UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
 FORM 10-Q
 
ý     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20162017
 OR
o        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Exact Name of Registrant as Commission I.R.S. Employer
Specified in Its Charter File Number Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC. 1-8503 99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC. 1-4955 99-0040500
State of Hawaii
(State or other jurisdiction of incorporation or organization)
 
Hawaiian Electric Industries, Inc. – 1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813
Hawaiian Electric Company, Inc. – 900 Richards Street, Honolulu, Hawaii  96813
(Address of principal executive offices and zip code)
 
Hawaiian Electric Industries, Inc. – (808) 543-5662
Hawaiian Electric Company, Inc. – (808) 543-7771
(Registrant’s telephone number, including area code)
 
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
 
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 o
 
Hawaiian Electric Company, Inc. Yes x No o
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 o
 
Hawaiian Electric Company, Inc. Yes x No o
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 o No x
Hawaiian Electric Company, Inc. Yes o No x
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”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Securities Exchange Act.Act of 1934.
Hawaiian Electric Industries, Inc. 
Large accelerated filer  x
 Hawaiian Electric Company, Inc. 
Large accelerated filer o
  
Accelerated filer o
   
Accelerated filer o
  
Non-accelerated filer o
   
Non-accelerated filer  x
  (Do not check if a smaller reporting company)   (Do not check if a smaller reporting company)
  
Smaller reporting company o
   
Smaller reporting company o
Emerging growth company o
Emerging growth company o
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. o
Hawaiian Electric Company, Inc. o
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 o No x
Hawaiian Electric Company, Inc. Yes o No x
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
Class of Common Stock Outstanding October 28, 2016July 27, 2017
Hawaiian Electric Industries, Inc. (Without Par Value) 108,524,493108,785,486 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value) 15,805,32716,019,785 Shares (not publicly traded)
Hawaiian Electric Industries, Inc. (HEI) is the sole holder of Hawaiian Electric Company, Inc. (Hawaiian Electric) common stock.
This combined Form 10-Q is separately filed by HEI and Hawaiian Electric. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to the other registrant, except that information relating to Hawaiian Electric is also attributed to HEI.


Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended SeptemberJune 30, 20162017
 
TABLE OF CONTENTS
 
Page No.  
ii
 
Glossary of Terms
iv
 
Cautionary Note Regarding Forward-Looking Statements
   
  
PART I. FINANCIAL INFORMATION
1
 
Item 1.
Financial Statements
   
Hawaiian Electric Industries, Inc. and Subsidiaries
1
  
Condensed Consolidated Statements of Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20162017 and 20152016
2
  
Condensed Consolidated Statements of Comprehensive Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20162017 and 20152016
3
  
Condensed Consolidated Balance Sheets (unaudited) - SeptemberJune 30, 20162017 and December 31, 20152016
4
  
Condensed Consolidated Statements of Changes in Shareholders’ Equity (unaudited) -
ninesix months ended SeptemberJune 30, 20162017 and 20152016
5
  
Condensed Consolidated Statements of Cash Flows (unaudited) -
ninesix months ended SeptemberJune 30, 20162017 and 20152016
   
Hawaiian Electric Company, Inc. and Subsidiaries
6
  
Condensed Consolidated Statements of Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20162017 and 20152016
6
Condensed Consolidated Statements of Comprehensive Income (unaudited) -
three and six months ended June 30, 2017 and 2016
7
  
Condensed Consolidated Statements of Comprehensive IncomeBalance Sheets (unaudited) -
three June 30, 2017 and nine months ended September 30,December 31, 2016 and 2015
8
  
Condensed Consolidated Balance SheetsStatements of Changes in Common Stock Equity (unaudited) - September
six months ended June 30, 20162017 and December 31, 20152016
9
  
Condensed Consolidated Statements of Changes in Common Stock EquityCash Flows (unaudited) -
ninesix months ended SeptemberJune 30, 20162017 and 20152016
10
  
Consolidated Statements of Cash Flows (unaudited) -
nine months ended September 30, 2016 and 2015
11
Notes to Condensed Consolidated Financial Statements (unaudited)
6559
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6559
  
HEI consolidated
7063
  
Electric Utilities
8275
  
Bank
9184
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
9184
 
Item 4.
Controls and Procedures
   
  
PART II.
OTHER INFORMATION
9285
 
Item 1.
Legal Proceedings
9285
 
Item 1A.
Risk Factors
9386
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
86
 
Item 5.
Other Information
9387
 
Item 6.
Exhibits
9488
 
Signatures
 

i


Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended SeptemberJune 30, 20162017
GLOSSARY OF TERMS
Terms Definitions
AES Hawaii AES Hawaii, Inc.
AFUDC Allowance for funds used during construction
AOCI Accumulated other comprehensive income/(loss)
AROAsset retirement obligation
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.
ASCAccounting Standards Codification
ASU Accounting Standards Update
CIP CT-1 Campbell Industrial Park 110 MW combustion turbine No. 1
CISCustomer Information System
Company 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)2015 and wound up in 2017); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
Consumer Advocate Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
CBRECommunity-based renewable energy
DER Distributed Energy Resourcesenergy resources
D&O Decision and order from the PUC
DG Distributed generation
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOH Department of Health of the State of Hawaii
DRIP HEI Dividend Reinvestment and Stock Purchase Plan
DSM Demand-side management
ECAC Energy cost adjustment clause
EGUElectrical generating unit
EIP 2010 Equity and Incentive Plan, as amended and restated
EPA Environmental Protection Agency — federal
EPS Earnings per share
ERISAERP/EAM Employee Retirement Income Security Act of 1974, as amendedEnterprise Resource Planning/Enterprise Asset Management
EVE Economic value of equity
Exchange Act Securities Exchange Act of 1934
FASB Financial Accounting Standards Board
FDIC Federal Deposit Insurance Corporation
federal U.S. Government
FERCFederal Energy Regulatory Commission
FHLB Federal Home Loan Bank
FHLMC Federal Home Loan Mortgage Corporation
FNMA Federal National Mortgage Association
FRB Federal Reserve Board
GAAP Accounting principles generally accepted in the United States of America
GHGGreenhouse gas

