
 investment
Troubled debt restructurings that subsequently defaulted  
  
  
Real estate: 
  
  
  
Residential 1-4 family1
 $239
 —
 $—
Commercial real estate—
 —
 —
 —
Home equity line of credit—
 —
 1
 6
Residential land—
 —
 —
 —
Commercial construction—
 —
 —
 —
Residential construction—
 —
 —
 —
Commercial1
 24
 1
 1,056
Consumer—
 —
 —
 —
 2
 $263
 2
 $1,062
If loans modified in a TDR subsequently default, ASB evaluates the loan for further impairment. Based on its evaluation, adjustments may be made in the allocation of the allowance or partial charge-offs may be taken to further write-down the carrying value of the loan. Commitments to lend additional funds to borrowers whose loan terms have been modified in a TDR totaled $2.6 million at December 31, 2016.
Mortgage servicing rights.In its mortgage banking business, ASB sells residential mortgage loans to government-sponsored entities and other parties, who may issue securities backed by pools of such loans. ASB retains no beneficial interests in these loans other than the servicing rights of certain loans sold.


ASB received $236.1 million, $275.3 million and $155.0 million of proceeds from the sale of residential mortgages in 2016, 2015, and 2014, respectively, and recognized gains on such sales of $6.6 million, $6.3 million, and $2.9 million in 2016, 2015, and 2014, respectively. Repurchased mortgage loans in 2016, 2015, and 2014, were nil, nil and $0.5 million, respectively.
Mortgage servicing fees, a component of other income, net, were $2.9 million, $3.5 million, and $3.5 million for the years ended December 31, 2016, 2015, and 2014, respectively.
Changes in the carrying value of mortgage servicing rights were as follows:
(in thousands)Gross
carrying amount		 Accumulated amortization Valuation allowance Net
carrying amount
December 31, 2016$17,271
 $(7,898) $—
 $9,373
December 31, 2015$14,531
1 
$(5,647)
1 
$—
 $8,884
1 Reflects sale of mortgage servicing rights and impact of loans paid in full.

Changes related to mortgage servicing rights were as follows:
(in thousands)2016
 2015
 2014
Mortgage servicing rights     
Balance, January 1$8,884
 $11,749
 $11,938
Amount capitalized2,740
 3,123
 1,637
Amortization(2,251) (2,682) (1,731)
Sale of mortgage servicing rights—
 (3,302) —
Other-than-temporary impairment—
 (4) (95)
Carrying amount before valuation allowance, December 319,373
 8,884
 11,749
Valuation allowance for mortgage servicing rights     
Balance, January 1—
 209
 251
Provision (recovery)—
 (205) 53
Other-than-temporary impairment—
 (4) (95)
Balance, December 31—
 —
 209
Net carrying value of mortgage servicing rights$9,373
 $8,884
 $11,540
The estimated aggregate amortization expenses of mortgage servicing rights for 2017, 2018, 2019, 2020 and 2021 are $1.3 million, $1.2 million, $1.0 million, $0.9 million and $0.8 million, respectively.
ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale with servicing rights retained. On a monthly basis, ASB compares the net carrying value of the mortgage servicing rights to its fair value to determine if there are any changes to the valuation allowance and/or other-than-temporary impairment for the mortgage servicing rights. ASB's MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15 and 30 year mortgages and note rate in bands of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Changes in mortgage interest rates impact the value of ASB's mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others, which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing rights and increase the amortization of the mortgage servicing rights. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others.
ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in other income, net in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.


Key assumptions used in estimating the fair value of ASB’s mortgage servicing rights used in the impairment analysis were as follows:
December 312016 2015
(dollars in thousands)   
Unpaid principal balance$1,188,380
 $1,097,314
Weighted average note rate3.96% 4.05%
Weighted average discount rate9.4% 9.6%
Weighted average prepayment speed8.5% 9.3%
The sensitivity analysis of fair value of MSR to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions was as follows:
December 312016 2015
(in thousands)   
Prepayment rate:   
25 basis points adverse rate change$(567) $(561)
50 basis points adverse rate change(1,154) (1,104)
Discount rate:   
25 basis points adverse rate change(128) (111)
50 basis points adverse rate change(254) (220)
The effect of a variation in certain assumptions on fair value is calculated without changing any other assumptions. This analysis typically cannot be extrapolated because the relationship of a change in one key assumption to the changes in the fair value of MSRs typically is not linear.
Deposit liabilities. The summarized components of deposit liabilities were as follows:
December 312016 2015
(dollars in thousands)Weighted-average stated rate
 Amount
 Weighted-average stated rate
 Amount 
Savings0.07% $2,208,594
 0.07% $2,030,644
Checking     
  
Interest-bearing0.02
 890,633
 0.02
 831,143
Noninterest-bearing—
 817,867
 —
 746,875
Commercial checking—
 821,184
 —
 773,499
Money market0.12
 153,126
 0.13
 167,641
Term certificates1.00
 657,525
 0.93
 475,452
 0.15% $5,548,929
 0.12% $5,025,254
As of December 31, 2016 and 2015, term certificates of $100,000 or more totaled $328.1 million and $163.2 million, respectively.
The approximate scheduled maturities of term certificates outstanding at December 31, 2016 were as follows:
(in thousands) 
2017$322,661
201870,611
2019105,478
202081,818
202173,686
Thereafter3,271
 $657,525


Interest expense on deposit liabilities by type of deposit was as follows:
Years ended December 312016
 2015
 2014
(in thousands)     
Term certificates$5,390
 $3,747
 $3,603
Savings1,402
 1,257
 1,134
Money market202
 205
 214
Interest-bearing checking173
 139
 126
 $7,167
 $5,348
 $5,077
Other borrowings.
Securities sold under agreements to repurchase.  Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the balance sheet. ASB pledges investment securities as collateral for securities sold under agreements to repurchase. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:
(in millions) 
Gross amount of
recognized liabilities
 
Gross amount
 offset in the
 Balance Sheet
 
Net amount of
 liabilities presented
in the Balance Sheet
Repurchase agreements  
  
  
December 31, 2016 $93
 $—
 $93
December 31, 2015 229
 —
 229
  Gross amount not offset in the Balance Sheet
(in millions) 
Net amount of 
liabilities presented
in the Balance Sheet
 
Financial
instruments
 
Cash
collateral
pledged
December 31, 2016  
  
  
Financial institution $—
 $—
 $—
Government entities 14
 15
 —
Commercial account holders 79
 101
 —
Total $93
 $116
 $—
December 31, 2015  
  
  
Financial institution $50
 $56
 $—
Government entities 56
 61
 —
Commercial account holders 123
 144
 —
Total $229
 $261
 $—
The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts or into segregated tri-party custodial accounts at the FHLB. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts. The counterparties or tri-parties may determine that additional collateral is required based on movements in the fair value of the collateral. Typically, a five percent discount is taken from the fair value of the investment securities to determine the value of the collateral pledged for the repurchase agreements.


Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:
(dollars in millions)2016
 2015
 2014
Amount outstanding as of December 31$93
 $229
 $191
Average amount outstanding during the year$170
 $219
 $155
Maximum amount outstanding as of any month-end$229
 $277
 $195
Weighted-average interest rate as of December 310.23% 1.24% 1.45%
Weighted-average interest rate during the year1.43% 1.29% 1.67%
Weighted-average remaining days to maturity as of December 316
 117
 343
Securities sold under agreements to repurchase were summarized as follows:
December 312016 2015
MaturityRepurchase liability
 
Weighted-average
interest rate

 
Collateralized by
 mortgage-related
securities and federal
agency obligations at fair value plus
 accrued interest

 Repurchase liability
 Weighted-average
interest rate
 Collateralized by
mortgage-related
securities and federal
agency obligations at fair value plus
accrued interest
(dollars in thousands) 
  
  
      
Overnight$79,083
 0.15% $100,305
 $122,684
 0.15% $144,146
1 to 29 days—
 —
 —
 —
 —
 —
30 to 90 days13,535
 0.70
 15,239
 18,535
 0.29
 20,364
Over 90 days—
 —
 —
 87,363
1 
2.96
 96,553
 $92,618
 0.23% $115,544
 $228,582
 1.24% $261,063
1
$50.3 million callable by the counterparties quarterly at par until maturity in 2016.
Advances from Federal Home Loan Bank. FHLB advances are fixed rate for a specific term and consist of the following:
December 31, 2016
Weighted-average
stated rate

 Amount
 
(dollars in thousands) 
  
 
Due in 
  
 
20174.28% $50,000
1 
20181.95
 50,000
 
2019—
 —
 
2020—
 —
 
2021—
 —
 
Thereafter—
 —
 
 3.12% $100,000
 
1
Callable quarterly at par until maturity in 2017.
ASB and the FHLB are parties to an Advances, Pledge and Security Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB’s credit policies, and makes certain warranties and representations to the FHLB. Upon the occurrence of and during the continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Advances Agreement or other credit arrangements between the parties), the FHLB may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB are collateralized by loans and stock in the FHLB. As of December 31, 2016 and 2015, ASB’s available FHLB borrowing capacity was $1.8 billion and $1.7 billion, respectively. ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB. ASB was in compliance with all Advances Agreement requirements as of December 31, 2016 and 2015.


Common stock equity.  In 1988, HEI agreed with the OTS predecessor regulatory agency at the time, to contribute additional capital to ASB up to a maximum aggregate amount of approximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2016, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement has been reduced to approximately $28.3 million. As of December 31, 2016, ASB was in compliance with the minimum capital requirements under OCC regulations.
In 2016, ASB paid cash dividends of $36 million to HEI, compared to cash dividends of $30 million in 2015. The FRB and OCC approved the dividends.
Related-party transactions. HEI charged ASB $2.3 million, $2.1 million and $2.3 million for general management and administrative services in 2016, 2015 and 2014, respectively. The amounts charged by HEI for services performed by HEI employees to its subsidiaries are allocated primarily on the basis of time expended in providing such services.
Derivative financial instruments. ASB enters into interest rate lock commitments (IRLCs) with borrowers, and forward commitments to sell loans or to-be-announced mortgage-backed securities to investors to hedge against the inherent interest rate and pricing risks associated with selling loans.
ASB enters into IRLCs for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. IRLCs that relate to the origination of mortgage loans that will be held for sale are considered derivative financial instruments under applicable accounting guidance. Outstanding IRLCs expose ASB to the risk that the price of the mortgage loans underlying the commitments may decline due to increases in mortgage interest rates from inception of the rate lock to the funding of the loan. The IRLCs are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
ASB enters into forward commitments to hedge the interest rate risk for rate locked mortgage applications in process and closed mortgage loans held for sale. These commitments are primarily forward sales of to-be-announced mortgage backed securities. Generally, when mortgage loans are closed, the forward commitment is liquidated and replaced with a mandatory delivery forward sale of the mortgage to a secondary market investor. In some cases, a best-efforts forward sale agreement is utilized as the forward commitment. These commitments are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
Changes in the fair value of IRLCs and forward commitments subsequent to inception are based on changes in the fair value of the underlying loan resulting from the fulfillment of the commitment and changes in the probability that the loan will fund within the terms of the commitment, which is affected primarily by changes in interest rates and the passage of time.
The notional amount and fair value of ASB’s derivative financial instruments were as follows:
December 312016 2015
(in thousands)Notional amount Fair value Notional amount Fair value
Interest rate lock commitments$25,883
 $421
 $22,241
 $384
Forward commitments30,813
 (177) 23,644
 (29)
ASB’s derivative financial instruments, their fair values, and balance sheet location were as follows:
Derivative Financial Instruments Not Designated       
as Hedging Instruments 1
       
December 312016 2015
(in thousands)Asset derivatives Liability derivatives Asset derivatives Liability derivatives
Interest rate lock commitments$445
 $24
 $384
 $—
Forward commitments8
 185
 1
 30
 $453
 $209
 $385
 $30
1 Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.


The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in the statements of income:
Derivative Financial Instruments Not DesignatedLocation of net gains      
as Hedging Instruments(losses) recognized in Years ended December 31
(in thousands)the Statements of Income 2016 2015 2014
Interest rate lock commitmentsMortgage banking income $37
 $(6) $(74)
Forward commitmentsMortgage banking income (148) 77
 (245)
 
 $(111) $71
 $(319)
Commitments. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory and property, plant and equipment.
Letters of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. ASB holds collateral supporting those commitments for which collateral is deemed necessary.
The following is a summary of outstanding off-balance sheet arrangements:
December 312016
 2015
(in thousands)   
Unfunded commitments to extend credit: 
  
Home equity line of credit$1,146,339
 $1,096,532
Commercial and commercial real estate577,410
 631,780
Consumer64,762
 60,198
Residential 1-4 family38,271
 24,863
Commercial and financial standby letters of credit16,017
 18,709
Total$1,842,799
 $1,832,082
Contingency. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into a judgment and loss sharing agreement with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2012, a federal judge granted preliminary approval to a proposed settlement between merchants and Visa over credit card fees and in December 2013, a federal judge granted final approval to the settlement. Some merchants and trade organizations filed a notice of appeal shortly after the approval was issued. As of December 31, 2016, ASB had accrued a reserve of $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.
Federal Deposit Insurance Corporation assessment. In February 2011, the Federal Deposit Insurance Corporation (FDIC) finalized rules to change its assessment base from total domestic deposits to average total assets minus average tangible equity, as required in the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Assessment rates were reduced to a range of 2.5 to 9 basis points on the new assessment base for financial institutions in the lowest risk category. Financial institutions in the highest risk category have assessment rates of 30 to 45 basis points. The new rate schedule was effective April 1, 2011. As of June 30, 2016, the deposit insurance fund surpassed a target of 1.15 percent of estimated insured deposits that triggered important changes in the FDIC assessments for all banks. The changes took effect for premiums billed and paid in December 2016. Banks with less than $10 billion in assets saw their overall schedule decline by two basis points for banks paying the lowest premiums and up to five points for those at the top end of the assessment scale. In addition, a new formula for calculating risk-based assessment rates is now in effect. For the years ended December 31, 2016 and 2015, ASB’s FDIC insurance assessments were $3.2 million and $3.0 million, respectively. The FDIC may impose special assessments in the future if it is deemed necessary to ensure the Deposit Insurance Fund ratio does not decline to a level that is close to zero or that could otherwise undermine public confidence in federal deposit insurance.


6 · Unconsolidated variable interest entities
HECO Capital Trust III.  Trust III was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,0006.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to Hawaiian Electric, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by Hawaiian Electric in the principal amount of $31.5 million and issued by Hawaii Electric Light and Maui Electric each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of the Utilities under an expense agreement and Hawaiian Electric’s obligations under its trust guarantee and its guarantee of the obligations of Hawaii Electric Light and Maui Electric under their respective debentures, are the sole assets of Trust III. Taken together, Hawaiian Electric’s obligations under the Hawaiian Electric debentures, the Hawaiian Electric indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in the aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. Trust III has at all times been an unconsolidated subsidiary of Hawaiian Electric. Since Hawaiian Electric, as the holder of 100% of the trust common securities, does not absorb the majority of the variability of Trust III, Hawaiian Electric is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheet as of December 31, 2016 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2016 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to Hawaiian Electric. As long as the 2004 Trust Preferred Securities are outstanding, Hawaiian Electric is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by Hawaiian Electric in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event any of the Utilities elect to defer payment of interest on any of their respective 2004 Debentures, then Hawaiian Electric will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.
Power purchase agreements.  As of December 31, 2016, the Utilities had five PPAs for firm capacity and other PPAs with IPPs and Schedule Q providers (i.e., customers with cogeneration and/or power production facilities who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of the firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs were as follows: 
Years ended December 31 2016 2015 2014
(in millions)      
AES Hawaii $149
 $134
 $145
Kalaeloa 152
 187
 279
HEP 29
 44
 51
HPOWER 71
 66
 66
Puna Geothermal Venture 28
 29
 45
Hawaiian Commercial & Sugar (HC&S) 1
 8
 15
Other IPPs 133
 126
 121
Total IPPs $563
 $594
 $722
In October 2015 the amended PPA between Maui Electric and HC&S became effective following PUC approval in September 2015. The amended PPA amended the pricing structure and rates for energy sold to Maui Electric, eliminated the capacity payment to HC&S, eliminated Maui Electric’s minimum purchase obligation, provided that Maui Electric may request up to 4 MW of scheduled energy during certain months and be provided up to 16 MW of emergency power, and extended the term of the PPA from 2014 to 2017. Effective on December 23, 2016, Maui Electric and HC&S agreed to terminate the PPA.
Some of the IPPs provided sufficient information for Hawaiian Electric to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. Other IPPs declined to provide the information necessary for Hawaiian Electric to determine the applicability of accounting standards for VIEs.


Since 2004, Hawaiian Electric has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2016, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.
If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs.
Kalaeloa Partners, L.P.  In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that Hawaiian Electric makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.
Hawaiian Electric and Kalaeloa are in negotiations to address the PPA term that ended on May 23, 2016. The PPA automatically extends on a month-to-month basis as long as the parties are still negotiating in good faith. The month-to-month term extensions shall end 60 days after either party notifies the other in writing that negotiations have terminated. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution.
Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in Kalaeloa by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, Hawaiian Electric has not consolidated Kalaeloa in its consolidated financial statements. The energy payments paid by Hawaiian Electric will fluctuate as fuel prices change, however, the PPA does not currently expose Hawaiian Electric to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through Hawaiian Electric's ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of December 31, 2016, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $12 million.
AES Hawaii, Inc.In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc.), which, as amended (through Amendment No. 2) and approved by the PUC, provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 30 years beginning in September 1992. In November 2015, Hawaiian Electric entered into an Amendment No. 3, for which PUC approval was requested and subsequently denied in January 2017. Amendment No. 3 would have increased the firm capacity from 180 MW to a maximum of 189 MW. The payments that Hawaiian Electric makes to AES Hawaii for energy associated with the first 180 MW of firm capacity include a fuel component, a variable O&M component and a fixed O&M component, all of which are subject to adjustment based on changes in the Gross National Product Implicit Price Deflator.
Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in AES Hawaii by reason of the provisions of Hawaiian Electric’s PPA with AES Hawaii. However, management has concluded that Hawaiian Electric is not the primary beneficiary of AES Hawaii because Hawaiian Electric does not have the power to control the most significant activities of AES Hawaii that impact AES Hawaii’s economic performance, including operations and maintenance of AES Hawaii’s facility. Thus, Hawaiian Electric has not consolidated AES Hawaii in its consolidated financial statements. As of December 31, 2016, Hawaiian Electric’s accounts payable to AES Hawaii amounted to $13 million.


7·Short-term borrowings
As of December 31, 2015, HEI had $103 million of outstanding commercial paper, with a weighted-average interest rate of 1.1% and Hawaiian Electric had no commercial paper outstanding. As of December 31, 2016, HEI and Hawaiian Electric had no commercial paper outstanding.
As of December 31, 2016, HEI and Hawaiian Electric maintained syndicated credit facilities of $150 million and $200 million, respectively. Both HEI and Hawaiian Electric had no borrowings under their respective facilities during 2015 and 2016. None of the facilities are collateralized.
Credit agreements.
HEI.  On April 2, 2014, HEI and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (HEI Facility). The HEI Facility increased HEI’s line of credit to $150 million from $125 million, extended the term of the facility to April 2, 2019, and provided improved pricing compared to HEI’s prior facility. Under the HEI Facility, draws would generally bear interest, based on HEI’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The HEI Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the HEI Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. In addition, the HEI Consolidated Net Worth covenant, as defined in the original facility, was removed from the HEI Facility, leaving only one financial covenant (relating to HEI’s ratio of funded debt to total capitalization, each on a non-consolidated basis). Under the credit agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (actual ratio of 13% as of December 31, 2016, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. The HEI Facility continues to contain customary conditions which must be met in order to draw on it, including compliance with covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI).
The HEI Facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.
Hawaiian Electric.  On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility continues to contain customary conditions which must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for Hawaii Electric Light and 42% for Maui Electric as of December 31, 2016, as calculated under the agreement)). In addition to customary defaults, Hawaiian Electric’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if Hawaiian Electric fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 57% as of December 31, 2016, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.
The Hawaiian Electric Facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay Hawaiian Electric’s short-term indebtedness, to make loans to subsidiaries and for Hawaiian Electric’s capital expenditures, working capital and general corporate purposes.


8·Long-term debt
December 312016
 2015
(dollars in thousands) 
  
Long-term debt of Utilities 1
$1,319,260
 $1,278,702
HEI term loan LIBOR + .75%, due 2017125,000
 125,000
HEI term loan LIBOR + .75%, due 201875,000
 —
HEI senior note 4.41%, paid 2016—
 75,000
HEI senior note 5.67%, due 202150,000
 50,000
HEI senior note 3.99%, due 202350,000
 50,000
Less unamortized debt issuance costs(241) (334)
 $1,619,019
 $1,578,368
1
See components of “Total long-term debt” and unamortized debt issuance costs in Hawaiian Electric and subsidiaries’ Consolidated Statements of Capitalization.
As of December 31, 2016, the aggregate principal payments required on the Company’s long-term debt for 2017 through 2021 are $125 million in 2017, $125 million in 2018, nil in 2019, $96 million in 2020 and $50 million in 2021. As of December 31, 2016, the aggregate payments of principal required on the Utilities' long-term debt for 2017 through 2021 are nil in 2017, $50 million in 2018, nil in 2019, $96 million in 2020 and nil in 2021.
The HEI term loans and senior notes contain customary representation and warranties, affirmative and negative covenants and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable). The HEI term loans and senior notes also contain provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement, expiring on April 2, 2019. Upon a change of control or certain dispositions of assets (as defined in the Master Note Purchase Agreement dated March 24, 2011), HEI is required to offer to prepay the senior notes. HEI is in compliance with its covenants. (See Note 7 of the Consolidated Financial Statements).
The Utilities’ senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by Hawaiian Electric, and each of Hawaii Electric Light and Maui Electric, of certain financial ratios generally consistent with those in Hawaiian Electric’s existing amended revolving noncollateralized credit agreement, expiring on April 2, 2019. The Utilities are in compliance with their covenants. (See Note 7 of the Consolidated Financial Statements).
Changes in long-term debt.
HEI.  On March 21, 2016, HEI entered into a $75 million term loan agreement with Bank of America, N.A., which matures on March 23, 2018, and includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On March 23, 2016, HEI drew an initial $75 million Eurodollar term loan at an initial interest rate of 1.18% for an initial one month interest period (and with subsequent resetting interest rates averaging 1.25% through December 31, 2016). The proceeds from the term loan were used to pay off HEI’s $75 million 4.41% senior note at maturity on March 24, 2016.
Hawaiian Electric.  On December 15, 2016, Hawaiian Electric issued, through a private placement pursuant to the Note Purchase Agreement, $40 million of Series 2016A unsecured senior notes bearing taxable interest of 4.54%, which are due December 1, 2046 (the Notes) and includes substantially the same financial covenants and customary conditions as Hawaiian Electric's credit agreement as described above.
All the proceeds of the Notes were used by Hawaiian Electric to finance its capital expenditures and/or to reimburse funds used for the payment of capital expenditures.
The Notes may be prepaid in whole or in part at any time at the prepayment price of the principal amount plus a “Make-Whole Amount.” The foregoing is a brief summary of only certain of the terms and conditions of the Note Purchase Agreement and does not purport to be a complete discussion of their terms. Accordingly, the foregoing description is qualified in its entirety by reference to the Note Purchase Agreement listed as Exhibit 4.23 to this Form 10-K.


9 · Shareholders’ equity
Reserved shares.  As of December 31, 2016, HEI had reserved a total of 11,857,869 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP), the HEI 2011 Nonemployee Director Stock Plan, the ASB 401(k) Plan and the 2010 Executive Incentive Plan.
Equity forward transaction.  On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering on that date of 6.1 million shares of HEI common stock at $26.75 per share. On March 19, 2013, HEI common stock closed at $27.01 per share. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with the resulting additional 0.9 million shares of HEI common stock.
The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans. Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of the equity forward transactions, HEI was required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward was subject to certain adjustments in accordance with the terms of the equity forward transactions.
The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC Topic 480, "Distinguishing Liabilities from Equity," and ASC Topic 815, "Derivatives and Hedging," and that they qualified for an exception from derivative accounting under ASC Topic 815 because the forward sale transactions were indexed to its own stock. On December 19, 2013 and July 14, 2014, HEI settled 1.3 million and 1.0 million shares under the equity forward for proceeds of $32.1 million (net of the underwriting discount of $1.3 million) and $23.9 million (net of underwriting discount of $1.0 million), respectively, which funds were ultimately used to purchase Hawaiian Electric shares.
On March 20, 2015, HEI settled the remaining 4.7 million shares under the equity forward for proceeds of $104.5 million (net of the underwriting discount of $4.7 million), which funds were used for the reduction of debt and for general corporate purposes. The proceeds were recorded in equity at the time of settlement. Prior to their settlement, the shares remaining under the equity forward transactions were reflected in HEI’s diluted EPS calculations using the treasury stock method.
For 2016, 2015 and 2014, the equity forward transactions did not have a material dilutive effect on HEI’s EPS.
Accumulated other comprehensive income/(loss).  Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:
 HEI Consolidated Hawaiian Electric Consolidated
 (in thousands) Net unrealized gains (losses) on securities  Unrealized gains(losses) on derivatives  Retirement benefit plans AOCI  Unrealized losses on derivatives  Retirement benefit plans AOCI
Balance, December 31, 2013$(3,663) $(525) $(12,562) $(16,750) $—
 $608
 $608
Current period other comprehensive income (loss)4,125
 236
 (14,989) (10,628) —
 (563) (563)
Balance, December 31, 2014462
 (289) (27,551) (27,378) —
 45
 45
Current period other comprehensive income (loss)(2,334) 235
 3,215
 1,116
 —
 880
 880
Balance, December 31, 2015(1,872) (54) (24,336) (26,262) —
 925
 925
Current period other comprehensive loss(6,059) (400) (408) (6,867) (454) (793) (1,247)
Balance, December 31, 2016$(7,931) $(454) $(24,744) $(33,129) $(454) $132
 (322)


Reclassifications out of AOCI were as follows:
  Amount reclassified from AOCI  
Years ended December 31 2016 2015 2014 Affected line item in the Statement of Income
(in thousands)        
HEI consolidated        
Net realized gains on securities $(360) $—
 $(1,715) Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges    
  
  
Window forward contracts (173) —
 —
 
Revenues-electric utilities (gains on window forward contracts–see Note 4 for additional details)
Interest rate contracts (settled in 2011) 54
 235
 236
 Interest expense
Retirement benefit plan items  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 14,518
 22,465
 11,344
 See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets 28,584
 (25,139) 207,833
 See Note 10 for additional details
Total reclassifications $42,623
 $(2,439) $217,698
  
Hawaiian Electric consolidated        
Derivatives qualified as cash flow hedges        
Window forward contracts (173) —
 —
 
Revenues (gains on window forward contracts–see Note 4 for additional details)
Retirement benefit plan items  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost $13,254
 $20,381
 $10,212
 See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets 28,584
 (25,139) 207,833
 See Note 10 for additional details
Total reclassifications $41,665
 $(4,758) $218,045
  

10 · Retirement benefits
Defined benefit plans. Substantially all of the employees of HEI and the Utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI Pension Plan). Substantially all of the employees of ASB and its subsidiaries participated in the American Savings Bank Retirement Plan (ASB Pension Plan) until it was frozen on December 31, 2007. The HEI Pension Plan and the ASB Pension Plan (collectively, the Plans) are qualified, noncontributory defined benefit pension plans and include, in the case of the HEI Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the Utilities and the union. The Plans are subject to the provisions of ERISA. In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.
The continuation of the Plans and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The ASB Pension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontributory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.
Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA


and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.
To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified under “Defined benefit pension and other postretirement benefit plans information” below.
Postretirement benefits other than pensions.  HEI and the Utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (Hawaiian Electric Benefits Plan). Eligibility of employees and dependents is based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.
The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees and retirees of Hawaiian Electric in August 2009, Hawaii Electric Light in November 2010, and Maui Electric in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargaining agreement.
The Company’s and Utilities' cost for OPEB has been adjusted to reflect the plan amendments, which reduced benefits and created prior service credits to be amortized over average future service of affected participants. The amortization of the prior service credit will reduce benefit costs over the next few years until the various credit bases are fully recognized. Each participating employer reserves the right to terminate its participation in the Hawaiian Electric Benefits Plan at any time.
Balance sheet recognition of the funded status of retirement plans.  Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO), to calculate the funded status).
The PUC allowed the Utilities to adopt pension and OPEB tracking mechanisms in previous rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the Utilities’ tracking mechanisms, any actual costs determined in accordance with GAAP that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit expenses (except for executive life and nonqualified pension plan expenses, which amounted to $0.9 million and $1.0 million in 2016 and 2015, respectively) determined in accordance with GAAP will be recovered.
Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The Utilities have reclassified to a regulatory asset/(liability) charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge to AOCI of $47 million pretax and $(41) million pretax for 2016 and 2015, respectively).
Under the pension tracking mechanism, the Utilities’ are required to make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.
The OPEB tracking mechanisms generally require the Utilities to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.
Retirement benefits expense for the Utilities for 2016, 2015 and 2014 was $31 million, $30 million and $32 million, respectively.


Defined benefit pension and other postretirement benefit plans information.  The changes in the obligations and assets of the Company’s and Utilities' retirement benefit plans and the changes in AOCI (gross) for 2016 and 2015 and the funded status of these plans and amounts related to these plans reflected in the Company’s and Utilities' consolidated balance sheet as of December 31, 2016 and 2015 were as follows:
 2016 2015
(in thousands)
Pension
benefits
 
Other
benefits
 
Pension
benefits
 
Other
benefits
HEI consolidated       
Benefit obligation, January 1$1,798,030
 $221,540
 $1,847,228
 $219,209
Service cost60,555
 3,331
 66,260
 3,927
Interest cost81,549
 9,670
 76,960
 9,011
Actuarial losses (gains)67,741
 7,831
 (124,239) (2,911)
Participants contributions—
 1,405
 —
 1,274
Benefits paid and expenses(72,381) (9,942) (68,179) (8,970)
Benefit obligation, December 311,935,494
 233,835
 1,798,030
 221,540
Fair value of plan assets, January 11,271,474
 170,687
 1,266,060
 180,332
Actual (loss) return on plan assets103,836
 11,352
 (14,422) (2,866)
Employer contributions65,463
 42
 86,802
 917
Participants contributions—
 1,405
 —
 1,274
Benefits paid and expenses(71,072) (9,235) (66,966) (8,970)
Fair value of plan assets, December 311,369,701
 174,251
 1,271,474
 170,687
Accrued benefit asset (liability), December 31$(565,793) $(59,584) $(526,556) $(50,853)
Other assets$13,477
 $—
 $12,509
 $—
Defined benefit pension and other postretirement benefit plans liability(579,270) (59,584) (539,065) (50,853)
Accrued benefit asset (liability), December 31$(565,793) $(59,584) $(526,556) $(50,853)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)$581,763
 $32,550
 $639,831
 $20,933
Recognized during year – prior service credit (cost)57
 1,793
 (4) 1,793
Recognized during year – net actuarial losses(24,832) (804) (36,800) (1,796)
Occurring during year – net actuarial losses (gains)62,463
 8,751
 (21,264) 11,620
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31619,451
 42,290
 581,763
 32,550
Cumulative impact of PUC D&Os(576,933) (43,974) (538,784) (35,333)
AOCI debit/(credit), December 31$42,518
 $(1,684) $42,979
 $(2,783)
Net actuarial loss$619,582
 $52,792
 $581,951
 $44,845
Prior service gain(131) (10,502) (188) (12,295)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31619,451
 42,290
 581,763
 32,550
Cumulative impact of PUC D&Os(576,933) (43,974) (538,784) (35,333)
AOCI debit/(credit), December 3142,518
 (1,684) 42,979
 (2,783)
Income taxes (benefits)(16,746) 656
 (16,944) 1,084
AOCI debit/(credit), net of taxes (benefits), December 31$25,772
 $(1,028) $26,035
 $(1,699)

As of December 31, 2016 and 2015, the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets.



        
 2016 2015
(in thousands)
Pension
benefits
 
Other
benefits
 
Pension
benefits
 
Other
benefits
Hawaiian Electric consolidated       
Benefit obligation, January 1$1,649,690
 $213,990
 $1,690,777
 $211,760
Service cost58,796
 3,284
 64,262
 3,870
Interest cost74,808
 9,337
 70,529
 8,700
Actuarial losses (gains)63,121
 7,545
 (114,286) (2,860)
Participants contributions—
 1,389
 —
 1,260
Benefits paid and expenses(66,789) (9,822) (63,037) (8,858)
Transfers—
 —
 1,445
 118
Benefit obligation, December 311,779,626
 225,723
 1,649,690
 213,990
Fair value of plan assets, January 11,141,833
 167,930
 1,129,005
 177,256
Actual (loss) return on plan assets93,441
 11,168
 (10,646) (2,712)
Employer contributions64,236
 11
 85,139
 864
Participants contributions—
 1,389
 —
 1,260
Benefits paid and expenses(66,326) (9,115) (62,584) (8,858)
Other—
 —
 919
 120
Fair value of plan assets, December 311,233,184
 171,383
 1,141,833
 167,930
Accrued benefit asset (liability), December 31$(546,442) $(54,340) $(507,857) $(46,060)
Other liabilities (short-term)(460) (596) (425) (518)
Defined benefit pension and other postretirement benefit plans liability(545,982) (53,744) (507,432) (45,542)
Accrued benefit asset (liability), December 31$(546,442) $(54,340) $(507,857) $(46,060)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)$541,118
 $31,485
 $595,103
 $20,090
Recognized during year – prior service credit (cost)(13) 1,803
 (40) 1,804
Recognized during year – net actuarial losses(22,693) (793) (33,371) (1,754)
Occurring during year – net actuarial losses (gains)61,313
 8,472
 (20,574) 11,345
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31579,725
 40,967
 541,118
 31,485
Cumulative impact of PUC D&Os(576,933) (43,974) (538,784) (35,333)
AOCI debit/(credit), December 31$2,792
 $(3,007) $2,334
 $(3,848)
Net actuarial loss$579,691
 $51,463
 $541,071
 $43,784
Prior service cost (gain)34
 (10,496) 47
 (12,299)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31579,725
 40,967
 541,118
 31,485
Cumulative impact of PUC D&Os(576,933) (43,974) (538,784) (35,333)
AOCI debit/(credit), December 312,792
 (3,007) 2,334
 (3,848)
Income taxes (benefits)(1,087) 1,170
 (908) 1,497
AOCI debit/(credit), net of taxes (benefits), December 31$1,705
 $(1,837) $1,426
 $(2,351)
As of December 31, 2016 and 2015, the other postretirement benefit plan shown in the table above had ABOs in excess of plan assets.
The Company does not expect any plan assets to be returned to the Company during the calendar year 2017.
The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2016, 2015 and 2014.
The Pension Protection Act of 2006 (Pension Protection Act) signed into law on August 17, 2006, amended the Employee Retirement Income Security Act of 1974 (ERISA).  Among other things, the Pension Protection Act changed the funding rules for qualified pension plans. On August 8, 2014, President Obama signed the latest change to the Pension Protection Act, the Highway and Transportation Funding Act of 2014 (HATFA). HATFA resulted in an increase of the Adjusted Funding Target


Attainment Percentage (AFTAP) for benefit distribution purposes and eased funding requirements effective with the 2014 plan year (a plan sponsor could have elected to apply the provisions of HATFA to 2013, but the Company did not so elect). The funding relief was extended by the Bipartisan Budget Act of 2015. As a result, the minimum funding requirements for the HEI Retirement Plan under ERISA are less than the net periodic cost for 2015 and 2016. Nevertheless, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities contributed the net periodic cost in 2015 and 2016 and expect to contribute the net periodic cost in 2017.
The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan. The HEI Retirement Plan met the threshold requirements in each of 2014, 2015 and 2016 so that the more conservative assumptions did not apply for either 2015 or 2016 and will not apply for 2017. Other factors could cause changes to the required contribution levels.
For purposes of calculating NPPC and NPBC, the Company and the Utilities have determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in each of years two through five – and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range restriction around the fair value of such assets (i.e., 85% to 115% of fair value).
A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.
The asset allocation of defined benefit retirement plans to equity and fixed income securities managers and related investment policy targets and ranges were as follows:
 
Pension benefits1
 
Other benefits2
     Investment policy     Investment policy
December 312016
 2015
 Target
 Range 2016
 2015
 Target
 Range
Assets held by category 
  
  
    
  
  
  
Equity securities managers71% 70% 70% 65-75 70% 70% 70% 65-75
Fixed income securities managers29
 30
 30
 25-35 30
 30
 30
 25-35
 100% 100% 100%   100% 100% 100%  
1
Asset allocation is applicable to only HEI and the Utilities. In 2014, ASB revised its defined benefit pension plan asset allocation to a liability driven investment strategy and, as of December 31, 2016 and 2015, nearly all of its pension assets were invested in fixed income securities.
2
Asset allocation is applicable to only HEI and the Utilities. ASB does not fund its other benefits.



Assets held in various trusts for the retirement benefit plans are measured at fair value on a recurring basis and were as follows:
 Pension benefits Other benefits
   Fair value measurements using   Fair value measurements using
(in millions)December 31 Quoted prices in active markets for identical assets
(Level 1)		 Significant other observable inputs
(Level 2)		 Significant unobservable inputs
(Level 3)		 December 31 Level 1 Level 2 Level 3
2016 
  
  
  
  
  
  
  
Equity securities$692
 $692
 $—
 $—
 $94
 $94
 $—
 $—
Equity index funds129
 129
 —
 —
 17
 17
 —
 —
Equity investments at net asset value (NAV)56
 —
 —
 —
 9
 —
 —
 —
   Total equity investments877
 821
 —
 —
 120
 111
 —
 —
Fixed income securities and public mutual funds276
 84
 192
 —
 44
 42
 2
 —
Fixed income investments at NAV180
 —
 —
 —
 4
 —
 —
 —
   Total fixed income investments456
 84
 192
 —
 48
 42
 2
 —
Cash equivalents at NAV33
 —
 —
 —
 6
 —
 —
 —
Total$1,366
 $905
 $192
 $—
 $174
 $153
 $2
 $—
Cash, receivables and payables, net4
  
  
  
 —
  
  
  
Fair value of plan assets$1,370
  
  
  
 $174
  
  
  
2015 
  
  
  
  
  
  
  
Equity securities$640
 $640
 $—
 $—
 $92
 $92
 $—
 $—
Equity index funds119
 119
 —
 —
 17
 17
 —
 —
Equity investments at NAV46
 —
 —
 —
 9
 —
 —
 —
   Total equity investments805
 759
 —
 —
 118
 109
 —
 —
Fixed income securities and public mutual funds260
 85
 175
 —
 44
 42
 2
 —
Fixed income investments at NAV165
 —
 —
 —
 4
 —
 —
 —
   Total fixed income investments425
 85
 175
 —
 48
 42
 2
 —
Cash equivalents at NAV38
 —
 —
 —
 5
 —
 —
 —
Total1,268
 $844
 $175
 $—
 171
 $151
 $2
 $—
Cash, receivables and payables, net3
  
  
  
 —
  
  
  
Fair value of plan assets$1,271
  
  
  
 $171
  
  
  
 Pension benefits Other benefits
Measured at net asset valueDecember 31
 Redemption frequency Redemption notice period December 31
 Redemption frequency Redemption notice period
(in millions)           
2016           
Non U.S. equity funds (a)56
 Daily - Quarterly 0 - 30 days 9
 Monthly -Quarterly 10-30 days
Fixed income investments (b)180
 Monthly 10 days 4
 Monthly 10 days
Cash equivalents (c)33
 Daily 0-1 day 6
 Daily 0-1 day
 $269
     $19
    
2015           
Non U.S. equity funds (a)46
 Daily - Quarterly 0 - 30 days 9
 Monthly - Quarterly 10-30 days
Fixed income investments (b)165
 Monthly 10 days 4
 Monthly 10 days
Cash equivalents (c)38
 Daily 0-1 day 5
 Daily 0-1 day
 $249
     $18
    
None of the investments presented in the tables above have unfunded commitments.


(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, 2016 and 2015 were: daily, 31% and 24%; monthly, 31% and 29%; and quarterly, 38% and 47%, respectively. Redemption frequency for other benefits assets as of December 31, 2016 and 2015 were: monthly, 57% and 54%; and quarterly, 42% and 46%, respectively.
(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; the fund has an average rating of AA1.
The fair values of the investments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset. Those judgments are developed by the Company based on the best information available in the circumstances.
The fair value of investments measured at net asset value presented in the tables above are intended to permit reconciliation to the fair value of plan assets amounts.
The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2016 and 2015.
Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds (Level 1). Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds are valued at the closing price reported on the active market on which the individual securities or funds are traded.
Fixed income securities (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings.
The following weighted-average assumptions were used in the accounting for the plans:
 Pension benefits Other benefits
December 312016 2015 2014 2016 2015 2014
Benefit obligation           
Discount rate4.26% 4.60% 4.22% 4.22% 4.57% 4.17%
Rate of compensation increase3.5
 3.5
 3.5
 NA   
 NA   
 NA   
Net periodic pension/benefit cost (years ended)           
Discount rate4.60
 4.22
 5.09
 4.57
 4.17
 5.03
Expected return on plan assets1
7.75
 7.75
 7.75
 7.75
 7.75
 7.75
Rate of compensation increase3.5
 3.5
 3.5
 NA   
 NA   
 NA   
NA  Not applicable
1 For 2016 and 2015, HEI's and utilities' plan assets only. For 2016 and 2015, ASB's expected return on plan assets was 4.80% and 4.22%, respectively.
The Company and the Utilities based their selection of an assumed discount rate for 2017 NPPC, NPBC and December 31, 2016 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2016. In selecting the expected rate of return on plan assets for 2017 NPPC and NPBC: a) HEI and the Utilities considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets in selecting 7.50% and b) ASB considered its liability driven investment strategy in selecting 4.46%, which is consistent with the assumed discount rate as of December 31, 2016 with a 20 basis point active manager premium. For 2016, the Company's retirement benefit plans' assets had a net return of 8.0%.
The Company and the Utilities adopted mortality tables published in October 2014 by the Society of Actuaries as its mortality assumptions as of December 31, 2014. The use of the RP-2014 Tables and the Mortality Improvement Scale MP-2014 had a significant effect on the Company’s and the Utilities’ benefit obligations and increased their costs and required contributions for 2015. The Company and the Utilities adopted revised mortality tables for their mortality assumptions as of December 31, 2016 and 2015 (based on information published by the Society of Actuaries in October 2016 and 2015,


respectively), the use of which lowered obligations of the Company and Utilities as of December 31, 2016 and 2015 and will lower their costs and required contributions in 2017.
As of December 31, 2016, the assumed health care trend rates for 2017 and future years were as follows: medical, 7.75%, grading down to 5% for 2028 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2015, the assumed health care trend rates for 2016 and future years were as follows: medical, 8%, grading down to 5% for 2028 and thereafter; dental, 5%; and vision, 4%.
The components of NPPC and NPBC were as follows:
 Pension benefits Other benefits
(in thousands)2016 2015 2014 2016 2015 2014
HEI consolidated           
Service cost$60,555
 $66,260
 $49,264
 $3,331
 $3,927
 $3,490
Interest cost81,549
 76,960
 72,202
 9,670
 9,011
 8,550
Expected return on plan assets(98,559) (88,554) (81,355) (12,273) (11,664) (10,902)
Amortization of net prior service (gain) cost(57) 4
 88
 (1,793) (1,793) (1,793)
Amortization of net actuarial losses (gains)24,832
 36,800
 20,304
 804
 1,796
 (11)
Net periodic pension/benefit cost68,320
 91,470
 60,503
 (261) 1,277
 (666)
Impact of PUC D&Os(18,117) (40,011) (13,324) 1,343
 (240) 1,976
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)50,203
 51,459
 47,179
 1,082
 1,037
 1,310
Hawaiian Electric consolidated           
Service cost$58,796
 $64,262
 $47,597
 $3,284
 $3,870
 $3,392
Interest cost74,808
 70,529
 65,979
 9,337
 8,700
 8,234
Expected return on plan assets(91,633) (82,541) (72,661) (12,096) (11,495) (10,739)
Amortization of net prior service (gain) cost13
 40
 62
 (1,803) (1,804) (1,804)
Amortization of net actuarial losses22,693
 33,371
 18,459
 793
 1,754
 —
Net periodic pension/benefit cost64,677
 85,661
 59,436
 (485) 1,025
 (917)
Impact of PUC D&Os(18,117) (40,011) (13,324) 1,343
 (240) 1,976
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)$46,560
 $45,650
 $46,112
 $858
 $785
 $1,059
The estimated prior service credit and net actuarial loss for defined benefit plans that will be amortized from AOCI or regulatory assets into NPPC and NPBC during 2017 is as follows:
 HEI consolidated Hawaiian Electric consolidated
(in millions)Pension benefits Other benefits Pension benefits Other benefits
Estimated prior service credit$(0.1) $(1.8) $—
 $(1.8)
Net actuarial loss26.1
 1.5
 24.0
 1.4
The Company recorded pension expense of $33 million, $35 million and $32 million and OPEB expense of $1.0 million, $0.9 million and $1.2 million in 2016, 2015 and 2014, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $30 million, $29 million and $31 million and OPEB expense of $0.7 million, $0.7 million and $1.0 million in 2016, 2015 and 2014, respectively, and charged the remaining amounts primarily to electric utility plant.
The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2016, for the Company, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.1 million and the accumulated postretirement benefit obligation (APBO) by $3.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the APBO by $4.2 million. As of December 31, 2016, for the Utilities, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.1 million and the APBO by $3.4 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the APBO by $4.1 million.


Additional information on the defined benefit pension plans' accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), PBOs and assets were as follows:
 HEI consolidated Hawaiian Electric consolidated
December 312016 2015 2016 2015
(in billions)       
Defined benefit plans - ABOs
$1.7
 $1.6
 $1.5
 $1.4
Defined benefit plans with ABO in excess of plan assets       
     ABOs1.6
 1.5
 1.5
 1.4
     Plan assets1.3
 1.2
 1.2
 1.1
Defined benefit plans with PBOs in excess of plan assets       
     PBOs1.8
 1.7
 1.8
 1.6
     Plan assets1.3
 1.2
 1.2
 1.1
HEI consolidated. The Company estimates that the cash funding for the qualified defined benefit pension plans in 2017 will be $67 million, which should fully satisfy the minimum required contributions to those plans, including requirements of the Utilities’ pension tracking mechanisms and the Plan’s funding policy. The Company's current estimate of contributions to its other postretirement benefit plans in 2017 is $0.2 million.
As of December 31, 2016, the benefits expected to be paid under all retirement benefit plans in 2017, 2018, 2019, 2020, 2021 and 2022 through 2026 amount to $85 million, $89 million, $92 million, $97 million, $101 million and $570 million, respectively.
Hawaiian Electric consolidated. The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2017 will be $66 million, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanisms and the Plan’s funding policy. The Utilities' current estimate of contributions to its other postretirement benefit plans in 2017 is $0.2 million.
As of December 31, 2016, the benefits expected to be paid under all retirement benefit plans in 2017, 2018, 2019, 2020, 2021 and 2022 through 2026 amounted to $79 million, $81 million, $84 million, $89 million, $92 million and $522 million, respectively.
Defined contribution plans information.  The ASB 401(k) Plan is a defined contribution plan, which includes a discretionary employer profit sharing contribution by ASB (AmeriShare) and a matching contribution by ASB on the first 4% of employee deferrals (AmeriMatch).
Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan).
For 2016, 2015 and 2014, the Company’s expenses for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan were $5 million, $6 million and $5 million, respectively, and cash contributions were $5 million, $5 million and $5 million, respectively. The Utilities’ expenses and cash contributions for its defined contribution pension plan under the HEIRSP Plan for 2016, 2015 and 2014 were $1.5 million, $1.5 million and $0.9 million, respectively.
11 ·Share-based compensation
Under the 2010 Equity and Incentive Plan, as amended, HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights (SARs), restricted shares, restricted stock units, performance shares and other share-based and cash-based awards. The 2010 Equity and Incentive Plan (original EIP) was amended and restated effective March 1, 2014 (EIP) and an additional 1.5 million shares was added to the shares available for issuance under these programs.
As of December 31, 2016, approximately 3.4 million shares remained available for future issuance under the terms of the EIP, assuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards, including an estimated 0.3 million shares that could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals for awards outstanding under long-term incentive plans.


As of May 11, 2010 (when the 2010 Equity and Incentive Plan became effective), no new awards could be granted under the 1987 Stock Option and Incentive Plan, as amended (SOIP). Since by March 2015 all of the shares of common stock reserved for the outstanding SOIP grants and awards were issued or such grants and awards had expired, the remaining shares registered under the SOIP were deregistered and delisted.
For the SARs that were outstanding under the SOIP, the exercise price of each SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. SARs and related dividend equivalents issued in the form of stock awards generally became exercisable in installments of 25% each year for four years, and expired if not exercised ten years from the date of the grant. SARs compensation expense was recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each SAR grant was calculated on the date of grant using a Binomial Option Pricing Model. There were no outstanding SARs as of December 31, 2016.
The restricted shares that had been issued under the 2010 Equity and Incentive Plan became unrestricted in four equal annual increments on the anniversaries of the grant date and were forfeited to the extent they had not become unrestricted for terminations of employment during the vesting period, except accelerated vesting was provided for terminations by reason of death, disability and termination without cause. Restricted shares compensation expense had been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares were paid quarterly in cash. There were no outstanding restricted shares as of December 31, 2016.
Restricted stock units awarded under the 2010 Equity and Incentive Plan in 2016, 2015, 2014, and 2013 will vest and be issued in unrestricted stock in four equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become vested for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid at the end of the restriction period when the associated restricted stock units vest.
Stock performance awards granted under the 2014-2016 long-term incentive plan (LTIP) entitle the grantee to shares of common stock with dividend equivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.
Under the 2011 Nonemployee Director Stock Plan (2011 Director Plan), HEI can issue shares of common stock as compensation to nonemployee directors of HEI, Hawaiian Electric and ASB. As of December 31, 2016, there were 121,198 shares remaining available for future issuance under the 2011 Director Plan.
Share-based compensation expense and the related income tax benefit were as follows:
(in millions)2016
 2015
 2014
HEI consolidated     
Share-based compensation expense1
$4.8
 $6.5
 $9.3
Income tax benefit1.6
 2.3
 3.4
Hawaiian Electric consolidated     
Share-based compensation expense1
1.4
 1.9
 3.1
Income tax benefit0.5
 0.7
 1.2
1
For 2016, the Company has not capitalized any share-based compensation. $0.15 million and $0.16 million of this share-based compensation expense was capitalized in 2015 and 2014, respectively.


Stock awards. Nonemployee director awards totaling $0.2 million were paid in cash (in lieu of common stock) in July 2016. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:
(dollars in millions)2016
 2015
 2014
Shares granted19,846
 28,246
 33,170
Fair value$0.6
 $0.8
 $0.8
Income tax benefit0.2
 0.3
 0.3
The number of shares issued to each nonemployee director of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI Common Stock on the grant date.
Stock appreciation rights. Information about HEI’s SARs is summarized as follows:
 2015 2014
 Shares (1) Shares (1)
Outstanding, January 180,000
 $26.18
 164,000
 $26.12
Granted—
 —
 —
 —
Exercised(80,000) 26.18
 (22,000) 26.18
Forfeited—
 —
 (62,000) 26.02
Expired—
 —
 —
 —
Outstanding, December 31—
 $—
 80,000
 $26.18
Exercisable, December 31—
 $—
 80,000
 $26.18
(1)Weighted-average exercise price

SARs activity and statistics were as follows:
(in thousands)2015
 2014
Intrinsic value of shares exercised 1
$502
 $29
Tax benefit realized for the deduction of exercises82
 11
1
Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalent rights exceeds the exercise price of the right.
Restricted shares and restricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards was as follows:
  2014
  Shares (1)
Outstanding, January 1 4,503
 $22.21
Granted —
 —
Vested (4,503) 22.21
Forfeited —
 —
Outstanding, December 31 —
 $—
(1)Weighted-average grant-date fair value per share based on the closing or average price of HEI common stock on the date of grant.
For 2014, total restricted stock vested had a grant-date fair value of $0.1 million and the tax benefits realized for the tax deductions related to restricted stock awards was nil.


Restricted stock units.Information about HEI’s grants of restricted stock units was as follows:
 2016 2015 2014
 Shares 
 (1) Shares 
 (1) Shares 
 (1)
Outstanding, January 1210,634
 $28.82
 261,235
 $25.77
 288,151
 $25.17
Granted114,431
 29.70
 85,772
 33.69
 117,786
 25.17
Vested(85,003) 27.84
 (102,173) 25.67
 (144,702) 24.09
Forfeited(19,379) 29.82
 (34,200) 27.09
 —
 —
Outstanding, December 31220,683
 $29.57
 210,634
 $28.82
 261,235
 $25.77
Total weighted-average grant-date fair value of shares granted ($ millions)$3.4
   $2.9
   $3.0
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For 2016, 2015 and 2014, total restricted stock units and related dividends that vested had a fair value of $2.8 million, $3.7 million and $4.1 million, respectively, and the related tax benefits were $0.9 million, $1.1 million and $1.2 million, respectively.
As of December 31, 2016, there was $4.2 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.4 years.
Long-term incentive plan payable in stock.  The 2014-2016 LTIP provides for performance awards under the original EIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP period includes awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the three-year period. In addition, the 2014-2016 LTIP has performance goals related to levels of HEI weighted composite return on average common equity (ROACE), Hawaiian Electric consolidated ROACE and ASB net income - all based on the three-year averages, and ASB return on assets relative to performance peers. The 2015-2017 and the 2016-2018 LTIP provide for performance awards payable in cash and, thus, are not included in the tables below.
LTIP linked to TRS.  Information about HEI’s LTIP grants linked to TRS was as follows:
 2016 2015 2014
 Shares
 (1) Shares
 (1) Shares
 (1)
Outstanding, January 1162,500
 $27.66
 257,956
 $28.45
 232,127
 $32.88
Granted—
 —
 —
 —
 97,524
 22.95
Vested (lapsed because goal not met)(78,553) 32.69
 (75,915) 30.71
 (70,189) 35.46
Forfeited(841) 22.95
 (19,541) 26.25
 (1,506) 28.32
Outstanding, December 3183,106
 $22.95
 162,500
 $27.66
 257,956
 $28.45
Total weighted-average grant-date fair value of shares granted ($ millions)$—
   $—
   $2.2
  
(1)Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period.


The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:
  2014
Risk-free interest rate 0.66%
Expected life in years 3
Expected volatility 17.8%
Range of expected volatility for Peer Group 12.4% to 23.3%
Grant date fair value (per share) $22.95
For 2016, 2015 and 2014, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 2013-2015 LTIP, 2012-2014 LTIP and 2011-2013 LTIP were treated as lapsed because the TRS performance goal was not met.
As of December 31, 2016, there was no unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS.
LTIP awards linked to other performance conditions.  Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:
 2016 2015 2014
 Shares
 (1) Shares
 (1) Shares
 (1)
Outstanding, January 1222,647
 $26.02
 364,731
 $26.01
 296,843
 $26.14
Granted—
 —
 —
 —
 129,603
 25.18
Vested and settled(109,097) 26.89
 (121,249) 26.05
 (65,089) 24.95
Increase above target (cancelled)(1,989) 25.26
 3,412
 26.89
 4,949
 26.70
Forfeited(1,745) 25.19
 (24,247) 25.82
 (1,575) 26.07
Outstanding, December 31109,816
 $25.18
 222,647
 $26.02
 364,731
 $26.01
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)$—
   $—
   $3.3
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For 2016, 2015 and 2014, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $3.6 million, $4.7 million and $1.9 million, respectively, and the related tax benefits were $1.4 million, $1.8 million and $0.8 million, respectively.
As of December 31, 2016, there was no unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS.


12·Income taxes
The components of income taxes attributable to net income for common stock were as follows:
 HEI consolidated Hawaiian Electric consolidated
Years ended December 312016
 2015
 2014
 2016
 2015
 2014
(in thousands) 
  
  
      
Federal 
  
  
      
Current$59,873
 $44,343
 $(8,959) $952
 $—
 $1,108
Deferred43,666
 36,664
 91,412
 70,513
 68,757
 68,775
Deferred tax credits, net268
 318
 —
 268
 318
 —
 103,807
 81,325
 82,453
 71,733
 69,075
 69,883
State 
  
  
  
  
  
Current16,473
 2,402
 (5,793) 9,232
 (1,048) (9,436)
Deferred3,452
 4,768
 12,813
 3,873
 6,869
 14,172
Deferred tax credits, net(37) 4,526
 6,106
 (37) 4,526
 6,106
 19,888
 11,696
 13,126
 13,068
 10,347
 10,842
Total$123,695
 $93,021
 $95,579
 $84,801
 $79,422
 $80,725
A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the consolidated statements of income was as follows:
 HEI consolidated Hawaiian Electric consolidated
Years ended December 312016
 2015
 2014
 2016
 2015
 2014
(in thousands) 
  
  
      
Amount at the federal statutory income tax rate$130,844
 $89,176
 $92,959
 $80,190
 $75,996
 $77,126
Increase (decrease) resulting from: 
  
  
  
  
  
State income taxes, net of federal income tax benefit13,915
 8,097
 9,073
 8,494
 6,726
 7,047
Other, net(21,064) (4,252) (6,453) (3,883) (3,300) (3,448)
Total$123,695
 $93,021
 $95,579
 $84,801
 $79,422
 $80,725
Effective income tax rate33.1% 36.5% 36.0% 37.0% 36.6% 36.6%
The Company's effective tax rate decreased in 2016 compared to 2015 and 2014 primarily due to the deductibility of previously capitalized merger costs. Additionally, current taxable income provided capacity for the domestic production activities deduction.


The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:
 HEI consolidated Hawaiian Electric consolidated
December 312016
 2015
 2016
 2015
(in thousands) 
  
    
Deferred tax assets 
  
    
Net operating loss1
$—
 $—
 $9,158
 $37,283
Allowance for bad debts24,500
 21,781
 2,364
 1,852
Other47,201
 43,089
 18,720
 18,386
Total deferred tax assets71,701
 64,870
 30,242
 57,521
Deferred tax liabilities 
  
    
Property, plant and equipment related538,484
 492,441
 536,885
 489,884
Repairs deduction103,782
 104,081
 103,782
 104,081
Regulatory assets, excluding amounts attributable to property, plant and equipment35,107
 34,261
 35,107
 34,261
Deferred RAM and RBA revenues26,053
 26,400
 26,053
 26,400
Retirement benefits48,400
 42,006
 51,445
 44,991
Other48,681
 46,558
 10,629
 12,710
Total deferred tax liabilities800,507
 745,747
 763,901
 712,327
Net deferred income tax liability$728,806
 $680,877
 $733,659
 $654,806
1
The Hawaiian Electric deferred tax asset includes the tax effect of federal net operating loss carryforwards of $9 million expiring in 2034 and federal general business credit carryforwards of $3 million expiring in 2032 through 2036, net of unrecognized federal tax benefits of $3 million due to uncertain tax positions.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company and the Utilities will realize substantially all of the benefits of the deferred tax assets. As of December 31, 2016, the valuation allowance for deferred tax benefits is not significant. In 2016, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation enacted in the Protecting Americans from Tax Hikes (PATH) Act of 2015.
The Utilities are included in the consolidated federal and Hawaii income tax returns of HEI and are subject to the provisions of HEI’s tax sharing agreement, which determines each subsidiary’s (or subgroup's) income tax return liabilities and refunds on a standalone basis as if it filed a separate return (or subgroup consolidated return). Consequently, although HEI consolidated does not anticipate any unutilized net operating loss (NOL) as of December 31, 2016, standalone Hawaiian Electric consolidated expects an unutilized NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The Hawaiian Electric deferred tax asset associated with this NOL as of December 31, 2016 has decreased from December 31, 2015 as shown above.
The following is a reconciliation of the Company’s liability for unrecognized tax benefits for 2016, 2015 and 2014.
 HEI consolidated Hawaiian Electric consolidated
(in millions)2016
 2015
 2014
 2016
 2015
 2014
Unrecognized tax benefits, January 1$3.6
 $—
 $0.9
 $3.6
 $—
 0.5
Reductions based on tax positions taken during the year(0.1) —
 —
 (0.1) —
 —
Additions for tax positions of prior years0.3
 3.6
 0.1
 0.3
 3.6
 0.1
Settlements

 

 (1.0) —
 —
 (0.6)
Unrecognized tax benefits, December 31$3.8
 $3.6
 $—
 $3.8
 $3.6
 $—
HEI consolidated. The Company recognizes interest accrued related to unrecognized tax benefits in “Interest expense-other than on deposit liabilities and other bank borrowings” and penalties, if any, in operating expenses. In 2016, 2015 and 2014, the Company recognized approximately $0.2 million, $0.1 million and $(1.7) million in interest (income) expense. The credit adjustments to interest expense in 2014 were primarily due to the resolution of tax issues with the Internal Revenue Service (IRS). The Company had $0.3 million and $0.1 million of interest accrued as of December 31, 2016 and 2015, respectively.


Hawaiian Electric consolidated. The Utilities recognize interest accrued related to unrecognized tax benefits in “Interest expense-other than on deposit liabilities and other bank borrowings” and penalties, if any, in operating expenses. In 2016, 2015 and 2014, the Utilities recognized approximately $0.03 million, $0.1 million and $(0.7) million, respectively, in interest (income) expense. Additional interest expense related to the Utilities' unrecognized tax benefits was recognized at HEI Consolidated because of the Utilities NOL position. The credit adjustments to interest expense in 2014 were primarily due to the resolution of tax issues with the IRS. The Utilities had $0.1 million and $0.1 million of interest accrued as of December 31, 2016 and 2015, respectively.
As of December 31, 2016, the disclosures above present the Company’s and the Utilities' accruals for potential tax liabilities. Based on information currently available, the Company and the Utilities believe these accruals have adequately provided for potential income tax issues with federal and state tax authorities, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.
IRS examinations have been completed and settled through the tax year 2011 and the statute of limitations has tolled for tax year 2012, leaving subsequent years subject to IRS examination.  The tax years 2011 and subsequent are still subject to examination by the Hawaii Department of Taxation.
Recent tax developments. On December 18, 2015, Congress passed, and President Obama signed into law, the “Protecting Americans from Tax Hikes (PATH) Act of 2015” and the “Consolidating Appropriations Act, 2016,” providing government funding and a number of significant tax changes.
The provision with the greatest impact on the Company is the extension of bonus depreciation. The PATH Act continues 50% bonus depreciation through 2017, phases down the percentage to 40% in 2018 and 30% in 2019 and then terminates bonus depreciation thereafter. Tax depreciation is expected to increase by approximately $126 million in 2016 and result in increased accumulated deferred tax liabilities.
Additionally, the “Consolidating Appropriations Act, 2016” extended a variety of energy-related credits that were expired or were soon to expire. These credits include the production credit for wind facilities and the 30% investment credit for qualified solar energy property, with various phase-out dates through 2021.




13·Cash flows
Years ended December 312016
 2015
 2014
(in millions)     
Supplemental disclosures of cash flow information 
  
  
HEI consolidated     
Interest paid to non-affiliates$84
 $83
 $84
Income taxes paid55
 75
 47
Income taxes refunded45
 55
 24
Hawaiian Electric consolidated     
Interest paid to non-affiliates62
 61
 61
Income taxes paid1
 13
 6
Income taxes refunded20
 12
 8
Supplemental disclosures of noncash activities 
  
  
HEI consolidated     
Property, plant and equipment–change in unpaid invoices and accruals (investing)
14
 5
 43
Common stock dividends reinvested in HEI common stock (financing) 1
17
 —
 —
Loans transferred from held for investment to held for sale (investing)24
 —
 —
Real estate acquired in settlement of loans (investing)1
 1
 3
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing)1
 5
 —
Obligations to fund low income housing investments, net (operating)14
 4
 14
Hawaiian Electric consolidated     
Electric utility property, plant and equipment 
  
  
AFUDC-equity (operating)8
 7
 7
Estimated fair value of noncash contributions in aid of construction (investing)28
 3
 3
Change in unpaid invoices and accruals (investing)14
 5
 40
Refinancing of long-term debt (financing)—
 47
 —
1
The amounts shown represents common stock dividends reinvested in HEI common stock under the HEI DRIP in noncash transactions.
14·Regulatory restrictions on net assets
As of December 31, 2016, the Utilities could not transfer approximately $729 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.
ASB is required to notify the FRB and OCC prior to making any capital distribution (including dividends) to HEI (through ASB Hawaii). Generally, the FRB and OCC may disapprove or deny ASB’s request to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation or agreement between ASB and the OCC. As of December 31, 2016, ASB could transfer approximately $152 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.
HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.
15·Significant group concentrations of credit risk
Most of the Company’s business activity is with customers located in the State of Hawaii.
The Utilities are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. The Utilities provide the only electric public utility service on the islands they serve. The Utilities grant credit to customers, all of whom reside or conduct business in the State of Hawaii.


Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment securities it owns. Substantially all real estate loans receivable are collateralized by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination.
16·Fair value measurements
Fair value estimates are estimates of the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company and the Utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company or the Utilities were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s and the Utilities' financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
The Company and the Utilities group their financial assets measured at fair value in three levels outlined as follows:
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.
Classification in the hierarchy is based upon the lowest level input that is significant to the fair value measurement of the asset or liability. For instruments classified in Level 1 and 2 where inputs are primarily based upon observable market data, there is less judgment applied in arriving at the fair value. For instruments classified in Level 3, management judgment is more significant due to the lack of observable market data.
Fair value is also used on a nonrecurring basis to evaluate certain assets for impairment or for disclosure purposes. Examples of nonrecurring uses of fair value include mortgage servicing rights accounted for by the amortization method, loan impairments for certain loans, real estate acquired in settlement of loans, goodwill and asset retirement obligations (AROs).
Earnings per share (HEI only).  Basic earnings per share (EPS) is computed by dividing net income for common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that dilutive common shares for stock compensation is added to the denominator. There were 0 shares of antidilutive securities outstanding during the years ended December 31, 2019, 2018 and 2017.
Impairment of long-lived assets and long-lived assets to be disposed of.  The Company and the Utilities review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.
Recent accounting pronouncements.
Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, “Leases (Topic 842),” which requires that lessees recognize a liability to make lease payments (the lease liability) and a right-of-use (ROU) asset, representing its right to use the underlying asset for the lease term, for all leases (except short-term leases) at the commencement date. For finance leases, a lessee is required to recognize interest on the lease liability separately from amortization of the ROU asset in the consolidated statements of income. For operating leases, a lessee is required to recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis.
The Company adopted ASU No. 2016-02 on January 1, 2019 and used the effective date as the date of initial application. Consequently, financial information for dates and periods before January 1, 2019 will not be updated and the disclosures required under the new standard will not be provided (i.e., the Company will continue to report prior comparative periods

92

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


presented in the financial statements under Accounting Standards Codification (ASC) 840, including the required disclosures under ASC 840).
The most significant effect of the new standard relates to the recognition of new ROU assets and lease liabilities on the Company’s balance sheet for purchase power agreements and real estate operating leases. On adoption, the Company recognized additional lease liabilities of approximately $257 million for the Company and approximately $236 million for the Utilities ($215 million related to PPAs), based on the present value of the remaining minimum rental payments, with corresponding ROU assets for existing operating leases, under current leasing standards. In determining the lease liability upon transition, the Company used the incremental borrowing rates as of the adoption date based on the remaining lease term and remaining lease payments. See Note 8 for more information.
Credit losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. ASU No. 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts) and enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. In addition, ASU No. 2016-13 amends the accounting for credit losses on available-for-sale (AFS) debt securities and purchased financial assets with credit deterioration. The other-than-temporary impairment model of accounting for credit losses on AFS debt securities will be replaced with an estimate of expected credit losses only when the fair value is below the amortized cost of the asset. The length of time the fair value of an AFS debt security has been below the amortized cost will no longer impact the determination of whether a credit loss exists. The AFS debt security model will also require the use of an allowance to record the estimated losses (and subsequent recoveries). The Company and Utilities will adopt ASU No. 2016-13 using an effective date of January 1, 2020 and will apply the guidance using a modified retrospective basis with the cumulative effect of initially applying the amendments to be recognized in retained earnings as of January 1, 2020.

The allowance for credit losses (ACL) is a material estimate of the Company. As a result of the change from an incurred loss model to a methodology that considers the credit loss over the expected life of the loan, the Company expects to record, upon completing its final analysis, an adjustment between $18 million to $22 million to increase the ACL, with a corresponding adjustment to reduce retained earnings as of January 1, 2020. The ACL is based on the composition, characteristics and quality of the loans and off balance sheet credit exposures as well as the prevailing economic conditions as of the adoption date. The increase to the ACL for the loan portfolio will result in a decrease to retained earnings and regulatory capital amounts and ratios. However, ASB expects to remain well capitalized under the regulatory framework after the adoption of ASU No. 2016-13. Based on the credit quality of the Company’s existing held-to-maturity and AFS investment securities portfolio, the Company will not recognize an ACL at adoption for those investments. The adoption of the new standard did not have a material impact to the Utilities’ customer and other accounts receivables and accrued unbilled revenue.
Compensation-retirement benefits-defined benefit plans. In August 2018, the FASB issued ASU No. 2018-14, “Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans,” which makes minor changes to the disclosure requirements for employers that sponsor defined benefit pension and/or other postretirement benefit plans. The new guidance eliminates requirements for certain disclosures that are no longer considered cost beneficial and requires new ones that the FASB considers pertinent. ASU No. 2018-14 is effective for fiscal years ending after December 15, 2020. The Company early adopted ASU No. 2018-14, effective for the year ended December 31, 2019, and applied the amended disclosure requirements to all periods presented. See Note 10 for additional information regarding the Company’s employee benefit plans.
Codification Improvements. In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which is intended to clarify certain issues related to the accounting for financial instruments.
•
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

93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


to transfers between classifications or categories for loans and debt securities, recoveries, variable interest rates and prepayments, vintage disclosures, and contractual extensions and renewal options.
•
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.

The amended guidance in ASU No. 2019-04 is effective for fiscal years and interim periods beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU No. 2019-04 in the first quarter of 2020 and the impact of the ASU on the Company’s consolidated financial statements was not material.
Reclassifications. Certain reclassifications have been made to prior years’ financial statements to conform to the 2019 presentation, which did not affect previously reported results of operations.
Electric utility

Regulation by the Public Utilities Commission of the State of Hawaii (PUC). The Utilities are regulated by the PUC and account for the effects of regulation under FASB ASC Topic 980, “Regulated Operations.” As a result, the Utilities’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations (see Note 3—“Regulatory assets and liabilities”). Their continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to, and collected from, customers.
The rate schedules of the Utilities include energy costs recovery clauses (ECRCs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules also include purchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECRCs and PPACs are required to be reconciled quarterly.
Accounts receivable.  Accounts receivable are recorded at the invoiced amount. The Utilities generally assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Utilities’ best estimate of the amount of probable credit losses in the Utilities’ existing accounts receivable. At December 31, 2019 and 2018, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $1.4 million and $1.5 million, respectively.
Electric utility revenues.  Revenues related to electric service are generally recorded when service is rendered and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. The Utilities also record revenue under a decoupling mechanism. See “Decoupling” discussion in Note 3 - Electric Utility segment.
Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.
Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.
The weighted-average AFUDC rate was 7.4% in 2019, 7.3% in 2018 and 7.7% in 2017, and reflected quarterly compounding.
Bank (HEI only)
Investment securities.  Investments in debt securities are classified as held-to-maturity (HTM), trading or available-for-sale (AFS). ASB determines the appropriate classification at the time of purchase. Debt securities that ASB intends to and has the ability to hold to maturity are classified as HTM securities and reported at amortized cost. Marketable debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable debt securities not classified as either HTM or trading securities are classified as AFS and reported at fair value. Unrealized gains and losses for AFS securities are excluded from earnings and reported on a net basis in accumulated other comprehensive income (AOCI) until realized.

94

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Interest income is recorded on an accrual basis. Discounts and premiums on securities are accreted or amortized into interest income using the interest method over the remaining contractual lives of the agency obligation securities and the estimated lives of the mortgage-backed securities adjusted for anticipated prepayments. ASB uses actual prepayment experience and estimates of future prepayments to determine the constant effective yield necessary to apply the interest method of income recognition. The discounts and premiums on the agency obligations portfolio are accreted or amortized on a prospective basis using expected contractual cash flows. The discounts and premiums on the mortgage-backed securities portfolio are accreted or amortized on a retrospective basis using changes in anticipated prepayments. This method requires a retrospective adjustment of the effective yield each time ASB changes the estimated life as if the new estimate had been known since the original acquisition date of the securities. Estimates of future prepayments are based on the underlying collateral characteristics and historic or projected prepayment behavior of each security. The specific identification method is used in determining realized gains and losses on the sales of securities.
For securities that are not trading securities, individual securities are assessed for impairment at least on a quarterly basis, and more frequently when economic or market conditions warrant. A security is impaired if the fair value of the security is less than its carrying value at the financial statement date. When a security is impaired, ASB determines whether this impairment is temporary or other-than-temporary. If ASB does not expect to recover the entire amortized cost basis of the security or there is a change in the expected cash flows, an OTTI exists. If ASB intends to sell the security, or will more likely than not be required to sell the security before recovery of its amortized cost, the OTTI must be recognized in earnings. If ASB does not intend to sell the security, and it is not more likely than not that ASB will be required to sell the security before recovery of its amortized cost, the OTTI must be separated into the amount representing the credit loss and the amount related to all other factors. The amount of OTTI related to the credit loss is recognized in earnings, while the remaining OTTI is recognized in AOCI. Based on ASB’s evaluation as of December 31, 2019, 2018 and 2017, there was 0 indicated impairment as ASB expects to collect the contractual cash flows for these investments.
Stock in Federal Home Loan Bank (FHLB) is carried at cost and is reviewed at least quarterly for impairment, with valuation adjustments recognized in noninterest income.
Loans.  ASB carries loans at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method.
Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over periods not exceeding the contractual life of the loan using the interest method or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.
Loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held for sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.
Allowance for loan losses.  ASB maintains an allowance for loan losses to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). The allowance for loan losses is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.
ASB disaggregates its portfolio loans into portfolio segments for purposes of determining the allowance for loan losses. Commercial, commercial real estate, and commercial construction loans are defined as non-homogeneous loans and ASB utilizes a risk rating system for evaluating the credit quality of the loans. Non-homogeneous loans are also categorized into the regulatory asset quality classifications—Pass, Special Mention, Substandard, Doubtful, and Loss based on credit quality. ASB utilizes a numerical-based, risk rating “PD Model” that takes into consideration fiscal year-end financial information of the borrower and identified financial attributes including retained earnings, operating cash flows, interest coverage, liquidity and

95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


leverage that demonstrate a strong correlation with default to assign default probabilities at the borrower level. In addition, a loss given default (LGD) value is assigned to each loan to measure loss in the event of default based on loan specific features such as collateral that mitigates the amount of loss in the event of default.
Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB supplements performance data with external credit bureau data and credit scores such as the Fair Isaac Corporation (FICO) score on a quarterly basis. ASB has built portfolio loss models for each major segment based on the combination of internal and external data to predict the probability of default at the loan level.
ASB also considers qualitative factors in determining the allowance for loan losses. These include but are not limited to adjustments for changes in policies and procedures in underwriting, monitoring or collections, economic conditions, portfolio mix, lending and risk management personnel, results of internal audit and quality control reviews, collateral values and any concentrations of credit.
The reserve for unfunded commitments is maintained at a level believed by management to be sufficient to absorb estimated probable losses related to unfunded credit facilities and is included in accounts payable and other liabilities in the consolidated balance sheets. The determination of the adequacy of the reserve is based upon an evaluation of the unfunded credit facilities, including an assessment of historical commitment utilization experience, credit risk grading and historical loss rates. This process takes into consideration the same risk elements that are analyzed in the determination of the adequacy of the allowance for loan losses, as discussed above. Net adjustments to the reserve for unfunded commitments are included in other noninterest expense in the consolidated statements of income.
The allowance for loan losses is based on currently available information and historical experience, and future adjustments may be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.
Nonperforming loans. Loans are generally placed on nonaccrual status when contractually past due 90 days or more, or earlier if the probability of collection is insufficient to warrant further accrual. All interest that is accrued but not collected is reversed. A loan may be returned to accrual status if (i) principal and interest payments have been brought current and repayment of the remaining contractual principal and interest is expected to be made, (ii) the loan has otherwise become well-secured and in the process of collection, or (iii) the borrower has been making regularly scheduled payments in full for the prior six months and it is reasonably assured that the loan will be brought fully current within a reasonable period. Cash receipts on nonaccruing loans are generally applied to reduce the unpaid principal balance.
Loans considered to be uncollectible are charged-off against the allowance for loan losses. The amount and timing of charge-offs on loans includes consideration of the loan type, length of delinquency, insufficiency of collateral value, lien priority and the overall financial condition of the borrower. Recoveries on loans previously charged-off are credited back to the allowance for loan losses. Loans that have been charged-off against the allowance for loan losses are periodically monitored to evaluate whether further adjustments to the allowance are necessary.
Loans in the commercial and commercial real estate portfolio are charged-off when the loan is risk rated “Doubtful” or “Loss.” The loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A commercial or commercial real estate loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 90 days or more; (b) significant improvement in the borrower’s repayment capacity is doubtful; and/or (c) collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist.
Loans in the residential mortgage and home equity portfolios are charged-off when the loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. Such loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 180 days or more; (b) it is probable that collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist; (c) notification of the borrower’s bankruptcy is received or the borrower’s debt is discharged in bankruptcy and the loan is not reaffirmed; or (d) in cases where ASB is in a subordinate position to other debt, the senior lien holder has foreclosed and ASB’s junior lien is extinguished.
Other consumer loans are generally charged-off when the balance becomes 120 days delinquent.

96

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Loans modified in a troubled debt restructuring. Loans are considered to have been modified in a troubled debt restructuring (TDR) when, due to a borrower’s financial difficulties, ASB makes concessions to the borrower that it would not otherwise consider for a non-troubled borrower. Modifications may include interest rate reductions, interest only payments for an extended period of time, protracted terms such as amortization and maturity beyond the customary length of time found in the normal market place, and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual loan that has been modified in a TDR remains on nonaccrual status until the borrower has demonstrated sustained repayment performance for a period of six consecutive months. However, performance prior to the modification, or significant events that coincide with the modification, are included in assessing whether the borrower can meet the new terms and may result in the loan being returned to accrual status at the time of loan modification or after a shorter performance period. If the borrower’s ability to meet the revised payment schedule is uncertain, or there is reasonable doubt over the full collectability of principal and interest, the loan remains on nonaccrual status.
Real estate acquired in settlement of loans.  ASB records real estate acquired in settlement of loans at fair value, less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. Costs related to holding real estate are charged to operations as incurred.
Goodwill. Goodwill is initially recorded as the excess of the purchase price over the fair value of the net assets acquired in a business combination and is subsequently evaluated at least annually for impairment during the fourth quarter. At December 31, 2019 and 2018, the amount of goodwill was $82.2 million. The goodwill relates to ASB and is the Company’s only intangible asset with an indefinite useful life.
To determine if there was an impairment to the book value of goodwill pertaining to ASB, the fair value of ASB was estimated using a valuation method based on a market approach and discounted cash flow method with each method having an equal weighting in determining the fair value of ASB. The market approach considers publicly traded financial institutions and measures the institutions’ market values as a multiple to (1) net income and (2) book equity. The median market value multiples for net income and book equity from the selected institutions were applied to ASB’s net income and book equity to calculate ASB’s fair value using the market approach. The discounted cash flow method values a company on a going concern basis and is based on the concept that the future benefits derived from a particular company can be measured by its sustainable after-tax cash flows in the future. For the three years ended December 31, 2019, there has been 0 impairment of goodwill.
Mortgage banking. Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held-for-sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold. ASB is obligated to subsequently repurchase a loan if the purchaser discovers a standard representation or warranty violation such as noncompliance with eligibility requirements, customer fraud or servicing violations. This primarily occurs during a loan file review. ASB considers and records a reserve for loan repurchases if appropriate.
ASB recognizes a mortgage servicing asset when a mortgage loan is sold with servicing rights retained. This mortgage servicing right (MSR) is initially capitalized at its presumed fair value based on market data at the time of sale and accounted for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing assets or liabilities are included as a component of gain on sale of loans. Under ASC Topic 860, “Transfers and Servicing,” ASB amortizes the MSRs in proportion to and over the period of estimated net servicing income and assess for impairment at each reporting date.
ASB’s MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15- and 30-year mortgages and note rate in bands primarily of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others.
ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. Because observable market prices with exact terms and conditions may not be readily available, ASB compares the fair value of MSRs to an estimated value calculated by an independent third-party on a semi-annual basis. The third-party relies on both published and unpublished sources of market related assumptions and its own experience and expertise to arrive at a value. ASB uses the third-party value only to assess the reasonableness of fair value generated by the valuation model.
Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in “Revenues - bank” in the consolidated

97

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.
Loan servicing fee income represents income earned for servicing mortgage loans owned by investors. It includes mortgage servicing fees and other ancillary servicing income, net of guaranty fees. Servicing fees are generally calculated on the outstanding principal balances of the loans serviced and are recorded as income when earned.
Tax credit investments. ASB invests in limited liability entities formed to operate qualifying affordable housing projects.
The affordable housing investments provide tax benefits to investors in the form of tax deductions from operating losses and tax credits. As a limited partner, ASB has no significant influence over the operations. These investments are initially recorded at the initial capital contribution with a liability recognized for the commitment to contribute additional capital over the term of the investment.
ASB uses the proportional amortization method of accounting for its investments. Under the proportional amortization method, ASB amortizes the cost of its investments in proportion to the tax credits and other tax benefits it receives. The amortization, tax credits and tax benefits are reported as a component of income tax expense.
For these limited liability entities, ASB assesses whether it is the primary beneficiary of the limited liability entity, which is a variable interest entity (VIE). The primary beneficiary of a VIE is determined to be the party that meets both of the following criteria: (i) has the power to make decisions that most significantly affect the economic performance of the VIE; and (ii) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. Generally, ASB, as a limited partner, is not deemed to be the primary beneficiary as it does not meet the power criterion, i.e., no power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and no direct ability to unilaterally remove the general partner.
All tax credit investments are evaluated for potential impairment at least annually, or more frequently, when events or conditions indicate that it is deemed probable that ASB will not recover its investment. If an investment is determined to be impaired, it is written down to its estimated fair value and the new cost basis of the investment is not adjusted for subsequent recoveries in value. As of December 31, 2019, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its low-income housing tax credit (LIHTC) investments.
At December 31, 2019 and 2018, the carrying amount of LIHTC investments was $66.3 million and $67.6 million, respectively, and included in other assets in the consolidated balance sheets.
ASB’s unfunded commitments to fund its LIHTC investment partnerships were $23.4 million and $18.1 million as of December 31, 2019 and 2018, respectively. These unfunded commitments are unconditional and legally binding and are recorded in other liabilities with a corresponding increase in other assets. As of December 31, 2019, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investment partnerships.
The table below summarizes the amounts in income tax expense related to ASB’s LIHTC investments:
Years ended December 312019
 2018
 2017
(in millions) 
  
  
Amounts in income taxes related to low-income housing tax credit investments 
  
  
   Amortization recognized in the provision for income taxes$(7.9) $(7.7) $(7.4)
   Tax credits and other tax benefits recognized in the provision for income taxes11.9
 10.9
 10.7
         Net benefit to income tax expense$4.0
 $3.2
 $3.3


98


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 2 · Segment financial information
The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described for the Company in the summary of significant accounting policies, except as otherwise indicated and except that federal and state income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on net income. Each segment accounts for intersegment sales and transfers as if the sales and transfers were to third parties (i.e., at current market prices). Intersegment revenues consist primarily of Hamakua Energy revenues, interest, rent and preferred stock dividends.
Electric utility
Hawaiian Electric and its wholly owned operating subsidiaries, Hawaii Electric Light and Maui Electric, are public electric utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. The utility subsidiaries are aggregated within the electric utility segment because they: (1) are involved in the business of supplying electric energy in the same geographical location (i.e., the State of Hawaii), (2) have similar production processes that comprise electric generation, (3) serve similar customers within their franchise territories (e.g., residential, commercial and industrial customers), (4) use similar electric grids to distribute the energy to their customers, (5) are regulated by the PUC and undergo similar rate-making processes, (6) have similar economic characteristics and (7) perform financial reporting oversight and management of the business at the consolidated level.
Bank
ASB is a federally chartered savings bank that provides a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System.
Other
“Other” includes amounts for the holding companies (HEI and ASB Hawaii, Inc.), Pacific Current, and other subsidiaries not qualifying as reportable segments, and intercompany eliminations.
Pacific Current. Pacific Current was formed in September 2017 to focus on investing in non-regulated renewable energy and sustainable infrastructure in the State of Hawaii to help achieve the state’s sustainability goals. Significant investments of Pacific Current made through its subsidiaries, Hamakua Energy, LLC and Mauo, LLC, include:
Hamakua power plant. On November 24, 2017, Hamakua Energy, LLC acquired Hamakua Energy Partners, L.P.’s 60-MW combined cycle power plant and other assets from affiliates of ArcLight Capital Partners, a private equity firm. The plant sells all the power it produces to Hawaii Electric Light under an existing power purchase agreement (PPA) that expires in 2030.
Solar + Storage Power Purchase Agreement (PPA). On February 2, 2018, Mauo, LLC executed definitive agreements to acquire a solar-plus-storage PPA for a multi-site, commercial-scale project that will provide 8.6 MW of solar capacity and 42.3 MWH of storage capacity on the islands of Maui and Oahu. The PPA has a 15-year term with an option to extend for an additional five years. The system is currently being constructed by a third party contractor under an Engineering, Procurement and Construction (EPC) contract that was contemporaneously negotiated and executed by Mauo, LLC. The EPC contract provides a fixed price for the purchase of the completed system, a project completion schedule and performance obligations designed to match the requirements of the PPA. Mauo, LLC is funding the construction of the project with a construction facility that will be repaid at the commercial operation date (ultimately with cash from investment tax credits, state renewable tax credits, non-recourse project debt, and equity). There are 5 separate project sites, which are expected to be placed into service during 2020.