ii
GLOSSARY OF TERMS, continued

Terms Definitions
GNMA Government National Mortgage Association
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.
HIEHEP Hamakua Energy Partners, L.P., successor in interest to Encogen Hawaii, Independent Energy, LLCL.P.
HEI Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., ASB Hawaii, Inc., HEI Properties, Inc. (dissolved in 2015)2015 and wound up in 2017) and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.)
HEIRSP Hawaiian Electric Industries Retirement Savings Plan
HELOC Home equity line of credit
HpowerHPOWER City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP Independent power producer
Kalaeloa Kalaeloa Partners, L.P.
KWH Kilowatthour/s (as applicable)
LNG Liquefied natural gas
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.
Merger As provided in the Merger Agreement (see below), merger of MergerNEE Acquisition Sub III, Inc. with and into HEI, with HEI surviving, and then merger of HEI with and into MergerNEE Acquisition Sub II,I, LLC, with MergerNEE Acquisition Sub III, LLC surviving as a wholly owned subsidiary of NEENextEra Energy, Inc.
Merger Agreement Agreement and Plan of Merger by and among HEI, NEE, Merger Sub II and Merger Sub I, dated December 3, 2014
Merger Sub INextEra Energy, Inc., NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE
Merger Sub IINEE Acquisition Sub I, LLC, a Delaware limited liability companydated December 3, 2014 and a wholly owned subsidiary of NEEterminated July 16, 2016
MPIRMajor Project Interim Recovery
MW Megawatt/s (as applicable)
NEE NextEra Energy, Inc.
NEM Net energy metering
NII Net interest income
NPBCNet periodic benefit costs
NPPCNet periodic pension costs
O&M Other operation and maintenance
OCC Office of the Comptroller of the Currency
OPEB Postretirement benefits other than pensions
PPA Power purchase agreement
PPAC Purchased power adjustment clause
PSIPs Power Supply Improvement Plans
PUC Public Utilities Commission of the State of Hawaii
PV PhotovaltaicPhotovoltaic
RAM Rate adjustment mechanism
RBA Revenue balancing account
RFP Request for proposals
ROACE Return on average common equity
RORB Return on rate base
RPS Renewable portfolio standards
SARStock appreciation right
SEC Securities and Exchange Commission
See Means the referenced material is incorporated by reference
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
TDR Troubled debt restructuring
Trust III HECO Capital Trust III
Utilities Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited
VIE Variable interest entity
 

iii


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,Hawaii; 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 developments (including global economic conditions and uncertainties,uncertainties; the effects of the United Kingdom’s referendum to withdraw from the European Union, unrest,Union; unrest; the conflict in Syria,Syria; the effects of changes that have or may occur in U.S. policy, such as with respect to immigration and trade; terrorist acts by ISIS or others,others; potential conflict or crisis with North KoreaKorea; and potential pandemics);
the effects of future actions or inaction of the U.S. government or related agencies, including those related to the U.S. debt ceiling, monetary policy and monetary policy;policy and regulation 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 potential effects of climate change, such as more severe storms and rising sea levels), including their impact on the Company's and Utilities' operations and the economy;
the timing 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;
changes in laws, regulations, market conditions 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;
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)EAM) 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 (PSIPs), 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 in 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’sits April 2014 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 adjustment clauses (ECACs);
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 impact of fuel price volatility on customer satisfaction and political and regulatory support for the Utilities;


iv



the risks associated with increasing reliance on renewable energy, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;
the growing risk that energy production from renewable generating resources may be curtailed and the interconnection of additional resources will be constrained as more generating resources are added to the Utilities' electric systems and as customers reduce their energy usage;
the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);
the potential that, as IPP contracts near the end of their terms, there may be less economic incentive for the IPPs to make investments in their units to ensure the availability of their units;
the ability of the Utilities to negotiate, periodically, favorable agreements for significant resources such as fuel supply contracts and collective bargaining agreements;
new technological developments that could affect the operations and prospects of the Utilities and ASB or their competitors;
new technological developments, such as the commercial development of energy storage and microgrids, that could affect the operations of the Utilities;
cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and the Utilities (including at ASB branches and electric utility plants) and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;
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, 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 capital lease accounting for PPAs with IPPs;
changes by securities rating agencies in their ratings of the securities of HEI and Hawaiian Electric and the 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 which may increase or decrease the required level of provision for loan losses, allowance for loan losses and charge-offs;
changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;
the final outcome of tax positions taken by HEI, the Utilities and ASB;
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); and
other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) 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 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.

v

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (unaudited)
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in thousands, except per share amounts) 2016 2015 2016 2015 2017 2016 2017 2016
Revenues  
  
  
  
  
  
  
  
Electric utility $572,253
 $648,127
 $1,549,700
 $1,779,732
 $556,875
 $495,395
 $1,075,486
 $977,447
Bank 73,708
 69,091
 213,297
 199,222
 75,329
 70,749
 148,185
 139,589
Other 94
 (42) 262
 (4) 77
 100
 172
 168
Total revenues 646,055
 717,176
 1,763,259
 1,978,950
 632,281
 566,244
 1,223,843
 1,117,204
Expenses  
  
  
  
  
  
  
  
Electric utility 482,441
 565,470
 1,333,876
 1,573,278
 501,828
 424,709
 971,501
 851,435
Bank 50,981
 48,289
 150,752
 138,063
 50,533
 50,525
 99,229
 99,771
Other 7,191
 6,322
 18,883
 28,278
 4,024
 5,555
 9,355
 11,692
Total expenses 540,613
 620,081
 1,503,511
 1,739,619
 556,385
 480,789
 1,080,085
 962,898
Operating income (loss)  
  
  
  
  
  
  
  
Electric utility 89,812
 82,657
 215,824
 206,454
 55,047
 70,686
 103,985
 126,012
Bank 22,727
 20,802
 62,545
 61,159
 24,796
 20,224
 48,956
 39,818
Other (7,097) (6,364) (18,621) (28,282) (3,947) (5,455) (9,183) (11,524)
Total operating income 105,442
 97,095
 259,748
 239,331
 75,896
 85,455
 143,758
 154,306
Merger termination fee 90,000
 —
 90,000
 —
Interest expense, net—other than on deposit liabilities and other bank borrowings (19,365) (19,229) (56,792) (57,235) (20,440) (17,301) (40,008) (37,427)
Allowance for borrowed funds used during construction 854
 737
 2,276
 1,918
 1,143
 760
 2,032
 1,422
Allowance for equity funds used during construction 2,274
 2,057
 6,010
 5,366
 3,027
 1,997
 5,426
 3,736
Income before income taxes 179,205
 80,660
 301,242
 189,380
 59,626
 70,911
 111,208
 122,037
Income taxes 51,592
 29,516
 96,203
 70,406
 20,492
 26,310
 37,408
 44,611
Net income 127,613
 51,144
 205,039
 118,974
 39,134
 44,601
 73,800
 77,426
Preferred stock dividends of subsidiaries 471
 471
 1,417
 1,417
 473
 473
 946
 946
Net income for common stock $127,142
 $50,673
 $203,622
 $117,557
 $38,661
 $44,128
 $72,854
 $76,480
Basic earnings per common share $1.17
 $0.47
 $1.89
 $1.11
 $0.36
 $0.41
 $0.67
 $0.71
Diluted earnings per common share $1.17
 $0.47
 $1.88
 $1.11
 $0.36
 $0.41
 $0.67
 $0.71
Dividends per common share $0.31
 $0.31
 $0.93
 $0.93
Dividends declared per common share $0.31
 $0.31
 $0.62
 $0.62
Weighted-average number of common shares outstanding 108,268
 107,457
 107,951
 106,067
 108,750
 107,962
 108,712
 107,791
Net effect of potentially dilutive shares 204
 281
 220
 280
 47
 171
 157
 187
Adjusted weighted-average shares 108,472
 107,738
 108,171
 106,347
Weighted-average shares assuming dilution 108,797
 108,133
 108,869
 107,978
 
The accompanying notes are an integral part of these condensed consolidated financial statements.



Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (unaudited)
  Three months ended September 30 Nine months ended September 30
(in thousands) 2016 2015 2016 2015
Net income for common stock $127,142
 $50,673
 $203,622
 $117,557
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 $1,417, $(2,543), $(5,413) and $(2,382) for the respective periods (2,147) 3,851
 8,197
 3,608
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, $238 and nil for the respective periods —
 —
 (360) —
Derivatives qualified as cash flow hedges:  
  
  
  
Effective portion of foreign currency hedge net unrealized gains, net of taxes of $205, nil, $368 and nil for the respective periods 321
 —
 578
 —
Less: reclassification adjustment to net income, net of (taxes) benefits of $(110), $37, $(75) and $112 for the respective periods (173) 59
 (119) 177
Retirement benefit plans:  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,324, $3,583, $6,943 and $10,760 for the respective periods 3,641
 5,611
 10,877
 16,850
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,109, $3,243, $6,327 and $9,729 for the respective periods (3,311) (5,091) (9,934) (15,274)
Other comprehensive income (loss), net of taxes (1,669) 4,430
 9,239
 5,361
Comprehensive income attributable to Hawaiian Electric Industries, Inc. $125,473
 $55,103
 $212,861
 $122,918
  Three months ended June 30 Six months ended June 30
(in thousands) 2017 2016 2017 2016
Net income for common stock $38,661
 $44,128
 $72,854
 $76,480
Other comprehensive income (loss), net of taxes:  
  
  
  
Net unrealized gains on available-for-sale investment securities:  
  
  
  
Net unrealized gains on available-for-sale investment securities arising during the period, net of taxes of $1,334, $1,925, $1,482 and $6,830, respectively 2,021
 2,916
 2,244
 10,344
Reclassification adjustment for net realized gains included in net income, net of taxes of nil, $238, nil and $238, respectively —
 (360) —
 (360)
Derivatives qualifying as cash flow hedges:  
  
  
  
Effective portion of foreign currency hedge net unrealized gains (losses) arising during the period, net of (taxes) benefits of nil, $475, nil and ($163), respectively —
 (745) —
 257
Reclassification adjustment to net income, net of tax benefits of nil, nil, $289 and $35, respectively —
 —
 454
 54
Retirement benefit plans:  
  
  
  
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,508, $2,362, $5,010 and $4,619, respectively 3,930
 3,698
 7,851
 7,236
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,281, $2,166, $4,582 and $4,218, respectively (3,581) (3,401) (7,194) (6,623)
Other comprehensive income, net of taxes 2,370
 2,108
 3,355
 10,908
Comprehensive income attributable to Hawaiian Electric Industries, Inc. $41,031
 $46,236
 $76,209
 $87,388
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (unaudited) 
(dollars in thousands) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Assets  
  
  
  
Cash and cash equivalents $284,355
 $300,478
 $210,381
 $278,452
Accounts receivable and unbilled revenues, net 250,076
 242,766
 249,539
 237,950
Available-for-sale investment securities, at fair value 996,984
 820,648
 1,302,886
 1,105,182
Stock in Federal Home Loan Bank, at cost 11,218
 10,678
 11,706
 11,218
Loans receivable held for investment, net 4,675,901
 4,565,781
 4,688,278
 4,683,160
Loans held for sale, at lower of cost or fair value 26,743
 4,631
 5,261
 18,817
Property, plant and equipment, net of accumulated depreciation of $2,416,937 and $2,339,319 at the respective dates 4,532,556
 4,377,658
Property, plant and equipment, net of accumulated depreciation of $2,508,291 and $2,444,348 at June 30, 2017 and December 31, 2016, respectively 4,726,524
 4,603,465
Regulatory assets 879,775
 896,731
 938,277
 957,451
Other 459,187
 480,457
 478,763
 447,621
Goodwill 82,190
 82,190
 82,190
 82,190
Total assets $12,198,985
 $11,782,018
 $12,693,805
 $12,425,506
Liabilities and shareholders’ equity  
  