99


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Segment financial information was as follows:
(in thousands)Electric utility
 Bank
 Other
 Total
2019 
  
  
  
Revenues from external customers$2,545,865
 $328,570
 $166
 $2,874,601
Intersegment revenues (eliminations)77
 —
 (77) —
Revenues2,545,942
 328,570
 89
 2,874,601
Depreciation and amortization245,362
 28,675
 4,076
 278,113
Interest expense, net70,842
 18,440
 20,057
 109,339
Income (loss) before income taxes197,140
 112,034
 (37,765) 271,409
Income taxes (benefit)38,305
 23,061
 (9,729) 51,637
Net income (loss)158,835
 88,973
 (28,036) 219,772
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income (loss) for common stock156,840
 88,973
 (27,931) 217,882
Capital expenditures419,898
 24,175
 13,447
 457,520
Assets (at December 31, 2019)6,388,682
 7,233,017
 123,552
 13,745,251
2018 
  
  
  
Revenues from external customers$2,546,472
 $314,275
 $102
 $2,860,849
Intersegment revenues (eliminations)53
 —
 (53) —
Revenues2,546,525
 314,275
 49
 2,860,849
Depreciation and amortization230,228
 21,443
 3,958
 255,629
Interest expense, net73,348
 15,539
 15,329
 104,216
Income (loss) before income taxes180,426
 106,578
 (32,543) 254,461
Income taxes (benefit)34,778
 24,069
 (8,050) 50,797
Net income (loss)145,648
 82,509
 (24,493) 203,664
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income (loss) for common stock143,653
 82,509
 (24,388) 201,774
Capital expenditures1
415,264
 72,666
 18,840
 537,369
Assets (at December 31, 2018)5,967,503
 7,027,894
 108,654
 13,104,051
        
2017 
  
  
  
Revenues from external customers$2,257,455
 $297,640
 $530
 $2,555,625
Intersegment revenues (eliminations)111
 —
 (111) —
Revenues2,257,566
 297,640
 419
 2,555,625
Depreciation and amortization201,282
 19,416
 1,300
 221,998
Interest expense, net69,637
 12,156
 9,335
 91,128
Income (loss) before income taxes205,145
 98,716
 (27,281) 276,580
Income taxes (benefit)83,199
 31,719
 (5,525) 109,393
Net income (loss)121,946
 66,997
 (21,756) 167,187
Preferred stock dividends of subsidiaries1,995
 —
 (105) 1,890
Net income (loss) for common stock119,951
 66,997
 (21,651) 165,297
Capital expenditures1
376,865
 53,272
 317
 495,187
Assets (at December 31, 2017)5,630,613
 6,798,659
 104,888
 12,534,160

1
Contributions in aid of construction balances are included in capital expenditures.
Intercompany electricity sales of the Utilities to ASB and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by the Utilities and the profit on such sales is nominal.
Bank fees that ASB charges the Utilities and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution and the profit on such fees is nominal.
Hamakua Energy’s sales to Hawaii Electric Light (a regulated affiliate) are eliminated in consolidation.

100

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 3 · Electric utility segment
Regulatory assets and liabilities.  Regulatory assets represent deferred costs and accrued decoupling revenues which are expected to be recovered through rates over PUC-authorized periods. Generally, the Utilities do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future, or amounts collected in excess of costs incurred that are refundable to customers. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, the Utilities include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. In the table below, noted in parentheses are the original PUC authorized amortization or recovery periods and, if different, the remaining amortization or recovery periods as of December 31, 2019 are noted.
Regulatory assets were as follows:
December 312019
 2018
(in thousands) 
  
Retirement benefit plans (balance primarily varies with plans’ funded statuses)$554,485
 $624,126
Income taxes (1-55 years)102,612
 114,076
Decoupling revenue balancing account and RAM (1-2 years)—
 49,560
Unamortized expense and premiums on retired debt and equity issuances (1-20 years; 1-19 years remaining)10,228
 10,065
Vacation earned, but not yet taken (1 year)12,535
 10,820
Other (1-39 years remaining)35,220
 24,779
Total regulatory assets$715,080
 $833,426
Included in: 
  
Current assets$30,710
 $71,016
Long-term assets684,370
 762,410
Total regulatory assets$715,080
 $833,426

Regulatory liabilities were as follows:
December 312019
 2018
(in thousands) 
  
Cost of removal in excess of salvage value (1-60 years)$521,977
 $491,006
Income taxes (1-55 years)386,990
 413,339
Decoupling revenue balancing account and RAM (1-2 years)16,370
 —
Retirement benefit plans (balance primarily varies with plans’ funded statuses)21,707
 19,129
Other (1-19 years remaining)25,266
 26,762
Total regulatory liabilities$972,310
 $950,236
Included in:   
Current liabilities$30,724
 $17,977
Long-term liabilities941,586
 932,259
Total regulatory liabilities$972,310
 $950,236

The regulatory asset and liability relating to retirement benefit plans was recorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for the Utilities in 2007 (see Note 10).
Major customers.  The Utilities received 11% ($281 million), 11% ($273 million) and 11% ($239 million) of their operating revenues from the sale of electricity to various federal government agencies in 2019, 2018 and 2017, respectively.

101

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Cumulative preferred stock. The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:
December 31, 2019
Voluntary
liquidation price
 
Redemption
price
Series 
  
C, D, E, H, J and K (Hawaiian Electric)$20
 $21
I (Hawaiian Electric)20
 20
G (Hawaii Electric Light)100
 100
H (Maui Electric)100
 100

Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric’s obligation to make payments on its own preferred stock.
Related-party transactions. HEI charged the Utilities $6.0 million, $5.9 million and $6.2 million for general management and administrative services in 2019, 2018 and 2017, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.
For the years ended December 31, 2019 and December 31, 2018, Hamakua Energy, LLC (an indirect subsidiary of HEI) sold energy and capacity to Hawaii Electric Light (subsidiary of Hawaiian Electric and indirect subsidiary of HEI) under a PPA in the amount of $68 million and $56 million, respectively.
Hawaiian Electric’s short-term borrowings from HEI totaled NaN at December 31, 2019 and 2018. Borrowings among the Utilities are eliminated in consolidation. Interest charged by HEI to Hawaiian Electric was not material for the years ended December 31, 2019 and 2018.
HECO Capital Trust III.Trust III, a wholly-owned unconsolidated subsidiary of Hawaiian Electric, was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to Hawaiian Electric, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by Hawaiian Electric in the principal amount of $31.5 million and issued by Hawaii Electric Light and Maui Electric each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. On May 15, 2019, Trust III redeemed $50 million of its outstanding 2004 Trust Preferred Securities and $1.5 million of trust common securities. Subsequently a Certificate of Cancellation of Statutory Trust was filed with the Delaware Secretary of State in order to cancel the Trust III, which became effective on June 10, 2019.
For the year-to-date period ending on the Trust’s cancellation date on June 10, 2019, Trust III’s income statement consisted of $1.2 million of interest income received from the 2004 Debentures; $1.2 million of distributions to holders of the Trust Preferred Securities; and $37,000 of common dividends on the trust common securities to Hawaiian Electric.
Unconsolidated variable interest entities.
Power purchase agreements.  As of December 31, 2019, the Utilities had 4 PPAs for firm capacity (excluding the PGV PPA as Puna Geothermal Venture (PGV) has been offline since May 2018 due to lava flow on Hawaii Island) and other PPAs with independent power producers (IPPs) and Schedule Q providers (i.e., customers with cogeneration and/or power production facilities who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs.
Pursuant to the current accounting standards for VIEs, the Utilities are deemed to have a variable interest in Kalaeloa Partners, L.P. (Kalaeloa), AES Hawaii, Inc. (AES Hawaii) and Hamakua Energy by reason of the provisions of the PPA that the Utilities have with the 3 IPPs. However, management has concluded that the Utilities are not the primary beneficiary of Kalaeloa, AES Hawaii and Hamakua Energy because the Utilities do not have the power to direct the activities that most significantly impact the 3 IPPs’ economic performance nor the obligation to absorb their expected losses, if any, that could potentially be significant to the IPPs. Thus, the Utilities have not consolidated Kalaeloa, AES Hawaii and Hamakua Energy in its consolidated financial statements. Hamakua Energy is an indirect subsidiary of Pacific Current, and is consolidated in HEI’s consolidated financial statements.
For the other PPAs with IPPs, the Utilities have concluded that the consolidation of the IPPs was not required because either the Utilities do not have variable interests in the IPPs due to the absence of an obligation in the PPAs for the Utilities to absorb any variability of the IPPs, or the IPP was considered a “governmental organization,” and thus excluded from the scope of

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accounting standards for VIEs. NaN IPPs of as-available energy declined to provide the information necessary for Utilities to determine the applicability of accounting standards for VIEs.
If information is ultimately received from the IPPs, a possible outcome of future analyses of such information is the consolidation of 1 or both of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs to the IPP.
Commitments and contingencies.
Contingencies. The Utilities are subject in the normal course of business to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial position. However, the Utilities cannot rule out the possibility that such outcomes could have a material effect on the results of operations or liquidity for a particular reporting period in the future.
Power purchase agreements.  Purchases from all IPPs were as follows: 
Years ended December 31 2019
 2018
 2017
(in millions)      
Kalaeloa $214
 $216
 $180
AES Hawaii 139
 140
 140
HPOWER 76
 69
 67
Puna Geothermal Venture —
 15
 38
Hamakua Energy 68
 56
 35
Wind IPPs 95
 107
 97
Solar IPPs 36
 29
 27
Other IPPs1
 5
 7
 3
Total IPPs $633
 $639
 $587

1 Includes hydro power and other PPAs
As of December 31, 2019, the Utilities had 4 firm capacity PPAs for a total of 516.5 megawatts (MW) of firm capacity. Since May 2018, PGV facility with 34.6 MW of firm capacity has been offline due to lava flow on Hawaii Island. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term (and as amended) and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $51 million in 2020, $38 million each in 2021, 2022, 2023 and 2024, and $241 million from 2025 through 2033.
In general, the Utilities base their payments under the PPAs upon available capacity and actual energy supplied and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. The Utilities pass on changes in the fuel component of the energy charges to customers through the ECRC in their rate schedules. The Utilities do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to Hawaiian Electric or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.
Purchase power adjustment clause. The PUC has approved purchased power adjustment clauses (PPACs) for the Utilities. Purchased power capacity, O&M and other non-energy costs previously recovered through base rates are now recovered in the PPACs and, subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs outside of a rate case. Purchased energy costs continue to be recovered through the ECRC.
Kalaeloa Partners, L.P.  Under a 1988 PPA, as amended, Hawaiian Electric is committed to purchase 208 MW of firm capacity from Kalaeloa. Hawaiian Electric and Kalaeloa are currently in negotiations to address the PPA term that ended on May 23, 2016. The PPA automatically extends on a month-to-month basis as long as the parties are still negotiating in good faith. Hawaiian Electric and Kalaeloa have agreed that neither party will terminate the PPA (which has been subject to automatic extension on a month-to-month basis) prior to July 31, 2020, to allow for a negotiated resolution and PUC approval.

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AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended (through Amendment No. 2) for a period of 30 years ending September 2022, Hawaiian Electric agreed to purchase 180 MW of firm capacity from AES Hawaii. Hawaiian Electric and AES Hawaii have been in dispute over an additional 9 MW of capacity. In February 2018, Hawaiian Electric reached agreement with AES Hawaii on an amendment to the PPA. However, in June 2018, the PUC issued an order suspending review of the amendment pending a DOH decision on AES Hawaii’s request for approval of its Emission Reduction Plan and partnership with Hawaiian Electric. If approved by the PUC, the amendment will resolve AES Hawaii’s claims related to the additional capacity.
Hu Honua Bioenergy, LLC (Hu Honua). In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii. Under the terms of the PPA, the Hu Honua plant was scheduled to be in service in 2016. However, Hu Honua encountered construction and litigation delays, which resulted in an amended and restated PPA between Hawaii Electric Light and Hu Honua dated May 5, 2017. In July 2017, the PUC approved the amended and restated PPA, which becomes effective once the PUC’s order is final and non-appealable. In August 2017, the PUC’s approval was appealed by a third party. On May 10, 2019, the Hawaii Supreme Court issued a decision remanding the matter to the PUC for further proceedings consistent with the court’s decision which must include express consideration of Green House Gas emissions that would result from approving the PPA, whether the cost of energy under the PPA is reasonable in light of the potential for GHG emissions, and whether the terms of the PPA are prudent and in the public interest, in light of its potential hidden and long-term consequences. On June 20, 2019, the PUC issued an order reopening the docket for further proceedings. On September 29, 2019, the PUC issued an order setting the procedural schedule for the matter and on December 20, 2019, issued an order modifying the procedural schedule. Pre-hearing matters will be conducted through March 6, 2020. Thereafter, the PUC will set the date for an evidentiary hearing and post-hearing briefing. Hu Honua expected to complete construction of the plant in the fourth quarter of 2019, but has been delayed.
Utility projects.  Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, or if PUC-imposed caps on project costs are expected to be exceeded, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.
Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) implementation project. On August 11, 2016, the PUC approved the Utilities’ request to commence the ERP/EAM implementation project, subject to certain conditions, including a $77.6 million cap on cost recovery as well as a requirement that the Utilities achieve future cost savings consistent with a minimum of $246 million in ERP/EAM project-related benefits to be delivered to customers over the system’s 12-year service life. The decision and order (D&O) approved the deferral of certain project costs and allowed the accrual of allowance for funds used during construction (AFUDC), but limited the AFUDC rate to 1.75%.
The ERP/EAM Implementation Project went live in October 2018. In the Hawaiian Electric 2017 rate case, a settlement agreement approved by the PUC included authorization for the deferred project costs to accrue a return at 1.75% after the project went into service and until the deferred project costs are included in rate base, and for amortization of the deferred costs to not begin until the amortization expense is incorporated in rates and the unamortized deferred project costs are included in rate base. As of December 31, 2019, the total deferred project costs and accrued carrying costs after the project went into service amounted to $59.3 million.
In February 2019, the PUC approved a methodology for passing the future cost saving benefits of the new ERP/EAM system to customers developed by the Utilities in collaboration with the Consumer Advocate. The Utilities filed a benefits clarification document on June 10, 2019, reflecting $150 million in future net O&M expense reductions and cost avoidance, and $96 million in capital cost reductions and tax savings over the 12-year service life. To the extent the reduction in O&M expense relates to amounts reflected in electric rates, the Utilities would reduce future rates for such amounts. As of December 31, 2019, the Utilities recorded a total of $2.4 million as a regulatory liability for amounts to be returned to customers for reduction in O&M expense included in rates.
On September 13, 2019, the Utilities filed their Semi-Annual Enterprise System Benefits Report for the period January 1 through June 30, 2019. In October 2019, the PUC approved the Utilities and the Consumer Advocate’s Stipulated Performance Metrics and Tracking Mechanism.
West Loch PV Project. In November 2019, Hawaiian Electric placed into service a 20-MW (ac) utility-owned and operated renewable and dispatchable solar facility on property owned by the Department of the Navy. PUC orders resulted in a project cost cap of $67 million and a performance guarantee to provide energy at 9.56 cents/kWh or less to the system. Capital cost recovery under MPIR was approved by the PUC in December 2019 (See “Decoupling” section below for MPIR guidelines and cost recovery discussion.) Project costs incurred as of December 31, 2019 amounted to $51.4 million and generated

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$13.4 million and $14.0 million in federal and state nonrefundable tax credits, respectively. The tax credits are being deferred and amortized, starting in 2020, over PUC-approved amortization periods.
Environmental regulation.  The Utilities are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.
Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases associated with current or previous operations. The Utilities report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.
Former Molokai Electric Company generation site.  In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983 but continued to operate at the Site under a lease until 1985. The EPA has since identified environmental impacts in the subsurface soil at the Site.In cooperation with the Hawaii Department of Health and EPA, Maui Electric further investigated the Site and the Adjacent Parcel to determine the extent of impacts of polychlorinated biphenyls (PCBs), residual fuel oils and other subsurface contaminants. Maui Electric has a reserve balance of $2.7 million as of December 31, 2019, representing the probable and reasonably estimable undiscounted cost for remediation of the Site and the Adjacent Parcel; however, final costs of remediation will depend on cleanup approach implemented.
Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is a Potentially Responsible Party responsible for the costs of investigation and cleanup of PCBs contamination in sediment in the area offshore of the Waiau Power Plant as part of the Pearl Harbor Superfund Site. Hawaiian Electric was also required by the EPA to assess potential sources and extent of PCB contamination onshore at Waiau Power Plant.
As of December 31, 2019, the reserve account balance recorded by Hawaiian Electric to address the PCB contamination was $4.2 million. The reserve balance represents the probable and reasonably estimable undiscounted cost for the onshore investigation and the remediation of PCB contamination in the offshore sediment. The final remediation costs will depend on the potential onshore source control requirements and actual offshore cleanup costs.
Asset retirement obligations. AROs represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The Utilities’ recognition of AROs have 0 impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by the Utilities relate to legal obligations associated with the retirement of plant and equipment, including removal of asbestos and other hazardous materials.
The Utilities recorded AROs related to 1) the removal of retired generating units, certain types of transformers and underground storage tanks; 2) the abandonment of fuel pipelines, underground injection and supply wells; and 3) the removal of equipment and restoration of leased land used in connection with Utility-owned renewable and dispatchable generation facilities. 
Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
(in thousands)2019
 2018
Balance, January 1$8,426
 $6,035
Accretion expense312
 282
Liabilities incurred1,594
 1,058
Liabilities settled(8) (74)
Revisions in estimated cash flows—
 1,125
Balance, December 31$10,324
 $8,426

The Utilities have not recorded AROs for assets that are expected to operate indefinitely or where the Utilities cannot estimate a settlement date (or range of potential settlement dates). As such, ARO liabilities are not recorded for certain asset retirement activities, including various Utilities-owned generating facilities and certain electric transmission, distribution and telecommunications assets resulting from easements over property not owned by the Utilities.

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Regulatory proceedings.
Decoupling.Decoupling is a regulatory model that is intended to provide the Utilities with financial stability and facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling mechanism has the following major components: (1) monthly revenue balancing account (RBA) revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales, (2) RAM revenues for escalation in certain O&M expenses and rate base changes, (3) MPIR component, (4) performance incentive mechanisms (PIMs), and (5) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the return on average common equity (ROACE) allowed in its most recent rate case. Under the decoupling mechanism, triennial general rate cases are required.
Rate adjustment mechanism. The RAM is based on the lesser of: a) an inflationary adjustment for certain O&M expenses and return on investment for certain rate base changes, or b) cumulative annual compounded increase in Gross Domestic Product Price Index applied to annualized target revenues (the RAM Cap). Annualized target revenues reset upon the issuance of an interim or final D&O in a rate case. Each of the Utilities’ RAM revenues was below its respective RAM Cap in 2019. The 2019 RAM also incorporated additional amortization of the regulatory liability associated with certain excess deferred taxes resulting from the Tax Act decrease in tax rates. The reduction in the RAM revenues will be counterbalanced by the lower income tax expense and, therefore, will have no net income impact.
Major project interim recovery. On April 27, 2017, the PUC issued an order that provided guidelines for interim recovery of revenues to support major projects placed in service between general rate cases.
Projects eligible for recovery through the MPIR adjustment mechanism are major projects (i.e., projects with capital expenditures net of customer contributions in excess of $2.5 million), including, but not restricted to, renewable energy, energy efficiency, utility scale generation, grid modernization and smaller qualifying projects grouped into programs for review. The MPIR adjustment mechanism provides the opportunity to recover revenues for approved costs of eligible projects placed in service between general rate cases wherein cost recovery is limited by a revenue cap and is not provided by other effective recovery mechanisms. The request for PUC approval must include a business case, and all costs that are allowed to be recovered through the MPIR adjustment mechanism must be offset by any related benefits. The guidelines provide for accrual of revenues approved for recovery upon in-service date to be collected from customers through the annual RBA tariff. Capital projects that are not recovered through the MPIR would be included in the RAM and be subject to the RAM Cap, until the next rate case when the Utilities would request recovery in base rates.
The PUC approved recovery of capital costs under the MPIR for Schofield Generating Station, which increased revenues in 2018 by $3.6 million and are being collected in customer bills since June 2019. In February 2019, Hawaiian Electric submitted an MPIR filing of $19.8 million for 2019 (which accrued effective January 1, 2019) that included the 2019 return on project amount (up to the capped amount) in rate base, depreciation and incremental O&M expenses, for collection from June 2020 through May 2021.
The PUC approved the Utilities’ requests for MPIR of the cost of the Grid Modernization Strategy Phase 1 project and West Loch PV project in March and December 2019, respectively. On February 7, 2020, the Utilities submitted an MPIR filing totaling $24.2 million for the Schofield Generation Station ($19.2 million), West Loch PV project ($4.5 million) and Grid Modernization Strategy Phase 1 project ($0.5 million for all three utilities) for the accrual of revenues effective January 1, 2020, that included the 2020 return on project amount (up to the capped amount) in rate base, depreciation and incremental O&M expenses, for collection from June 2021 through May 2022.
Performance incentive mechanisms. The PUC has established the following PIMs.
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

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each respective utility’s approved rate base (or maximum penalties or rewards of approximately $1.3 million - in total for the three utilities).
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 0 penalties. On March 25, 2019, the PUC approved 6 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.
On October 9, 2019, the PUC issued an order establishing PIMs for the Utilities with regards to the Variable Renewable Dispatchable Generation and Energy Storage requests for proposals (RFPs) as well as the Delivery of Grid Services via Customer-sited Distributed Energy Resources RFPs, that were issued on August 22, 2019 for Oahu, Maui and Hawaii island. The order establishes pricing thresholds, timelines to complete contracting, and other performance criteria for the performance incentive eligibility. The PIMs provide incentives only without penalties. The earliest the Utilities would be eligible for a PIM pursuant to this order is upon PUC approval of executed contracts resulting from the Phase 2 RFPs. The order requires contracts under the Grid Service RFP be filed for approval by May 2020, and by September 2020 under the Renewable RFPs. There is no set time period for approval. The Utilities filed a motion for reconsideration and/or clarification regarding the order on October 21, 2019, relating to certain design aspects and eligibility criteria for the PIMs.
Annual decoupling filings. The net annual incremental amounts approved to be collected (refunded) from June 1, 2019 through May 31, 2020 are as follows:
(in millions) Hawaiian Electric Hawaii Electric Light Maui Electric Total
2019 Annual incremental RAM adjusted revenues,net of changes in Tax Act adjustment* $6.5
 $1.1
 $5.4
 $13.0
Annual change in accrued RBA balance as of December 31, 2018 (and associated revenue taxes) which incorporates MPIR recovery (12.2) (2.0) 0.8
 (13.4)
Performance Incentive Mechanisms (net) (1.3) —
 (0.4) (1.7)
Net annual incremental amount to be collected (refunded) under the tariffs $(7.0) $(0.9) $5.8
 $(2.1)
*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.
Performance-based regulation proceeding. On April 18, 2018, the PUC issued an order, instituting a proceeding to investigate performance-based regulation (PBR). The PUC stated that PBR seeks to utilize both revenue adjustment mechanisms and performance mechanisms to more strongly align utilities’ incentives with customer interests.
The order stated that, in general, the PUC is interested in ratemaking elements and/or mechanisms that result in:
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.

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The proceeding has two phases. Phase 1 examined the current regulatory framework and identified those areas of utility performance that are deserving of further focus in Phase 2. In May 2019, the PUC issued an order concluding Phase 1, which established guiding principles, regulatory goals, and priority outcomes to guide the development of the PBR mechanisms in Phase 2. The PUC identified the following guiding principles, which will inform the development of the PBR framework: 1) a customer-centric approach, 2) administrative efficiency to reduce regulatory burdens; and 3) utility financial integrity to maintain the utility’s financial health. Priority goals (and priority outcomes) identified by the PUC were: enhance customer experience (affordability, reliability, interconnection experience, and customer engagement), improve utility performance (cost control, distributed energy resources (DER) asset effectiveness, and grid investment efficiency), and advance societal outcomes (capital formation, customer equity, GHG reduction, electrification of transportation, and resilience).
The order also outlined the PUC’s vision of a comprehensive PBR framework that would be further developed in Phase 2. The framework envisioned would include 1) a five-year multi-year rate plan with an index-driven annual revenue adjustment based on an inflation factor, an X-factor which would encompass productivity, a Z-factor to account for exceptional circumstances not in the utility’s control and a customer dividend, 2) a symmetric earnings sharing mechanism that would help ensure that utility earnings do not excessively benefit or suffer from external factors outside of utility control or unforeseen results of regulatory mechanisms, 3) off-ramp provisions, 4) continuation of the RBA, MPIR adjustment mechanism, the pension and OPEB tracking mechanism, and other recovery mechanisms, and 5) a portfolio of performance incentive mechanisms for customer engagement and DER asset effectiveness (rewards only), and interconnection experience (both rewards and penalties), in addition to scorecards to track progress against targeted performance levels, shared savings mechanisms to apportion savings to the utility and customers, and reported metrics.
The Phase 2 schedule includes working group meetings through the first half of 2020, followed by statements of positions, evidentiary hearing in October 2020 and anticipated decision in December 2020.
Most recent rate proceedings.
Hawaiian Electric 2020 test year rate case. On August 21, 2019, Hawaiian Electric filed an application for a general rate increase for its 2020 test year rate case, requesting an increase of $77.6 million over revenues at current effective rates (for a 4.1% increase in revenues), based on an 8.0% rate of return (which incorporates a ROACE of 10.5%). In September 2019, the PUC issued an order ruling that Hawaiian Electric’s application was complete as of the date of filing. It also ordered that an outside consultant, selected by the PUC, would independently conduct a management audit of Hawaiian Electric. The PUC expects the audit to conclude in May 2020.
Maui Electric consolidated 2015 and 2018 test year rate cases. On August 9, 2018, the PUC approved an interim rate increase based on a stipulated settlement, that included the effects of the 2017 Tax Act, between Maui Electric and the Consumer Advocate. On March 18, 2019, the PUC issued its D&O that approved, with certain modifications, the stipulated settlement, which addressed all issues in the rate case.
Revised tariffs reflecting a final increase of $12.2 million over revenues at current effective rates based on the approved 7.43% rate of return (which incorporates a ROACE of 9.5% and a capital structure that includes a 57% common equity capitalization) on a $454 million rate base became effective on June 1, 2019. Maui Electric’s ECRC tariff, resulting in the recovery of all fuel and purchased energy through the ECRC and the removal of the recovery of these costs from base rates, became effective on September 1, 2019. The ECRC reflects a 98%/2% fossil fuel generation cost risk-sharing split between ratepayers and Maui Electric, with an annual maximum increase or decrease to revenues to $0.6 million for the utility.
Hawaii Electric Light 2019 test year rate case. On December 14, 2018, Hawaii Electric Light filed an application for a general rate increase for its 2019 test year rate case, requesting an increase of $13.4 million over revenues at current effective rates (for a 3.4% increase in revenues), based on an 8.3% rate of return (which incorporates a ROACE of 10.5%).
On September 24, 2019, Hawaii Electric Light and the Consumer Advocate (Parties) filed a Stipulated Partial Settlement Letter (Partial Settlement) which documented agreements reached with the Consumer Advocate on all of the issues in the proceeding except for the ROACE, capital structure, amortization period for the state investment tax credit (ITC), and symmetric or asymmetric automatic annual target heat rate adjustment (collectively, remaining issues). On November 13, 2019, the PUC issued an interim decision maintaining Hawaii Electric Light’s revenues at current effective rates based on an interim revenue requirement of $387 million, average rate base of $534 million, and a 7.52% ROR on average rate base that incorporates a ROACE of 9.5% and 58.0% total equity ratio. On November 25, 2019, the Parties filed separate responses to the interim order, agreeing that: (1) they do not intend to withdraw from the Partial Settlement; (2) they waive their respective rights to an evidentiary hearing on the remaining contested issues; and (3) the remaining issues in the proceeding can be decided based on the evidence in the record and should be the subject of the filing of opening and reply briefs in February 2020. On December 13, 2019, the PUC issued an order approving the interim tariffs (effective January 1, 2020), removing the evidentiary hearing from

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the procedural schedule, and scheduling the filing of supplemental evidence on January 17, 2020 and simultaneous opening and reply briefs on February 3, 2020 and February 24, 2020. There is no statutory deadline for the PUC to issue a final decision.
Consolidating financialinformation. Consolidating financial information for Hawaiian Electric and its subsidiaries are presented for the years ended December 31, 2019, 2018 and 2017, and as of December 31, 2019 and 2018.
Hawaiian Electric unconditionally guarantees Hawaii Electric Light’s and Maui Electric’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of Hawaii Electric Light and Maui Electric and (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder (see Hawaiian Electric and Subsidiaries’ Consolidated Statements of Capitalization). Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.

109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of income
Year ended December 31, 2019
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$1,803,698
 364,590
 378,202
 —
 (548)[1] $2,545,942
Expenses            
Fuel oil494,728
 84,565
 141,416
 —
 —
  720,709
Purchased power494,215
 90,989
 48,052
 —
 —
  633,256
Other operation and maintenance319,771
 76,091
 85,875
 —
 —
  481,737
Depreciation143,470
 41,812
 30,449
 —
 —
  215,731
Taxes, other than income taxes170,979
 33,787
 35,365
 —
 —
  240,131
   Total expenses1,623,163
 327,244
 341,157
 —
 —
  2,291,564
Operating income180,535
 37,346
 37,045
 —
 (548)  254,378
Allowance for equity funds used during construction9,955
 816
 1,216
 —
 —
  11,987
Equity in earnings of subsidiaries43,167
 —
 —
 —
 (43,167)[2] —
Retirement defined benefits expense—other than service costs(2,287) (422) (127) —
 —
  (2,836)
Interest expense and other charges, net(51,199) (10,741) (9,450) —
 548
[1] (70,842)
Allowance for borrowed funds used during construction3,666
 342
 445
 —
 —
  4,453
Income before income taxes183,837
 27,341
 29,129
 —
 (43,167)  197,140
Income taxes25,917
 5,990
 6,398
 —
 —
  38,305
Net income157,920
 21,351
 22,731
 —
 (43,167)  158,835
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric157,920
 20,817
 22,350
 —
 (43,167)  157,920
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$156,840
 20,817
 22,350
 —
 (43,167)  $156,840

Consolidating statement of comprehensive income
Year ended December 31, 2019
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Net income for common stock$156,840
 20,817
 22,350
 —
 (43,167)  $156,840
Other comprehensive income (loss), net of taxes:            
Retirement benefit plans: 
  
  
  
     
Net gains (losses) arising during the period, net of taxes5,249
 373
 (204) —
 (169)[1] 5,249
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits9,550
 1,455
 1,182
 —
 (2,637)[1] 9,550
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes(16,177) (1,840) (1,152) —
 2,992
[1] (16,177)
Other comprehensive loss, net of tax benefits(1,378) (12) (174) —
 186
  (1,378)
Comprehensive income attributable to common shareholder$155,462
 20,805
 22,176
 —
 (42,981)  $155,462


110

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of income
Year ended December 31, 2018
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$1,802,550
 375,493
 368,700
 —
 (218)[1] $2,546,525
Expenses            
Fuel oil523,706
 90,792
 146,030
 —
 —
  760,528
Purchased power494,450
 95,838
 49,019
 —
 —
  639,307
Other operation and maintenance313,346
 70,396
 77,749
 —
 —
  461,491
Depreciation137,410
 40,235
 25,981
 —
 —
  203,626
Taxes, other than income taxes170,363
 34,850
 34,699
 —
 —
  239,912
   Total expenses1,639,275
 332,111
 333,478
 —
 —
  2,304,864
Operating income163,275
 43,382
 35,222
 —
 (218)  241,661
Allowance for equity funds used
   during construction
9,208
 478
 1,191
 —
 —
  10,877
Equity in earnings of subsidiaries45,393
 —
 —
 —
 (45,393)[2] —
Retirement defined benefits expense—other than service costs(2,649) (417) (565) —
 —
  (3,631)
Interest expense and other charges, net(52,180) (11,836) (9,550) —
 218
[1] (73,348)
Allowance for borrowed funds used during construction4,019
 276
 572
 —
 —
  4,867
Income before income taxes167,066
 31,883
 26,870
 —
 (45,393)  180,426
Income taxes22,333
 6,868
 5,577
 —
 —
  34,778
Net income144,733
 25,015
 21,293
 —
 (45,393)  145,648
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric144,733
 24,481
 20,912
 —
 (45,393)  144,733
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$143,653
 24,481
 20,912
 —
 (45,393)  $143,653

Consolidating statement of comprehensive income
Year ended December 31, 2018
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Net income for common stock$143,653
 24,481
 20,912
 —
 (45,393)  $143,653
Other comprehensive income (loss), net of taxes:            
Retirement benefit plans: 
  
  
  
  
   
Net losses arising during the period, net of tax benefits(26,019) (6,090) (5,004) —
 11,094
[1] (26,019)
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits19,012
 2,819
 2,423
 —
 (5,242)[1] 19,012
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes8,325
 3,305
 2,788
 —
 (6,093)[1] 8,325
Other comprehensive income, net of taxes1,318
 34
 207
 —
 (241)  1,318
Comprehensive income attributable to common shareholder$144,971
 24,515
 21,119
 —
 (45,634)  $144,971


111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of income
Year ended December 31, 2017
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Revenues$1,598,504
 333,467
 325,678
 —
 (83)[1] $2,257,566
Expenses            
Fuel oil408,204
 63,894
 115,670
 —
 —
  587,768
Purchased power454,189
 87,772
 44,673
 —
 —
  586,634
Other operation and maintenance274,391
 66,184
 71,332
 —
 —
  411,907
Depreciation130,889
 38,741
 23,154
 —
 —
  192,784
Taxes, other than income taxes152,933
 31,184
 30,832
 —
 —
  214,949
   Total expenses1,420,606
 287,775
 285,661
 —
 —
  1,994,042
Operating income177,898
 45,692
 40,017
 —
 (83)  263,524
Allowance for equity funds used
   during construction
10,896
 554
 1,033
 —
 —
  12,483
Equity in earnings of subsidiaries38,057
 —
 —
 —
 (38,057)[2] —
Retirement defined benefits expense—other than service costs(5,049) (93) (861) —
 —
  (6,003)
Interest expense and other charges, net(48,277) (11,799) (9,644) —
 83
[1] (69,637)
Allowance for borrowed funds used during construction4,089
 238
 451
 —
 —
  4,778
Income before income taxes177,614
 34,592
 30,996
 —
 (38,057)  205,145
Income taxes56,583
 13,912
 12,704
 —
 —
  83,199
Net income121,031
 20,680
 18,292
 —
 (38,057)  121,946
Preferred stock dividends of subsidiaries—
 534
 381
 —
 —
  915
Net income attributable to Hawaiian Electric121,031
 20,146
 17,911
 —
 (38,057)  121,031
Preferred stock dividends of Hawaiian Electric1,080
 —
 —
 —
 —
  1,080
Net income for common stock$119,951
 20,146
 17,911
 —
 (38,057)  $119,951
Consolidating statement of comprehensive income
Year ended December 31, 2017
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments  Hawaiian Electric
Consolidated
Net income for common stock$119,951
 20,146
 17,911
 —
 (38,057)  $119,951
Other comprehensive income (loss), net of taxes:            
Derivatives qualified as cash flow hedges:            
Reclassification adjustment to net income, net of tax benefits454
 —
 —
 —
 —
  454
Retirement benefit plans: 
  
  
  
  
   
Net gains arising during the period, net of taxes63,105
 3,093
 7,329
 —
 (10,422)[1] 63,105
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits14,477
 1,903
 1,619
 —
 (3,522)[1] 14,477
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes(78,724) (4,994) (9,003) —
 13,997
[1] (78,724)
Other comprehensive income (loss), net of taxes(688) 2
 (55) —
 53
  (688)
Comprehensive income attributable to common shareholder$119,263
 20,148
 17,856
 —
 (38,004)  $119,263

112

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating balance sheet
December 31, 2019
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Assets 
  
  
  
  
   
Property, plant and equipment            
Utility property, plant and equipment 
  
  
  
  
   
Land$42,598
 5,606
 3,612
 —
 —
  $51,816
Plant and equipment4,765,362
 1,313,727
 1,161,199
 —
 —
  7,240,288
Less accumulated depreciation(1,591,241) (574,615) (524,301) —
 —
  (2,690,157)
Construction in progress165,137
 9,993
 17,944
 —
 —
  193,074
Utility property, plant and equipment, net3,381,856
 754,711
 658,454
 —
 —
  4,795,021
Nonutility property, plant and equipment, less accumulated depreciation5,310
 114
 1,532
 —
 —
  6,956
Total property, plant and equipment, net3,387,166
 754,825
 659,986
 —
 —
  4,801,977
Investment in wholly-owned subsidiaries, at equity591,969
 —
 —
 —
 (591,969)[2] —
Current assets 
  
  
  
  
   
Cash and cash equivalents2,239
 6,885
 1,797
 101
 —
  11,022
Restricted cash30,749
 123
 —
 —
 —
  30,872
Advances to affiliates27,700
 8,000
 —
 —
 (35,700)[1] —
Customer accounts receivable, net105,454
 24,520
 22,816
 —
 —
  152,790
Accrued unbilled revenues, net83,148
 17,071
 17,008
 —
 —
  117,227
Other accounts receivable, net18,396
 1,907
 1,960
 —
 (10,695)[1] 11,568
Fuel oil stock, at average cost69,003
 8,901
 14,033
 —
 —
  91,937
Materials and supplies, at average cost34,876
 8,313
 17,513
 —
 —
  60,702
Prepayments and other88,334
 3,725
 24,921
 —
 —
  116,980
Regulatory assets27,689
 1,641
 1,380
 —
 —
  30,710
Total current assets487,588
 81,086
 101,428
 101
 (46,395)  623,808
Other long-term assets 
  
  
  
  
   