  
  
Liabilities  
  
  
  
Accounts payable $134,176
 $138,523
 $194,755
 $143,279
Interest and dividends payable 27,115
 26,042
 22,124
 25,225
Deposit liabilities 5,380,721
 5,025,254
 5,724,386
 5,548,929
Short-term borrowings—other than bank —
 103,063
 49,789
 —
Other bank borrowings 265,388
 328,582
 188,130
 192,618
Long-term debt, net—other than bank 1,579,065
 1,578,368
 1,618,647
 1,619,019
Deferred income taxes 721,470
 680,877
 750,413
 728,806
Regulatory liabilities 400,479
 371,543
 431,630
 410,693
Contributions in aid of construction 525,491
 506,087
 543,204
 543,525
Defined benefit pension and other postretirement benefit plans liability 572,933
 589,918
 626,795
 638,854
Other 489,466
 471,828
 434,610
 473,512
Total liabilities 10,096,304
 9,820,085
 10,584,483
 10,324,460
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: 108,503,210 shares and 107,460,406 shares at the respective dates 1,657,421
 1,629,136
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,785,486 shares and 108,583,413 shares at June 30, 2017 and December 31, 2016, respectively 1,660,403
 1,660,910
Retained earnings 427,990
 324,766
 444,400
 438,972
Accumulated other comprehensive loss, net of tax benefits (17,023) (26,262) (29,774) (33,129)
Total shareholders’ equity 2,068,388
 1,927,640
 2,075,029
 2,066,753
Total liabilities and shareholders’ equity $12,198,985
 $11,782,018
 $12,693,805
 $12,425,506
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Shareholders’ Equity (unaudited) 
  Common stock Retained 
Accumulated
other
comprehensive
  
(in thousands, except per share amounts) Shares Amount Earnings income (loss) Total
Balance, December 31, 2015 107,460
 $1,629,136
 $324,766
 $(26,262) $1,927,640
Net income for common stock —
 —
 203,622
 —
 203,622
Other comprehensive income, net of taxes —
 —
 —
 9,239
 9,239
Issuance of common stock, net 1,043
 28,285
 —
 —
 28,285
Common stock dividends ($0.93 per share) —
 —
 (100,398) —
 (100,398)
Balance, September 30, 2016 108,503
 $1,657,421
 $427,990
 $(17,023) $2,068,388
Balance, December 31, 2014 102,565
 $1,521,297
 $296,654
 $(27,378) $1,790,573
Net income for common stock —
 —
 117,557
 —
 117,557
Other comprehensive income, net of taxes —
 —
 —
 5,361
 5,361
Issuance of common stock, net 4,894
 105,962
 —
 —
 105,962
Common stock dividends ($0.93 per share) —
 —
 (98,452) —
 (98,452)
Balance, September 30, 2015 107,459
 $1,627,259
 $315,759
 $(22,017) $1,921,001
  Common stock Retained 
Accumulated
other
comprehensive
  
(in thousands) Shares Amount Earnings income (loss) Total
Balance, December 31, 2016 108,583
 $1,660,910
 $438,972
 $(33,129) $2,066,753
Net income for common stock —
 —
 72,854
 —
 72,854
Other comprehensive income, net of taxes —
 —
 —
 3,355
 3,355
Issuance of common stock, net of expenses 202
 (507) —
 —
 (507)
Common stock dividends —
 —
 (67,426) —
 (67,426)
Balance, June 30, 2017 108,785
 $1,660,403
 $444,400
 $(29,774) $2,075,029
Balance, December 31, 2015 107,460
 $1,629,136
 $324,766
 $(26,262) $1,927,640
Net income for common stock —
 —
 76,480
 —
 76,480
Other comprehensive income, net of taxes —
 —
 —
 10,908
 10,908
Issuance of common stock, net of expenses 727
 18,002
 —
 —
 18,002
Common stock dividends —
 —
 (66,848) —
 (66,848)
Balance, June 30, 2016 108,187
 $1,647,138
 $334,398
 $(15,354) $1,966,182
 
The accompanying notes are an integral part of these condensed consolidated financial statements.



Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (unaudited)
Nine months ended September 30 2016 2015
(in thousands)    
Cash flows from operating activities  
  
Net income $205,039
 $118,974
Adjustments to reconcile net income to net cash provided by operating activities  
  
Depreciation of property, plant and equipment 145,684
 137,721
Other amortization 7,368
 7,252
Provision for loan losses 15,266
 5,436
Loans receivable originated and purchased, held for sale (172,657) (226,081)
Proceeds from sale of loans receivable, held for sale 168,490
 231,509
Deferred income taxes 30,667
 2,723
Share-based compensation expense 3,581
 4,780
Excess tax benefits from share-based payment arrangements (398) (1,012)
Allowance for equity funds used during construction (6,010) (5,366)
Impairment of utility assets —
 4,828
Other 3,234
 3,921
Changes in assets and liabilities  
  
Decrease (increase) in accounts receivable and unbilled revenues, net (12,104) 8,248
Decrease in fuel oil stock 6,736
 35,942
Increase in regulatory assets (2,251) (23,458)
Increase (decrease) in accounts, interest and dividends payable 3,399
 (34,171)
Change in prepaid and accrued income taxes and utility revenue taxes 52,558
 (8,458)
Increase in defined benefit pension and other postretirement benefit plans liability 150
 418
Change in other assets and liabilities (39,850) (41,954)
Net cash provided by operating activities 408,902
 221,252
Cash flows from investing activities  
  
Available-for-sale investment securities purchased (354,165) (326,965)
Principal repayments on available-for-sale investment securities 172,829
 96,053
Proceeds from sale of available-for-sale investment securities 16,423
 —
Purchase of stock from Federal Home Loan Bank (2,773) (1,600)
Redemption of stock from Federal Home Loan Bank 2,233
 60,223
Net increase in loans held for investment (175,303) (101,771)
Proceeds from sale of commercial loans 37,946
 —
Proceeds from sale of real estate acquired in settlement of loans 829
 1,258
Proceeds from sale of real estate held-for-sale 1,764
 7,280
Capital expenditures (259,207) (276,186)
Contributions in aid of construction 23,568
 34,627
Other 112
 4,084
Net cash used in investing activities (535,744) (502,997)
Cash flows from financing activities  
  
Net increase in deposit liabilities 355,467
 202,539
Net increase (decrease) in short-term borrowings with original maturities of three months or less (103,063) 53,020
Net increase (decrease) in retail repurchase agreements (21,121) 67,934
Proceeds from other bank borrowings 55,835
 50,000
Repayments of other bank borrowings (97,902) (40,000)
Proceeds from issuance of long-term debt 75,000
 —
Repayment of long-term debt (75,000) —
Excess tax benefits from share-based payment arrangements 398
 1,012
Net proceeds from issuance of common stock 10,901
 104,437
Common stock dividends (83,620) (98,452)
Preferred stock dividends of subsidiaries (1,417) (1,417)
Other (4,759) (4,453)
Net cash provided by financing activities 110,719
 334,620
Net increase (decrease) in cash and cash equivalents (16,123) 52,875
Cash and cash equivalents, beginning of period 300,478
 175,542
Cash and cash equivalents, end of period $284,355
 $228,417
  Six months ended June 30
(in thousands) 2017 2016
Cash flows from operating activities  
  
Net income $73,800
 $77,426
Adjustments to reconcile net income to net cash provided by operating activities  
  
Depreciation of property, plant and equipment 100,062
 97,148
Other amortization 6,101
 4,840
Provision for loan losses 6,741
 9,519
Loans receivable originated and purchased, held for sale (69,595) (98,004)
Proceeds from sale of loans receivable, held for sale 79,944
 98,457
Deferred income taxes 17,047
 21,738
Share-based compensation expense 3,285
 2,011
Allowance for equity funds used during construction (5,426) (3,736)
Other 246
 2,982
Changes in assets and liabilities  
  
Decrease (increase) in accounts receivable and unbilled revenues, net (12,394) 12,894
Decrease (increase) in fuel oil stock (5,962) 9,644
Decrease (increase) in regulatory assets 8,179
 (11,752)
Increase in accounts, interest and dividends payable 55,451
 20,837
Change in prepaid and accrued income taxes, tax credits and utility revenue taxes (37,954) 622
Increase in defined benefit pension and other postretirement benefit plans liability 420
 95
Change in other assets and liabilities (33,922) (18,878)
Net cash provided by operating activities 186,023
 225,843
Cash flows from investing activities  
  
Available-for-sale investment securities purchased (295,510) (176,598)
Principal repayments on available-for-sale investment securities 99,663
 102,716
Proceeds from sale of available-for-sale investment securities —
 16,423
Purchase of stock from Federal Home Loan Bank (2,868) (2,773)
Redemption of stock from Federal Home Loan Bank 2,380
 2,233
Net increase in loans held for investment (20,326) (155,930)
Proceeds from sale of commercial loans 13,493
 14,105
Proceeds from sale of real estate acquired in settlement of loans 185
 553
Capital expenditures (222,246) (203,631)
Contributions in aid of construction 17,571
 16,810
Other 8,216
 1,106
Net cash used in investing activities (399,442) (384,986)
Cash flows from financing activities  
  
Net increase in deposit liabilities 175,457
 206,949
Net increase in short-term borrowings with original maturities of three months or less 49,789
 12,922
Net increase (decrease) in retail repurchase agreements 9,048
 (27,158)
Proceeds from other bank borrowings 59,500
 55,835
Repayments of other bank borrowings (73,034) (84,369)
Proceeds from issuance of long-term debt 265,000
 75,000
Repayment of long-term debt and funds transferred for redemption of special purpose revenue bonds (265,000) (75,000)
Withheld shares for employee taxes on vested share-based compensation (3,787) (2,345)
Net proceeds from issuance of common stock —
 7,668
Common stock dividends (67,426) (55,591)
Preferred stock dividends of subsidiaries (946) (946)
Other (3,253) 2,908
Net cash provided by financing activities 145,348
 115,873
Net decrease in cash and cash equivalents (68,071) (43,270)
Cash and cash equivalents, beginning of period 278,452
 300,478
Cash and cash equivalents, end of period $210,381
 $257,208

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


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (unaudited)
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in thousands) 2016 2015 2016 2015 2017 2016 2017 2016
Revenues $572,253
 $648,127
 $1,549,700
 $1,779,732
 $556,875
 $495,395
 $1,075,486
 $977,447
Expenses  
  
  
  
  
  
  
  
Fuel oil 128,624
 195,633
 334,263
 518,670
 141,259
 91,899
 285,529
 205,639
Purchased power 157,750
 160,518
 412,667
 445,809
 153,067
 139,058
 280,191
 254,917
Other operation and maintenance 94,789
 103,653
 298,260
 306,519
 106,374
 99,563
 206,614
 203,471
Depreciation 46,759
 44,356
 140,300
 132,840
 48,156
 46,760
 96,372
 93,541
Taxes, other than income taxes 54,519
 61,310
 148,386
 169,440
 52,972
 47,429
 102,795
 93,867
Total expenses 482,441
 565,470
 1,333,876
 1,573,278
 501,828
 424,709
 971,501
 851,435
Operating income 89,812
 82,657
 215,824
 206,454
 55,047
 70,686
 103,985
 126,012
Allowance for equity funds used during construction 2,274
 2,057
 6,010
 5,366
 3,027
 1,997
 5,426
 3,736
Interest expense and other charges, net (17,323) (16,557) (49,734) (49,170) (18,214) (15,103) (35,718) (32,411)
Allowance for borrowed funds used during construction 854
 737
 2,276
 1,918
 1,143
 760
 2,032
 1,422
Income before income taxes 75,617
 68,894
 174,376
 164,568
 41,003
 58,340
 75,725
 98,759
Income taxes 28,145
 25,390
 64,682
 60,351
 14,860
 21,984
 27,618
 36,537
Net income 47,472
 43,504
 109,694
 104,217
 26,143
 36,356
 48,107
 62,222
Preferred stock dividends of subsidiaries 228
 228
 686
 686
 229
 229
 458
 458
Net income attributable to Hawaiian Electric 47,244
 43,276
 109,008
 103,531
 25,914
 36,127
 47,649
 61,764
Preferred stock dividends of Hawaiian Electric 270
 270
 810
 810
 270
 270
 540
 540
Net income for common stock $46,974
 $43,006
 $108,198
 $102,721
 $25,644
 $35,857
 $47,109
 $61,224
The accompanying notes are an integral part of these condensed consolidated financial statements.
HEI owns all of the common stock of Hawaiian Electric. Therefore, per share data with respect to shares of common stock of Hawaiian Electric are not meaningful.