Operating lease right-of-use assets174,886
 1,537
 386
 —
 —
  176,809
Regulatory assets476,390
 109,163
 98,817
 —
 —
  684,370
Other69,010
 15,493
 17,215
 —
 —
  101,718
Total other long-term assets720,286
 126,193
 116,418
 —
 —
  962,897
Total assets$5,187,009
 962,104
 877,832
 101
 (638,364)  $6,388,682
Capitalization and liabilities 
  
  
  
  
   
Capitalization 
  
  
  
  
   
Common stock equity$2,047,352
 298,998
 292,870
 101
 (591,969)[2] $2,047,352
Cumulative preferred stock–not subject to mandatory redemption22,293
 7,000
 5,000
 —
 —
  34,293
Long-term debt, net1,006,737
 206,416
 188,561
 —
 —
  1,401,714
Total capitalization3,076,382
 512,414
 486,431
 101
 (591,969)  3,483,359
Current liabilities 
  
  
  
  
   
Current portion of operating lease liabilities63,582
 94
 31
 —
 —
  63,707
Current portion of long-term debt, net61,958
 13,995
 20,000
 —
 —
  95,953
Short-term borrowings-non-affiliate88,987
 —
 —
 —
 —
  88,987
Short-term borrowings-affiliate8,000
 —
 27,700
 —
 (35,700)[1] —
Accounts payable139,056
 25,629
 23,085
 —
 —
  187,770
Interest and preferred dividends payable14,759
 3,115
 2,900
 —
 (46)[1] 20,728
Taxes accrued143,522
 32,541
 31,929
 —
 —
  207,992
Regulatory liabilities13,363
 9,454
 7,907
 —
 —
  30,724
Other51,295
 11,362
 15,297
 —
 (10,649)[1] 67,305
Total current liabilities584,522
 96,190
 128,849
 —
 (46,395)  763,166
Deferred credits and other liabilities 
  
  
  
  
   
Operating lease liabilities111,598
 1,442
 360
 —
 —
  113,400
Deferred income taxes265,864
 53,534
 57,752
 —
 —
  377,150
Regulatory liabilities664,894
 178,474
 98,218
 —
 —
  941,586
Unamortized tax credits86,852
 16,196
 14,820
 —
 —
  117,868
Defined benefit pension and other postretirement benefit plans liability339,471
 69,928
 69,364
 —
 —
  478,763
Other57,426
 33,926
 22,038
 —
 —
  113,390
Total deferred credits and other liabilities1,526,105
 353,500
 262,552
 —
 —
  2,142,157
Total capitalization and liabilities$5,187,009
 962,104
 877,832
 101
 (638,364)  $6,388,682

113

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating balance sheet
December 31, 2018
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Assets 
  
  
  
  
   
Property, plant and equipment            
Utility property, plant and equipment 
  
  
  
  
   
Land$40,449
 5,606
 3,612
 —
 —
  $49,667
Plant and equipment4,456,090
 1,259,553
 1,094,028
 —
 —
  6,809,671
Less accumulated depreciation(1,523,861) (547,848) (505,633) —
 —
  (2,577,342)
Construction in progress193,677
 8,781
 30,687
 —
 —
  233,145
Utility property, plant and equipment, net3,166,355
 726,092
 622,694
 —
 —
  4,515,141
Nonutility property, plant and equipment, less accumulated depreciation5,314
 115
 1,532
 —
 —
  6,961
Total property, plant and equipment, net3,171,669
 726,207
 624,226
 —
 —
  4,522,102
Investment in wholly-owned subsidiaries, at equity576,838
 —
 —
 —
 (576,838)[2] —
Current assets 
  
  
  
  
   
Cash and cash equivalents16,732
 15,623
 3,421
 101
 —
  35,877
Customer accounts receivable, net125,960
 26,483
 25,453
 —
 —
  177,896
Accrued unbilled revenues, net88,060
 17,051
 16,627
 —
 —
  121,738
Other accounts receivable, net21,962
 3,131
 3,033
 —
 (21,911)[1] 6,215
Fuel oil stock, at average cost54,262
 11,027
 14,646
 —
 —
  79,935
Materials and supplies, at average cost30,291
 7,155
 17,758
 —
 —
  55,204
Prepayments and other23,214
 5,212
 3,692
 —
 —
  32,118
Regulatory assets60,093
 3,177
 7,746
 —
 —
  71,016
Total current assets420,574
 88,859
 92,376
 101
 (21,911)  579,999
Other long-term assets 
  
  
  
  
   
Regulatory assets537,708
 120,658
 104,044
 —
 —
  762,410
Other69,749
 15,944
 17,299
 —
 —
  102,992
Total other long-term assets607,457
 136,602
 121,343
 —
 —
  865,402
Total assets$4,776,538
 951,668
 837,945
 101
 (598,749)  $5,967,503
Capitalization and liabilities 
  
  
  
  
   
Capitalization 
  
  
  
  
   
Common stock equity$1,957,641
 295,874
 280,863
 101
 (576,838)[2] $1,957,641
Cumulative preferred stock–not subject to mandatory redemption22,293
 7,000
 5,000
 —
 —
  34,293
Long-term debt, net1,000,137
 217,749
 200,916
 —
 —
  1,418,802
Total capitalization2,980,071
 520,623
 486,779
 101
 (576,838)  3,410,736
Current liabilities 
  
  
  
  
   
Short-term borrowings-non-affiliate25,000
 —
 —
 —
 —
  25,000
Accounts payable126,384
 20,045
 25,362
 —
 —
  171,791
Interest and preferred dividends payable16,203
 4,203
 2,841
 —
 (32)[1] 23,215
Taxes accrued164,747
 34,128
 34,458
 —
 —
  233,333
Regulatory liabilities7,699
 4,872
 5,406
 —
 —
  17,977
Other46,391
 15,077
 20,414
 —
 (21,879)[1] 60,003
Total current liabilities386,424
 78,325
 88,481
 —
 (21,911)  531,319
Deferred credits and other liabilities 
  
  
  
  
   
Deferred income taxes271,438
 54,936
 56,823
 —
 —
  383,197
Regulatory liabilities657,210
 176,101
 98,948
 —
 —
  932,259
Unamortized tax credits60,271
 16,217
 15,034
 —
 —
  91,522
Defined benefit pension and other postretirement benefit plans liability359,174
 73,147
 71,338
 —
 —
  503,659
Other61,950
 32,319
 20,542
 —
 —
  114,811
Total deferred credits and other liabilities1,410,043
 352,720
 262,685
 —
 —
  2,025,448
Total capitalization and liabilities$4,776,538
 951,668
 837,945
 101
 (598,749)  $5,967,503


114

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statements of changes in common stock equity
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Balance, December 31, 2016$1,799,787
 291,291
 259,554
 101
 (550,946) $1,799,787
Net income for common stock119,951
 20,146
 17,911
 —
 (38,057) 119,951
Other comprehensive income (loss), net of taxes(688) 2
 (55) —
 53
 (688)
Issuance of common stock, net of expenses14,000
 4
 4,801
 —
 (4,805) 14,000
Common stock dividends(87,767) (24,796) (11,946) —
 36,742
 (87,767)
Balance, December 31, 20171,845,283
 286,647
 270,265
 101
 (557,013) 1,845,283
Net income for common stock143,653
 24,481
 20,912
 —
 (45,393) 143,653
Other comprehensive income, net of taxes1,318
 34
 207
 —
 (241) 1,318
Issuance of common stock, net of expenses70,692
 1
 1,498
 —
 (1,499) 70,692
Common stock dividends(103,305) (15,289) (12,019) —
 27,308
 (103,305)
Balance, December 31, 20181,957,641
 295,874
 280,863
 101
 (576,838) 1,957,641
Net income for common stock156,840
 20,817
 22,350
 —
 (43,167) 156,840
Other comprehensive loss, net of tax benefits(1,378) (12) (174) —
 186
 (1,378)
Issuance of common stock, net of expenses35,501
 (1) 4,899
 —
 (4,898) 35,501
Common stock dividends(101,252) (17,680) (15,068) —
 32,748
 (101,252)
Balance, December 31, 2019$2,047,352
 298,998
 292,870
 101
 (591,969) $2,047,352


115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of cash flows
Year ended December 31, 2019
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$157,920
 21,351
 22,731
 —
 (43,167)[2] $158,835
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
Equity in earnings of subsidiaries(43,204) —
 —
 —
 43,167
[2] (37)
Common stock dividends received from subsidiaries32,783
 —
 —
 —
 (32,748)[2] 35
Depreciation of property, plant and equipment143,470
 41,812
 30,449
 —
 —
  215,731
Other amortization23,351
 4,810
 1,470
 —
 —
  29,631
Deferred income taxes(13,547) (2,383) (354) —
 —
  (16,284)
Income tax credits, net27,277
 (13) (5) —
 —
  27,259
State refundable credit(6,245) (559) (1,565) —
 —
  (8,369)
Allowance for equity funds used during construction(9,955) (816) (1,216) —
 —
  (11,987)
Other298
 (48) (50) —
 —
  200
Changes in assets and liabilities:   
      
   
Decrease in accounts receivable25,376
 3,326
 3,469
 —
 (11,215)[1] 20,956
Decrease (increase) in accrued unbilled revenues4,912
 (20) (381) —
 —
  4,511
Decrease (increase) in fuel oil stock(14,741) 2,126
 613
 —
 —
  (12,002)
Decrease (increase) in materials and supplies(4,585) (1,158) 245
 —
 —
  (5,498)
Decrease in regulatory assets55,494
 9,218
 6,550
 —
 —
  71,262
Increase (decrease) in regulatory liabilities102
 (1,558) 3,409
 


 


  1,953
Increase (decrease) in accounts payable4,687
 (3,160) (3,578) —
 —
  (2,051)
Change in prepaid and accrued income taxes, tax credits and revenue taxes(24,900) (893) (3,097) —
 367
[1] (28,523)
Decrease in defined benefit pension and other postretirement benefit plans liability(3,033) (762) (653) —
 —
  (4,448)
Change in other assets and liabilities(15,341) (6,152) (6,940) —
 11,215
[1] (17,218)
Net cash provided by operating activities340,119
 65,121
 51,097
 —
 (32,381)  423,956
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(311,538) (49,811) (58,549) —
 —
  (419,898)
Advances to affiliates(27,700) (8,000) —
 —
 35,700
[1] —
Other5,241
 297
 1,303
 —
 4,533
[1],[2] 11,374
Net cash used in investing activities(333,997) (57,514) (57,246) —
 40,233
  (408,524)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(101,252) (17,680) (15,068) —
 32,748
[2] (101,252)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from issuance of common stock35,500
 —
 4,900
 —
 (4,900)[2] 35,500
Proceeds from issuance of long-term debt190,000
 72,500
 17,500
 —
 —
  280,000
Repayment of long-term debt and funds transferred for repayment of long-term dent(183,546) (70,000) (30,000) —
 —
  (283,546)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less46,987
 —
 27,700
 —
 (35,700)[1] 38,987
Proceeds from issuance of short-term debt75,000
 —
 —
 —
 —
  75,000
Repayment of short-term debt(50,000) —
 —
 —
 —
  (50,000)
Other(1,475) (508) (126) —
 —
  (2,109)
Net cash provided by (used in) financing activities10,134
 (16,222) 4,525
 —
 (7,852)  (9,415)
Net increase (decrease) in cash, cash equivalents and restricted cash16,256
 (8,615) (1,624) —
 —
  6,017
Cash, cash equivalents and restricted cash, January 116,732
 15,623
 3,421
 101
 —
  35,877
Cash, cash equivalents and restricted cash, December 3132,988
 7,008
 1,797
 101
 —
  41,894
Less: Restricted cash(30,749) (123) —
 —
 —
  (30,872)
Cash and cash equivalents, December 31$2,239
 6,885
 1,797
 101
 —
  $11,022

116

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of cash flows
Year ended December 31, 2018
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries 
Consolidating
adjustments
  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$144,733
 25,015
 21,293
 —
 (45,393)[2] $145,648
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
Equity in earnings of subsidiaries(45,493) —
 —
 —
 45,393
[2] (100)
Common stock dividends received from subsidiaries27,408
 —
 —
 —
 (27,308)[2] 100
Depreciation of property, plant and equipment137,410
 40,235
 25,981
 —
 —
  203,626
Other amortization20,956
 5,069
 577
 —
 —
  26,602
Deferred income taxes(9,806) (341) 2,165
 —
 —
  (7,982)
Income tax credits, net(83) (14) (2) —
 —
  (99)
State refundable credit(4,941) (547) (751) —
 —
  (6,239)
Allowance for equity funds used during construction(9,208) (478) (1,191) —
 —
  (10,877)
Other3,991
 348
 429
 —
 —
  4,768
Changes in assets and liabilities:   
      
   
Increase in accounts receivable(51,656) (4,867) (8,614) —
 14,220
[1] (50,917)
Increase in accrued unbilled revenues(10,884) (1,111) (2,689) —
 —
  (14,684)
Decrease (increase) in fuel oil stock10,710
 (2,329) (1,443) —
 —
  6,938
Decrease (increase) in materials and supplies(1,966) 886
 273
 —
 —
  (807)
Decrease (increase) in regulatory assets12,192
 71
 (3,011) —
 —
  9,252
Increase in regulatory liabilities26,540
 5,380
 5,438
 —
 —
  37,358
Increase in accounts payable14,748
 6,104
 3,506
 —
 —
  24,358
Change in prepaid and accrued income taxes, tax credits and revenue taxes24,438
 (2,118) 3,047
 —
 (331)[1] 25,036
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability17,178
 (760) 2,328
 —
 —
  18,746
Change in other assets and liabilities(8,056) 2,806
 2,356
 —
 (14,220)[1] (17,114)
Net cash provided by operating activities298,211
 73,349
 49,692
 —
 (27,639)  393,613
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(305,703) (51,054) (58,507) —
 —
  (415,264)
Advances from affiliates—
 —
 12,000
 —
 (12,000)[1] —
Other3,226
 1,182
 3,843
 —
 1,831
[1],[2] 10,082
Net cash used in investing activities(302,477) (49,872) (42,664) —
 (10,169)  (405,182)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(103,305) (15,289) (12,019) —
 27,308
[2] (103,305)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from the issuance of common stock70,700
 —
 1,500
 —
 (1,500)[2] 70,700
Proceeds from the issuance of long-term debt75,000
 15,000
 10,000
 —
 —
  100,000
Repayment of long-term debt(30,000) (11,000) (9,000) —
 —
  (50,000)
Net decrease in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less(16,999) —
 —
 —
 12,000
[1] (4,999)
Proceeds from issuance of short-term debt25,000
 —
 —
 —
 —
  25,000
Other(377) (56) (39) —
 —
  (472)
Net cash provided by (used in) financing activities18,939
 (11,879) (9,939) —
 37,808
  34,929
Net increase (decrease) in cash and cash equivalents14,673
 11,598
 (2,911) —
 —
  23,360
Cash and cash equivalents, January 12,059
 4,025
 6,332
 101
 —
  12,517
Cash and cash equivalents, December 31$16,732
 15,623
 3,421
 101
 —
  $35,877


117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Consolidating statement of cash flows
Year ended December 31, 2017
(in thousands)Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating
adjustments		  Hawaiian Electric
Consolidated
Cash flows from operating activities 
  
  
  
  
   
Net income$121,031
 20,680
 18,292
 —
 (38,057)[2] $121,946
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
  
  
   
Equity in earnings of subsidiaries(38,157) —
 —
 —
 38,057
[2] (100)
Common stock dividends received from subsidiaries36,867
 —
 —
 —
 (36,742)[2] 125
Depreciation of property, plant and equipment130,889
 38,741
 23,154
 —
 —
  192,784
Other amortization2,398
 3,225
 2,875
 —
 —
  8,498
Deferred income taxes26,342
 3,954
 8,004
 —
 (263)[1] 38,037
Income tax credits, net(35) (16) (1) —
 —
  (52)
State refundable credit(1,382) (528) (341) —
 —
  (2,251)
Allowance for equity funds used during construction(10,896) (554) (1,033) —
 —
  (12,483)
Other263
 974
 —
 —
 —
  1,237
Changes in assets and liabilities: 
  
      
   
Decrease (increase) in accounts receivable1,817
 (359) 45
 —
 1,411
[1] 2,914
Increase in accrued unbilled revenues(11,355) (2,376) (1,630) —
 —
  (15,361)
Increase in fuel oil stock(17,733) (469) (2,241) —
 —
  (20,443)
Decrease (increase) in materials and supplies1,603
 (661) (1,660) —
 —
  (718)
Increase in regulatory assets(8,395) (4,007) (4,854) —
 —
  (17,256)
Increase in regulatory liabilities2,552
 315
 735
 —
 —
  3,602
Increase (decrease) in accounts payable23,519
 (3,547) 5,762
 —
 —
  25,734
Change in prepaid and accrued income taxes, tax credits and revenue taxes16,716
 7,961
 5,362
 —
 (177)[1] 29,862
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability709
 52
 (157) —
 —
  604
Change in other assets and liabilities(18,765) (748) (569) —
 (1,411)[1] (21,493)
Net cash provided by operating activities257,988
 62,637
 51,743
 —
 (37,182)  335,186
Cash flows from investing activities 
  
  
  
  
   
Capital expenditures(281,752) (47,784) (47,329) —
 —
  (376,865)
Advances from (to) affiliates—
 3,500
 (2,000) —
 (1,500)[1] —
Other(1,711) 649
 400
 —
 5,240
[1],[2] 4,578
Net cash used in investing activities(283,463) (43,635) (48,929) —
 3,740
  (372,287)
Cash flows from financing activities 
  
  
  
  
   
Common stock dividends(87,767) (24,796) (11,946) —
 36,742
[2] (87,767)
Preferred stock dividends of Hawaiian Electric and subsidiaries(1,080) (534) (381) —
 —
  (1,995)
Proceeds from the issuance of common stock14,000
 —
 4,800
 —
 (4,800)[2] 14,000
Proceeds from the issuance of long-term debt202,000
 28,000
 85,000
 —
 —
  315,000
Repayment of long-term debt(162,000) (28,000) (75,000) —
 —
  (265,000)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less3,499
 —
 —
 —
 1,500
[1] 4,999
Other(2,506) (396) (1,003) —
 —
  (3,905)
Net cash provided by (used in) financing activities(33,854) (25,726) 1,470
 —
 33,442
  (24,668)
Net increase (decrease) in cash and cash equivalents(59,329) (6,724) 4,284
 —
 —
  (61,769)
Cash and cash equivalents, January 161,388
 10,749
 2,048
 101
 —
  74,286
Cash and cash equivalents, December 31$2,059
 4,025
 6,332
 101
 —
  $12,517

Explanation of consolidating adjustments on consolidating schedules:
[1]Eliminations of intercompany receivables and payables and other intercompany transactions.
[2]Elimination of investment in subsidiaries, carried at equity.

118

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 4· Bank segment (HEI only)
Selected financial information
American Savings Bank, F.S.B.
Statements of Income and Comprehensive Income Data
Years ended December 312019
 2018
 2017
(in thousands) 
  
  
Interest and dividend income 
  
  
Interest and fees on loans$233,632
 $220,463
 $207,255
Interest and dividends on investment securities32,922
 37,762
 28,823
Total interest and dividend income266,554
 258,225
 236,078
Interest expense 
  
  
Interest on deposit liabilities16,830
 13,991
 9,660
Interest on other borrowings1,610
 1,548
 2,496
Total interest expense18,440
 15,539
 12,156
Net interest income248,114
 242,686
 223,922
Provision for loan losses23,480
 14,745
 10,901
Net interest income after provision for loan losses224,634
 227,941
 213,021
Noninterest income 
  
  
Fees from other financial services19,275
 18,937
 22,796
Fee income on deposit liabilities20,877
 21,311
 22,204
Fee income on other financial products6,507
 7,052
 7,205
Bank-owned life insurance7,687
 5,057
 5,539
Mortgage banking income4,943
 1,493
 2,201
Gain on sale of real estate10,762
 —
 —
Gains on sale of investment securities, net653
 —
 —
Other income, net2,074
 2,200
 1,617
Total noninterest income72,778
 56,050
 61,562
Noninterest expense 
  
  
Compensation and employee benefits103,009
 98,387
 94,931
Occupancy21,272
 17,073
 16,699
Data processing15,306
 14,268
 13,280
Services10,239
 10,847
 10,994
Equipment8,760
 7,186
 7,232
Office supplies, printing and postage5,512
 6,134
 6,182
Marketing4,490
 3,567
 3,501
FDIC insurance1,204
 2,713
 2,904
Other expense15,586
 17,238
 20,144
Total noninterest expense185,378
 177,413
 175,867
Income before income taxes112,034
 106,578
 98,716
Income taxes23,061
 24,069
 31,719
Net income88,973
 82,509
 66,997
Other comprehensive income (loss), net of taxes29,406
 (7,119) (3,139)
Comprehensive income$118,379
 $75,390
 $63,858




119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Reconciliation to amounts per HEI Consolidated Statements of Income*:
Years ended December 312019
 2018
 2017
(in thousands)     
Interest and dividend income$266,554
 $258,225
 $236,078
Noninterest income72,778
 56,050
 61,562
Less: Gain on sale of real estate(10,762) —
 —
*Revenues-Bank328,570
 314,275
 297,640
Total interest expense18,440
 15,539
 12,156
Provision for loan losses23,480
 14,745
 10,901
Noninterest expense185,378
 177,413
 175,867
Less: Retirement defined benefits credit (expense)—other than service costs472
 (1,657) (820)
Add: Gain on sale of real estate(10,762) —
 —
*Expenses-Bank217,008
 206,040
 198,104
*Operating income-Bank111,562
 108,235
 99,536
Add back: Retirement defined benefits expense (credit)—other than service costs(472) 1,657
 820
Income before income taxes$112,034
 $106,578
 $98,716

Balance Sheets Data
December 31 2019
 2018
(in thousands)  
  
Assets  
  
Cash and due from banks $129,770
 $122,059
Interest-bearing deposits 48,628
 4,225
Investment securities    
Available-for-sale, at fair value 1,232,826
 1,388,533
Held-to-maturity, at amortized cost (fair value of $143,467 and $142,057 at December 31, 2019 and 2018, respectively) 139,451
 141,875
Stock in Federal Home Loan Bank, at cost 8,434
 9,958
Loans held for investment 5,121,176
 4,843,021
Allowance for loan losses (53,355) (52,119)
Net loans 5,067,821
 4,790,902
Loans held for sale, at lower of cost or fair value 12,286
 1,805
Other 511,611
 486,347
Goodwill 82,190
 82,190
Total assets $7,233,017
 $7,027,894
Liabilities and shareholder’s equity  
  
Deposit liabilities–noninterest-bearing $1,909,682
 $1,800,727
Deposit liabilities–interest-bearing 4,362,220
 4,358,125
Other borrowings 115,110
 110,040
Other 146,954
 124,613
Total liabilities 6,533,966
 6,393,505
Commitments and contingencies 


 


Common stock 1
 1
Additional paid in capital 349,453
 347,170
Retained earnings 358,259
 325,286
Accumulated other comprehensive loss, net of tax benefits    
     Net unrealized gains (losses) on securities$2,481
 $(24,423) 
     Retirement benefit plans(11,143)(8,662)(13,645)(38,068)
Total shareholder’s equity 699,051
 634,389
Total liabilities and shareholder’s equity $7,233,017
 $7,027,894



120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


December 31 2019
 2018
(in thousands)  
  
Other assets  
  
Bank-owned life insurance $157,465
 $151,172
Premises and equipment, net 204,449
 214,415
Accrued interest receivable 19,365
 20,140
Mortgage servicing rights 9,101
 8,062
Low-income housing investments 66,302
 67,626
Real estate acquired in settlement of loans, net —
 406
Other 54,929
 24,526
  $511,611
 $486,347
Other liabilities  
  
Accrued expenses $45,822
 $54,084
Federal and state income taxes payable 14,996
 2,012
Cashier’s checks 23,647
 26,906
Advance payments by borrowers 10,486
 10,183
Other 52,003
 31,428
  $146,954
 $124,613

Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.
The decrease in premises and equipment, net was due to the sale of 2 building facilities.
Investment securities. The major components of investment securities were as follows:
         Gross unrealized losses
   
Gross unrealized
gains
 Gross unrealized
losses		 Estimated fair value Less than 12 months 12 months or longer
(dollars in thousands)
Amortized
cost
    Number of issues Fair value Amount Number of issues Fair value Amount
December 31, 2019                   
Available-for-sale 
  
  
  
    
  
    
  
U.S. Treasury and federal agency obligations$117,255
 $652
 $(120) $117,787
 2 $4,110
 $(11) 3 $27,637
 $(109)
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies1,024,892
 6,000
 (4,507) 1,026,385
 19 152,071
 (819) 75 318,020
 (3,688)
Corporate bonds58,694
 1,363
 —
 60,057
 — —
 —
 — —
 —
Mortgage revenue bonds28,597
 —
 —
 28,597
 — —
 —
 — —
 —
 $1,229,438
 $8,015
 $(4,627) $1,232,826
 21 $156,181
 $(830) 78 $345,657
 $(3,797)
Held-to-maturity                   
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies$139,451
 $4,087
 $(71) $143,467
 1 $12,986
 $(71) — $—
 $—
 $139,451
 $4,087
 $(71) $143,467
 1 $12,986
 $(71) — $—
 $—


121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


         Gross unrealized losses
   
Gross unrealized
gains
 Gross unrealized
losses		 Estimated fair value Less than 12 months 12 months or longer
(dollars in thousands)
Amortized
cost
    Number of issues Fair value Amount Number of issues Fair value Amount
December 31, 2018                   
Available-for-sale 
  
  
  
    
  
    
  
U.S. Treasury and federal agency obligations$156,694
 $62
 $(2,407) $154,349
 5 $25,882
 $(208) 19 $118,405
 $(2,199)
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies1,192,169
 789
 (31,542) 1,161,416
 22 129,011
 (1,330) 145 947,890
 (30,212)
Corporate bonds49,398
 103
 (369) 49,132
 6 23,175
 (369) — —
 —
Mortgage revenue bond23,636
 —
 —
 23,636
 — —
 —
 — —
 —
 $1,421,897
 $954
 $(34,318) $1,388,533
 33 $178,068
 $(1,907) 164 $1,066,295
 $(32,411)
Held-to-maturity                   
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies$141,875
 $1,446
 $(1,264) $142,057
 3 $29,814
 $(400) 2 $31,505
 $(864)
 $141,875
 $1,446
 $(1,264) $142,057
 3 $29,814
 $(400) 2 $31,505
 $(864)

ASB does not believe that the investment securities that were in an unrealized loss position as of December 31, 2019, represent an OTTI. Total gross unrealized losses were primarily attributable to change in market conditions. On a quarterly basis the investment securities are evaluated for changes in financial condition of the issuer. Based upon ASB’s evaluation, all securities held within the investment portfolio continue to be investment grade by one or more agencies. The contractual cash flows of the U.S. Treasury, federal agency obligations and agency mortgage-backed securities are backed by the full faith and credit guaranty of the United States government or an agency of the government. ASB does not intend to sell the securities before the recovery of its amortized cost basis and there have been no adverse changes in the timing of the contractual cash flows for the securities. ASB did not recognize OTTI for 2019, 2018 and 2017.
U.S. Treasury, federal agency obligations, corporate bonds, and mortgage revenue bonds have contractual terms to maturity. Mortgage-backed securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages.
The contractual maturities of investment securities were as follows:
 Amortized Fair
December 31, 2019Cost value
(in thousands)   
Available-for-sale   
Due in one year or less$60,200
 $60,249
Due after one year through five years75,694
 77,225
Due after five years through ten years53,225
 53,540
Due after ten years15,427
 15,427
 204,546
 206,441
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies1,024,892
 1,026,385
Total available-for-sale securities$1,229,438
 $1,232,826
Held-to-maturity   
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies$139,451
 $143,467
Total held-to-maturity securities$139,451
 $143,467


122

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The proceeds, gross gains and losses from sales of available-for-sale securities were as follows:
Years ended December 312019
 2018
 2017
(in millions)     
Proceeds$19.8
 $—
 $—
Gross gains0.7
 —
 —
Gross losses—
 —
 —

Interest income from taxable and non-taxable investment securities were as follows:
Years ended December 312019
 2018
 2017
(in thousands)     
Taxable$31,847
 $37,153
 $28,398
Non-taxable1,074
 609
 425
 $32,921
 $37,762
 $28,823

ASB pledged securities with a market value of approximately $546 million as of December 31, 2019 and 2018, as collateral for public funds and other deposits, automated clearinghouse transactions with Bank of Hawaii, borrowing at the discount window of the Federal Reserve Bank of San Francisco, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2019 and 2018, securities with a carrying value of $130 million and $92 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.
Stock in FHLB.  As of December 31, 2019 and 2018, ASB’s stock in FHLB was carried at cost ($8.4 million and $10.0 million, respectively) because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and borrowing levels.
Quarterly and as conditions warrant, ASB reviews its investment in the stock of the FHLB for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2019, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2019, 2018 and 2017 based on its evaluation of the underlying investment.
Future deterioration in the FHLB’s financial position and/or negative developments in any of the factors considered in ASB’s impairment evaluation may result in future impairment losses.
Loans. The components of loans were summarized as follows:
December 312019
 2018
(in thousands) 
  
Real estate: 
  
Residential 1-4 family$2,178,135
 $2,143,397
Commercial real estate824,830
 748,398
Home equity line of credit1,092,125
 978,237
Residential land14,704
 13,138
Commercial construction70,605
 92,264
Residential construction11,670
 14,307
Total real estate4,192,069
 3,989,741
Commercial670,674
 587,891
Consumer257,921
 266,002
Total loans5,120,664
 4,843,634
Less: Deferred fees and discounts512
 (613)
Allowance for loan losses(53,355) (52,119)
Total loans, net$5,067,821
 $4,790,902

ASB’s policy is to require private mortgage insurance on all real estate loans when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For non-owner occupied residential property purchases, the loan-to-value ratio may not exceed 75% of the lower of the appraised value or purchase price at origination.

123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


ASB services real estate loans for investors (principal balance of $1.3 billion, $1.2 billion and $1.2 billion as of December 31, 2019, 2018 and 2017, respectively), which are not included in the accompanying balance sheets data. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan servicing cost to expense as incurred.
As of December 31, 2019 and 2018, ASB had pledged loans with an amortized cost of approximately $2.9 billion and $2.7 billion, respectively, as collateral to secure advances from the FHLB.
As of December 31, 2019 and 2018, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board (FRB) Regulation O) of such individuals, was $24.1 million and $24.0 million, respectively. As of December 31, 2019 and 2018, $18.0 million and $18.3 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms.
Allowance for loan losses.  As discussed in Note 1, ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio.

124

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The allowance for loan losses (balances and changes) and financing receivables were as follows:
(in thousands)Residential 1-4 family Commercial
real estate		 Home equity
line of credit		 Residential land Commercial construction Residential construction Commercial Consumer Total
December 31, 2019   
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
Beginning balance$1,976
 $14,505
 $6,371
 $479
 $2,790
 $4
 $9,225
 $16,769
 $52,119
Charge-offs(26) —
 (144) (4) —
 —
 (6,811) (21,677) (28,662)
Recoveries854
 —
 17
 229
 —
 —
 2,351
 2,967
 6,418
Provision(424) 548
 678
 (255) (693) (1) 5,480
 18,147
 23,480
Ending balance$2,380
 $15,053
 $6,922
 $449
 $2,097
 $3
 $10,245
 $16,206
 $53,355
Ending balance: individually evaluated for impairment$898
 $2
 $322
 $—
 $—
 $—
 $1,015
 $454
 $2,691
Ending balance: collectively evaluated for impairment$1,482
 $15,051
 $6,600
 $449
 $2,097
 $3
 $9,230
 $15,752
 $50,664
Financing Receivables:  
  
  
  
  
  
  
  
Ending balance$2,178,135
 $824,830
 $1,092,125
 $14,704
 $70,605
 $11,670
 $670,674
 $257,921
 $5,120,664
Ending balance: individually evaluated for impairment$15,600
 $1,048
 $12,073
 $3,091
 $—
 $—
 $8,418
 $507
 $40,737
Ending balance: collectively evaluated for impairment$2,162,535
 $823,782
 $1,080,052
 $11,613
 $70,605
 $11,670
 $662,256
 $257,414
 $5,079,927
December 31, 2018   
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
Beginning balance$2,902
 $15,796
 $7,522
 $896
 $4,671
 $12
 $10,851
 $10,987
 $53,637
Charge-offs(128) —
 (353) (18) —
 —
 (2,722) (17,296) (20,517)
Recoveries74
 —
 257
 179
 —
 —
 2,136
 1,608
 4,254
Provision(872) (1,291) (1,055) (578) (1,881) (8) (1,040) 21,470
 14,745
Ending balance$1,976
 $14,505
 $6,371
 $479
 $2,790
 $4
 $9,225
 $16,769
 $52,119
Ending balance: individually evaluated for impairment$876
 $7
 $701
 $6
 $—
 $—
 $628
 $4
 $2,222
Ending balance: collectively evaluated for impairment$1,100
 $14,498
 $5,670
 $473
 $2,790
 $4
 $8,597
 $16,765
 $49,897
Financing Receivables:  
  
  
  
  
  
  
  
Ending balance$2,143,397
 $748,398
 $978,237
 $13,138
 $92,264
 $14,307
 $587,891
 $266,002
 $4,843,634
Ending balance: individually evaluated for impairment$16,494
 $915
 $14,800
 $2,059
 $—
 $—
 $5,340
 $89
 $39,697
Ending balance: collectively evaluated for impairment$2,126,903
 $747,483
 $963,437
 $11,079
 $92,264
 $14,307
 $582,551
 $265,913
 $4,803,937
December 31, 2017                 
Allowance for loan losses:                
Beginning balance$2,873
 $16,004
 $5,039
 $1,738
 $6,449
 $12
 $16,618
 $6,800
 $55,533
Charge-offs(826) —
 (14) (210) —
 —
 (4,006) (11,757) (16,813)
Recoveries157
 —
 308
 482
 —
 —
 1,852
 1,217
 4,016
Provision698
 (208) 2,189
 (1,114) (1,778) —
 (3,613) 14,727
 10,901
Ending balance$2,902
 $15,796
 $7,522
 $896
 $4,671
 $12
 $10,851
 $10,987
 $53,637
Ending balance: individually evaluated for impairment$1,248
 $65
 $647
 $47
 $—
 $—
 $694
 $29
 $2,730
Ending balance: collectively evaluated for impairment$1,654
 $15,731
 $6,875
 $849
 $4,671
 $12
 $10,157
 $10,958
 $50,907
Financing Receivables:                
Ending balance$2,118,047
 $733,106
 $913,052
 $15,797
 $108,273
 $14,910
 $544,828
 $223,564
 $4,671,577
Ending balance: individually evaluated for impairment$18,284
 $1,016
 $8,188
 $1,265
 $—
 $—
 $4,574
 $66
 $33,393
Ending balance: collectively evaluated for impairment$2,099,763
 $732,090
 $904,864
 $14,532
 $108,273
 $14,910
 $540,254
 $223,498
 $4,638,184

Credit quality.  ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so

125

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial, commercial real estate and commercial construction loans.
Each commercial and commercial real estate loan is assigned an Asset Quality Rating (AQR) reflecting the likelihood of repayment or orderly liquidation of that loan transaction pursuant to regulatory credit classifications:  Pass, Special Mention, Substandard, Doubtful, and Loss. The AQR is a function of the probability of default model rating, the loss given default, and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens and major changes in business and economic conditions. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt. Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that ASB may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable. An asset classified Loss is considered uncollectible and has such little value that its continuance as a bankable asset is not warranted.
The credit risk profile by internally assigned grade for loans was as follows:
December 312019 2018
(in thousands)
Commercial
real estate
 
Commercial
construction
 Commercial Total 
Commercial
real estate
 
Commercial
construction
 Commercial Total
Grade: 
  
  
    
  
  
  
Pass$756,747
 $68,316
 $621,657
 $1,446,720
 $658,288
 $89,974
 $547,640
 $1,295,902
Special mention4,451
 —
 29,921
 34,372
 32,871
 —
 11,598
 44,469
Substandard63,632
 2,289
 19,096
 85,017
 57,239
 2,290
 28,653
 88,182
Doubtful—
 —
 —
 —
 —
 —
 —
 —
Loss—
 —
 —
 —
��—
 —
 —
 —
Total$824,830
 $70,605
 $670,674
 $1,566,109
 $748,398
 $92,264
 $587,891
 $1,428,553


126

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The credit risk profile based on payment activity for loans was as follows:
(in thousands)
30-59
days
past due
 
60-89
days
past due
 
Greater
than
90 days
 
Total
past due
 Current 
Total
financing
receivables
 
Recorded
investment>
90 days and
accruing
December 31, 2019 
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
Residential 1-4 family$2,588
 $290
 $1,808
 $4,686
 $2,173,449
 $2,178,135
 $—
Commercial real estate—
 —
 —
 —
 824,830
 824,830
 —
Home equity line of credit813
 —
 2,117
 2,930
 1,089,195
 1,092,125
 —
Residential land—
 —
 25
 25
 14,679
 14,704
 —
Commercial construction—
 —
 —
 —
 70,605
 70,605
 —
Residential construction—
 —
 —
 —
 11,670
 11,670
 —
Commercial1,077
 311
 172
 1,560
 669,114
 670,674
 —
Consumer4,386
 3,257
 2,907
 10,550
 247,371
 257,921
 —
Total loans$8,864
 $3,858
 $7,029
 $19,751
 $5,100,913
 $5,120,664
 $—
December 31, 2018 
  
  
  
  
  
  
Real estate: 
  
  
  
  
  
  
Residential 1-4 family$3,757
 $2,773
 $2,339
 $8,869
 $2,134,528
 $2,143,397
 $—
Commercial real estate—
 —
 —
 —
 748,398
 748,398
 —
Home equity line of credit1,139
 681
 2,720
 4,540
 973,697
 978,237
 —
Residential land9
 —
 319
 328
 12,810
 13,138
 —
Commercial construction—
 —
 —
 —
 92,264
 92,264
 —
Residential construction—
 —
 —
 —
 14,307
 14,307
 —
Commercial315
 281
 548
 1,144
 586,747
 587,891
 —
Consumer5,220
 3,166
 2,702
 11,088
 254,914
 266,002
 —
Total loans$10,440
 $6,901
 $8,628
 $25,969
 $4,817,665
 $4,843,634
 $—


The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due, and TDR loans was as follows:
 Nonaccrual loans Accruing loans 90 days or more past due Troubled debt restructured loans not included in nonaccrual loans
December 312019
 2018
 2019
 2018
 2019
 2018
(in thousands)           
Real estate: 
  
        
Residential 1-4 family$11,395
 $12,037
 $—
 $—
 $9,869
 $10,194
Commercial real estate195
 —
 —
 —
 853
 915
Home equity line of credit6,638
 6,348
 —
 —
 10,376
 11,597
Residential land448
 436
 —
 —
 2,644
 1,622
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial5,947
 4,278
 —
 —
 2,614
 1,527
Consumer5,113
 4,196
 —
 —
 57
 62
Total$29,736
 $27,295
 $—
 $—
 $26,413
 $25,917


127

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The total carrying amount and the total unpaid principal balance of impaired loans were as follows:
December 312019 2018
(in thousands)
Recorded
investment
 
Unpaid
principal
balance
 
Related
allowance
 
Recorded
investment
 
Unpaid
principal
balance
 
Related
allowance
With no related allowance recorded 
  
  
  
  
  
Real estate: 
  
  
  
  
  
Residential 1-4 family$6,817
 $7,207
 $—
 $7,822
 $8,333
 $—
Commercial real estate195
 200
 —
 —
 —
 —
Home equity line of credit1,984
 2,135
 —
 2,743
 3,004
 —
Residential land3,091
 3,294
 —
 2,030
 2,228
 —
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial1,948
 2,285
 —
 3,722
 4,775
 —
Consumer2
 2
 —
 32
 32
 —
 14,037
 15,123
 —
 16,349
 18,372
 —
With an allowance recorded 
  
  
  
  
  
Real estate: 
  
  
  
  
  
Residential 1-4 family8,783
 8,835
 898
 8,672
 8,875
 876
Commercial real estate853
 853
 2
 915
 915
 7
Home equity line of credit10,089
 10,099
 322
 12,057
 12,086
 701
Residential land—
 —
 —
 29
 29
 6
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial6,470
 6,470
 1,015
 1,618
 1,618
 628
Consumer505
 505
 454
 57
 57
 4
 26,700
 26,762
 2,691
 23,348
 23,580
 2,222
Total 
  
  
  
  
  
Real estate: 
  
  
  
  
  
Residential 1-4 family15,600
 16,042
 898
 16,494
 17,208
 876
Commercial real estate1,048
 1,053
 2
 915
 915
 7
Home equity line of credit12,073
 12,234
 322
 14,800
 15,090
 701
Residential land3,091
 3,294
 —
 2,059
 2,257
 6
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial8,418
 8,755
 1,015
 5,340
 6,393
 628
Consumer507
 507
 454
 89
 89
 4
 $40,737
 $41,885
 $2,691
 $39,697
 $41,952
 $2,222


128

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


ASB’s average recorded investment of, and interest income recognized from, impaired loans were as follows:
December 312019 2018 2017
(in thousands)Average
recorded
investment		 Interest
income
recognized*		 Average
recorded
investment		 Interest
income
recognized*		 Average
recorded
investment		 Interest
income
recognized*
With no related allowance recorded 
  
  
  
    
Real estate:           
Residential 1-4 family$8,169
 $907
 $8,595
 $445
 $9,440
 $316
Commercial real estate16
 —
 —
 —
 91
 11
Home equity line of credit2,020
 84
 2,206
 75
 1,976
 101
Residential land2,662
 129
 1,532
 40
 1,094
 117
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial4,534
 276
 3,275
 28
 2,776
 54
Consumer21
 4
 22
 —
 1
 —
 17,422
 1,400
 15,630
 588
 15,378
 599
With an allowance recorded           
Real estate:           
Residential 1-4 family8,390
 359
 8,878
 363
 9,818
 493
Commercial real estate886
 37
 982
 42
 1,241
 54
Home equity line of credit11,319
 567
 10,617
 440
 5,045
 251
Residential land27
 —
 37
 3
 1,308
 97
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial6,990
 132
 1,789
 122
 3,691
 723
Consumer360
 24
 57
 4
 57
 3
 27,972
 1,119
 22,360
 974
 21,160
 1,621
Total           
Real estate:           
Residential 1-4 family16,559
 1,266
 17,473
 808
 19,258
 809
Commercial real estate902
 37
 982
 42
 1,332
 65
Home equity line of credit13,339
 651
 12,823
 515
 7,021
 352
Residential land2,689
 129
 1,569
 43
 2,402
 214
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial11,524
 408
 5,064
 150
 6,467
 777
Consumer381
 28
 79
 4
 58
 3
 $45,394
 $2,519
 $37,990
 $1,562
 $36,538
 $2,220
* Since loan was classified as impaired.
Troubled debt restructurings.  A loan modification is deemed to be a TDR when the borrower is determined to be experiencing financial difficulties and ASB grants a concession it would not otherwise consider. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.
ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period, and temporary deferral

129

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


or reduction of principal payments. ASB generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.
All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment:  (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Loan modifications that occurred during 2019, 2018, and 2017were as follows:
Years endedDecember 31, 2019 December 31, 2018
(dollars in thousands)Number of contracts 
Outstanding 
recorded 
investment
 (as of period end)1
 
Related allowance
(as of period end)
 Number of contracts 
Outstanding 
recorded 
investment
 (as of period end)1
 
Related allowance
(as of period end)
Real estate: 
  
  
  
  
  
Residential 1-4 family11
 $1,770
 $190
 3
 $566
 $26
Commercial real estate—
 —
 —
 —
 —
 —
Home equity line of credit3
 442
 73
 53
 6,659
 578
Residential land3
 1,086
 —
 2
 1,338
 —
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial8
 5,523
 417
 12
 2,165
 211
Consumer—
 —
 —
 —
 —
 —
 25
 $8,821
 $680
 70
 $10,728
 $815
            
Year endedDecember 31, 2017      
(dollars in thousands)Number of contracts
 
Outstanding 
recorded 
investment
 (as of period end)1

 
Related allowance
(as of period end)

      
  Real estate:           
Residential 1-4 family3
 $469
 $65
      
Commercial real estate—
 —
 —
      
Home equity line of credit44
 2,791
 545
      
Residential land1
 92
 —
      
Commercial construction—
 —
 —
      
Residential construction—
 —
 —
      
Commercial8
 525
 250
      
Consumer1
 58
 29
      
 57
 $3,935
 $889
      

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.