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (unaudited)
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in thousands) 2016 2015 2016 2015 2017 2016 2017 2016
Net income for common stock $46,974
 $43,006
 $108,198
 $102,721
 $25,644
 $35,857
 $47,109
 $61,224
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
  
  
Derivatives qualified as cash flow hedges:        
Effective portion of foreign currency hedge net unrealized gains, net of taxes of $205, nil, $368 and nil for the respective periods 321
 —
 578
 —
Less: reclassification adjustment to net income, net of taxes of $110, nil, $110 and nil for the respective periods (173) —
 (173) —
Derivatives qualifying as cash flow hedges:        
Effective portion of foreign currency hedge net unrealized gains (losses) arising during the period, net of (taxes) benefits of nil, $475, nil and ($163), respectively —
 (745) —
 257
Reclassification adjustment to net income, net of tax benefits of nil, nil, $289 and nil, respectively —
 —
 454
 —
Retirement benefit plans:  
  
  
  
  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,110, $3,245, $6,331 and $9,735 for the respective periods 3,314
 5,095
 9,941
 15,285
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,109, $3,243, $6,327 and $9,729 for the respective periods (3,311) (5,091) (9,934) (15,274)
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,306, $2,160, $4,610 and $4,221, respectively 3,621
 3,391
 7,239
 6,627
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,281, $2,166, $4,582 and $4,218, respectively (3,581) (3,401) (7,194) (6,623)
Other comprehensive income (loss), net of taxes 151
 4
 412
 11
 40
 (755) 499
 261
Comprehensive income attributable to Hawaiian Electric Company, Inc. $47,125
 $43,010
 $108,610
 $102,732
 $25,684
 $35,102
 $47,608
 $61,485

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


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (unaudited)
(dollars in thousands, except par value) September 30,
2016		 December 31,
2015		 June 30, 2017
 December 31, 2016
Assets  
  
  
  
Property, plant and equipment        
Utility property, plant and equipment  
  
  
  
Land $53,175
 $52,792
 $53,178
 $53,153
Plant and equipment 6,483,562
 6,315,698
 6,711,418
 6,605,732
Less accumulated depreciation (2,343,601) (2,266,004) (2,430,097) (2,369,282)
Construction in progress 236,608
 175,309
 272,438
 211,742
Utility property, plant and equipment, net 4,429,744
 4,277,795
 4,606,937
 4,501,345
Nonutility property, plant and equipment, less accumulated depreciation of $1,231 and $1,229 at respective dates 7,374
 7,272
Nonutility property, plant and equipment, less accumulated depreciation of $1,233 as of June 30, 2017 and $1,232 as of December 31, 2016 7,410
 7,407
Total property, plant and equipment, net 4,437,118
 4,285,067
 4,614,347
 4,508,752
Current assets  
  
  
  
Cash and cash equivalents 22,977
 24,449
 42,582
 74,286
Customer accounts receivable, net 134,418
 132,778
 126,161
 123,688
Accrued unbilled revenues, net 95,167
 84,509
 103,596
 91,693
Other accounts receivable, net 4,629
 10,408
 3,684
 5,233
Fuel oil stock, at average cost 64,480
 71,216
 72,392
 66,430
Materials and supplies, at average cost 57,356
 54,429
 57,099
 53,679
Prepayments and other 35,645
 36,640
 36,340
 23,100
Regulatory assets 74,681
 72,231
 74,167
 66,032
Total current assets 489,353
 486,660
 516,021
 504,141
Other long-term assets  
  
  
  
Regulatory assets 805,094
 824,500
 864,110
 891,419
Unamortized debt expense 267
 497
 690
 208
Other 68,994
 75,486
 75,987
 70,908
Total other long-term assets 874,355
 900,483
 940,787
 962,535
Total assets $5,800,826
 $5,672,210
 $6,071,155
 $5,975,428
Capitalization and liabilities  
  
  
  
Capitalization  
  
  
  
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 15,805,327 shares) $105,388
 $105,388
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 16,019,785 shares at June 30, 2017 and December 31, 2016) $106,818
 $106,818
Premium on capital stock 578,921
 578,930
 601,486
 601,491
Retained earnings 1,081,081
 1,043,082
 1,095,025
 1,091,800
Accumulated other comprehensive income, net of income taxes 1,337
 925
Accumulated other comprehensive income (loss), net of taxes 177
 (322)
Common stock equity 1,766,727
 1,728,325
 1,803,506
 1,799,787
Cumulative preferred stock — not subject to mandatory redemption 34,293
 34,293
 34,293
 34,293
Long-term debt, net 1,279,327
 1,278,702
 1,318,845
 1,319,260
Total capitalization 3,080,347
 3,041,320
 3,156,644
 3,153,340
Commitments and contingencies (Note 4) 

 

Commitments and contingencies (Note 3) 

 

Current liabilities  
  
  
  
Short-term borrowings from affiliates 21,000
 —
Short-term borrowings from non-affiliates 43,990
 —
Accounts payable 107,497
 114,846
 162,375
 117,814
Interest and preferred dividends payable 25,934
 23,111
 19,497
 22,838
Taxes accrued 167,276
 191,084
 142,263
 172,730
Regulatory liabilities 2,987
 2,204
 2,883
 3,762
Other 56,753
 54,079
 53,140
 55,221
Total current liabilities 381,447
 385,324
 424,148
 372,365
Deferred credits and other liabilities  
  
  
  
Deferred income taxes 714,559
 654,806
 759,972
 733,659
Regulatory liabilities 397,492
 369,339
 428,747
 406,931
Unamortized tax credits 87,794
 84,214
 91,386
 88,961
Defined benefit pension and other postretirement benefit plans liability 535,912
 552,974
 587,718
 599,726
Other 77,784
 78,146
 79,336
 76,921
Total deferred credits and other liabilities 1,813,541
 1,739,479
 1,947,159
 1,906,198
Contributions in aid of construction 525,491
 506,087
 543,204
 543,525
Total capitalization and liabilities $5,800,826
 $5,672,210
 $6,071,155
 $5,975,428
The accompanying notes are an integral part of these condensed consolidated financial statements.


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Common Stock Equity (unaudited)
 
 Common stock 
Premium
on
capital
 Retained 
Accumulated
other
comprehensive
   Common stock 
Premium
on
capital
 Retained 
Accumulated
other
comprehensive
  
(in thousands) Shares Amount stock earnings income (loss) Total Shares Amount stock earnings income (loss) Total
Balance, December 31, 2016 16,020
 $106,818
 $601,491
 $1,091,800
 $(322) $1,799,787
Net income for common stock —
 —
 —
 47,109
 —
 47,109
Other comprehensive income, net of taxes —
 —
 —
 —
 499
 499
Common stock dividends —
 —
 —
 (43,884) —
 (43,884)
Common stock issuance expenses —
 —
 (5) —
 —
 (5)
Balance, June 30, 2017 16,020
 $106,818
 $601,486
 $1,095,025
 $177
 $1,803,506
Balance, December 31, 2015 15,805
 $105,388
 $578,930
 $1,043,082
 $925
 $1,728,325
 15,805
 $105,388
 $578,930
 $1,043,082
 $925
 $1,728,325
Net income for common stock —
 —
 —
 108,198
 —
 108,198
 —
 —
 —
 61,224
 —
 61,224
Other comprehensive income, net of taxes —
 —
 —
 —
 412
 412
 —
 —
 —
 —
 261
 261
Common stock dividends —
 —
 —
 (70,199) —
 (70,199) —
 —
 —
 (46,800) —
 (46,800)
Common stock issuance expenses —
 —
 (9) —
 —
 (9) —
 —
 (4) —
 —
 (4)
Balance, September 30, 2016 15,805
 $105,388
 $578,921
 $1,081,081
 $1,337
 $1,766,727
Balance, December 31, 2014 15,805
 $105,388
 $578,938
 $997,773
 $45
 $1,682,144
Net income for common stock —
 —
 —
 102,721
 —
 102,721
Other comprehensive income, net of taxes —
 —
 —
 —
 11
 11
Common stock dividends —
 —
 —
 (67,804) —
 (67,804)
Common stock issuance expenses —
 —
 (8) —
 —
 (8)
Balance, September 30, 2015 15,805
 $105,388
 $578,930
 $1,032,690
 $56
 $1,717,064
Balance, June 30, 2016 15,805
 $105,388
 $578,926
 $1,057,506
 $1,186
 $1,743,006
 
The accompanying notes are an integral part of these condensed consolidated financial statements.



Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (unaudited) 
Nine months ended September 30 2016 2015
 Six months ended June 30
(in thousands)     2017 2016
Cash flows from operating activities  
  
  
  
Net income $109,694

$104,217
 $48,107

$62,222
Adjustments to reconcile net income to net cash provided by operating activities  

 
  

 
Depreciation of property, plant and equipment 140,300

132,840
 96,372

93,541
Other amortization 5,380

4,999
 4,262

3,793
Deferred income taxes 55,648

58,211
 23,599

32,118
Tax credits, net 5,256

4,247
Allowance for equity funds used during construction (6,010)
(5,366) (5,426)
(3,736)
Impairment of utility assets —
 4,828
Other (2,022) (326) 1,615
 2,982
Changes in assets and liabilities  

 
  

 
Increase in accounts receivable (655)
(4,464)
Decrease (increase) in accrued unbilled revenues (10,658)
13,796
Decrease in fuel oil stock 6,736

35,942
Decrease (increase) in accounts receivable (1,729)
16,682
Increase in accrued unbilled revenues (11,903)
(3,215)
Decrease (increase) in fuel oil stock (5,962)
9,644
Increase in materials and supplies (2,927)
(1,723) (3,420)
(2,482)
Increase in regulatory assets (2,251)
(23,458)
Decrease in accounts payable (676)
(40,375)
Change in prepaid and accrued income taxes and revenue taxes (9,595)
(61,635)
Decrease (increase) in regulatory assets 8,179

(677)
Increase in accounts payable 51,637

23,427
Change in prepaid and accrued income taxes, tax credits and revenue taxes (40,910)
(28,192)
Increase in defined benefit pension and other postretirement benefit plans liability 360

331
 302

237
Change in other assets and liabilities (13,309)
(20,478) (14,047)
(12,220)
Net cash provided by operating activities 275,271

201,586
 150,676

194,124
Cash flows from investing activities  
  
  
  
Capital expenditures (250,704) (265,521) (202,080) (197,332)
Contributions in aid of construction 23,568
 34,627
 17,571
 16,810
Other 1,100
 778
 6,250
 331
Net cash used in investing activities (226,036) (230,116) (178,259) (180,191)
Cash flows from financing activities  
  
  
  
Common stock dividends (70,199) (67,804) (43,884) (46,800)
Preferred stock dividends of Hawaiian Electric and subsidiaries (1,496) (1,496) (998) (998)
Proceeds from issuance of special purpose revenue bonds 265,000
 —
Funds transferred for redemption of special purpose revenue bonds (265,000) —
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 21,000
 94,995
 43,990
 36,995
Other (12) (223) (3,229) —
Net cash provided by (used in) financing activities (50,707) 25,472
Net decrease in cash and cash equivalents (1,472) (3,058)
Net cash used in financing activities (4,121) (10,803)
Net increase (decrease) in cash and cash equivalents (31,704) 3,130
Cash and cash equivalents, beginning of period 24,449
 13,762
 74,286
 24,449
Cash and cash equivalents, end of period $22,977
 $10,704
 $42,582
 $27,579