130

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Loans modified in TDRs that experienced a payment default of 90 days or more in 2019, 2018, and 2017 and for which the payment default occurred within one year of the modification, were as follows:
Years ended December 312019 2018 2017
(dollars in thousands)
Number of
 contracts
 
Recorded
investment
 
Number of
 contracts
 
Recorded
investment
 Number of
contracts		 Recorded
investment
Troubled debt restructurings that subsequently defaulted  
  
  
    
Real estate: 
  
  
  
    
Residential 1-4 family—
 $—
 —
 $—
 1
 $222
Commercial real estate—
 —
 —
 —
 —
 —
Home equity line of credit—
 —
 1
 81
 —
 —
Residential land—
 —
 —
 —
 —
 —
Commercial construction—
 —
 —
 —
 —
 —
Residential construction—
 —
 —
 —
 —
 —
Commercial—
 —
 1
 246
 —
 —
Consumer—
 —
 —
 —
 —
 —
 —
 $—
 2
 $327
 1
 $222

If loans modified in a TDR subsequently default, ASB evaluates the loan for further impairment. Based on its evaluation, adjustments may be made in the allocation of the allowance or partial charge-offs may be taken to further write-down the carrying value of the loan. Commitments to lend additional funds to borrowers whose loan terms have been modified in a TDR were NaN at December 31, 2019 and 2018.
The Company had $3.5 million and $4.2 million of consumer mortgage loans collateralized by residential real estate property that were in the process of foreclosure at December 31, 2019 and 2018, respectively.
Mortgage servicing rights (MSRs).In its mortgage banking business, ASB sells residential mortgage loans to government-sponsored entities and other parties, who may issue securities backed by pools of such loans. ASB retains no beneficial interests in these loans other than the servicing rights of certain loans sold.
ASB received $277.1 million, $112.2 million and $128.0 million of proceeds from the sale of residential mortgages in 2019, 2018, and 2017, respectively, and recognized gains on such sales of $4.9 million, $1.5 million, and $2.2 million in 2019, 2018, and 2017, respectively. Repurchased mortgage loans were NaN for 2019, 2018 and 2017. The repurchase reserve was $0.1 million as of December 31, 2019, 2018 and 2017.
Mortgage servicing fees, a component of other income, net, were $3.0 million for the years ended December 31, 2019, 2018, and 2017.
Changes in the carrying value of MSRs were as follows:
(in thousands)
Gross
carrying amount1
 
Accumulated amortization1
 Valuation allowance Net
carrying amount
December 31, 2019$21,543
 $(12,442) $—
 $9,101
December 31, 2018$18,556
 $(10,494) $—
 $8,062
1 Reflects impact of loans paid in full.


131

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Changes related to MSRs were as follows:
(in thousands)2019
 2018
 2017
Mortgage servicing rights     
Balance, January 1$8,062
 $8,639
 $9,373
Amount capitalized2,987
 1,045
 1,239
Amortization(1,948) (1,622) (1,973)
Sale of mortgage servicing rights—
 —
 —
Other-than-temporary impairment—
 —
 —
Carrying amount before valuation allowance, December 319,101
 8,062
 8,639
Valuation allowance for mortgage servicing rights     
Balance, January 1—
 —
 —
Provision (recovery)—
 —
 —
Other-than-temporary impairment—
 —
 —
Balance, December 31—
 —
 —
Net carrying value of mortgage servicing rights$9,101
 $8,062
 $8,639

The estimated aggregate amortization expenses of MSRs for 2020, 2021, 2022, 2023 and 2024 are $1.5 million, $1.2 million, $1.1 million, $0.9 million and $0.8 million, respectively.
ASB capitalizes MSRs acquired upon the sale of mortgage loans with servicing rights retained. On a monthly basis, ASB compares the net carrying value of the MSRs to its fair value to determine if there are any changes to the valuation allowance and/or other-than-temporary impairment for the MSRs.
ASB uses a present value cash flow model to estimate the fair value of MSRs. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in “Revenues - bank” in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.
Key assumptions used in estimating the fair value of ASB’s MSRs used in the impairment analysis were as follows:
December 312019
 2018
(dollars in thousands)   
Unpaid principal balance$1,276,437
 $1,188,514
Weighted average note rate3.96% 3.98%
Weighted average discount rate9.3% 10.0%
Weighted average prepayment speed11.4% 6.5%

The sensitivity analysis of fair value of MSRs to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions was as follows:
December 312019
 2018
(in thousands)   
Prepayment rate:   
25 basis points adverse rate change$(950) $(250)
50 basis points adverse rate change(1,947) (566)
Discount rate:   
25 basis points adverse rate change(102) (139)
50 basis points adverse rate change(202) (275)

The effect of a variation in certain assumptions on fair value is calculated without changing any other assumptions. This analysis typically cannot be extrapolated because the relationship of a change in one key assumption to the changes in the fair value of MSRs typically is not linear.

132

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Deposit liabilities. The summarized components of deposit liabilities were as follows:
December 312019 2018
(dollars in thousands)Weighted-average stated rate
 Amount
 Weighted-average stated rate
 Amount 
Savings0.09% $2,379,522
 0.07% $2,322,552
Checking     
  
Interest-bearing0.09
 1,062,122
 0.09
 1,055,019
Noninterest-bearing—
 977,459
 —
 932,608
Commercial checking—
 932,223
 —
 868,119
Money market0.69
 150,751
 0.63
 152,713
Time certificates1.42
 769,825
 1.61
 827,841
 0.24% $6,271,902
 0.27% $6,158,852

As of December 31, 2019 and 2018, time certificates of $100,000 or more totaled $456.5 million and $500.2 million, respectively.
The approximate scheduled maturities of time certificates outstanding at December 31, 2019 were as follows:
(in thousands) 
2020$503,214
2021112,632
202287,132
202329,134
202435,253
Thereafter2,460
 $769,825

Overdrawn deposit accounts are classified as loans and totaled $2.4 million and $2.1 million at December 31, 2019 and 2018, respectively.
Interest expense on deposit liabilities by type of deposit was as follows:
Years ended December 312019
 2018
 2017
(in thousands)     
Time certificates$12,675
 $11,044
 $7,687
Savings1,904
 1,639
 1,567
Money market953
 602
 168
Interest-bearing checking1,298
 706
 238
 $16,830
 $13,991
 $9,660

Other borrowings.
Securities sold under agreements to repurchase.  Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. ASB pledges investment securities as collateral for securities sold under agreements to repurchase. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:
(in millions) 
Gross amount of
recognized liabilities
 
Gross amount
 offset in the
 Balance Sheets
 
Net amount of
 liabilities presented
in the Balance Sheets
Repurchase agreements  
  
  
December 31, 2019 $115
 $—
 $115
December 31, 2018 65
 —
 65

133

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


  Gross amount not offset in the Balance Sheets
(in millions) 
Net amount of 
liabilities presented
in the Balance Sheets
 
Financial
instruments
 
Cash
collateral
pledged
Commercial account holders  
  
  
December 31, 2019 $115
 $130
 $—
December 31, 2018 65
 92
 —

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts or into segregated tri-party custodial accounts at the FHLB. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts. The counterparties or tri-parties may determine that additional collateral is required based on movements in the fair value of the collateral. Typically, a 5 percent discount is taken from the fair value of the investment securities to determine the value of the collateral pledged for the repurchase agreements.
Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:
(dollars in millions)2019
 2018
 2017
Amount outstanding as of December 31$115
 $65
 $141
Average amount outstanding during the year$80
 $99
 $98
Maximum amount outstanding as of any month-end$115
 $152
 $141
Weighted-average interest rate as of December 310.98% 0.75% 0.65%
Weighted-average interest rate during the year0.96% 0.71% 0.26%
Weighted-average remaining days to maturity as of December 311
 1
 1

Securities sold under agreements to repurchase were summarized as follows:
December 312019 2018
MaturityRepurchase liability
 
Weighted-average
interest rate

 
Collateralized by
 mortgage-backed
securities and federal
agency obligations at fair value plus
 accrued interest

 Repurchase liability
 Weighted-average
interest rate
 Collateralized by
mortgage-backed
securities and federal
agency obligations at fair value plus
accrued interest
(dollars in thousands) 
  
  
      
Overnight$115,110
 0.98% $129,527
 $65,040
 0.75% $92,290
1 to 29 days—
 —
 —
 —
 —
 —
30 to 90 days—
 —
 —
 —
 —
 —
Over 90 days—
 —
 —
 —
 —
 —
 $115,110
 0.98% $129,527
 $65,040
 0.75% $92,290
Advances from Federal Home Loan Bank. FHLB advances were NaN and $45 million as of December 31, 2019 and 2018.
ASB and the FHLB are parties to an Advances, Pledge and Security Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB’s credit policies, and makes certain warranties and representations to the FHLB. Upon the occurrence of and during the continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Advances Agreement or other credit arrangements between the parties), the FHLB may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB are collateralized by loans and stock in the FHLB. As of December 31, 2019 and 2018, ASB’s available FHLB borrowing capacity was $2.3 billion, and $2.0 billion, respectively. In February 2020, the FHLB of Des Moines notified ASB that certain assets would no longer qualify as collateral for FHLB advances, reducing ASB's total FHLB borrowing capacity to approximately $1.5 billion. The notice included high-quality home equity lines of credit and was technical in nature and unrelated to the credit quality of the home equity loans, of which approximately 54% are in first lien position. ASB is working with the FHLB to understand the nature of the disqualification of those assets as collateral and re-establishing eligibility.

134

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB. ASB was in compliance with all Advances Agreement requirements as of December 31, 2019 and 2018.
Common stock equity.  ASB is regulated and supervised by the OCC. Failure to meet minimum capital requirements can initiate certain mandatory and possibly additional discretionary actions by regulators that, if undertaken, could have a direct material effect on ASB’s financial statements. Under capital adequacy guidelines and the regulatory framework for prompt corrective action, ASB must meet specific capital guidelines that involve quantitative measures of ASB’s assets, liabilities, and certain off-balance sheet items as calculated under regulatory accounting practices. The capital amounts and classification are also subject to qualitative judgments by the regulators about components, risk weightings, and other factors.
The prompt corrective action provisions impose certain restrictions on institutions that are undercapitalized. The restrictions imposed become increasingly more severe as an institution’s capital category declines from “undercapitalized” to “critically undercapitalized.” The regulators have substantial discretion in the corrective actions that might direct and could include restrictions on dividends and other distributions that ASB may make to ASB Hawaii and the requirement that ASB develop and implement a plan to restore its capital.In 1988, HEI agreed with the OTS predecessor regulatory agency at the time, to contribute additional capital to ASB up to a maximum aggregate amount of approximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2019, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement has been reduced to approximately $28.3 million.
To be categorized as “well capitalized,” ASB must maintain minimum total capital, Tier 1 capital, and Tier 1 leverage ratios as set forth in the table below. As of December 31, 2019, and 2018 ASB was in compliance with the minimum capital requirements under OCC regulations, and was categorized as “well capitalized” under the regulatory framework for prompt corrective action. There are no conditions or events that management believes have changed the institution’s category under the capital guidelines.
The tables below set forth actual and minimum required capital amounts and ratios:
 Actual Minimum required Required to be well capitalized
(dollars in thousands)Capital Ratio Capital Ratio Capital Ratio
December 31, 2019           
Tier 1 leverage641,547
 9.06% 283,122
 4.00% 353,903
 5.00%
Common equity tier 1641,547
 13.18% 219,071
 4.50% 316,435
 6.50%
Tier 1 capital641,547
 13.18% 292,094
 6.00% 389,459
 8.00%
Total capital696,643
 14.31% 389,459
 8.00% 486,823
 10.00%
December 31, 2018           
Tier 1 leverage606,291
 8.70% 278,811
 4.00% 348,514
 5.00%
Common equity tier 1606,291
 12.80% 213,190
 4.50% 307,941
 6.50%
Tier 1 capital606,291
 12.80% 284,253
 6.00% 379,004
 8.00%
Total capital660,151
 13.93% 379,004
 8.00% 473,755
 10.00%

In 2019, ASB paid cash dividends of $56.0 million to HEI, compared to cash dividends of $50.0 million in 2018. The FRB and OCC approved the dividends.
Related-party transactions. HEI charged ASB $2.3 million, $2.2 million and $2.1 million for general management and administrative services in 2019, 2018 and 2017, respectively. The amounts charged by HEI for services performed by HEI employees to its subsidiaries are allocated primarily on the basis of time expended in providing such services. All amounts charged to ASB were settled as a capital contribution by HEI to ASB.
Derivative financial instruments. ASB enters into interest rate lock commitments (IRLCs) with borrowers, and forward commitments to sell loans or to-be-announced mortgage-backed securities to investors to hedge against the inherent interest rate and pricing risks associated with selling loans.
ASB enters into IRLCs for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. IRLCs that relate to the origination of mortgage loans that will be held for sale are considered derivative financial instruments under applicable accounting guidance. Outstanding IRLCs expose ASB to the risk that the price of the mortgage loans underlying the commitments may decline due to increases in mortgage interest rates from inception of the rate lock to the funding of the loan. The IRLCs are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.

135

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


ASB enters into forward commitments to hedge the interest rate risk for rate locked mortgage applications in process and closed mortgage loans held for sale. These commitments are primarily forward sales of to-be-announced mortgage backed securities. Generally, when mortgage loans are closed, the forward commitment is liquidated and replaced with a mandatory delivery forward sale of the mortgage to a secondary market investor. In some cases, a best-efforts forward sale agreement is utilized as the forward commitment. These commitments are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
Changes in the fair value of IRLCs and forward commitments subsequent to inception are based on changes in the fair value of the underlying loan resulting from the fulfillment of the commitment and changes in the probability that the loan will fund within the terms of the commitment, which is affected primarily by changes in interest rates and the passage of time.
The notional amount and fair value of ASB’s derivative financial instruments were as follows:
December 312019 2018
(in thousands)Notional amount Fair value Notional amount Fair value
Interest rate lock commitments$23,171
 $297
 $10,180
 $91
Forward commitments29,383
 (42) 10,132
 (43)

ASB’s derivative financial instruments, their fair values, and balance sheet location were as follows:
Derivative Financial Instruments Not Designated       
as Hedging Instruments 1
       
December 312019 2018
(in thousands)Asset derivatives Liability derivatives Asset derivatives Liability derivatives
Interest rate lock commitments$297
 $—
 $91
 $—
Forward commitments3
 45
 —
 43
 $300
 $45
 $91
 $43
1 Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.
The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in ASB’s statements of income:
Derivative Financial Instruments Not DesignatedLocation of net gains      
as Hedging Instruments(losses) recognized in Years ended December 31
(in thousands)the Statements of Income 2019 2018 2017
Interest rate lock commitmentsMortgage banking income $206
 $(40) $(290)
Forward commitmentsMortgage banking income 1
 (19) 153
 
 $207
 $(59) $(137)

Commitments. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory and property, plant and equipment.
Letters of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. ASB holds collateral supporting those commitments for which collateral is deemed necessary.

136

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The following is a summary of outstanding off-balance sheet arrangements:
December 312019
 2018
(in thousands)   
Unfunded commitments to extend credit: 
  
Home equity line of credit$1,290,854
 $1,242,804
Commercial and commercial real estate484,806
 515,058
Consumer70,088
 70,292
Residential 1-4 family21,131
 17,552
Commercial and financial standby letters of credit11,912
 13,340
Total$1,878,791
 $1,859,046

Contingency. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into a judgment and loss sharing agreement with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2012, a federal judge granted preliminary approval to a proposed settlement between merchants and Visa over credit card fees and in December 2013, a federal judge granted final approval to the settlement. Some merchants and trade organizations filed a notice of appeal shortly after the approval was issued. As of December 31, 2019, ASB had accrued a reserve of $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.
Federal Deposit Insurance Corporation assessment. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) raised the minimum reserve ratio for the Deposit Insurance Fund to 1.35 percent but required the Federal Deposit Insurance Corporation (FDIC) to offset the effect of the increase in the minimum reserve ratio on small institutions (generally insured depository institutions with total consolidated assets of $10 billion or less) when setting assessments. In September 2018, the reserve ratio reached 1.36 percent and the FDIC awarded the small institutions an assessment credit, which was applied to the 2019 second and third quarter assessments for these banks. For the years ended December 31, 2019, 2018 and 2017 ASB’s FDIC insurance expenses were $1.2 million, $2.5 million and $2.6 million, respectively.
Note 5·Short-term borrowings
Commercial paper and bank term loan. As of December 31, 2019 and 2018, HEI had $97 million and $49 million of commercial paper outstanding, with a weighted-average interest rate of 2.3% and 2.9%, respectively.
As of December 31, 2019 and 2018, Hawaiian Electric had $39 million of and 0 commercial paper outstanding, respectively. Additionally, on December 23, 2019, Hawaiian Electric entered into a 364-day, $100 million term loan credit agreement that matures on December 21, 2020. The term loan credit agreement includes substantially the same financial covenant and customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in the loan outstanding becoming immediately due and payable) consistent with those in Hawaiian Electric’s existing, amended revolving unsecured credit agreement. Hawaiian Electric drew the first $50 million on December 23, 2019 and has until March 23, 2020, to draw the remaining $50 million, if needed. The weighted-average interest rate of Hawaiian Electric’s outstanding commercial paper and bank term loan as of December 31, 2019 was 2.3%.
As of December 31, 2019 and 2018, HEI had 3 letters of credit outstanding in the aggregate amount of $6 million and $7 million, respectively, on behalf of Hamakua Energy.
Credit agreements. HEI and Hawaiian Electric each entered into a separate agreement with a syndicate of 8 financial institutions (the HEI Facility and Hawaiian Electric Facility, respectively, and together, the Credit Facilities), effective July 3, 2017, to amend and restate their respective previously existing revolving unsecured credit agreements. The $150 million HEI Facility and $200 million Hawaiian Electric Facility both terminate on June 30, 2022. As of December 31, 2019 and December 31, 2018, 0 amounts were outstanding under the Credit Facilities. None of the facilities are collateralized.
Under the Credit Facilities, draws would generally bear interest, based on each company’s respective current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 1.375% and annual fees on undrawn commitments, excluding swingline borrowings, of 20 basis points. The Credit Facilities contain provisions for pricing adjustments in the event of a long-term ratings change based on the respective Credit Facilities’ ratings-based pricing grid, which includes the ratings by Fitch, Moody’s and S&P. Certain modifications were made to incorporate some updated terms

137

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


and conditions customary for facilities of this type. The Credit Facilities continue to contain customary conditions that must be met in order to draw on them, including compliance with covenants (such as covenants preventing HEI’s/Hawaiian Electric’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI/Hawaiian Electric; and a covenant in Hawaiian Electric’s facility restricting Hawaiian Electric’s ability, as well as the ability of any of its subsidiaries, to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65%).
Under the HEI Facility, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less or if HEI no longer owns Hawaiian Electric or ASB. Under the Hawaiian Electric Facility, it is an event of default if Hawaiian Electric fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35%, or if Hawaiian Electric is no longer owned by HEI.
The Credit Facilities will be maintained to support each company’s respective short-term commercial paper program, but may be drawn on to meet each company’s respective working capital needs and general corporate purposes.

Note 6·Long-term debt
December 312019
 2018
(dollars in thousands) 
  
Long-term debt of Utilities, net of unamortized debt issuance costs 1
$1,497,667
 $1,418,802
HEI 2.99% term loan, due 2022150,000
 150,000
HEI 5.67% senior notes, due 202150,000
 50,000
HEI 3.99% senior notes, due 202350,000
 50,000
HEI 4.58% senior notes, due 202550,000
 50,000
HEI 4.72% senior notes, due 2028100,000
 100,000
Hamakua Energy 4.02% notes, due 2030, secured by real and personal property of Hamakua Energy, LLC59,699
 63,438
Mauo LIBOR + 1.375% loan, due 20229,349
 —
Less unamortized debt issuance costs(2,350) (2,599)
 $1,964,365
 $1,879,641
1
See components of “Total long-term debt” and unamortized debt issuance costs in Hawaiian Electric and subsidiaries’ Consolidated Statements of Capitalization.
As of December 31, 2019, the aggregate principal payments required on the Company’s long-term debt for 2020 through 2024 are $102 million in 2020, $54 million in 2021, $213 million in 2022, $154 million in 2023 and $5 million in 2024. As of December 31, 2019, the aggregate payments of principal required on the Utilities’ long-term debt for 2020 through 2024 are $96 million in 2020, NaN in 2021, $52 million in 2022, $100 million in 2023 and NaN in 2024.
The HEI term loans and senior notes contain customary representation and warranties, affirmative and negative covenants and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable). The HEI term loans and senior notes also contain provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s existing, amended revolving unsecured credit agreement. Upon a change of control or certain dispositions of assets (as defined in the Master Note Purchase Agreements dated March 24, 2011 and October 4, 2018), HEI is required to offer to prepay the senior notes.
The Utilities’ senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by Hawaiian Electric, and each of Hawaii Electric Light and Maui Electric, of certain financial ratios generally consistent with those in Hawaiian Electric’s existing, amended revolving unsecured credit agreement.
Changes in long-term debt.
Mauo. In June 2018, Mauo, LLC, an indirect subsidiary of Pacific Current, LLC, entered into an unsecured $50.5 million construction loan facility in connection with the construction of the solar-plus-storage PPA project. In October 2019, the loan was amended to extend the maturity date to March 31, 2022 and to revise certain other defined terms. The loan bears interest at LIBOR plus 1.375%. As of December 31, 2019, $9 million was outstanding under the facility. The loan is guaranteed by HEI

138

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


and contains restrictive covenants that are substantially the same as the financial covenants contained in HEI’s senior credit facility, as amended.
Hawaiian Electric.  On May 13, 2019, the Utilities issued, through a private placement pursuant to separate Note Purchase Agreements (the Note Purchase Agreements), the following unsecured notes bearing taxable interest (the Unsecured Notes):
Series 2019A
Aggregate principal amount$50 million
Fixed coupon interest rate4.21%
Maturity dateMay 15, 2034
Principal amount by company:
Hawaiian Electric$30 million
Hawaii Electric Light$10 million
Maui Electric$10 million
The Unsecured Notes include substantially the same financial covenants and customary conditions as Hawaiian Electric’s credit agreement. Hawaiian Electric is also a party as guarantor under the Note Purchase Agreements entered into by Hawaii Electric Light and Maui Electric. The Unsecured Notes may be prepaid in whole or in part at any time at the prepayment price of the principal amount plus a “Make-Whole Amount,” as defined in the Note Purchase Agreements. On May 15, 2019, proceeds from the sale were applied to redeem the Utilities’ 2004 junior subordinated deferrable interest debentures at par value:
2004 Junior subordinated deferrable interest debentures redeemed
Aggregate principal amount$51.5 million
Fixed coupon interest rate6.50%
Maturity dateMay 15, 2034
Principal amount by company:
Hawaiian Electric$31.5 million
Hawaii Electric Light$10 million
Maui Electric$10 million
On July 18, 2019, the Department of Budget and Finance of the State of Hawaii (DBF) for the benefit of Hawaiian Electric and Hawaii Electric Light, issued, at par:
Refunding Series 2019 Special Purpose Revenue Bonds
Aggregate principal amount$150 million
Fixed coupon interest rate3.20%
Maturity dateJuly 1, 2039
DBF loaned the proceeds to:
Hawaiian Electric$90 million
Hawaii Electric Light$60 million
On July 26, 2019, proceeds from the sale were applied to redeem at par, bonds previously issued by the DBF for the benefit of Hawaiian Electric and Hawaii Electric Light:
Series 2009 Special Purpose Revenue Bonds Redeemed
Aggregate principal amount$150 million
Fixed coupon interest rate6.50%
Maturity dateJuly 1, 2039
Principal amount by company:
Hawaiian Electric$90 million
Hawaii Electric Light$60 million

139

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


On October 10, 2019, the DBF for the benefit of Hawaiian Electric, Hawaii Electric Light and Maui Electric, issued, at par:
Series 2019 Special Purpose Revenue Bonds
Aggregate principal amount$80 million
Fixed coupon interest rate3.50%
Maturity dateOctober 1, 2049
DBF loaned the proceeds to:
Hawaiian Electric$70 million
Hawaii Electric Light$2.5 million
Maui Electric$7.5 million

Proceeds from the Series 2019 Special Purpose Revenue Bonds will be used only to finance capital expenditures, including reimbursements to the Companies for previously incurred approved capital expenditures. The undrawn funds are deposited with a trustee and earn interest at market rates. As of December 31, 2019, Hawaiian Electric and Hawaii Electric Light had $30.8 million and $0.1 million of undrawn funds remaining with the trustee, respectively. Maui Electric received all bond proceeds at closing and had 0 undrawn funds as of December 31, 2019. Undrawn funds are included in restricted cash in the consolidated balance sheets. (See Note 1).
On December 31, 2019, Hawaiian Electric and Maui Electric wired approximately $84 million to pay off the Series 2012B senior note ($62 million for Hawaiian Electric, $20 million for Maui Electric, and approximately $2 million of accrued interest), which matured on January 1, 2020.
Note 7 · Shareholders’ equity
Reserved shares.  As of December 31, 2019, HEI had reserved a total of 18.5 million shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP), the HEI 2011 Nonemployee Director Stock Plan, the ASB 401(k) Plan and the 2010 Executive Incentive Plan.
Accumulated other comprehensive income/(loss).  Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:
 HEI Consolidated Hawaiian Electric Consolidated
 (in thousands) Net unrealized gains (losses) on securities  Unrealized gains (losses) on derivatives Retirement benefit plans AOCI  Unrealized gains (losses) on derivatives Retirement benefit plans AOCI
Balance, December 31, 2016$(7,931) $(454) $(24,744) $(33,129) $(454) $132
 $(322)
Current period other comprehensive income (loss) and reclassifications, net of taxes(4,370) 454
 2,544
 (1,372) 454
 (1,142) (688)
Reclass of AOCI for tax rate reduction impact1
(2,650) —
 (4,790) (7,440) —
 (209) (209)
Balance, December 31, 2017(14,951) —
 (26,990) (41,941) —
 (1,219) (1,219)
Current period other comprehensive income (loss) and reclassifications, net of taxes(9,472) (436) 1,239
 (8,669) —
 1,318
 1,318
Balance, December 31, 2018(24,423) (436) (25,751) (50,610) —
 99
 99
Current period other comprehensive income (loss) and reclassifications, net of taxes26,904
 (1,177) 4,844
 30,571
 —
 (1,378) (1,378)
Balance, December 31, 2019$2,481
 $(1,613) $(20,907) $(20,039) $—
 $(1,279) $(1,279)

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.

140

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Reclassifications out of AOCI were as follows:
  Amount reclassified from AOCI 
Affected line item in the Statement of
Income/Balance Sheet
Years ended December 31 2019 2018 2017 
(in thousands)        
HEI consolidated        
Net realized gains on securities included in net income $(478) $—
 $—
 Revenues-bank (gains on sale of investment securities, net)
Derivatives qualifying as cash flow hedges:    
  
  
Window forward contracts —
 —
 454
 Property, plant and equipment-electric utilities (2017)
Retirement benefit plans:  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 10,107
 21,015
 15,737
 See Note 10 for additional details
Impact of D&Os of the PUC included in regulatory assets (16,177) 8,325
 (78,724) See Note 10 for additional details
Total reclassifications $(6,548) $29,340
 $(62,533)  
Hawaiian Electric consolidated        
Derivatives qualifying as cash flow hedges        
Window forward contracts $—
 $—
 $454
 Property, plant and equipment (2017)
Retirement benefit plans:  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 9,550
 19,012
 14,477
 See Note 10 for additional details
Impact of D&Os of the PUC included in regulatory assets (16,177) 8,325
 (78,724) See Note 10 for additional details
Total reclassifications $(6,627) $27,337
 $(63,793)  


Note 8 · Leases
The Company adopted ASU No. 2016-02 and related amendments on January 1, 2019, and used the effective date as the date of initial application. The Company elected the practical expedient package under which the Company did not reassess its prior conclusions about whether any expired or existing contracts are or contain leases, whether there is a change in lease classification for any expired or existing leases under the new standard, or whether there were initial direct costs for any existing leases that would be treated differently under the new standard. The Company elected the short-term lease recognition exemption for all of its leases that qualify, and accordingly, does not recognize lease liabilities and ROU assets for all leases that have lease terms that are 12 months or less. The amounts related to short-term leases are not material. The Company elected the practical expedient to not separate lease and non-lease components for its real estate and equipment and fossil fuel and renewable energy PPAs. The Company elected the practical expedient to not assess all existing land easements that were not previously accounted for in accordance with ASC 840.
The Company leases certain real estate and equipment for various terms under long-term operating lease agreements. The agreements expire at various dates through 2054 and provide for renewal options up to 10 years. The periods associated with the renewal options are excluded for the purpose of determining the lease term unless the exercise of the renewable option is reasonably certain. In the normal course of business, it is expected that many of these agreements will be replaced by similar agreements. Certain real estate leases require the Company to pay for operating expenses such as common area maintenance, real estate taxes and insurance, which are recognized as variable lease expense when incurred and are not included in the measurement of the lease liability.
Additionally, the Utilities contract with independent power producers to supply energy under long-term power purchase agreements. Certain PPAs are treated as operating leases under the new standard because the Company elected the practical expedient package under which prior conclusions about lease identification were not reassessed. The fixed capacity payments under the PPAs are included in the lease liability, while the variable lease payments (e.g., payments based on kWh) are excluded from the lease liability. Several as-available PPAs have variable-only payment terms based on production. For PPAs with no minimum lease payments, the Utilities do not recognize any lease liabilities or ROU assets, and the related costs are reported as variable lease costs.

141

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


In August 2019, Hawaiian Electric entered into a lease agreement for a total office space of approximately 195,000 square feet in downtown Honolulu to lower costs and bring together office workers currently in separate leased buildings. The lease consists of two different phases with commencement dates of January 2020 and January 2021, respectively, and is an operating lease for a term of 12 years with various options to extend up to 10 years. Annual base rent expense for each phase is approximately $1.9 million and $1.7 million, respectively, and the operating lease liability recorded upon commencement of the first phase of the lease was $21 million and the operating lease liability to be recorded upon commencement of the second phase is approximately $19 million. In addition to the annual base rent payments that are included in the lease liability, there are additional payments for operating expenses, which are recognized as variable lease cost when incurred. These payments are related to operating expenses, such as common area maintenance, various taxes and insurance. Under the terms of the lease, Hawaiian Electric is entitled to receive up to $5.0 million and $4.6 million in reimbursements for various office improvements for each phase, respectively. The amounts are to be included as a reduction to the initial measurement of the ROU asset on each respective commencement date, and will be subsequently adjusted if the actual reimbursements are different from the initial amounts previously recognized.
The Utilities’ lease payments for each operating lease agreement were discounted using its estimated unsecured borrowing rates for the appropriate term, reduced for the estimated impact of collateral, which is a reduction of approximately 15 basis points. ASB’s lease payments for each operating lease agreement were discounted using Federal Home Loan Bank of Des Moines (FHLB) fixed rate advance rates, which are collateralized, for the appropriate term. The FHLB is ASB’s primary wholesale funding source and can provide collateralized borrowing rates for various terms starting at overnight borrowings to 30-year borrowing terms.
Amounts related to the Company’s total lease cost and cash flows arising from lease transaction are as follows:
 HEI consolidated Hawaiian Electric consolidated
Year ended December 31, 2019Other leasesPPAs classified as leasesTotal Other leasesPPAs classified as leasesTotal
(dollars in thousands)       
Operating lease cost$10,265
$63,319
$73,584
 $4,955
$63,319
$68,274
Variable lease cost13,034
192,138
205,172
 10,272
192,138
202,410
Total lease cost$23,299
$255,457
$278,756
 $15,227
$255,457
$270,684
Other information       
Cash paid for amounts included in the measurement of lease liabilities—Operating cash flows from operating leases$10,447
$62,594
$73,041
 $5,768
$62,594
$68,362
Weighted-average remaining lease term—operating leases (in years)6.5
2.8
3.5
 4.5
2.8
2.9
Weighted-average discount rate—operating leases3.50%4.08%3.96% 4.11%4.08%4.08%

The following table summarizes the maturity of our operating lease liabilities as of December 31, 2019:
 HEI consolidated Hawaiian Electric consolidated
(in millions)Other leasesPPAs classified as leasesTotal Other leasesPPAs classified as leasesTotal
2020$12
$63
$75
 $7
$63
$70
202110
63
73
 5
63
68
20226
42
48
 3
42
45
20235
—
5
 2
—
2
20244
—
4
 1
—
1
Thereafter9
—
9
 2
—
2
Total lease payments46
168
214
 20
168
188
Less: Imputed interest(5)(9)(14) (2)(9)(11)
Total present value of lease payments1
$41
$159
$200
 $18
$159
$177
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.

142

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The future minimum lease obligations under operating leases in effect as of December 31, 2018, having a term in excess of one year as determined prior to the adoption of ASC 842 are as follows:
 HEI consolidated Hawaiian Electric consolidated
(in millions)Other leasesPPAs classified as leasesTotal Other leasesPPAs classified as leasesTotal
2019$11
$63
$74
 $6
$63
$69
20209
63
72
 6
63
69
20218
63
71
 5
63
68
20225
42
47
 2
42
44
20234
—
4
 2
—
2
Thereafter12
—
12
 3
—
3
Total lease payments$49
$231
$280
 $24
$231
$255
HEI’s consolidated operating lease expense prior to the adoption of ASC 842 was $21 million and $20 million in 2018 and 2017, respectively. The Utilities’ operating lease expense prior to the adoption of ASC 842 was $11 million each year for 2018 and 2017.

Note 9· Revenues
Revenue from contracts with customers. The revenues subject to Topic 606 include the Utilities’ electric energy sales revenue and the ASB’s transaction fees, as further described below.
Electric Utilities.
Electric energy sales.Electric energy sales represent revenues from the generation and transmission of electricity to customers under tariffs approved by the PUC. Transaction pricing for electricity is determined and approved by the PUC for each rate class and includes revenues from the base electric charges, which are composed of (1) the customer, demand, energy, and minimum charges, and (2) the power factor, service voltage, and other adjustments as provided in each rate and rate rider schedule. The Utilities satisfy performance obligations over time, i.e., the Utilities generate and transfer control of the electricity over time as the customer simultaneously receives and consumes the benefits provided by the Utilities’ performance. Payments from customers are generally due within 30 days from the end of the billing period. As electric bills to customers reflect the amount that corresponds directly with the value of the Utilities’ performance to date, the Utilities have elected to use the right to invoice practical expedient, which entitles them to recognize revenue in the amount they have the right to invoice.
The Utilities’ revenues include amounts for recovery of various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. For 2019, 2018 and 2017, the Utilities’ revenues include recovery of revenue taxes of approximately $226 million, $226 million and $202 million, respectively, which amounts are in “Taxes, other than income taxes” expense. However, the Utilities pay revenue taxes to the taxing authorities based on (1) the prior year’s billed revenues (in the case of public service company taxes and PUC fees) in the current year or (2) the current year’s cash collections from electric sales (in the case of franchise taxes) after year end. As of December 31, 2019 and 2018, the Utilities had recorded $132 million and $130 million, respectively, in “Taxes accrued, including revenue taxes” on the Utilities’ consolidated balance sheet for amounts previously collected from customers or accrued for public service company taxes and PUC fees, net of amounts paid to the taxing authorities. Such amounts will be used to pay public service company taxes and PUC fees owed for the following year.
Bank.
Bankfees. Bank fees are primarily transaction-based and are recognized when the transaction has occurred and the performance obligation satisfied. From time to time, customers will request a fee waiver and ASB may grant reversals of fees. Revenues are not recorded for the estimated amount of fee reversals for each period. Under the new standard, certain fees paid to third parties that were previously recognized as a component of noninterest expense are now netted with fee income. The change in presentation will have no effect on the reported amount of operating income.
Fees from other financial services - These fees primarily include debit card interchange income and fees, automated teller machine fees, credit card interchange income and fees, check ordering fees, wire fees, safe deposit rental fees, corporate/business fees, merchant income, online banking fees and international banking fees. Amounts paid to third parties for payment network expenses are included in this financial statement caption in ASB’s Statements of Income and Comprehensive Income

143

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Data (in Revenues—Bank financial statement caption of HEI’s Consolidated Statements of Income). Previously, these expenses were recorded in the other expense financial statement caption of ASB’s Statements of Income and Comprehensive Income Data (in Expenses—Bank financial statement caption of HEI’s Consolidated Statements of Income).
Fee income on deposit liabilities - These fees primarily include “not sufficient funds” fees, monthly deposit account service charge fees, commercial account analysis fees and other deposit fees.
Fee income on other financial products - These fees primarily include commission income from the sales of annuity, mutual fund, and life insurance products. In 2017, ASB began offering a fee-based, managed account product in which income is based on a percentage of assets under management. ASB satisfies its performance obligations under the managed account arrangement over time, and consequently, fees for assets under management are recognized over time as the customer simultaneously receives and consumes the benefit of asset management services. Fees recognized to date from the managed account product were minimal.
Revenues from other sources. Revenues from other sources not subject to Topic 606 are accounted for as follows:
Electric Utilities.
Regulatory revenues. Regulatory revenues primarily consist of revenues from decoupling mechanism, cost recovery surcharges and the Tax Act adjustments.
Decoupling mechanism - Under the decoupling mechanism, the Utilities are allowed to recover or obligated to refund the difference between actual revenue and the target revenue as determined by the PUC, collect revenue adjustment mechanism and major project interim recovery revenues, and recover or refund performance incentive mechanism penalties or rewards. These adjustments will be reflected in tariffs in future periods. Under the decoupling tariff approved in 2011, the prior year accrued RBA revenues and the annual RAM amount are billed from June 1 of each year through May 31 of the following year, which is within 24 months following the end of the year in which they are recorded as required by the accounting standard for alternative revenue programs.
Cost recovery surcharges- For the timely recovery of additional costs incurred, and reconciliation of costs and expenses included in tariffed rates, the Utilities recognize revenues under surcharge mechanisms approved by the PUC. These will be reflected in tariffs in future periods (e.g., ECRC and PPAC).
Tax Act adjustments - These represent adjustments to revenues for the amounts included in tariffed revenues that will be returned to customers as a result of the Tax Act.
Since revenue adjustments discussed above resulted from either agreements with the PUC or change in tax law, rather than contracts with customers, they are not subject to the scope of Topic 606. Also, see Notes 1, 3 and 12 of the Consolidated Financial Statements. The Utilities have elected to present these revenue adjustments on a gross basis, which results in the amounts being billed to customers presented in revenues from contracts with customers and the amortization of the related regulatory asset/liability as revenues from other sources. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or refunds to customers, it could result in negative regulatory revenue during the year.
Utility pole attachment fees. These fees primarily represent revenues from third-party companies for their access to and shared use of Utilities-owned poles through licensing agreements. As the shared portion of the utility pole is functionally dependent on the rest of the structure, no distinct goods appear to exist. Therefore, these fees are not subject to the scope of Topic 606, but recognized in accordance with ASC Topic 610, Other Income.
Bank.
Interest and dividend income. Interest and fees on loans are recognized in accordance with ASC Topic 310, Receivables, including the related allowance for loan losses. Interest and dividends on investment securities are recognized in accordance with ASC Topic 320, Investments-Debt and Equity Securities. See Notes 1 and 4 of the Consolidated Financial Statements.
Other bank noninterest income. Other bank noninterest income primarily consists of mortgage banking income and bank-owned life insurance income.
Mortgage banking income - Mortgage banking income consists primarily of realized and unrealized gains on sale of loans accounted for pursuant to ASC Topic 860, Transfers and Servicing. Interest rate lock commitments and forward loan sales are considered derivatives and are accounted pursuant to ASC Topic 815, Derivatives and Hedging.

144

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Bank-Owned Life Insurance (BOLI) - The recognition of BOLI cash surrender value does not represent a contract with a customer and is accounted for in accordance with Emerging Issues Task Force Issue 06-05, Accounting for Purchases of Life Insurance-Determining the Amount that Could be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance.
Revenue disaggregation. The following tables disaggregate revenues by major source, timing of revenue recognition, and segment:
  Year ended December 31, 2019 Year ended December 31, 2018
(in thousands) Electric  utility Bank Other Total Electric  utility Bank Other Total
Revenues from contracts with customers                
Electric energy sales - residential $807,652
 $—
 $—
 $807,652
 $801,846
 $—
 $—
 $801,846
Electric energy sales - commercial 846,110
 —
 —
 846,110
 853,672
 —
 —
 853,672
Electric energy sales - large light and power 905,308
 —
 —
 905,308
 894,770
 —
 —
 894,770
Electric energy sales - other 16,296
 —
 —
 16,296
 17,243
 —
 —
 17,243
Bank fees —
 46,659
 —
 46,659
 —
 47,300
 —
 47,300
Total revenues from contracts with customers 2,575,366
 46,659
 —
 2,622,025
 2,567,531
 47,300
 —
 2,614,831
Revenues from other sources                
Regulatory revenue (54,101) —
 —
 (54,101) (37,687) —
 —
 (37,687)
Bank interest and dividend income —
 266,554
 —
 266,554
 —
 258,225
 —
 258,225
Other bank noninterest income —
 15,357
 —
 15,357
 —
 8,750
 —
 8,750
Other 24,677
 —
 89
 24,766
 16,681
 —
 49
 16,730
Total revenues from other sources (29,424) 281,911
 89
 252,576
 (21,006) 266,975
 49
 246,018
Total revenues $2,545,942
 $328,570
 $89
 $2,874,601
 $2,546,525
 $314,275
 $49
 $2,860,849
Timing of revenue recognition                
Services/goods transferred at a point in time $—
 $46,659
 $—
 $46,659
 $—
 $47,300
 $—
 $47,300
Services/goods transferred over time 2,575,366
 —
 —
 2,575,366
 2,567,531
 —
 —
 2,567,531
Total revenues from contracts with customers $2,575,366
 $46,659
 $—
 $2,622,025
 $2,567,531
 $47,300
 $—
 $2,614,831

There are no material contract assets or liabilities associated with revenues from contracts with customers existing at December 31, 2018 or December 31, 2019. Accounts receivable and unbilled revenues related to contracts with customers represent an unconditional right to consideration since all performance obligations have been satisfied. These amounts are disclosed as accounts receivable and unbilled revenues, net on HEI’s consolidated balance sheets and customer accounts receivable, net and accrued unbilled revenues, net on Hawaiian Electric’s consolidated balance sheets.
As of December 31, 2019, the Company had no material remaining performance obligations due to the nature of the Company’s contracts with its customers. For the Utilities, performance obligations are fulfilled as electricity is delivered to customers. For ASB, fees are recognized when a transaction is completed.

145

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 10 · Retirement benefits
Defined benefit plans. Substantially all of the employees of HEI and the Utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI Pension Plan). Substantially all of the employees of ASB participated in the American Savings Bank Retirement Plan (ASB Pension Plan) until it was frozen on December 31, 2007. The HEI Pension Plan and the ASB Pension Plan (collectively, the Plans) are qualified, noncontributory defined benefit pension plans and include, in the case of the HEI Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the Utilities and the union. The Plans are subject to the provisions of ERISA. In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.
The continuation of the Plans and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The ASB Pension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontributory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.
Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.
Postretirement benefits other than pensions.  HEI and the Utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (Hawaiian Electric Benefits Plan). Eligibility of employees and dependents is based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.
The executive death benefit plan was frozen on September 10, 2009 for participants at benefit levels as of that date.
The Company’s and Utilities’ cost for OPEB has been adjusted to reflect the plan amendments, which reduced benefits and created prior service credits to be amortized over average future service of affected participants. The amortization of the prior service credit will reduce benefit until the various credit bases are fully recognized. Each participating employer reserves the right to terminate its participation in the Hawaiian Electric Benefits Plan at any time.
Balance sheet recognition of the funded status of retirement plans.  Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO), to calculate the funded status).
The PUC allowed the Utilities to adopt pension and OPEB tracking mechanisms in previous rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the Utilities’ tracking mechanisms, any actual costs determined in accordance with GAAP that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.1 million and $1.0 million in 2019 and 2018, respectively) determined in accordance with GAAP will be recovered.
Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The Utilities have reclassified to a regulatory asset/(liability) charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge to AOCI of $(21.8) million pretax and $11.2 million pretax for 2019 and 2018, respectively).

146

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Under the pension tracking mechanism, the Utilities are required to make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contributions imposed by the Internal Revenue Code. Contributions in excess of the calculated NPPC are recorded in a separate regulatory asset. In 2018, the pension tracking mechanism was modified to allow prior year contributions made in excess of NPPC to satisfy future contributions, when the ERISA minimum required contribution is less than NPPC. The Utilities reduced their 2018 contribution for this modification.
The OPEB tracking mechanisms generally require the Utilities to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, (excluding amounts for executive life), except when limited by material, adverse consequences imposed by federal regulations. Future decisions in rate cases could further impact funding amounts.
Defined benefit pension and other postretirement benefit plans information.  The changes in the obligations and assets of the Company’s and Utilities’ retirement benefit plans and the changes in AOCI (gross) for 2019 and 2018 and the funded status of these plans and amounts related to these plans reflected in the Company’s and Utilities’ consolidated balance sheet as of December 31, 2019 and 2018 were as follows:
 2019 2018
(in thousands)
Pension
benefits
 
Other
benefits
 
Pension
benefits
 
Other
benefits
HEI consolidated       
Benefit obligation, January 1$1,991,384
 $188,666
 $2,094,356
 $212,601
Service cost62,135
 2,209
 68,987
 2,721
Interest cost84,267
 8,004
 77,374
 7,933
Actuarial losses (gains)224,421
 25,998
 (171,226) (25,977)
Participants contributions—
 2,351
 —
 2,505
Benefits paid and expenses(83,924) (11,589) (78,107) (11,117)
Benefit obligation, December 312,278,283
 215,639
 1,991,384
 188,666
Fair value of plan assets, January 11,479,067
 173,693
 1,618,703
 193,995
Actual return on plan assets354,072
 35,525
 (101,406) (11,846)
Employer contributions48,629
 —
 38,496
 —
Participants contributions—
 2,351
 —
 2,505
Benefits paid and expenses(82,568) (10,738) (76,726) (10,961)
Fair value of plan assets, December 311,799,200
 200,831
 1,479,067
 173,693
Accrued benefit asset (liability), December 31$(479,083) $(14,808) $(512,317) $(14,973)
Other assets$19,396
 $—
 $10,930
 $—
Defined benefit pension and other postretirement benefit plans liability(498,479) (14,808) (523,247) (14,973)
Accrued benefit asset (liability), December 31$(479,083) $(14,808) $(512,317) $(14,973)
AOCI debit, January 1 (excluding impact of PUC D&Os)$536,920
 $1,962
 $527,830
 $1,474
Recognized during year – prior service credit42
 1,806
 42
 1,805
Recognized during year – net actuarial (losses) gains(15,479) 13
 (30,084) (95)
Occurring during year – net actuarial losses (gains)(17,662) 2,829
 39,132
 (1,222)
AOCI debit before cumulative impact of PUC D&Os, December 31503,821
 6,610
 536,920
 1,962
Cumulative impact of PUC D&Os(474,628) (7,458) (498,944) (4,929)
AOCI debit/(credit), December 31$29,193
 $(848) $37,976
 $(2,967)
Net actuarial loss$503,813
 $11,707
 $536,954
 $8,865
Prior service cost (gain)8
 (5,097) (34) (6,903)
AOCI debit before cumulative impact of PUC D&Os, December 31503,821
 6,610
 536,920
 1,962
Cumulative impact of PUC D&Os(474,628) (7,458) (498,944) (4,929)
AOCI debit/(credit), December 3129,193
 (848) 37,976
 (2,967)
Income taxes (benefits)(7,677) 219
 (10,023) 765
AOCI debit/(credit), net of taxes (benefits), December 31$21,516
 $(629) $27,953
 $(2,202)
As of December 31, 2019 and 2018, the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets.


147

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


 2019 2018
(in thousands)
Pension
benefits
 
Other
benefits
 
Pension
benefits
 
Other
benefits
Hawaiian Electric consolidated       
Benefit obligation, January 1$1,837,653
 $181,162
 $1,928,648
 $204,644
Service cost60,461
 2,191
 67,359
 2,704
Interest cost77,851
 7,673
 71,294
 7,628
Actuarial losses (gains)212,310
 25,123
 (158,258) (25,330)
Participants contributions—
 2,311
 —
 2,472
Benefits paid and expenses(77,060) (11,382) (71,535) (10,958)
Transfers(311) (5) 145
 2
Benefit obligation, December 312,110,904
 207,073
 1,837,653
 181,162
Fair value of plan assets, January 11,343,113
 170,862
 1,468,403
 190,814
Actual return on plan assets326,204
 34,928
 (91,836) (11,625)
Employer contributions47,808
 —
 37,550
 —
Participants contributions—
 2,311
 —
 2,472
Benefits paid and expenses(76,581) (10,532) (71,060) (10,801)
Other(127) (5) 56
 2
Fair value of plan assets, December 311,640,417
 197,564
 1,343,113
 170,862
Accrued benefit liability, December 31$(470,487) $(9,509) $(494,540) $(10,300)
Other liabilities (short-term)(518) (715) (512) (669)
Defined benefit pension and other postretirement benefit plans liability(469,969) (8,794) (494,028) (9,631)
Accrued benefit liability, December 31$(470,487) $(9,509) $(494,540) $(10,300)
AOCI debit, January 1 (excluding impact of PUC D&Os)$502,189
 $1,551
 $493,464
 $839
Recognized during year – prior service credit (cost)(7) 1,803
 (8) 1,803
Recognized during year – net actuarial losses(14,658) —
 (27,302) (98)
Occurring during year – net actuarial losses (gains)(9,446) 2,376
 36,035
 (993)
AOCI debit before cumulative impact of PUC D&Os, December 31478,078
 5,730
 502,189
 1,551
Cumulative impact of PUC D&Os(474,628) (7,458) (498,944) (4,929)
AOCI debit/(credit), December 31$3,450
 $(1,728) $3,245
 $(3,378)
Net actuarial loss$478,069
 $10,815
 $502,173
 $8,439
Prior service cost (gain)9
 (5,085) 16
 (6,888)
AOCI debit before cumulative impact of PUC D&Os, December 31478,078
 5,730
 502,189
 1,551
Cumulative impact of PUC D&Os(474,628) (7,458) (498,944) (4,929)
AOCI debit/(credit), December 313,450
 (1,728) 3,245
 (3,378)
Income taxes (benefits)(888) 445
 (836) 870
AOCI debit/(credit), net of taxes (benefits), December 31$2,562
 $(1,283) $2,409
 $(2,508)

As of December 31, 2019 and 2018, the other postretirement benefit plan shown in the table above had ABOs in excess of plan assets.
Pension benefits. In 2019, investment returns were higher than assumed rates and together with updates to mortality assumptions projected generationally, improved the funded position. Actuarial losses due to demographic experience, including assumption changes, the most significant of which was the decrease in the discount rate used to measure PBO compared to the prior year, partially offset the improvement in funded position.
In 2018, actuarial gains due to demographic experience, including assumption changes, the most significant of which was the increase in the discount rate used to measure PBO and updates to mortality assumptions projected generationally improved funded position but investment losses more than offset any improvement resulting in a deterioration in the funded position.

148

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Other benefits. In 2019, investment returns were higher than assumed rates, which improved funded position and predominately offset the actuarial losses due to demographic experience, including assumption changes, the most significant of which was the decrease in the discount rate used to measure APBO. Updates to the per capita claims costs also contributed to a deterioration in the funded position.
In 2018, actuarial gains due to demographic experience, including assumption changes, the most significant of which was the increase in the discount rate used to measure APBO along with updates to mortality assumptions projected generationally and per capita claims costs improved funded position beyond the deterioration caused by investment losses.
The dates used to determine retirement benefit measurements for the defined benefit plans and OPEB were December 31 of 2019, 2018 and 2017.
For purposes of calculating NPPC and NPBC, the Company and the Utilities have determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in each of years two through five – and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range restriction around the fair value of such assets (i.e., 85% to 115% of fair value).
A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund and pension liability volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.
The asset allocation of defined benefit retirement plans to equity and fixed income securities (excluding cash) and related investment policy targets and ranges were as follows:
 
Pension benefits1
 
Other benefits2
     Investment policy     Investment policy
December 312019
 2018
 Target
 Range 2019
 2018
 Target
 Range
Assets held by category 
  
  
    
  
  
  
Equity securities71% 69% 70% 65-75 71% 70% 70% 65-75
Fixed income securities29
 31
 30
 25-35 29
 30
 30
 25-35
 100% 100% 100%   100% 100% 100%  

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.

149

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Assets held in various trusts for the retirement benefit plans are measured at fair value on a recurring basis and were as follows:
 Pension benefits Other benefits
   Fair value measurements using   Fair value measurements using
(in millions)December 31 Quoted prices in active markets for identical assets
(Level 1)		 Significant other observable inputs
(Level 2)		 Significant unobservable inputs
(Level 3)		 December 31 Level 1 Level 2 Level 3
2019 
  
  
  
  
  
  
  
Equity securities$470
 $470
 $—
 $—
 $61
 $61
 $—
 $—
Equity index and exchange-traded funds610
 610
 —
 —
 69
 69
 —
 —
Equity investments at net asset value (NAV)78
 —
 —
 —
 11
 —
 —
 —
   Total equity investments1,158
 1,080
 —
 —
 141
 130
 —
 —
Fixed income securities and public mutual funds353
 123
 230
 —
 52
 49
 2
 —
Fixed income investments at NAV245
 —
 —
 —
 4
 —
 —
 —
   Total fixed income investments598
 123
 230
 —
 56
 49
 2
 —
Cash equivalents at NAV39
 —
 —
 —
 4
 —
 —
 —
Total1,795
 $1,203
 $230
 $—
 201
 $179
 $2
 $—
Cash, receivables and payables, net4
  
  
  
 —
  
  
  
Fair value of plan assets$1,799
  
  
  
 $201
  
  
  
2018 
  
  
  
  
  
  
  
Equity securities$507
 $507
 $—
 $—
 $65
 $65
 $—
 $—
Equity index and exchange-traded funds348
 348
 —
 —
 42
 42
 —
 —
Equity investments at NAV65
 —
 —
 —
 10
 —
 —
 —
   Total equity investments920
 855
 —
 —
 117
 107
 —
 —
Fixed income securities and public mutual funds310
 123
 187
 —
 47
 45
 2
 —
Fixed income investments at NAV208
 —
 —
 —
 4
 —
 —
 —
   Total fixed income investments518
 123
 187
 —
 51
 45
 2
 —
Cash equivalents at NAV36
 —
 —
 —
 5
 —
 —
 —
Total1,474
 $978
 $187
 $—
 173
 $152
 $2
 $—
Cash, receivables and payables, net5
  
  
  
 1
  
  
  
Fair value of plan assets$1,479
  
  
  
 $174
  
  
  


150

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


 Pension benefits Other benefits
Measured at net asset valueDecember 31
 Redemption frequency Redemption notice period December 31
 Redemption frequency Redemption notice period
(in millions)           
2019           
Non U.S. equity funds (a)$78
 Daily-Monthly 5-30 days $11
 Daily-Monthly 5-30 days
Fixed income investments (b)245
 Monthly 15 days 4
 Monthly 15 days
Cash equivalents (c)39
 Daily 0-1 day 4
 Daily 0-1 day
 $362
     $19
    
2018           
Non U.S. equity funds (a)$65
 Daily-Monthly 5-30 days $10
 Daily-Monthly 5-30 days
Fixed income investments (b)208
 Monthly 15 days 4
 Monthly 15 days
Cash equivalents (c)36
 Daily 0-1 day 5
 Daily 0-1 day
 $309
     $19
    
None of the investments presented in the tables above have unfunded commitments.
(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.
The fair values of the investments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset. Those judgments are developed by the Company based on the best information available in the circumstances.
The fair value of investments measured at net asset value presented in the tables above are intended to permit reconciliation to the fair value of plan assets amounts.
The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2019 and 2018.
Equity securities, equity index and exchange-traded funds, U.S. Treasury fixed income securities and public mutual funds (Level 1). Equity securities, equity index and exchange-traded funds, U.S. Treasury fixed income securities and public mutual funds are valued at the closing price reported on the active market on which the individual securities or funds are traded.
Fixed income securities (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings.
The following weighted-average assumptions were used in the accounting for the plans:
 Pension benefits Other benefits
December 312019 2018 2017 2019 2018 2017
Benefit obligation           
Discount rate3.61% 4.31% 3.74% 3.52% 4.34% 3.72%
Rate of compensation increase3.5
 3.5
 3.5
 NA   
 NA   
 NA   
Net periodic pension/benefit cost (years ended)           
Discount rate4.31
 3.74
 4.26
 4.34
 3.72
 4.22
Expected return on plan assets1
7.25
 7.50
 7.50
 7.25
 7.50
 7.50
Rate of compensation increase2
3.5
 3.5
 3.5
 NA   
 NA   
 NA   
NA  Not applicable
1 HEI’s and Utilities’ plan assets only. For 2019, 2018 and 2017, ASB’s expected return on plan assets was 4.51%, 3.94% and 4.46%, respectively.
2 The Company and the Utilities use a graded rate of compensation increase assumption based on age. The rate provided above is an average across all future years of service for the current population.

151

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The Company and the Utilities based their selection of an assumed discount rate for 2020 NPPC and NPBC and December 31, 2019 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (generally rated Aa or better) as of December 31, 2019. In selecting the expected rate of return on plan assets for 2020 NPPC and NPBC: a) HEI and the Utilities considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets in selecting 7.25% and b) ASB considered its liability driven investment strategy in selecting 3.69%, which is consistent with the assumed discount rate as of December 31, 2019 with a 20 basis point active manager premium. For 2019, retirement benefit plans’ assets of HEI and the Utilities had a net return of 24.3%.
As of December 31, 2019, the assumed health care trend rates for 2020 and future years were as follows: medical, 7%, grading down to 5% for 2028 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2018, the assumed health care trend rates for 2019 and future years were as follows: medical, 7.25%, grading down to 5% for 2028 and thereafter; dental, 5%; and vision, 4%.
The components of NPPC and NPBC were as follows:
 Pension benefits Other benefits
(in thousands)2019 2018 2017 2019 2018 2017
HEI consolidated           
Service cost$62,135
 $68,987
 $64,906
 $2,209
 $2,721
 $3,374
Interest cost84,267
 77,374
 81,185
 8,004
 7,933
 9,453
Expected return on plan assets(111,989) (108,953) (102,745) (12,356) (12,908) (12,326)
Amortization of net prior service gain(42) (42) (55) (1,806) (1,805) (1,793)
Amortization of net actuarial losses15,479
 30,084
 26,496
 (13) 95
 1,130
Net periodic pension/benefit cost49,850
 67,450
 69,787
 (3,962) (3,964) (162)
Impact of PUC D&Os48,143
 25,828
 (18,004) 3,258
 3,842
 1,211
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)$97,993
 $93,278
 $51,783
 $(704) $(122) $1,049
Hawaiian Electric consolidated           
Service cost$60,461
 $67,359
 $63,059
 $2,191
 $2,704
 $3,353
Interest cost77,851
 71,294
 74,632
 7,673
 7,628
 9,115
Expected return on plan assets(104,632) (102,368) (95,892) (12,180) (12,713) (12,147)
Amortization of net prior service (gain) cost7
 8
 8
 (1,803) (1,803) (1,804)
Amortization of net actuarial losses14,658
 27,302
 24,392
 —
 98
 1,102
Net periodic pension/benefit cost48,345
 63,595
 66,199
 (4,119) (4,086) (381)
Impact of PUC D&Os48,143
 25,828
 (18,004) 3,258
 3,842
 1,211
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)$96,488
 $89,423
 $48,195
 $(861) $(244) $830

The Company recorded pension expense of $59 million, $59 million and $33 million and OPEB expense of $(0.1) million, NaN and $1.0 million in 2019, 2018 and 2017, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $57 million, $55 million and $30 million and OPEB (income) expense of $(0.3) million, $(0.1) million and $0.8 million in 2019, 2018 and 2017, respectively, and charged the remaining amounts primarily to electric utility plant.

152

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Additional information on the defined benefit pension plans’ accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), and pension plans with ABOs and PBOs in excess of plan assets were as follows:
 HEI consolidated Hawaiian Electric consolidated
December 312019 2018 2019 2018
(in billions)       
Defined benefit plans - ABOs
$2.0
 $1.7
 $1.8
 $1.6
Defined benefit plans with ABO in excess of plan assets       
     ABOs1.9
 1.6
 1.8
 1.6
     Fair value of plan assets1.7
 1.4
 1.6
 1.3
Defined benefit plans with PBOs in excess of plan assets       
     PBOs2.2
 1.9
 2.1
 1.8
     Fair value of plan assets1.7
 1.4
 1.6
 1.3

HEI consolidated. The Company estimates that the cash funding for the qualified defined benefit pension plans in 2020 will be $69 million, which should fully satisfy the minimum required contributions to those plans, including requirements of the Utilities’ pension tracking mechanisms and the Plan’s funding policy. The Company’s current estimate of contributions to its other postretirement benefit plans in 2020 is NaN.
As of December 31, 2019, the benefits expected to be paid under all retirement benefit plans in 2020, 2021, 2022, 2023, 2024 and 2025 through 2029 amount to $91 million, $95 million, $99 million, $103 million, $107 million and $593 million, respectively.
Hawaiian Electric consolidated. The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2020 will be $68 million, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanisms and the Plan’s funding policy. The Utilities’ current estimate of contributions to its other postretirement benefit plans in 2020 is NaN.
As of December 31, 2019, the benefits expected to be paid under all retirement benefit plans in 2020, 2021, 2022, 2023, 2024 and 2025 through 2029 amounted to $84 million, $87 million, $90 million, $93 million, $97 million and $544 million, respectively.
Defined contribution plans information.  For 2019, 2018 and 2017, the Company’s expenses for its defined contribution plans under the HEIRSP and the ASB 401(k) Plan were $7 million, $7 million and $7 million, respectively, and cash contributions were $7 million, $7 million and $6 million, respectively. The Utilities’ expenses and cash contributions for its defined contribution plan under the HEIRSP for 2019, 2018 and 2017 were $3 million, $2 million and $2 million, respectively.
Note 11 ·Share-based compensation
Under the 2010 Equity and Incentive Plan, as amended, HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights (SARs), restricted shares, restricted stock units, performance shares and other share-based and cash-based awards. The 2010 Equity and Incentive Plan (original EIP) was amended and restated effective March 1, 2014 (EIP) and an additional 1.5 million shares were added to the shares available for issuance under these programs.
As of December 31, 2019, approximately 3.2 million shares remained available for future issuance under the terms of the EIP, assuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards, including an estimated 0.7 million shares that could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals for awards outstanding under long-term incentive plans (assuming that such performance goals are achieved at maximum levels).
Restricted stock units awarded under the 2010 Equity and Incentive Plan in 2019, 2018, 2017 and 2016 will vest and be issued in unrestricted stock in 4 equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become vested for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid at the end of the restriction period when the associated restricted stock units vest.

153

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Stock performance awards granted under the 2019-2021, 2018-2020 and 2017-2019 long-term incentive plans (LTIP) entitle the grantee to shares of common stock with dividend equivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.
Under the 2011 Nonemployee Director Stock Plan (2011 Director Plan), HEI can issue shares of common stock as compensation to nonemployee directors of HEI, Hawaiian Electric and ASB. On June 26, 2019, an additional 300,000 shares were made available for issuance under the 2011 Director Plan. As of December 31, 2019, there were 310,263 shares remaining available for future issuance under the 2011 Director Plan.
Share-based compensation expense and the related income tax benefit were as follows:
(in millions)2019
 2018
 2017
HEI consolidated     
Share-based compensation expense1
$10.0
 $7.8
 $5.4
Income tax benefit1.4
 1.1
 1.9
Hawaiian Electric consolidated     
Share-based compensation expense1
3.2
 2.7
 1.9
Income tax benefit0.6
 0.5
 0.7
1
For 2019, 2018 and 2017, the Company has not capitalized any share-based compensation.
Stock awards. HEI granted HEI common stock to nonemployee directors under the 2011 Director Plan as follows:
(dollars in millions)2019
 2018
 2017
Shares granted36,344
 38,821
 35,770
Fair value$1.6
 $1.3
 $1.2
Income tax benefit0.4
 0.3
 0.5

The number of shares issued to each nonemployee director of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI common stock on the grant date.
Restricted stock units.Information about HEI’s grants of restricted stock units was as follows:
 2019 2018 2017
 Shares 
 (1) Shares 
 (1) Shares 
 (1)
Outstanding, January 1200,358
 $33.05
 197,047
 $31.53
 220,683
 $29.57
Granted96,565
 37.82
 93,853
 34.12
 97,873
 33.47
Vested(76,813) 32.61
 (75,683) 30.56
 (92,147) 28.88
Forfeited(12,469) 34.20
 (14,859) 32.35
 (29,362) 31.57
Outstanding, December 31207,641
 $35.36
 200,358
 $33.05
 197,047
 $31.53
Total weighted-average grant-date fair value of shares granted (in millions)$3.7
   $3.2
   $3.3
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For 2019, 2018 and 2017, total restricted stock units and related dividends that vested had a fair value of $3.2 million, $2.7 million and $3.5 million, respectively, and the related tax benefits were $0.5 million, $0.4 million and $1.1 million, respectively.
As of December 31, 2019, there was $4.8 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.5 years.
Long-term incentive plan payable in stock.  The 2017-2019, 2018-2020 and 2019-2021 LTIPs provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals, including a market condition goal. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made, subject to the achievement of specified performance levels and calculated dividend equivalents. The potential payout varies from 0% to 200% of the number of target shares, depending on the achievement of the goals. The market condition goal is

154

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


based on HEI’s total shareholder return (TSR) compared to the Edison Electric Institute Index over the relevant three-year period. The other performance condition goals relate to earnings per share (EPS) growth, return on average common equity (ROACE), Hawaiian Electric’s net income growth, ASB’s efficiency ratio, and Pacific Current’s EBITDA growth and return on average invested capital.
LTIP linked to TSR.  Information about HEI’s LTIP grants linked to TSR was as follows:
 2019 2018 2017
 Shares
 (1) Shares
 (1) Shares
 (1)
Outstanding, January 165,578
 $38.81
 32,904
 $39.51
 83,106
 $22.95
Granted35,215
 41.07
 37,832
 38.21
 37,204
 39.51
Vested (issued or unissued and cancelled)—
 —
 —
 —
 (83,106) 22.95
Forfeited(4,391) 39.19
 (5,158) 38.84
 (4,300) 39.51
Outstanding, December 3196,402
 $39.62
 65,578
 $38.81
 32,904
 $39.51
Total weighted-average grant-date fair value of shares granted (in millions)$1.4
   $1.4
   $1.5
  
(1)Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period.
The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TSR and the resulting fair value of LTIP awards granted:
 2019
 2018
 2017
Risk-free interest rate2.48% 2.29% 1.46%
Expected life in years3
 3
 3
Expected volatility15.8% 17.0% 20.1%
Range of expected volatility for Peer Group15.0% to 73.2%
 15.1% to 26.2%
 15.4% to 26.0%
Grant date fair value (per share)$41.07
 $38.20
 $39.51

For 2017, total vested LTIP awards linked to TSR and related dividends had a fair value of $1.9 million and the related tax benefits were $0.7 million. There were no share-based LTIP awards linked to TSR with a vesting date in 2018 or 2019.
As of December 31, 2019, there was $1.4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TSR. The cost is expected to be recognized over a weighted-average period of 1.5 years.
LTIP awards linked to other performance conditions.  Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:
 2019 2018 2017
 Shares
 (1) Shares
 (1) Shares
 (1)
Outstanding, January 1276,169
 $33.80
 131,616
 $33.47
 109,816
 $25.18
Granted140,855
 37.78
 151,328
 34.12
 148,818
 33.47
Vested—
 —
 —
 —
 (109,816) 25.18
Increase above target (cancelled)4,314
 33.53
 13,858
 33.49
 —
 —
Forfeited(17,570) 34.66
 (20,633) 33.80
 (17,202) 33.48
Outstanding, December 31403,768
 $35.15
 276,169
 $33.80
 131,616
 $33.47
Total weighted-average grant-date fair value of shares granted (at target performance levels) (in millions)$5.3
   $5.2
   $5.0
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

155

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


For 2017, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $4.2 million and the related tax benefits were $1.6 million. There were no share-based LTIP awards linked to other performance conditions with a vesting date in 2018 or 2019.
As of December 31, 2019, there was $5.1 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TSR. The cost is expected to be recognized over a weighted-average period of 1.5 years.
Note 12·Income taxes
The components of income taxes attributable to net income for common stock were as follows:
 HEI consolidated Hawaiian Electric consolidated
Years ended December 312019 2018 2017 2019 2018 2017
(in thousands) 
  
  
      
Federal 
  
  
      
Current$28,736
 $42,903
 $61,534
 $21,751
 $29,649
 $36,267
Deferred*(4,353) (6,099) 33,967
 (7,793) (5,245) 35,229
Deferred tax credits, net**13,410
 (12) (20) 13,155
 (12) (20)
 37,793
 36,792
 95,481
 27,113
 24,392
 71,476
State 
  
  
  
  
  
Current10,472
 17,361
 10,076
 5,579
 13,210
 8,947
Deferred(10,732) (3,269) 3,868
 (8,491) (2,737) 2,808
Deferred tax credits, net**14,104
 (87) (32) 14,104
 (87) (32)
 13,844
 14,005
 13,912
 11,192
 10,386
 11,723
Total$51,637
 $50,797
 $109,393
 $38,305
 $34,778
 $83,199

*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.
A reconciliation of the amount of income taxes computed at the federal statutory rate to the amount provided in the consolidated statements of income was as follows:
 HEI consolidated Hawaiian Electric consolidated
Years ended December 312019 2018 2017 2019 2018 2017
(in thousands) 
  
  
      
Amount at the federal statutory income tax rate$56,996
 $53,437
 $96,796
 $41,399
 $37,889
 $71,801
Increase (decrease) resulting from: 
  
  
  
  
  
State income taxes, net of federal income tax benefit11,658
 11,832
 9,789
 8,703
 8,080
 7,584
Net deferred tax asset (liability) adjustment related to the Tax Act(9,255) (9,540) 13,420
 (9,255) (9,285) 9,168
Other, net(7,762) (4,932) (10,612) (2,542) (1,906) (5,354)
Total$51,637
 $50,797
 $109,393
 $38,305
 $34,778
 $83,199
Effective income tax rate19.0% 20.0% 39.6% 19.4% 19.3% 40.6%



156

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:
 HEI consolidated Hawaiian Electric consolidated
December 312019 2018 2019 2018
(in thousands) 
  
    
Deferred tax assets 
  
    
Regulatory liabilities, excluding amounts attributable to property, plant and equipment$100,427
 $104,868
 $100,427
 $104,868
Operating lease liabilities51,573
 —
 45,608
 —
Allowance for bad debts14,858
 14,647
 560
 659
Other1
54,028
 46,036
 41,181
 26,522
Total deferred tax assets220,886
 165,551
 187,776
 132,049
Deferred tax liabilities 
  
    
Property, plant and equipment related464,312
 437,644
 458,349
 434,831
Operating lease right-of-use assets51,542
 —
 45,608
 —
Regulatory assets, excluding amounts attributable to property, plant and equipment33,897
 37,345
 33,897
 37,345
Deferred RAM and RBA revenues—
 11,278
 —
 11,278
Retirement benefits9,684
 20,173
 13,072
 25,430
Other40,776
 31,629
 14,001
 6,362
Total deferred tax liabilities600,211
 538,069
 564,927
 515,246
Net deferred income tax liability$379,325
 $372,518
 $377,151
 $383,197

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.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company and the Utilities will realize substantially all of the benefits of the deferred tax assets. As of December 31, 2019 and 2018, valuation allowances for deferred tax benefits were NaN. The Utilities are included in the consolidated federal and Hawaii income tax returns of HEI and are subject to the provisions of HEI’s tax sharing agreement, which determines each subsidiary’s (or subgroup’s) income tax return liabilities and refunds on a standalone basis as if it filed a separate return (or subgroup consolidated return).
The following is a reconciliation of the Company’s liability for unrecognized tax benefits for 2019, 2018 and 2017.
 HEI consolidated Hawaiian Electric consolidated
(in millions)2019 2018 2017 2019 2018 2017
Unrecognized tax benefits, January 1$2.1
 $4.0
 $3.8
 $1.6
 $3.5
 3.8
Additions based on tax positions taken during the year0.5
 0.3
 0.9
 0.5
 0.3
 0.4
Reductions based on tax positions taken during the year—
 —
 (0.2) —
 —
 (0.2)
Additions for tax positions of prior years0.1
 0.1
 —
 0.1
 0.1
 —
Reductions for tax positions of prior years(0.2) (0.1) (0.5) (0.2) (0.1) (0.5)
Lapses of statute of limitations(0.3) (2.2) —
 (0.3) (2.2) —
Unrecognized tax benefits, December 31$2.2
 $2.1
 $4.0
 $1.7
 $1.6
 $3.5

At December 31, 2019 and 2018, there were $0.5 million of unrecognized tax benefits, if recognized, would affect the Company’s annual effective tax rate. As of December 31, 2019 and 2018, the Utilities had 0 unrecognized tax benefits that, if recognized, would affect the Utilities’ annual effective tax rate. The Company and Utilities believe that the unrecognized tax benefits will not significantly increase or decrease within the next 12 months.
HEI consolidated. The Company recognizes interest accrued related to unrecognized tax benefits in “Interest expense-other than on deposit liabilities and other bank borrowings” and penalties, if any, in operating expenses. In 2019, 2018 and 2017, the Company recognized approximately $0.1 million, $(0.1) million and $0.2 million in interest expense. The Company had $0.6 million and $0.4 million of interest accrued as of December 31, 2019 and 2018, respectively.

157

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Hawaiian Electric consolidated. The Utilities recognize interest accrued related to unrecognized tax benefits in “Interest expense and other charges, net” and penalties, if any, in operating expenses. In 2019, 2018 and 2017, the Utilities recognized approximately $0.1 million in interest expense. The Utilities had $0.4 million and $0.3 million of interest accrued as of December 31, 2019 and 2018, respectively.
As of December 31, 2019, the disclosures above present the Company’s and the Utilities’ accruals for potential tax liabilities, which involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts. Based on information currently available, the Company and the Utilities believe these accruals have adequately provided for potential income tax issues with federal and state tax authorities, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.
IRS examinations have been completed and settled through the tax year 2011 and the statute of limitations has expired for years prior to 2016, leaving subsequent years subject to IRS examination.  The tax years 2011 and subsequent are still subject to examination by the Hawaii Department of Taxation.
Major tax developments. The changes enacted in the 2017Tax Cuts and Jobs Act continue to impact corporate taxpayers. The following summarizes the provisions that have a major impact on the Company.
Lower tax rate. The corporate income tax rate reduction from 35% to 21% lowered the Company’s effective tax rate in 2018 and the subsequent years. For the regulated Utilities, the excess ADIT resulting from the rate change is being returned to customers over various periods determined with the approval of the PUC.
Bonus depreciation. The Tax Act allows 100% bonus depreciation through the end of 2022 for qualified property purchased and placed in service after September 27, 2017. The Tax Act provides that property used in the trade or business of a regulated utility (including the furnishing or selling electrical energy) is not qualified property. However, property placed into service after September 27, 2017 are grandfathered under the pre-Tax Act rules allowing 50% bonus depreciation if subject to written binding purchase contracts prior to September 28, 2017.
Other applicable provisions. There are a number of other provisions in the Tax Act that have an impact on the Company, including the repeal of the domestic production activities deduction (DPAD), non-deductibility of transportation fringe benefits excluded from employees income, and the increased limitation on the deductibility of executive compensation.
SAB No. 118. On December 22, 2017, the SEC staff issued SAB No. 118 to address the application of GAAP in situations
when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in
reasonable detail to complete the accounting for certain income tax effects of the Tax Act.
The Company applied the guidance in SAB No. 118 when accounting for enactment date effects of the Tax Act in 2017 and throughout 2018. At December 31, 2017, the Company had not completed its re-measurement of deferred tax assets and liabilities as a result of the reduction in the US federal corporate income tax rate to 21% and, in accordance with SAB No. 118, recorded a provisional amount. The Tax Act’s reduction of the corporate tax rate to 21% resulted in a net deferred tax balance that was in excess of the taxes the Company expected to pay or be refunded in the future when the temporary differences that created these deferred taxes reverse. The excess related to the Utilities’ deferred taxes that were identified to be refunded in rates was reclassified to a regulatory liability and is currently being returned to the customers over various periods of time. The remaining excess was written off through deferred tax expense. Consequently, in 2017, the Company recorded a provisional increase in deferred tax expense of $13.4 million ($9.2 million at the Utilities). In December 2018, the end date of the measurement period for purposes of SAB No. 118 passed, and consequently, the Company (and Utilities) completed its analysis based on available Treasury and legislative guidance relating to the Tax Act.
In 2018, the Company re-measured certain deferred tax assets and liabilities based on the rates at which they were expected to reverse in the future. For the period ended December 31, 2018, the net deferred tax liabilities decreased by $13.9 million ($13.6 million at the Utilities) with the corresponding net adjustment that decreased deferred tax expense by $5.5 million ($5.2 million at the Utilities) and increased the regulatory liability by $11.3 million. The decrease in deferred tax expense is included as a component of income tax expense and had the effect of decreasing the effective tax rate in 2018 from 22.1% to 20.0% (22.2% to 19.3% at the Utilities).


158

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 13·Cash flows
Years ended December 312019
 2018
 2017
(in millions)     
Supplemental disclosures of cash flow information 
  
  
HEI consolidated     
Interest paid to non-affiliates, net of amounts capitalized$107
 $102
 $83
Income taxes paid (including refundable credits)56
 72
 55
Income taxes refunded (including refundable credits)4
 34
 1
Hawaiian Electric consolidated     
Interest paid to non-affiliates, net of amounts capitalized68
 73
 63
Income taxes paid (including refundable credits)55
 64
 26
Income taxes refunded (including refundable credits)4
 31
 —
Supplemental disclosures of noncash activities 
  
  
HEI consolidated     
Unpaid invoices and accruals for capital expenditures, balance, end of period (investing)64
 59
 38
Loans transferred from held for investment to held for sale (investing)—
 1
 41
Common stock issued (gross) for director and executive/management compensation (financing)1
5
 4
 11
Obligations to fund low income housing investments, net (investing)11
 12
 13
Transfer of retail repurchase agreements to deposit liabilities (financing)—
 102
 —
Hawaiian Electric consolidated     
Unpaid invoices and accruals for capital expenditures, balance, end of period (investing)62
 44
 38
HEI Consolidated and Hawaiian Electric consolidated     
Electric utility property, plant and equipment     
Estimated fair value of noncash contributions in aid of construction (investing)9
 14
 18
Acquisition of Hawaiian Telcom’s interest in joint poles (investing)—
 48
 —

1The amounts shown represent the market value of common stock issued for director and executive/management compensation and withheld to satisfy statutory tax liabilities.
Note 14·Regulatory restrictions on net assets
The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capitalization of the electric utilities (including the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restricted in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed as relinquishing any right the PUC may have to review the dividend policies of the electric utility subsidiaries. As of December 31, 2019, the consolidated common stock equity of HEI’s electric utility subsidiaries was 56% of their total capitalization (as calculated for purposes of the PUC Agreement). As of December 31, 2019, Hawaiian Electric and its subsidiaries had common stock equity of $2.0 billion of which approximately $825 million was not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.
The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. ASB is required to notify the FRB and OCC prior to making any capital distribution (including dividends) to HEI (through ASB Hawaii). All dividends are subject to review by the OCC and FRB and receipt of a letter from the FRB communicating the agencies’ non-objection to the payment of any dividend ASB proposes to declare and pay to ASB Hawaii and HEI. Generally, the FRB and OCC may disapprove or deny ASB’s request to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises

159

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation or agreement between ASB and the OCC. As of December 31, 2019, in order to maintain its “well-capitalized” position, ASB could not transfer approximately $487 million of net assets to HEI.
HEI and its subsidiaries are also subject to debt covenants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual restrictions applicable to HEI and/or its subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock.
Note 15·Significant group concentrations of credit risk
Most of the Company’s business activity is with customers located in the State of Hawaii.
The Utilities are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. The Utilities provide the only electric public utility service on the islands they serve. The Utilities extend credit to customers, all of whom reside or conduct business in the State of Hawaii. See Note 3 of the Consolidated Financial Statements for a discussion of the Utilities’ major customers. The International Brotherhood of Electrical Workers Local 1260 represents roughly half of the Utilities’ workforce covered by a collective bargaining agreement that expires on October 31, 2021.
Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment securities it owns. Substantially all real estate loans are collateralized by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination.
Pacific Current’s investments are in the State of Hawaii since its strategy is focused on investing in non-regulated renewable energy and sustainable infrastructure in the State of Hawaii.
Note 16·Fair value measurements
Fair value measurement and disclosure valuation methodology. The following are descriptions of the valuation methodologies used for assets and liabilities recorded at fair value and for estimating fair value for financial instruments not carried at fair value:
Short-term borrowings—other than bank.  The carrying amount of short-term borrowings approximated fair value because of the short maturity of these instruments.
Investment securities. The fair value of ASB’s investment securities is determined quarterly through pricing obtained from independent third-party pricing services or from brokers not affiliated with the trade. Non-binding broker quotes are infrequent and generally occur for new securities that are settled close to the month-end pricing date. The third-party pricing vendors ASB uses for pricing its securities are reputable firms that provide pricing services on a global basis and have processes in place to ensure quality and control. The third-party pricing services use a variety of methods to determine the fair value of securities that fall under Level 2 of the ASB’s fair value measurement hierarchy. Among the considerations are quoted prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds, and other observable market factors.
To enhance the robustness of the pricing process, ASB will on a quarterly basis compare its standard third-party vendor’s price with that of another third-party vendor. If the prices are within an acceptable tolerance range, the price of the standard


vendor will be accepted. If the variance is beyond the tolerance range, an evaluation will be conducted by ASB and a challenge to the price may be made. Fair value in such cases will be based on the value that best reflects the data and observable characteristics of the security. In all cases, the fair value used will have been independently determined by a third-party pricing vendor or non-affiliated broker and not by ASB.broker.
The fair value of the mortgage revenue bondbonds is estimated using a discounted cash flow model to calculate the present value of future principal and interest payments and, therefore is classified within Level 3 of the valuation hierarchy.
Loans held for sale. LoansResidential and commercial loans are carried at the lower of cost or market and are valued using market observable pricing inputs, which are derived from third party loan sales and, securitizations and, therefore, are classified within Level 2 of the valuation hierarchy.
Loans held for investment. Fair value of loans held for investment is derived using a discounted cash flow approach which includes an evaluation of the underlying loan characteristics. The valuation model uses loan characteristics which includes product type, maturity dates and the underlying interest rate of the portfolio. This information is input into the valuation models

160

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


along with various forecast valuation assumptions including prepayment forecasts, to determine the discount rate. These assumptions are derived from internal and third party sources. NotingSince the valuation is derived from model-based techniques, ASB includes loans held for investment within Level 3 of the valuation hierarchy.
Impaired loans. At the time a loan is considered impaired, it is valued at the lower of cost or fair value. Fair value is determined primarily by using an income, cost or market approach and is normally provided through appraisals. Impaired loans carried at fair value generally receive specific allocations within the allowance for loan losses. For collateral-dependent loans, fair value is commonly based on recent real estate appraisals. These appraisals may utilize a single valuation approach or a combination of approaches including comparable sales and the income approach. Adjustments are routinely made in the appraisal process by the independent appraisers to adjust for differences between the comparable sales and income data available. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. Non-real estate collateral may be valued using an appraisal, net book value per the borrower’s financial statements, or aging reports, adjusted or discounted based on management’s historical knowledge, changes in market conditions from the time of the valuation and management’s expertise and knowledge of the client and client’s business, resulting in a Level 3 fair value classification. Generally, impaired loans are evaluated quarterly for additional impairment and adjusted accordingly.
Other realReal estate ownedacquired in settlement of loans. Foreclosed assets are carried at fair value (less estimated costs to sell) and isare generally based upon appraisals or independent market prices that are periodically updated subsequent to classification as real estate owned. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. ASB estimates the fair value of collateral-dependent loans and real estate owned using the sales comparison approach.
Mortgage servicing rights. Mortgage servicing rights (MSR)MSRs are capitalized at fair value based on market data at the time of sale and accounted for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing rightsMSRs are evaluated for impairment at each reporting date. ASB's MSR isMSRs are stratified based on predominant risk characteristics of the underlying loans including loan type and note rate. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in "Other income, net""Revenues - bank" in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable. ASB compares the fair value of MSRMSRs to an estimated value calculated by an independent third-party. The third-party relies on both published and unpublished sources of market related assumptions and theirits own experience and expertise to arrive at a value. ASB uses the third-party value only to assess the reasonableness of its own estimate.
Time depositsDeposit liabilities. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for depositsFHLB advances of similar remaining maturities. Deposit liabilities are classified in Level 2 of the valuation hierarchy.
Other borrowings. For fixed-rate advances and repurchase agreements, fair value is estimated using quantitative discounted cash flow models that require the use of interest rate inputs that are currently offered for advances and repurchase agreements of similar remaining maturities. The majority of market inputs are actively quoted and can be validated through external sources, including broker market transactions and third party pricing services.
Long-term debt-otherdebt—other than bank.  Fair value of long-term debt of HEI and the Utilities was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities and from discounting the future cash flows using the current rates offered for debt of the same or similar risks, terms, and remaining maturities. Long-term debt-other than bank is classified in Level 2 of the valuation hierarchy.
Interest rate lock commitments (IRLCs). The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.


Forward sales commitments. To be announced (TBA) mortgage-backed securities forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined using quoted prices in the market place that are observable and are classified as Level 2 measurements.
Window forward contract. The estimated fair value was obtained from a third-party financial services provider based on the effective exchange rate offered for the foreign currency denominated transaction. Window forward contracts are classified as Level 2 measurements.
The following table presents the carrying or notional amount, fair value, and placement in the fair value hierarchy of the Company’s financial instruments. For stock in Federal Home Loan Bank, the carrying amount is a reasonable estimate of fair value because it can only be redeemed at par.For bank-owned life insurance, the carrying amount is the cash surrender value of the insurance policies, which is a reasonable estimate of fair value. For financial liabilities such as noninterest-bearing demand, interest-bearing demand, and savings and money market deposits, the carrying amount is a reasonable estimate of fair value as these liabilities have no stated maturity.



161

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

   Estimated fair value
(in thousands)
Carrying or notional
amount
 
Quoted prices in active markets for identical assets
 (Level 1)
 
Significant other observable inputs
(Level 2)
 Significant unobservable inputs
(Level 3)		 Total
December 31, 2016 
  
  
  
  
Financial assets 
  
  
  
  
HEI consolidated         
Money market funds$13,085
 $—
 $13,085
 $—
 $13,085
Available-for-sale investment securities1,105,182
 —
 1,089,755
 15,427
 1,105,182
Stock in Federal Home Loan Bank11,218
 —
 11,218
 —
 11,218
Loans receivable, net4,701,977
 —
 13,333
 4,839,493
 4,852,826
Mortgage servicing rights9,373
 —
 —
 13,216
 13,216
Bank-owned life insurance143,197
 —
 143,197
 —
 143,197
Derivative assets23,578
 —
 453
 —
 453
Financial liabilities 
  
  
  
  
HEI consolidated         
Deposit liabilities5,548,929
 —
 5,546,644
 —
 5,546,644
Other bank borrowings192,618
 —
 193,991
 —
 193,991
Long-term debt, net—other than bank1,619,019
 —
 1,704,717
 —
 1,704,717
Derivative liabilities53,852
 129
 823
 —
 952
Hawaiian Electric consolidated         
Long-term debt, net1,319,260
 —
 1,399,490
 —
 1,399,490
Derivative liabilities20,734
 —
 743
 —
 743
December 31, 2015 
  
  
  
  
Financial assets 
  
  
  
  
HEI consolidated         
Money market funds$10
 $—
 $10
 $—
 $10
Available-for-sale investment securities820,648
 —
 820,648
 —
 820,648
Stock in Federal Home Loan Bank10,678
 —
 10,678
 —
 10,678
Loans receivable, net4,570,412
 —
 4,639
 4,744,886
 4,749,525
Mortgage servicing rights8,884
 —
 —
 11,790
 11,790
Bank-owned life insurance138,139
 —
 138,139
 —
 138,139
Derivative assets22,616
 —
 385
 —
 385
Financial liabilities 
  
  
  
  
HEI consolidated         
Deposit liabilities5,025,254
 —
 5,024,500
 —
 5,024,500
Short-term borrowings—other than bank103,063
 —
 103,063
 —
 103,063
Other bank borrowings328,582
 —
 333,392
 —
 333,392
Long-term debt, net—other than bank*1,578,368
 —
 1,669,087
 —
 1,669,087
Derivative liabilities23,269
 15
 15
 —
 30
Hawaiian Electric consolidated         
Long-term debt, net*1,278,702
 —
 1,363,766
 —
 1,363,766

* See Note 1 for the impact to prior period financial information of the adoption of ASU No. 2015-03.
   Estimated fair value
(in thousands)
Carrying or notional
amount
 
Quoted prices in active markets for identical assets
 (Level 1)
 
Significant other observable inputs
(Level 2)
 Significant unobservable inputs
(Level 3)		 Total
December 31, 2019 
  
  
  
  
Financial assets 
  
  
  
  
HEI consolidated         
Available-for-sale investment securities$1,232,826
 $—
 $1,204,229
 $28,597
 $1,232,826
Held-to-maturity investment securities139,451
 —
 143,467
 —
 143,467
Stock in Federal Home Loan Bank8,434
 —
 8,434
 —
 8,434
Loans, net5,080,107
 —
 12,295
 5,145,242
 5,157,537
Mortgage servicing rights9,101
 —
 —
 12,379
 12,379
Derivative assets25,179
 —
 300
 —
 300
Financial liabilities 
  
  
  
  
HEI consolidated         
Deposit liabilities769,825
 —
 765,976
 —
 765,976
Short-term borrowings—other than bank185,710
 —
 185,710
 —
 185,710
Other bank borrowings115,110
 —
 115,107
 —
 115,107
Long-term debt, net—other than bank1,964,365
 


 2,156,927
 


 2,156,927
Derivative liabilities51,375
 33
 2,185
 —
 2,218
Hawaiian Electric consolidated         
Short-term borrowings88,987
 —
 88,987
 —
 88,987
Long-term debt, net1,497,667
 —
 1,670,189
 —
 1,670,189
December 31, 2018 
  
  
  
  
Financial assets 
  
  
  
  
HEI consolidated         
Available-for-sale investment securities$1,388,533
 $—
 $1,364,897
 $23,636
 $1,388,533
Held-to-maturity investment securities141,875
 —
 142,057
 —
 142,057
Stock in Federal Home Loan Bank9,958
 —
 9,958
 —
 9,958
Loans, net4,792,707
 —
 1,809
 4,800,244
 4,802,053
Mortgage servicing rights8,062
 —
 —
 13,618
 13,618
Derivative assets10,180
 —
 91
 —
 91
Financial liabilities 
  
  
  
  
HEI consolidated         
Deposit liabilities827,841
 —
 817,667
 —
 817,667
Short-term borrowings—other than bank73,992
 —
 73,992
 —
 73,992
Other bank borrowings110,040
 —
 110,037
 —
 110,037
Long-term debt, net—other than bank1,879,641
 —
 1,904,261
 —
 1,904,261
Derivative liabilities34,132
 34
 596
 —
 630
Hawaiian Electric consolidated         
Short-term borrowings25,000
 —
 25,000
 —
 25,000
Long-term debt, net1,418,802
 —
 1,443,968
 —
 1,443,968





162

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Fair value measurements on a recurring basis.  Assets and liabilities measured at fair value on a recurring basis were as follows:
December 312019 2018
 Fair value measurements using Fair value measurements using
(in thousands)Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Available-for-sale investment securities (bank segment) 
  
  
      
Mortgage-backed securities — issued or guaranteed by U.S. Government agencies or sponsored agencies$—
 $1,026,385
 $—
 $—
 $1,161,416
 $—
U.S. Treasury and federal agency obligations—
 117,787
 —
 —
 154,349
 —
Corporate bonds—
 60,057
 —
 —
 49,132
 —
Mortgage revenue bonds—
 —
 28,597
 —
 —
 23,636
 $—
 $1,204,229
 $28,597
 $—
 $1,364,897
 $23,636
Derivative assets           
Interest rate lock commitments (bank segment)1
$—
 $297
 $—
 $—
 $91
 $—
Forward commitments (bank segment)1
—
 3
 —
 —
 —
 —
 $—
 $300
 $—
 $—
 $91
 $—
Derivative liabilities           
Interest rate lock commitments (bank segment)1
$—
 $—
 $—
 $—
 $—
 $—
Forward commitments (bank segment)1
33
 12
 —
 34
 9
 —
Interest rate swap (Other segment)2
—
 2,173
 —
 —
 587
 —

$33
 $2,185
 $—
 $34
 $596
 $—

December 312016 2015
 Fair value measurements using Fair value measurements using
(in thousands)Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Money market funds (“other” segment)$—
 $13,085
 $—
 $—
 $10
 $—
Available-for-sale investment securities (bank segment) 
  
  
      
Mortgage-related securities-FNMA, FHLMC and GNMA$—
 $897,474
 $—
 $—
 $607,689
 $—
U.S. Treasury and federal agency obligations—
 192,281
 —
 —
 212,959
 —
Mortgage revenue bond—
 —
 15,427
 —
 —
 —
 $—
 $1,089,755
 $15,427
 $—
 $820,648
 $—
Derivative assets (bank segment) 1
           
Interest rate lock commitments$—
 $445
 $—
 $—
 $384
 $—
Forward commitments—
 8
 —
 —
 1
 —
 $—
 $453
 $—
 $—
 $385
 $—
Derivative liabilities           
Interest rate lock commitments (bank segment) 1
$—
 $24
 $—
 $—
 $—
 $—
Forward commitments (bank segment) 1
129
 56
 —
 15
 15
 —
Window forward contracts (electric utility segment)2
—
 743
 —
 —
 —
 —

$129
 $823
 $—
 $15
 $15
 $—
1 Derivatives are carried at fair value in other assets or other liabilities in the balance sheets with changes in value included in mortgage banking income.
1
2		Derivatives are carried at fair value with changes in value reflected in the balance sheet in other assets or other liabilities and included in mortgage banking income.
2
Liability derivatives are included in other currentOther liabilities in the balance sheets.
There were no transfers of financial assets and liabilities between Level 1 and Level 2 of the fair value hierarchy during the years ended December 31, 20162019 and 2015.2018.
The changes in Level 3 assets and liabilities measured at fair value on a recurring basis were as follows:
(in thousands)2019
2018
Mortgage revenue bonds  
Balance, January 1$23,636
$15,427
Principal payments received—
—
Purchases4,961
8,209
Unrealized gain (loss) included in other comprehensive income—
—
Balance, December 31$28,597
$23,636
(in thousands)Mortgage revenue bond
Balance at December 31, 2015$—
Principal payments received—
Purchases15,427
Unrealized gain (loss) included in other comprehensive income—
Balance at December 31, 2016$15,427

ASB holds onetwo mortgage revenue bondbonds issued by the Department of Budget and Finance of the State of Hawaii. The Company estimates the fair value by using a discounted cash flow model to calculate the present value of estimated future principal and interest payments. The unobservable input used in the fair value measurement is the weighted average discount rate. As of December 31, 2016,2019, the weighted average discount rate was 2.517%3.41% which was derived by incorporating a credit spread over the one month LIBOR rate. Significant increases (decreases) in the weighted average discount rate could result in a significantly lower (higher) fair value measurement.

163

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Fair value measurements on a nonrecurring basis.  Certain assets and liabilities are measured at fair value on a nonrecurring basis and therefore are not included in the tables above. These measurements primarily result from assets carried at the lower of cost or fair value or from impairment of individual assets. The carrying value of assets measured at fair value on a nonrecurring


basis were as follows:
   Fair value measurements using
(in thousands)Balance Level 1 Level 2 Level 3
December 31, 2019 
  
  
  
Loans$25
 $—
 $—
 $25
December 31, 2018       
Loans77
 —
 —
 77
Real estate acquired in settlement of loans186
 —
 —
 186

   Fair value measurements using
(in thousands)Balance Level 1 Level 2 Level 3
December 31, 2016 
  
  
  
Loans$2,767
 $—
 $—
 $2,767
Real estate acquired in settlement of loans1,189
 —
 —
 1,189
December 31, 2015       
Loans178
 —
 —
 178
Real estate acquired in settlement of loans1,030
 —
 —
 1,030
For 20162019 and 2015,2018, there were no adjustments to fair value for ASB’s loans held for sale.
The following table presents quantitative information about Level 3 fair value measurements for financial instruments measured at fair value on a nonrecurring basis:
       
Significant unobservable
 input value (1)
(dollars in thousands)Fair value Valuation technique Significant unobservable input Range Weighted
Average
December 31, 2019         
Residential land$25
 Fair value of property or collateral Appraised value less 7% selling cost N/A (2) N/A (2)
Total loans$25
        
December 31, 2018         
Home equity lines of credit77
 Fair value of property or collateral Appraised value less 7% selling cost N/A (2) N/A (2)
Total loans$77
        
Real estate acquired in settlement of loans$186
 Fair value of property or collateral Appraised value less 7% selling cost N/A (2) N/A (2)
       
Significant unobservable
 input value (1)
(dollars in thousands)Fair value Valuation technique Significant unobservable input Range Weighted
Average
December 31, 2016         
Residential loans$2,468
 Sales price Sales price 95-100% 97%
Residential loans287
 Fair value of property or collateral Appraised value less 7% selling cost 42-65% 61%
Home equity lines of credit12
 Fair value of property or collateral Appraised value less 7% selling cost   N/A (2)
Total loans$2,767
        
          
Real estate acquired in settlement of loans$1,189
 Fair value of property or collateral Appraised value less 7% selling cost 100% 100%
December 31, 2015         
Residential loans$50
 Fair value of property or collateral Appraised value less 7% selling cost 
 N/A (2)
Home equity lines of credit128
 Fair value of property or collateral Appraised value less 7% selling cost 
 N/A (2)
Total loans$178
        
          
Real estate acquired in settlement of loans$1,030
 Fair value of property or collateral Appraised value less 7% selling cost 100% 100%

(1)Represent percent of outstanding principal balance.
(2)N/A - Not applicable. There is one loan in each fair value measurement type.
(2) N/A - Not applicable. There is one asset in each fair value measurement type.
Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurements.


164



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 17·Other related-party transactionsQuarterly information (unaudited)
Mr. Timothy Johns, a member of the Hawaiian Electric Board of Directors, is an executive officer of Hawaii Medical Service Association (HMSA). Ms. Susan Li, an executive of Hawaiian Electric, is the Chair of the Hawaii Dental Service (HDS) Board of Directors. The Company’s HMSA costs and expense (for health insurance premiums, claims plus administration expense and stop-loss insurance coverages) and HDS costs and expense (for dental insurance premiums) and the Utilities’ HMSA costs and expense (for health insurance premiums) and HDS costs and expense (for dental insurance premiums) were as follows:
 HEI consolidated Hawaiian Electric consolidated
(in millions)2016 2015 2014 2016 2015 2014
HMSA costs$28
 $30
 $25
 $22
 $23
 $20
HMSA expense*20
 21
 18
 14
 14
 13
HDS costs3
 3
 3
 2
 2
 2
HDS expense*2
 2
 2
 1
 1
 1
* Charged the remaining costs primarily to electric utility plant.
The costs and expense in the table above are gross amounts (i.e., not net of employee contributions to employee benefits).


18·Quarterly information (unaudited)
Selected quarterly information was as follows:
Quarters ended Years endedQuarters ended Years ended
(in thousands, except per share amounts)March 31 June 30 Sept. 30 Dec. 31 December 31March 31 June 30 Sept. 30 Dec. 31 December 31
HEI consolidated                  
20161
 
  
  
  
  
2019 
  
  
  
  
Revenues$661,615
 $715,485
 $771,535
 $725,966
 $2,874,601
Operating income1
77,937
 72,634
 97,308
 100,795
 348,674
Net income1
46,161
 42,985
 63,890
 66,736
 219,772
Net income for common stock1
45,688
 42,512
 63,419
 66,263
 217,882
Basic earnings per common share 1,2
0.42
 0.39
 0.58
 0.61
 2.00
Diluted earnings per common share 1,3
0.42
 0.39
 0.58
 0.61
 1.99
Dividends per common share0.32
 0.32
 0.32
 0.32
 1.28
2018 
  
  
  
  
Revenues$550,960
 $566,244
 $646,055
 $617,395
 $2,380,654
$645,874
 $685,277
 $768,048
 $761,650
 $2,860,849
Operating income68,851
 85,455
 105,442
 88,427
 348,175
71,889
 78,799
 98,064
 84,604
 333,356
Net income32,825
 44,601
 127,613
 45,107
 250,146
40,720
 46,527
 66,371
 50,046
 203,664
Net income for common stock32,352
 44,128
 127,142
 44,634
 248,256
40,247
 46,054
 65,900
 49,573
 201,774
Basic earnings per common share 2
0.30
 0.41
 1.17
 0.41
 2.30
0.37
 0.42
 0.61
 0.46
 1.85
Diluted earnings per common share 3
0.30
 0.41
 1.17
 0.41
 2.29
0.37
 0.42
 0.60
 0.45
 1.85
Dividends per common share0.31
 0.31
 0.31
 0.31
 1.24
0.31
 0.31
 0.31
 0.31
 1.24
Market price per common share 4
         
High32.69
 34.98
 33.57
 34.08
 34.98
Low27.30
 31.35
 29.14
 28.31
 27.30
20151
 
  
  
  
  
Hawaiian Electric consolidated         
2019 
  
  
  
  
Revenues$637,862
 $623,912
 $717,176
 $624,032
 $2,602,982
$578,495
 $633,784
 $688,330
 $645,333
 $2,545,942
Operating income69,506
 72,730
 97,095
 83,222
 322,553
56,560
 55,694
 71,793
 70,331
 254,378
Net income32,339
 35,491
 51,144
 42,793
 161,767
32,625
 33,073
 47,277
 45,860
 158,835
Net income for common stock31,866
 35,018
 50,673
 42,320
 159,877
32,126
 32,574
 46,779
 45,361
 156,840
Basic earnings per common share 2
0.31
 0.33
 0.47
 0.39
 1.50
Diluted earnings per common share 3
0.31
 0.33
 0.47
 0.39
 1.50
Dividends per common share0.31
 0.31
 0.31
 0.31
 1.24
Market price per common share 4
 
  
  
  
  
High34.86
 32.58
 31.28
 30.29
 34.86
Low31.75
 29.62
 27.02
 27.45
 27.02
Hawaiian Electric consolidated         
2016 
  
  
  
  
2018 
  
  
  
  
Revenues$482,052
 $495,395
 $572,253
 $544,668
 $2,094,368
$570,427
 $608,126
 $687,409
 $680,563
 2,546,525
Operating income55,326
 70,686
 89,812
 68,644
 284,468
51,369
 55,144
 74,036
 61,112
 241,661
Net income25,866
 36,356
 47,472
 34,618
 144,312
27,974
 31,668
 50,210
 35,796
 145,648
Net income for common stock25,367
 35,857
 46,974
 34,119
 142,317
27,475
 31,169
 49,712
 35,297
 143,653
2015 
  
  
  
  
Revenues573,442
 558,163
 648,127
 555,434
 2,335,166
Operating income57,636
 66,161
 82,657
 67,662
 274,116
Net income27,373
 33,340
 43,504
 33,492
 137,709
Net income for common stock26,874
 32,841
 43,006
 32,993
 135,714
Note: HEI owns all of Hawaiian Electric'sElectric’s common stock, therefore per share data for Hawaiian Electric is not meaningful.
1 
InOperating income for the third quarter of 2016, HEI received a $90 million termination fee from NEE and in 2016 and 2015 received and incurred other merger and spin-off-related amounts (see Note 2 to the Consolidated Financial Statements). For the first quarter of 2015, second quarter of 2015, third quarter of 2015, fourth quarter of 2015, first quarter of 2016, second quarter of 2016 and third quarter of 2016, the Company recorded merger- and spin-off-related income/(expenses), net of tax impacts of $(5) million, $(7) million, $(2) million, $(2) million, $(2) million, $(2)2019 includes gains on property sales totaling $10.8 million, and $64net income and net income for common stock includes $7.9 million respectively.(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.



165
4
Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.





ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
HEI and Hawaiian Electric: None
ITEM 9A.CONTROLS AND PROCEDURES
HEI:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, HEI Chief Executive Officer (CEO), and James A. Ajello,Gregory C. Hazelton, HEI Chief Financial Officer (CFO), have evaluated the disclosure controls and procedures of HEI as of December 31, 2016.2019. Based on their evaluation, as of December 31, 2016,2019, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:
(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.
Management'sManagement’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting was 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.
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.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20162019 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2016.2019.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 20162019 has been audited by PricewaterhouseCoopersDeloitte & Touche LLP, an independent registered public accounting firm, as stated in theirits report which appears herein.
Changes in Internal Control over Financial Reporting
There have been no changes in internal control over financial reporting during the quarter ended December 31, 20162019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Hawaiian Electric:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Alan M. Oshima,Scott W. H. Seu, Hawaiian Electric CEO, and Tayne S. Y. Sekimura, Hawaiian Electric CFO, have evaluated the disclosure controls and procedures of Hawaiian Electric as of December 31, 2016.2019. Based on their evaluation, as of December 31, 2016,2019, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by Hawaiian Electric in reports Hawaiian Electric files or submits under the Securities Exchange Act of 1934:
(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.



Management'sManagement’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Hawaiian Electric’s internal control over financial reporting was 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.
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.
Management conducted an evaluation of the effectiveness of Hawaiian Electric’s internal control over financial reporting as of December 31, 20162019 based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Based on this evaluation, management has concluded that Hawaiian Electric’s internal control over financial reporting was effective as of December 31, 2016.2019.
Changes in Internal Control over Financial Reporting
There have been no changes in internal control over financial reporting during the quarter ended December 31, 20162019 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.

ITEM 9B.OTHER INFORMATION
HEI and Hawaiian Electric: None
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
HEI:
Information regarding HEI'sHEI’s executive officers is provided in the "Executive Officers of the Registrant"“Information about our Executive Officers” section following Item 4 of this report.
The remaining information required by this Item 10 for HEI is incorporated herein by reference to the following sections in HEI's 2017HEI’s 2020 Proxy Statement:
“Nominees for three Class III directors whose terms expire at the 20202023 Annual Meeting”
“Nominee for one Class I director whose term expires at the 20182021 Annual Meeting”
“Continuing Class I directors whose terms expire at the 20182021 Annual Meeting”
“Continuing Class II directors whose terms expire at the 20192022 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)
Family relationships; director arrangements
There are no family relationships between any HEI director or director nominee and any other HEI director or director nominee or any HEI executive officer. There are no arrangements or understandings between any HEI director or director nominee and any other person pursuant to which such director or director nominee was selected. Information required to be reported under this caption is incorporated herein by reference to the “Other relationships and related person transactions” section in HEI’s 2020 Proxy Statement.
Delinquent Section 16(a) beneficial ownership reporting compliancereports
Information required to be reported under this caption is incorporated herein by reference to the “Stock Ownership Information-Section“Delinquent Section 16(a) Beneficial Ownership Reporting Compliance”Reports” section in HEI's 2017HEI’s 2020 Proxy Statement.


Code of Conduct
The HEI Board has adopted a Corporate Code of Conduct that includes a code of ethics applicable to, among others, its principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is


available on HEI’s website at www.hei.com. HEI electsintends to disclose the information required by Form 8-K, Item 5.05, “Amendments to the Registrant’s Code of Ethics, or Waiver of a Provision of the Code of Ethics,” through this website and such information will remain available on this website for at least a 12-month period.
Hawaiian Electric:
The information required by this Item 10 for Hawaiian Electric is incorporated herein by reference to pages 1 to 75 of Hawaiian Electric Exhibit 99.1.
ITEM 11.EXECUTIVE COMPENSATION
HEI:
The information required by this Item 11 for HEI is incorporated herein by reference to the information relating to executive and director compensation in HEI's 2017HEI’s 2020 Proxy Statement.
Hawaiian Electric:
The information required by this Item 11 for Hawaiian Electric is incorporated herein by reference to:
Pages 86 to 2931 of Hawaiian Electric Exhibit 99.1 to this Form 10-K;
The discussion of “2015-17“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, 2015;2017; and
Information concerning compensation paid to directors of Hawaiian Electric who are also directors of HEI under the section of HEI's 2017HEI’s 2020 Proxy Statement entitled, “Director Compensation.”
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION


HEI:
The information required to be reported under this caption for HEI is incorporated herein by reference to the “Compensation Committee Interlocks and Insider Participation” section in HEI's 2017HEI’s 2020 Proxy Statement.
Hawaiian Electric:
The information required to be reported under this caption for Hawaiian Electric is incorporated herein by reference to page 3221 of Hawaiian Electric Exhibit 99.1.



168




ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
HEI:
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information required by this Item 12 for HEI is incorporated herein by reference to the “Stock Ownership Information-Security Ownership of Certain Beneficial Owners” section in HEI's 2017HEI’s 2020 Proxy Statement.
Equity Compensation Plan Information
Information as of December 31, 20162019 about HEI Common Stock that may be issued under all of the Company’s equity compensation plans was as follows:
Plan category
(a)
Number of
securities
to be issued upon
exercise of
outstanding
options, warrants
and rights (1)
 
(b)
Weighted-average
exercise price of
outstanding
options,
warrants and
rights
 
(c)
Number of securities
remaining available for
future issuance
under equity
compensation plans
(excluding securities
reflected in column (a)) (2)
(a)
Number of
securities
to be issued upon
exercise of
outstanding
options, warrants
and rights (1)
 
(b)
Weighted-average
exercise price of
outstanding
options,
warrants and
rights
 
(c)
Number of securities
remaining available for
future issuance
under equity
compensation plans
(excluding securities
reflected in column (a)) (2)
Equity compensation plans approved by shareholders266,754
 $—
 3,278,383
706,851
 $—
 2,759,090
Equity compensation plans not approved by shareholders—
 —
 —
—
 —
 —
Total266,754
 $—
 3,278,383
706,851
 $—
 2,759,090
(1)This column includes the number of shares of HEI Common Stock which may be issued under the Revised and Amended HEI 2010 Equity Incentive Plan (amended EIP) on account of awards outstanding as of December 31, 2016,2019, including:
EIP 
161,145158,649

Restricted stock units plus estimated compounded dividend equivalents (if applicable) *
105,609548,202

Shares to be issued in February 20172020, 2021 and 2022 under the 2014-2016 LTIP2017-2019, 2018-2020 and 2019-2021 LTIPs, respectively, plus compounded dividend equivalents
266,754706,851

 
*Under the amended EIP as of December 31, 2016,2019, 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, 20162019 for future awards, including 3,157,1852,448,827 shares available for future awards under the amended EIP and 121,198310,263 shares available for future awards under the 2011 Nonemployee Director Plan.



Hawaiian Electric:
The information required by this Item 12 for Hawaiian Electric is incorporated herein by reference to pages 3331 to 3432 of Hawaiian Electric Exhibit 99.1.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
HEI:
The information required by this Item 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in HEI's 2017HEI’s 2020 Proxy Statement.
Hawaiian Electric:
The information required by this Item 13 for Hawaiian Electric is incorporated herein by reference to pages 3432 to 3533 of Hawaiian Electric Exhibit 99.1.

169


ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
HEI:
The information required by this Item 14 for HEI is incorporated herein by reference to the relevant information in the Audit & Risk Committee Report in HEI's 2017HEI’s 2020 Proxy Statement (but no other part of the “Audit & Risk Committee Report” is incorporated herein by reference).
Hawaiian Electric:
The information required by this Item 14 for Hawaiian Electric is incorporated herein by reference to page 3634 of Hawaiian Electric Exhibit 99.1.
PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial statements
See Item 8 for the Consolidated Financial Statements of HEI and Hawaiian Electric.
(a)(2) and (c) Financial statement schedules
The following financial statement schedules for HEI and Hawaiian Electric are included in this report on the pages indicated below:
Page/s in Form 10-K Page/s in Form 10-K
HEI Hawaiian Electric HEI Hawaiian Electric
Schedule ICondensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) at December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014
185-187
 NACondensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) at December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017
171-173
 NA
Schedule IIValuation and Qualifying Accounts, Hawaiian Electric Industries, Inc. and subsidiaries and Hawaiian Electric Company, Inc. and subsidiaries for the years ended December 31, 2016, 2015 and 2014
189
 
189
Valuation and Qualifying Accounts, Hawaiian Electric Industries, Inc. and subsidiaries and Hawaiian Electric Company, Inc. and subsidiaries for the years ended December 31, 2019, 2018 and 2017
175
 
175
NA Not applicable.        
Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the Consolidated Financial Statements.


ITEM 16.FORM 10-K SUMMARY
None.

170


Hawaiian Electric Industries, Inc.
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED BALANCE SHEETS
December 312019
 2018
(dollars in thousands) 
  
Assets 
  
Cash and cash equivalents$953
 $3,742
Accounts receivable779
 2,604
Notes receivable from subsidiaries22,598
 20,789
Property, plant and equipment, net2,931
 3,456
Deferred income tax assets10,754
 10,147
Other assets and intercompany receivables21,770
 11,963
Investments in subsidiaries, at equity2,761,802
 2,605,038
   Total assets$2,821,587
 $2,657,739
Liabilities and shareholders’ equity 
  
Liabilities 
  
Accounts payable$1,509
 $2,001
Interest payable3,041
 3,476
Notes payable to subsidiaries—
 34
Commercial paper96,723
 48,992
Long-term debt, net399,064
 398,874
Retirement benefits liability29,367
 29,565
Other11,623
 12,517
   Total liabilities541,327
 495,459
Shareholders’ equity 
  
Preferred stock, no par value, authorized 10,000,000 shares; issued: none—
 —
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,973,328
shares and 108,879,245 shares at December 31, 2019 and 2018, respectively		1,678,257
 1,669,267
Retained earnings622,042
 543,623
Accumulated other comprehensive loss(20,039) (50,610)
   Total shareholders’ equity2,280,260
 2,162,280
   Total liabilities and shareholders’ equity$2,821,587
 $2,657,739




171

December 312016 2015
(dollars in thousands) 
  
Assets 
  
Cash and cash equivalents$14,924
 $55,116
Accounts receivable3,788
 5,459
Property, plant and equipment, net4,143
 4,514
Deferred income tax assets17,280
 16,715
Other assets9,858
 11,650
Investments in subsidiaries, at equity2,383,405
 2,293,679
   Total assets$2,433,398
 $2,387,133
Liabilities and shareholders’ equity 
  
Liabilities 
  
Accounts payable$379
 $1,254
Interest payable1,735
 2,450
Notes payable to subsidiaries5,373
 5,946
Commercial paper—
 103,063
Long-term debt, net299,759
 299,666
Retirement benefits liability33,939
 31,704
Other25,460
 15,410
   Total liabilities366,645
 459,493
Shareholders’ equity 
  
Preferred stock, no par value, authorized 10,000,000 shares; issued: none—
 —
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,583,413
shares and 107,460,406 shares at December 31, 2016 and 2015, respectively		1,660,910
 1,629,136
Retained earnings438,972
 324,766
Accumulated other comprehensive loss(33,129) (26,262)
   Total shareholders' equity2,066,753
 1,927,640
   Total liabilities and shareholders' equity$2,433,398
 $2,387,133





Hawaiian Electric Industries, Inc.
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
Years ended December 312016 2015 20142019
 2018
 2017
(in thousands) 
  
  
 
  
  
Revenues$647
 $327
 $303
$777
 $429
 $798
Equity in net income of subsidiaries199,485
 190,033
 188,727
246,005
 226,972
 187,097
Expenses: 
  
  
   
  
Operating, administrative and general18,701
 34,350
 20,921
19,195
 19,515
 16,578
Depreciation of property, plant and equipment566
 576
 575
570
 597
 548
Taxes, other than income taxes4,726
 440
 469
570
 509
 496
Total expenses23,993
 35,366
 21,965
20,335
 20,621
 17,622
Income before merger termination fee, interest expense and income (taxes) benefits176,139
 154,994
 167,065
Merger termination fee90,000
 —
 —
Income before interest expense and income (taxes) benefits266,139
 154,994
 167,065
226,447
 206,780
 170,273
Retirement defined benefits expense—other than service costs442
 674
 1,119
Interest expense9,037
 10,788
 11,599
17,930
 12,664
 9,389
Income before income (taxes) benefits257,102
 144,206
 155,466
Income (taxes) benefits(8,846) 15,671
 13,047
Income before income benefits208,075
 193,442
 159,765
Income benefits9,807
 8,332
 5,532
Net income$248,256
 $159,877
 $168,513
$217,882
 $201,774
 $165,297


HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
STATEMENTS OF COMPREHENSIVE INCOME
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Incorporated by reference are HEI and Subsidiaries’ Statements of Consolidated Comprehensive Income and Consolidated Statements of Changes in Shareholders’ Equity in Part II, Item 8.

172




Hawaiian Electric Industries, Inc.
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
Years ended December 312016 2015 20142019
 2018
 2017
(in thousands)          
Net cash provided by operating activities$191,306
 $97,141
 $100,794
$131,120
 $135,470
 $99,600
Cash flows from investing activities 
  
  
 
  
  
Increase in note receivable from subsidiary(1,187) (20,596) (70,000)
Decrease in note receivable from subsidiary—
 —
 66,391
Capital expenditures(212) (173) (74)(47) (143) (317)
Investments in subsidiaries(24,000) —
 (40,000)(38,935) (71,970) (22,353)
Other1
 —
 —
(1,001) 140
 (177)
Net cash used in investing activities(24,211) (173) (40,074)(41,170) (92,569) (26,456)
Cash flows from financing activities 
  
  
 
  
  
Net increase (decrease) in notes payable to subsidiaries with original maturities of three months or less(618) 87
 (222)—
 (30) 98
Net increase (decrease) in short-term borrowings with original maturities of three months or less(103,063) (15,909) 13,490
47,731
 (14,000) 62,993
Proceeds from issuance of short-term debt—
 —
 125,000
Repayment of short-term debt—
 (50,000) (75,000)
Proceeds from issuance of long-term debt75,000
 —
 125,000
—
 150,000
 150,000
Repayment of long-term debt(75,000) —
 (100,000)—
 —
 (200,000)
Excess tax benefits from share-based payment arrangements404
 978
 277
Net proceeds from issuance of common stock13,220
 104,435
 26,898
Withheld shares for employee taxes on vested share-based compensation(997) (996) (3,828)
Common stock dividends(117,274) (131,765) (126,458)(139,463) (134,987) (134,873)
Other44
 46
 —
(10) (848) (756)
Net cash used in financing activities(207,287) (42,128) (61,015)(92,739) (50,861) (76,366)
Net increase (decrease) in cash and equivalents(40,192) 54,840
 (295)
Net decrease in cash and equivalents(2,789) (7,960) (3,222)
Cash and cash equivalents, January 155,116
 276
 571
3,742
 11,702
 14,924
Cash and cash equivalents, December 31$14,924
 $55,116
 $276
$953
 $3,742
 $11,702





NOTES TO CONDENSED FINANCIAL INFORMATION


Basis of Presentation
The “Notes to Consolidated Financial Statements” in Part II, Item 8 should be read in conjunction with the above HEI (Parent Company) financial statements. All HEI subsidiaries are reflected in the Condensed Financial Statements under the equity method. Income taxes for equity method investments are included in “Equity in net income of subsidiaries.”
Long-term debt
The components of long-term debt, net, were as follows:
December 312016 2015
(dollars in thousands) 
  
HEI Term loan LIBOR + .75%, due 2017$125,000
 $125,000
HEI Term loan LIBOR + .75%, due 201875,000
 —
HEI senior note 4.41%, paid in 2016—
 75,000
HEI senior note 5.67%, due 202150,000
 50,000
HEI senior note 3.99%, due 202350,000
 50,000
Less unamortized debt issuance costs(241) (334)
Long-term debt, net$299,759
 $299,666
See Note 1 of the Consolidated Financial Statements for the impact to prior period financial information of the adoption of ASU No. 2015-03.
December 312019
 2018
(dollars in thousands) 
  
HEI 2.99% term loan, due 2022$150,000
 $150,000
HEI 5.67% senior note, due 202150,000
 50,000
HEI 3.99% senior note, due 202350,000
 50,000
HEI 4.58% senior notes, due 202550,000
 50,000
HEI 4.72% senior notes, due 2028100,000
 100,000
Less unamortized debt issuance costs(936) (1,126)
Long-term debt, net$399,064
 $398,874
The aggregate payments of principal required within five years after December 31, 20162019 on long-term debt are $125 millionNaN in 2017, $75 million in 2018 and nil in 2019 and 2020, and $50 million in 2021.2021, $150 million in 2022, $50 million in 2023, NaN for 2024, and $150 million thereafter.
Indemnities
As of December 31, 2016,2019, HEI has a General Agreement of Indemnity in favor of both Liberty Mutual Insurance Company (Liberty) and Travelers Casualty and Surety Company of America (Travelers) for losses in connection with any and all bonds, undertakings or instruments of guarantee and any renewals or extensions thereof executed by Liberty or Travelers, including, but not limited to, a $0.2$0.6 million self-insured United States Longshore & Harbor bond and a $0.6$0.7 million self-insured automobile bond.
Income taxes
The Company’s financial reporting policy for income tax allocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.
Dividends from HEI subsidiaries
In 2016, 20152019, 2018 and 2014,2017, cash dividends received from subsidiaries were $130$157 million, $121$154 million and $124$125 million, respectively.
Supplemental disclosures of noncash activities
In 2016, 20152019, 2018 and 2014,2017, $2.3 million, $2.3 million and $2.4$2.8 million, respectively, of HEI accounts receivable from ASB Hawaii were reduced with a corresponding reduction in HEI notes payable to ASB Hawaii in noncash transactions.
In 2016, 20152019, 2018 and 2014,2017, $2.3 million, $0.3$2.3 million and $2.5$2.8 million, respectively, were contributed as equity by HEI into ASB Hawaii with a corresponding increase in HEI notes payable to ASB Hawaii in noncash transactions.
In 2017, $3.6 million of HEI notes receivable from Hamakua Energy, LLC were converted to equity in a noncash transaction.
Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP),DRIP, common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17 million, nilwas immaterial for 2019, 2018 and nil in 2016, 2015 and 2014, respectively. HEI satisfied the requirements of the HEI DRIP, Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and ASB 401(k) Plan from March 6, 2014 through January 5, 2016 by acquiring for cash its common shares through open market purchases rather than by issuing additional shares. From January 6, 2016 through December 6, 2016, HEI satisfied its share purchase requirements for the plans through new issuances, except that from June 2, 2016 through August 9, 2016,2017 as HEI satisfied the share purchase requirements of the HEIRSPDRIP in 2019, 2018 and ASB 401(k) Plan through open market purchases of its common stock. From December 7, 2016 to date, HEI satisfied the share purchase requirements of these three plans2017 through open market purchases of its common stock rather than through new issuances.
Other
The “Notes to Consolidated Financial Statements” in Part II, Item 8 should be read in conjunction with the above HEI (Parent Company) financial statements.
174




Hawaiian Electric Industries, Inc. and subsidiaries
and Hawaiian Electric Company, Inc. and subsidiaries
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2016, 20152019, 2018 and 20142017
Col. ACol. B Col. C  Col. D  Col. ECol. B Col. C  Col. D  Col. E
(in thousands)  Additions        Additions      
Description
Balance
at begin-
ning of
period
 
Charged to
costs and
expenses
 
Charged
to other
accounts
  Deductions  
Balance at
end of
period
Balance
at begin-
ning of
period
 
Charged to
costs and
expenses
 
Charged
to other
accounts
  Deductions  
Balance at
end of
period
2016 
  
  
   
   
2019 
  
  
   
   
Allowance for uncollectible accounts – electric utility$1,699
 $2,383
 $877
(a) $3,838
(b),(c) $1,121
$1,480
 $2,106
 $795
(a) $3,004
(b) $1,377
Allowance for uncollectible interest – bank$1,679
 $—
 $155
  $—
  $1,834
$373
 $—
 $(99)  $—
  $274
Allowance for losses for loans receivable – bank$50,038
 $16,763
(d)$2,977
(a) $14,245
(b) $55,533
Deferred tax valuation allowance – HEI$54
 $—
 $—
 $16
 $38
2015 
  
  
   
   
Allowance for losses for loans – bank$52,119
 $23,480
(c)$6,418
(a) $28,662
(b) $53,355
2018 
  
  
   
   
Allowance for uncollectible accounts – electric utility$1,959
 $3,653
 $977
(a) $4,890
(b) $1,699
$1,178
 $2,474
 $(4,099)(a), (d) $(1,927)(b),(d) $1,480
Allowance for uncollectible interest – bank$1,514
 $—
 $165
  $—
  $1,679
$367
 $—
 $6
  $—
  $373
Allowance for losses for loans receivable – bank$45,618
 $6,275
(d)$4,571
(a) $6,426
(b) $50,038
Allowance for mortgage-servicing assets – bank$209
 $—
 $(205) $4
  $—
Deferred tax valuation allowance – HEI$45
 $9
 $—
 $—
 $54
2014 
  
  
   
   
Allowance for losses for loans – bank$53,637
 $14,745
(c)$4,254
(a) $20,517
(b) $52,119
2017 
  
  
   
   
Allowance for uncollectible accounts – electric utility$2,329
 $1,384
 $1,613
(a) $3,367
(b) $1,959
$1,121
 $1,810
 $785
(a) $2,538
(b),(d) $1,178
Allowance for uncollectible interest – bank$1,661
 $—
 $—
  $147
  $1,514
$1,834
 $—
 $—
  $1,467
  $367
Allowance for losses for loans receivable – bank$40,116
 $6,126
(d)$4,926
(a) $5,550
(b) $45,618
Allowance for mortgage-servicing assets – bank$251
 $53
 $—
 $95
  $209
Allowance for losses for loans – bank$55,533
 $10,901
(c)$4,016
(a) $16,813
(b) $53,637
Deferred tax valuation allowance – HEI$278
 $17
 $—
 $250
 $45
$38
 $—
 $—
 $38
 $—
(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.
(d)Represents provision for loan lossassets in 2018 and 2017 were $(4,934), and $841, respectively.












175




(a)(3) and (b) Exhibits
The Exhibit Index attached to this Form 10-K is incorporated herein by reference. The exhibits listed for HEI and Hawaiian Electric are listed in the index under the headings “HEI” and “Hawaiian Electric,” respectively, except that the exhibits listed under “Hawaiian Electric” are also exhibits for HEI.
EXHIBIT INDEX
The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.
Exhibit no.DescriptionFormFile NumberExhibit #Filing date
HEI:     
 3(i)
HEI’s Amended and Restated Articles of Incorporation.
8-K1-85033(i)5/6/09
 3(ii)
Amended and Restated Bylaws of HEI effective February 14, 2019.
8-K1-85033.12/19/19
*4
Description of HEI Common Stock
    
 4.1Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries.10-K1-85034.13/31/93
 4.2
Master Note Purchase Agreement among HEI and the Purchasers thereto, dated March 24, 2011.
8-K1-85034(a)3/28/11
 4.2(a)
First Supplement to Note Purchase Agreement among HEI and the Purchasers thereto, dated March 6, 2013.
8-K1-85034(a)3/6/13
 4.3
Hawaiian Electric Industries Retirement Savings Plan, restatement effective January 1, 2013.
10-K1-85034.52/19/13
 4.3(a)
Amendment 2014-1 to Hawaiian Electric Industries Retirement Savings Plan, effective as of January 1, 2015
S-8333-
232360		4.46/26/19
 4.3(b)
Amendment 2015-1 to Hawaiian Electric Industries Retirement Savings Plan, effective as of February 1, 2015
S-8333-
232360		4.56/26/19
 4.3(c)
Amendment 2015-2 to Hawaiian Electric Industries Retirement Savings Plan, effective as of February 1, 2015
S-8333-
232360		4.66/26/19
 4.3(d)
Amendment 2019-1 to Hawaiian Electric Industries Retirement Savings Plan, effective as of May 6, 2019
S-8333-
232360		4.76/26/19
*4.3(e)
Amendment 2019-1 to the Hawaiian Electric Industries Retirement Savings Plan, effective as of May 6, 2019
    
 4.3(f)
Amendment 2019-2 to the Hawaiian Electric Industries Retirement Savings Plan, effective as of August 1, 2019
10-Q1-85034.211/1/19
 4.4
Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company, as Trustee
10-Q1-8503411/8/12
 4.4(a)
Letter Amendment effective November 28, 2012 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company.
10-K1-85034.6(a)2/19/13
 4.4(b)
Letter Amendment effective October 1, 2014 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company.
10-Q1-8503411/6/14
 4.4(c)
First Amendment to Master Trust Agreement (dated as of September 4, 2012) effective March 1, 2015 between HEI and ASB and Fidelity Management Trust Company.
10-Q1-850345/6/15
 4.4(d)
Letter Amendment effective August 3, 2015 to Master Trust Agreement (dated as of September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
10-K1-85034.4(d)3/1/18
 4.4(e)
Letter Amendment effective August 15, 2017 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
10-Q1-8503411/2/17
 4.4(f)
Second Amendment effective January 1, 2018 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
10-K1-85034.4(f)3/1/18
 4.4(g)
Letter of Direction effective January 2, 2018 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
10-K1-85034.4(g)3/1/18


Exhibit no.DescriptionFormFile NumberExhibit #Filing date
 4.4(h)
Third Amendment effective July 1, 2018 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
10-Q1-850348/3/18
 4.4(i)
Fourth Amendment effective June 26, 2019 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
S-8333-
232360		4.156/26/19
*4.4(j)
Letter Amendment effective November 1, 2019 to Master Trust Agreement (dated September 4, 2012) between HEI and ASB and Fidelity Management Trust Company.
    
 4.5
Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated effective October 5, 2017.
S-3
333-
220842
4.310/5/17
 4.5(a)
Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated.
S-3333-
234591		4.311/8/19
 4.6
American Savings Bank 401(k) Plan, restatement effective January 1, 2013.
10-K1-85034.82/19/13
 4.6(a)
Amendment 2013-1 to the American Savings Bank 401(k) Plan, effective January 1, 2014.
10-K1-85034.7(a)2/23/16
 4.6(b)
Amendment 2019-1 to the American Savings Bank 401(k) Plan, effective as of May 6, 2019.
S-8333-
232361		4.56/26/19
*4.6(c)
Amendment 2020-1 to the American Savings Bank 401(k) Plan, effective as of January 1, 2020.
    
 10.1
Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982.
10-K1-850310.12/28/07
 10.2Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle).8-K1-8503(28)-25/26/88**
 10.3OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988.10-K1-850310.3(a)3/31/93
       
HEI Exhibits 10.4 through 10.21 are management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.19 are also management contracts or compensatory plans or arrangements with Hawaiian Electric participants.    
 10.4
HEI Executive Incentive Compensation Plan amended as of February 4, 2013.
10-K1-850310.42/19/13
 10.5
HEI Executives’ Deferred Compensation Plan amended and restated effective January 1, 2019.
10-K1-850310.52/28/19
 10.6
Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated November 16, 2010.
10-K1-850310.62/18/11
 10.7
Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated February 14, 2014.
Proxy (DEF 14A)1-8503Appendix D3/25/14
 10.7(a)
Form of Non-Qualified Stock Option Agreement pursuant to 2010 Equity and Incentive Plan.
S-8
333-
166737
4.45/11/10
 10.7(b)
Form of Stock Appreciation Right Agreement pursuant to 2010 Equity and Incentive Plan.
S-8
333-
166737
4.55/11/10
 10.7(c)
Form of Restricted Shares Agreement pursuant to 2010 Equity and Incentive Plan.
S-8
333-
166737
4.65/11/10
 10.7(d)
Form of Performance Shares Agreement pursuant to 2010 Equity and Incentive Plan.
S-8
333-
166737
4.75/11/10
 10.7(e)
Form of Restricted Stock Unit Agreement, amended as of December 15, 2016, pursuant to 2010 Equity and Incentive Plan, as amended and restated February 14, 2014.
10-K1-850310.7(e)2/24/17
 10.8
HEI Long-Term Incentive Plan amended as of February 4, 2013.
10-K1-850310.82/19/13
 10.9
HEI Supplemental Executive Retirement Plan amended and restated as of January 1, 2009.
10-Q1-850310.311/5/08
 10.9(a)
Amendments to the HEI Supplemental Executive Retirement Plan Freezing Benefit Accruals Effective December 31, 2008.
10-K1-850310.9(a)2/27/09
 10.10
HEI Excess Pay Plan amended and restated as of January 1, 2009.
10-K1-850310.102/27/09
 10.10(a)
HEI Excess Pay Plan Addendum for Constance H. Lau.
10-K1-850310.10(a)2/27/09


Exhibit no.DescriptionFormFile NumberExhibit #Filing date
 10.10(b)
Amendment No. 1 dated December 13, 2010 to January 1, 2009 Restatement of HEI Excess Pay Plan.
10-K1-850310.10(c)2/19/13
 10.11
Form of Change in Control Agreement.
10-K1-850310.112/27/09
 10.12Nonemployee Director Retirement Plan, effective as of October 1, 1989.10-K1-850310.153/27/90**
*10.13
HEI 2011 Nonemployee Director Stock Plan, as amended effective October 31, 2019.
    
 10.14
Nonemployee Director’s Compensation Schedule effective January 1, 2019.
10-K1-850310.52/28/19
 10.15
HEI Non-Employee Directors’ Deferred Compensation Plan.
10-Q1-850310.511/5/08
 10.16
Executive Death Benefit Plan of HEI and Participating Subsidiaries restatement effective as of January 1, 2009.
10-Q1-850310.611/5/08
 10.16(a)
Resolution of the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc. Re: Adoption of Amendment No. 1 to January 1, 2009 Restatement of the Executive Death Benefit Plan.
10-Q1-850310.111/5/09
 10.17
Amended and Restated Severance Pay Plan for Management Employees of Hawaiian Electric Industries, Inc. and Executive Employees of Affiliates, effective as of April 2, 2018.
10-Q1-8503108/3/18
 10.18
Hawaiian Electric Industries, Inc. Executives’ Deferred Compensation Plan effective on January 1, 2009.
10-Q1-850310.211/5/08
 10.19
Form of Indemnity Agreement (HEI, Hawaiian Electric and ASB with their respective directors and HEI with certain of its senior officers).
10-Q1-850310.111/8/12
 10.20
American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2009).
10-Q1-850310.711/5/08
 10.20(a)
Amendment No. 1 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 30, 2009.
10-K1-850310.20(a)2/23/16
 10.20(b)
Amendment No. 2 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 29, 2010.
10-K1-850310.20(b)2/23/16
 10.20(c)
Amendment No. 3 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 3, 2014.
10-K1-850310.20(c)2/23/16
 10.20(d)
Amendment No. 4 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 4, 2017.
10-K1-850310.20(d)3/1/18
*10.20(e)
Amendment No. 5 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 5, 2018.
    
 10.21
American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan, effective January 1, 2009.
10-Q1-850310.811/5/08
 10.21(a)
Amendments to the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan Freezing Benefit Accruals Effective December 31, 2008.
10-K1-850310.19(b)2/27/09
 10.22
Second Amended and Restated Credit Agreement, dated as of June 30, 2017, among HEI, as Borrower, the Lenders Party Thereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., MUFG Union Bank, N.A., Barclays Bank PLC, U.S. Bank National Association and Bank of Hawaii as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and JPMorgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners.
10-Q1-850310.18/3/17
*11
HEI - Computation of Earnings per Share of Common Stock.
    
*21.1
HEI - Subsidiaries of the Registrant.
    
*23.1
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
    
*31.1
Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).
    
*31.2
Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Gregory C. Hazelton (HEI Chief Financial Officer).
    
*32.1
HEI Certification Pursuant to 18 U.S.C. Section 1350.
    
*101.INSXBRL Instance Document.    
*101.SCHXBRL Taxonomy Extension Schema Document.    
*101.CALXBRL Taxonomy Extension Calculation Linkbase Document.    
*101.DEFXBRL Taxonomy Extension Definition Linkbase Document.    


Exhibit no.DescriptionFormFile NumberExhibit #Filing date
*101.LABXBRL Taxonomy Extension Label Linkbase Document.    
*101.PREXBRL Taxonomy Extension Presentation Linkbase Document.    
 104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)    
       
Hawaiian Electric:    
 3(i).1Hawaiian Electric’s Certificate of Amendment of Articles of Incorporation.10-K1-49553.13/31/89
 3(i).2Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation.10-K1-49553.1(b)3/27/90**
 3(i).3Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation.10-K1-49553(i).43/23/99
 3(i).4
Articles of Amendment amending Article V of Hawaiian Electric’s Amended Articles of Incorporation effective August 6, 2009.
10-Q1-49553(i).48/7/09
 3(ii)
Hawaiian Electric’s Amended and Restated Bylaws (as last amended August 6, 2010).
8-K1-49553(ii)8/9/10
*4
Description of Hawaiian Electric’s Preferred Stock
    
 4.1
Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of Hawaiian Electric, Hawaii Electric Light and Maui Electric
10-K1-49554.13/19/03
 4.2
Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated April 19, 2012.
8-K1-49554(a)4/23/12
 4.3
Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric and the Purchasers that are parties thereto, dated April 19, 2012.
8-K1-49554(b)4/23/12
 4.4
Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light and the Purchasers that are parties thereto, dated April 19, 2012.
8-K1-49554(c)4/23/12
 4.5
Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated September 13, 2012.
8-K1-495549/14/12
 4.6
Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013.
8-K1-49554(a)10/7/13
 4.7
Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 3, 2013.
8-K1-49554(b)10/7/13
 4.8
Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013.
10-Q1-4955411/7/13
 4.9
Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015.
8-K1-49554(a)10/16/15
 4.10
Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 15, 2015.
8-K1-49554(b)10/16/15
 4.11
Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015.
8-K1-49554(c)10/16/15
 4.12
Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of December 15, 2016.
8-K1-4955412/19/16
 10.1(a)Power Purchase Agreement between Kalaeloa Partners, L.P., and Hawaiian Electric dated October 14, 1988.10-Q1-495510(a)11/14/88
 10.1(b)Amendment No. 1 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated June 15, 1989.10-Q1-495510(c)8/14/89
 10.1(c)Lease Agreement between Kalaeloa Partners, L.P., as Lessor, and Hawaiian Electric, as Lessee, dated February 27, 1989.10-Q1-495510(d)8/14/89
 10.1(d)Restated and Amended Amendment No. 2 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated February 9, 1990.10-K1-495510.2(c)3/27/90**
 10.1(e)Amendment No. 3 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated December 10, 1991.10-K1-495510.2(e)3/24/92
 10.1(f)
Amendment No. 4 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 1, 1999.
10-Q1-495510.111/8/00


Exhibit no.DescriptionFormFile NumberExhibit #Filing date
10.1(g)
Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004.
10-Q1-495510.311/5/04
10.1(h)
Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004.
10-Q1-495510.411/5/04
10.1(i)
Letter agreement dated July 28, 2016 and executed August 1, 2016 extending the term of the Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 14, 1988 (as amended).
10-Q1-49551011/4/16
10.2(a)Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric, entered into on March 25, 1988.10-Q1-495510(a)5/16/88
10.2(b)Agreement between Hawaiian Electric and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988.10-K1-495510.43/31/89
10.2(c)Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric.10-Q1-49551011/13/89
10.2(d)Hawaiian Electric’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990.10-K1-495513(c)3/27/90**
10.2(e)
Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and Hawaiian Electric.
10-K1-495510.2(e)3/9/04
10.2(f)
Amendment No. 4, entered into as of February 14, 2018, to Power Purchase Agreement between AES Hawaii, Inc. and Hawaiian Electric Company, Inc. (subject to PUC approval).
10-Q1-4955105/10/18
10.3(a)Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986.10-Q1-495510(a)8/14/89
10.3(b)Firm Capacity Amendment between Hawaii Electric Light and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986.10-Q1-495510(b)8/14/89
10.3(c)Amendment made in October 1993 to Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended.10-K1-495510.5(b)3/27/98
10.3(d)Third Amendment dated March 7, 1995 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended.10-K1-495510.5(c)3/27/98
10.3(e)Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended.10-K1-495510.5(b)3/25/96
10.3(f)
Fifth Amendment dated February 7, 2011 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended.
10-K1-495510.4(f)2/17/12
10.3(g)
Power Purchase Agreement between Puna Geothermal Venture and Hawaii Electric Light dated February 7, 2011.
10-K1-495510.4(g)2/17/12
*10.3(h)
Amended and Restated Power Purchase Agreement between Puna Geothermal Venture and Hawaii Electric Light dated December 31, 2019 (subject to PUC approval).
10.4(a)Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light,” which is provided in final form as Exhibit 10.6(b)).10-K1-495510.73/27/98
10.4(b)Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997.10-K1-495510.7(a)3/27/98
10.4(c)Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997.10-K1-495510.7(b)3/23/99
10.4(d)
Notice and acknowledgment under power purchase agreement effective November 24, 2017 by Hamakua Energy, LLC and acknowledged by Hawaii Electric Light.
10-K1-495510.4(d)3/1/18


Exhibit no.DescriptionFormFile NumberExhibit #Filing date
 10.5
Supply Contract for Low Sulfur Fuel Oil, High Sulfur Fuel Oil, No. 2 Diesel, and Ultra-Low Sulfur Diesel by and between Hawaiian Electric, Hawaii Electric Light, and Maui Electric and PAR Hawaii Refining, LLC dated January 21, 2019 (certain confidential information has been omitted)
10-Q1-4955105/7/19
 10.6(a)
Contract of private carriage by and between HITI and Hawaii Electric Light dated December 4, 2000.
10-K1-495510.133/23/01
 10.6(b)
Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Hawaii Electric Light, dated July 1, 2011.
10-K1-495510.13(b)2/19/13
 10.7(a)
Contract of private carriage by and between HITI and Maui Electric dated December 4, 2000.
10-K1-495510.143/23/01
 10.7(b)
Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Maui Electric, dated July 1, 2011.
10-K1-495510.14(b)2/19/13
 10.8
Amended and Restated Power Purchase Agreement between Hawaiian Electric and Hu Honua Bioenergy, LLC dated May 9, 2017.
10-K1-495510.11(a)3/1/18
 10.9
Second Amended and Restated Credit Agreement, dated as of June 30, 2017, among Hawaiian Electric Company, Inc., as Borrower, the Lenders Party Hereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., MUFG Union Bank, N.A., Barclays Bank PLC, U.S. Bank National Association and Bank of Hawaii as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and JPMorgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners.
10-Q1-495510.28/3/17
 11Computation of Earnings Per Share of Common Stock (See note on Hawaiian Electric’s Item 6. Selected Financial Data).    
*21.2
Hawaiian Electric - Subsidiaries of the Registrant.
    
*31.3
Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Scott W. H. Seu (Hawaiian Electric Chief Executive Officer).
    
*31.4
Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (Hawaiian Electric Chief Financial Officer).
    
*32.2
Hawaiian Electric Certification Pursuant to 18 U.S.C. Section 1350.
    
*99.1
Hawaiian Electric’s Directors, Executive Officers and Corporate Governance; Hawaiian Electric’s Executive Compensation; Hawaiian Electric’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters; Hawaiian Electric’s Certain Relationships and Related Transactions, and Director Independence; and Hawaiian Electric’s Principal Accounting Fees and Services.
    
** Date of transmittal letter to SEC.


181


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.
HAWAIIAN ELECTRIC INDUSTRIES, INC. HAWAIIAN ELECTRIC COMPANY, INC.
  (Registrant)   (Registrant)
       
       
By /s/ James A. AjelloGregory C. Hazelton By /s/ Tayne S. Y. Sekimura
  James A. AjelloGregory C. Hazelton   Tayne S. Y. Sekimura
  Executive Vice President and Chief Financial Officer   Senior Vice President and Chief Financial Officer
  (Principal Financial and Accounting Officer of HEI)   (Principal  (Principal Financial Officer of Hawaiian Electric)
       
Date: February 24, 201728, 2020 Date: February 24, 201728, 2020
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 registrants and in the capacities indicated on February 24, 2017.28, 2020. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.
Signature Title
   
/s/ Constance H. Lau President & Chief Executive Officer of HEI and Director of HEI
Constance H. Lau ChairmanDirector of the Board of Directors of Hawaiian ElectricHEI
  (ChiefPrincipal Executive Officer of HEI)
   
/s/ Alan M. OshimaScott W. H. Seu President & Chief Executive Officer of Hawaiian Electric
Scott W. H. Seu   and Director of Hawaiian Electric
Alan M. Oshima (Chief   (Principal Executive Officer of Hawaiian Electric)
   
/s/ James A. AjelloGregory C. Hazelton Executive Vice President and Chief Financial Officer of HEI
James A. AjelloGregory C. Hazelton (Principalof HEI (Principal Financial and Accounting Officer of HEI)
   
/s/ Tayne S. Y. Sekimura Senior Vice President and Chief Financial Officer
Tayne S. Y. Sekimura Chief Financial Officer of Hawaiian Electric (Principal Financial Officer
  (Principal Financialof Hawaiian Electric)
/s/ Paul K. ItoVice President, Tax, Controller and Treasurer
Paul K. Itoof HEI (Principal Accounting Officer of Hawaiian Electric)HEI)
   
/s/ Patsy H. Nanbu Controller of Hawaiian Electric
Patsy H. Nanbu (Principal Accounting Officer of Hawaiian Electric)
   
   


SIGNATURES (continued)


Signature Title
/s/ Kevin M. BurkeDirector of Hawaiian Electric
Kevin M. Burke  
   
   
/s/ Don E. CarrollCeleste A. Connors Director of Hawaiian ElectricHEI
Don E. CarrollCeleste A. Connors  
   
   
/s/ Richard J. Dahl Director of HEI and Hawaiian Electric
Richard J. Dahl  
   
   
/s/ Thomas B. Fargo Director of HEI
Thomas B. Fargo  
   
   
/s/ Peggy Y. Fowler Director of HEI
Peggy Y. Fowler  
   
   
/s/ Timothy E. Johns DirectorChairman of the Board of Directors of Hawaiian Electric
Timothy E. Johns  
   
   
/s/ Micah A. Kane Director of Hawaiian ElectricHEI
Micah A. Kane  
   
   
/s/ Bert A. Kobayashi, Jr. Director of Hawaiian Electric
Bert A. Kobayashi, Jr.  
   
   
/s/ Mary G. PowellDirector of HEI
Mary G. Powell
   
/s/ Keith P. Russell Director of HEI
Keith P. Russell  
   
   
/s/ William James K. ScottScilacci, Jr. Director of HEI
William James K. ScottScilacci, Jr.  
   
   
/s/ Kelvin H. Taketa Director of HEI and Hawaiian Electric
Kelvin H. Taketa
/s/ Barry K. TaniguchiDirector of HEI
Barry K. Taniguchi  
   
   
/s/ Jeffrey N. Watanabe Chairman of the Board of Directors of HEI and director of Hawaiian Electric
Jeffrey N. Watanabe  


EXHIBIT INDEX
The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.
Exhibit no.Description
HEI:
2Agreement and Plan of Merger, dated as of December 3, 2014, by and among NextEra Energy, Inc., NEE Acquisition Sub I, LLC, NEE Acquisition Sub II, Inc. and HEI (Exhibit 2.1 to HEI’s Current Report on Form 8-K December 3, 2014, File No. 1-8503).
   
 3(i)HEI’s Amended and Restated Articles of Incorporation (Exhibit 3(i) to HEI’s Current Report on Form 8-K, dated May 5, 2009, File No. 1-8503).
  
3(ii)/s/ Eva T. Zlotnicka Amended and Restated BylawsDirector of HEI as last amended May 9, 2011 (Exhibit 3(ii) to HEI’s Current Report on Form 8-K May 9, 2011, File No. 1-8503).
4.1Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).
4.2Master Note Purchase Agreement among HEI and the Purchasers thereto, dated March 24, 2011 (Exhibit 4(a) to HEI’s Current Report on Form 8-K dated March 24, 2011, File No. 1-8503).
4.2(a)First Supplement to Note Purchase Agreement among HEI and the Purchasers thereto, dated March 6, 2013 (Exhibit 4(a) to HEI’s Current Report on Form 8-K dated March 6, 2013, File No. 1-8503).
4.3(a)Loan Agreement dated as of May 2, 2014 among HEI, as Borrower, the Lenders Party Thereto and Royal Bank of Canada, as Syndication Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Administrative Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. and RBC Capital Markets, as Joint Lead Arrangers and Joint Book Runners (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-8503).
4.3(b)Amendment No. 1 dated as of October 8, 2015 by and among HEI, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as lender and Administrative Agent, and U.S. Bank, National Association, as lender, to Loan Agreement dated as of May 2, 2014 (Exhibit 4 to HEI’s Current Report on Form 8-K dated October 8, 2015, File No. 1-8503).
4.4Loan Agreement dated as of March 21, 2016 between Hawaiian Electric Industries, Inc., as Borrower and Bank of America, N.A. as Lender (Exhibit 4 to HEI’s Current Report on Form 8-K dated March 21, 2016, File No. 1-8503).
4.5Hawaiian Electric Industries Retirement Savings Plan, restatement effective January 1, 2013 (Exhibit 4.5 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
4.6Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).
4.6(a)Letter Amendment effective November 28, 2012 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4.6(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
4.6(b)Letter Amendment effective October 1, 2014 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-8503).
4.6(c)First Amendment to Master Trust Agreement (dated as of September 4, 2012) effective March 1, 2015 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, File No. 1-8503).
4.6(d)Letter Amendment effective August 3, 2015 to Master Trust Agreement (dated as of September 4, 2012) between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-8503).
4.7Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated effective October 6, 2014 (Exhibit 4(a) to Registration Statement on Form S-3, Registration No. 333-199183).
Eva T. Zlotnicka  



183
Exhibit no.Description
4.8American Savings Bank 401(k) Plan, restatement effective January 1, 2013 (Exhibit 4.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
4.8(a)Amendment 2013-1 to the American Savings Bank 401(k) Plan, effective January 1, 2014. (Exhibit 4.7(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-8503).
10.1Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982. (Exhibit 10.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).
10.2Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).
10.3OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).
HEI Exhibits 10.4 through 10.21 are management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.19 are also management contracts or compensatory plans or arrangements with Hawaiian Electric participants.
10.4HEI Executive Incentive Compensation Plan amended as of February 4, 2013 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
10.5HEI Executives’ Deferred Compensation Plan (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.6Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated November 16, 2010 (Exhibit 10.6 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).
10.7Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated February 14, 2014 (Exhibit D to HEI’s Proxy Statement for Annual Meeting of Shareholders filed on March 25, 2014, File No. 1-8503).
10.7(a)Form of Non-Qualified Stock Option Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.4 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).
10.7(b)Form of Stock Appreciation Right Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.5 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).
10.7(c)Form of Restricted Shares Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.6 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).
10.7(d)Form of Performance Shares Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.7 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).
*10.7(e)Form of Restricted Stock Unit Agreement, amended as of December 15, 2016, pursuant to 2010 Equity and Incentive Plan, as amended and restated February 14, 2014.
10.8HEI Long-Term Incentive Plan amended as of February 4, 2013 (Exhibit 10.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
10.9HEI Supplemental Executive Retirement Plan amended and restated as of January 1, 2009 (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.9(a)Amendments to the HEI Supplemental Executive Retirement Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.9(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).
10.10HEI Excess Pay Plan amended and restated as of January 1, 2009 (Exhibit 10.10 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).
10.10(a)HEI Excess Pay Plan Addendum for Constance H. Lau (Exhibit 10.10(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).


Exhibit no.Description
10.10(b)Amendment No. 1 dated December 13, 2010 to January 1, 2009 Restatement of HEI Excess Pay Plan (Exhibit 10.10(c) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).
10.11Form of Change in Control Agreement (Exhibit 10.11 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).
10.12Nonemployee Director Retirement Plan, effective as of October 1, 1989 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).
10.13HEI 2011 Nonemployee Director Stock Plan (Appendix A to HEI’s Proxy Statement for 2011 Annual Meeting of Shareholders filed on March 21, 2011, File No. 1-8503).
*10.14Nonemployee Director’s Compensation Schedule effective January 1, 2017.
10.15HEI Non-Employee Directors’ Deferred Compensation Plan (Exhibit 10.5 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.16Executive Death Benefit Plan of HEI and Participating Subsidiaries restatement effective as of January 1, 2009 (Exhibit 10.6 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.16(a)Resolution of the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc. Re: Adoption of Amendment No. 1 to January 1, 2009 Restatement of the Executive Death Benefit Plan (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8503).
10.17Severance Pay Plan for Merit Employees of HEI and affiliates, restatement effective as of January 1, 2009 (Exhibit 10.17 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).
10.18Hawaiian Electric Industries Deferred Compensation Plan adopted on December 13, 2010 (Exhibit 10.18 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).
10.19Form of Indemnity Agreement (HEI, Hawaiian Electric and ASB with their respective directors and HEI with certain of its senior officers) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).
10.20American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2009) (Exhibit 10.7 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.20(a)Amendment No. 1 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 30, 2009. (Exhibit 10.20(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-8503).
10.20(b)Amendment No. 2 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 29, 2010. (Exhibit 10.20(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-8503).
10.20(c)Amendment No. 3 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 3, 2014. (Exhibit 10.20(c) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-8503).
10.21American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan, effective January 1, 2009 (Exhibit 10.8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).
10.21(a)Amendments to the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.19(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).
10.22Amended and Restated Credit Agreement, dated as of April 2, 2014, among HEI, as Borrower, the Lenders Party Thereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., Bank of Hawaii, Royal Bank of Canada, Union Bank, N.A. and U.S. Bank National Association as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners (Exhibit 10.1 to HEI’s Current Report on Form 8-K dated April 2, 2014, File No. 1-8503).


Exhibit no.Description
*11HEI - Computation of Earnings per Share of Common Stock.
*12.1HEI - Computation of Ratio of Earnings to Fixed Charges.
*21.1HEI - Subsidiaries of the Registrant.
*23.1Consent of Independent Registered Public Accounting Firm.
*31.1Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).
*31.2Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer).
*32.1HEI Certification Pursuant to 18 U.S.C. Section 1350.
*101.INSXBRL Instance Document.
*101.SCHXBRL Taxonomy Extension Schema Document.
*101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
*101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
*101.LABXBRL Taxonomy Extension Label Linkbase Document.
*101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
Hawaiian Electric:
2.1Asset Purchase Agreement by and among Hamakua Energy Partners, L.P. and Hamakua Land Partnership, L.L.P., as sellers, and Hawaii Electric Light Company, Inc., as buyer, dated as of December 21, 2015. (confidential treatment has been granted for portions of this exhibit through March 31, 2017). (Exhibit 2.1 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, File No. 1-4955).**
3(i).1Hawaiian Electric’s Certificate of Amendment of Articles of Incorporation (Exhibit 3.1 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).
3(i).2Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation (Exhibit 3.1(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).
3(i).3Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation (Exhibit 3(i).4 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).
3(i).4Articles of Amendment amending Article V of Hawaiian Electric’s Amended Articles of Incorporation effective August 6, 2009 (Exhibit 3(i).4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-4955).
3(ii)Hawaiian Electric’s Amended and Restated Bylaws (as last amended August 6, 2010) (Exhibit 3(ii) to Hawaiian Electric’s Current Report on Form 8-K dated August 9, 2010, File No. 1-4955).
4.1Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of Hawaiian Electric, Hawaii Electric Light and Maui Electric (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).
4.2Certificate of Trust of HECO Capital Trust III (incorporated by reference to Exhibit 4(a) to Registration No. 333-111073).
4.3Amended and Restated Trust Agreement of HECO Capital Trust III dated as of March 1, 2004 (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.4Hawaiian Electric Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 2004 (Exhibit 4(f) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
**Pursuant to Item 6.01 (b)(2) of Regulation S-K, exhibits and schedules are omitted. Hawaiian Electric agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.


Exhibit no.Description
4.56.500% Quarterly Income Trust Preferred Security issued by HECO Capital Trust III, dated March 18, 2004 (Exhibit 4(d) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.66.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Hawaiian Electric, dated March 18, 2004 (Exhibit 4(g) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.7Trust Guarantee Agreement between The Bank of New York, as Trust Guarantee Trustee, and Hawaiian Electric dated as of March 1, 2004 (Exhibit 4(l) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.8Maui Electric Junior Indenture with The Bank of New York, as Trustee, including Hawaiian Electric Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(h) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.9Hawaii Electric Light Junior Indenture with The Bank of New York, as Trustee, including Hawaiian Electric Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(j) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.106.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Maui Electric, dated March 18, 2004 (Exhibit 4(i) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.116.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Hawaii Electric Light, dated March 18, 2004 (Exhibit 4(k) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.12Expense Agreement, dated March 1, 2004, among HECO Capital Trust III, Hawaiian Electric, Maui Electric and Hawaii Electric Light (Exhibit 4(m) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
4.13Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).
4.14Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).
4.15Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).
4.16Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated September 13, 2012 (Exhibit 4 to Hawaiian Electric’s Current Report on Form 8-K dated September 13, 2012, File No. 1-4955).
4.17Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated October 3, 2013, File No. 1-4955).
4.18Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated October 3, 2013, File No. 1-4955).
4.19Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, 2013, File No. 1-4955).
4.20Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).
4.21Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).


Exhibit no.Description
4.22Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).
4.23Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of December 15, 2016. (Exhibit 4 to Hawaiian Electric’s Current Report on Form 8-K dated December 15, 2016, File No. 1-4955).
10.1(a)Power Purchase Agreement between Kalaeloa Partners, L.P., and Hawaiian Electric dated October 14, 1988 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1988, File No. 1-4955).
10.1(b)Amendment No. 1 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).
10.1(c)Lease Agreement between Kalaeloa Partners, L.P., as Lessor, and Hawaiian Electric, as Lessee, dated February 27, 1989 (Exhibit 10(d) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).
10.1(d)Restated and Amended Amendment No. 2 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).
10.1(e)Amendment No. 3 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-4955).
10.1(f)Amendment No. 4 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).
10.1(g)Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.3 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).
10.1(h)Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).
10.1(i)Letter agreement dated July 28, 2016 and executed August 1, 2016 extending the term of the Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 14, 1988 (as amended) (Exhibit 10 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, File No. 1-4955).
10.2(a)Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric, entered into on March 25, 1988 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).
10.2(b)Agreement between Hawaiian Electric and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 1988, File No. 1-4955).
10.2(c)Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric (Exhibit 10 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1-4955).
10.2(d)Hawaiian Electric’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).
10.2(e)Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and Hawaiian Electric (Exhibit 10.2(e) to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 2003, File No. 1-4955).
10.3(a)Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).


Exhibit no.Description
10.3(b)Firm Capacity Amendment between Hawaii Electric Light and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).
10.3(c)Amendment made in October 1993 to Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).
10.3(d)Third Amendment dated March 7, 1995 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).
10.3(e)Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).
10.3(f)Fifth Amendment dated February 7, 2011 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.4(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).
10.3(g)Power Purchase Agreement between Puna Geothermal Venture and Hawaii Electric Light dated February 7, 2011 (Exhibit 10.4(g) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).
10.4(a)Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light,” which is provided in final form as Exhibit 10.6(b)) (Exhibit 10.7 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).
10.4(b)Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (Exhibit 10.7(a) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).
10.4(c)Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (Exhibit 10.7(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).
10.4(d)Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and Hawaii Electric Light (Exhibit 10.7(c) to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).
10.4(e)Consent and Agreement Concerning Certain Assets of Black River Energy, LLC By and Among Great Point Power Hamakua Holdings, LLC, Hamakua Energy Partners, L.P. and Hawaii Electric Light dated April 19, 2010 (Exhibit 10.6(e) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).
10.4(f)Guarantee Agreement between Great Point Power Hamakua Holdings, LLC and Hawaii Electric Light dated June 4, 2010 (Exhibit 10.6(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).
10.5Inter-Island Supply Contract for Petroleum Fuels by and between Chevron Products Company and Hawaiian Electric, Hawaii Electric Light and Maui Electric dated as of February 18, 2016 (confidential treatment has been granted for portions of this exhibit through December 31, 2019) (Exhibit 10.1 to Hawaiian Electric’s Amendment No. 1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 1-4955).
10.6Supply Contract for LSFO, Diesel and MATS Fuel by and between Hawaiian Electric and Chevron Products Company dated February 18, 2016 (confidential treatment has been granted for portions of this exhibit through December 31, 2019) (Exhibit 10.2 to Hawaiian Electric’s Amendment No. 1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 1-4955).


Exhibit no.Description
10.7Fuels Terminalling Agreement by and between Chevron Products Company and Hawaii Electric Light dated February 18, 2016 (confidential treatment has been granted for portions of this exhibit through December 31, 2019) (Exhibit 10.2 to Hawaiian Electric’s Amendment No. 1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, File No. 1-4955).
10.8(a)Contract of private carriage by and between HITI and Hawaii Electric Light dated December 4, 2000 (Exhibit 10.13 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).
10.8(b)Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Hawaii Electric Light, dated July 1, 2011 (Exhibit 10.13(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-4955).
10.9(a)Contract of private carriage by and between HITI and Maui Electric dated December 4, 2000 (Exhibit 10.14 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).
10.9(b)Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Maui Electric, dated July 1, 2011 (Exhibit 10.14(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-4955).
10.10Amended and Restated Credit Agreement, dated as of April 2, 2014, among Hawaiian Electric, as Borrower, the Lenders Party Thereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., Bank of Hawaii, Royal Bank of Canada, Union Bank, N.A. and U.S. Bank National Association as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners (Exhibit 10.2 to Hawaiian Electric’s Current Report on Form 8-K dated April 2, 2014, File No. 1-4955).
11Computation of Earnings Per Share of Common Stock (See note on Hawaiian Electric’s Item 6. Selected Financial Data).
*12.2Hawaiian Electric - Computation of Ratio of Earnings to Fixed Charges.
*21.2Hawaiian Electric - Subsidiaries of the Registrant.
*31.3Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Alan M. Oshima (Hawaiian Electric Chief Executive Officer).
*31.4Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (Hawaiian Electric Chief Financial Officer).
*32.2Hawaiian Electric Certification Pursuant to 18 U.S.C. Section 1350.
*99.1Hawaiian Electric’s Directors, Executive Officers and Corporate Governance; Hawaiian Electric’s Executive Compensation; Hawaiian Electric’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters; Hawaiian Electric’s Certain Relationships and Related Transactions, and Director Independence; and Hawaiian Electric’s Principal Accounting Fees and Services.