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



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1 · Basis of presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the unaudited condensed consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited condensed consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s and Hawaiian Electric’s Form 10-K for the year ended December 31, 20152016.
In the opinion of HEI’s and Hawaiian Electric’s management, the accompanying unaudited condensed consolidated financial statements contain all material adjustments required by GAAP to fairly state consolidated HEI’s and Hawaiian Electric’s financial positions as of SeptemberJune 30, 20162017 and December 31, 20152016, the results of their operations for the three and ninesix months ended SeptemberJune 30, 20162017 and 20152016 and their cash flows for the ninesix months ended SeptemberJune 30, 20162017 and 2015.2016. All such adjustments are of a normal recurring nature, unless otherwise disclosed below or in other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year.
2 · TerminationRecent accounting pronouncements.
Revenues from contracts with customers. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The core principle of proposed mergerthe 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 June 30, 2017, the Company has identified its revenue streams from, and performance obligations related to, contracts with customers and has performed an analysis of these revenue streams for the impacts of Topic 606. The majority of the revenue subject to Topic 606 is the Utilities’ electric sales revenue and the Company and Hawaiian Electric do not expect a material impact on the timing or pattern of revenue recognition upon adoption of ASU No. 2014-09. The Company and Hawaiian Electric expect changes to the presentation and disclosure of revenues. The Company plans to adopt ASU No. 2014-09 (and subsequently issued revenue-related ASUs, as applicable) in the first quarter of 2018 using the modified retrospective approach. The Company continues to monitor developments in industry-specific application guidance and evaluate further impacts of Topic 606.
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 expects changes to disclosures, but otherwise believes the impact of adoption will not be material to the Company’s and Hawaiian Electric’s consolidated financial statements.


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. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election and recognize lease expense for such leases generally on a straight-line basis over the lease term. For finance leases, a lessee is required to recognize interest on the lease liability separately from amortization of the right-of-use asset in the condensed consolidated statement 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 plans to adopt ASU No. 2016-02 in the first quarter of 2019 and has not yet determined the method or 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 No. 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. From January 1, 2017, no excess tax benefits or 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 cashflow 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 are classified as financing activities on the HEI unaudited condensed 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 matters
On December 3, 2014, HEI, NextEra Energy, Inc. (NEE)financial instruments held by financial institutions and two subsidiariesother organizations. ASU No. 2016-13 requires the measurement of NEE entered intoall 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 Agreementorganization’s portfolio. In addition, ASU No. 2016-13 amends the accounting for credit losses on available-for-sale (AFS) debt securities and Planpurchased financial assets with credit deterioration. The other-than-temporary impairment model of Merger (the Merger Agreement), under which Hawaiian Electric wasaccounting 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 become a subsidiaryrecord the estimated losses (and subsequent recoveries). The accounting for the initial recognition of NEE. The Merger Agreement contemplated that, priorthe estimated expected credit losses for purchased financial assets with credit deterioration would be recognized through an allowance for credit losses with an offset to the Merger, HEI would distribute to its shareholders allcost basis of the common stockrelated financial asset at acquisition (i.e., there is no impact to net income at initial recognition).
The Company plans to adopt ASU No. 2016-13 in the first quarter of ASB Hawaii, Inc. (ASB Hawaii)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 parent company of ASB (such distribution referred to as the Spin-Off).predominance principle.
The closingCompany plans to adopt ASU No. 2016-15 in the first quarter of 2018 using a retrospective transition method and has not yet determined the Merger was subjectimpact of adoption.
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 various conditions, including receiptadopt ASU No. 2016-18 in the first quarter of regulatory approval from2018 using a retrospective transition method and believes the Hawaii Public Utilities Commission (PUC)impact of adoption will not be material to the Company’s and Hawaiian Electric’s consolidated statements of cash flows.
Goodwill impairment. In January 2015, NEE2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” Prior to the adoption of ASU No. 2017-04, an entity was required to perform a two-step test to determine the amount, if any, of goodwill impairment. In Step 1, an entity compared the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeded its fair value, the entity performed Step 2 and compared the implied fair value of goodwill with the carrying amount of that goodwill for that reporting unit. An impairment charge equal to the amount by which the carrying amount of goodwill for the reporting unit exceeded the implied fair value of that goodwill would then be recorded. ASU No. 2017-04 removes the second step of the test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value. ASU No. 2017-04 does not amend the optional qualitative assessment of goodwill impairment.
The Company plans to adopt ASU No. 2017-04 prospectively in the fourth quarter of 2017 and believes the impact of adoption will not be material to the Company’s and Hawaiian Electric filedElectric’s consolidated financial statements.
Net periodic pension cost and net periodic postretirement benefit cost. In March 2017, the FASB issued ASU No. 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires that an application withemployer report the PUC requesting approvalservice cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. It also requires the other components of net periodic pension cost and net periodic postretirement benefit cost as defined in paragraphs 715-30-35-4 and 715-60-35-9 to be presented in the proposed Merger. On July 15, 2016,income statement separately from the PUC dismissedservice cost component and outside a subtotal of income from operations. Additionally, only the application without prejudice.service cost component is eligible for capitalization under GAAP, when applicable.
On July 16, 2016, NEE terminatedThe Company plans to adopt ASU No. 2017-07 in 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 the thirdfirst quarter of 2016,2018 and has not yet determined the Company recognized $64 millionimpact of net income, 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 the third quarter of 2016 ($2 million) (all net of tax impacts). The Spin-Off of ASB Hawaii was cancelled as it was cross-conditioned on the merger consummation.
In May 2016, the Utilities 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. On July 21, 2016, the Utilities withdrew the three applications.
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. To date, all of these lawsuits (seven of which were consolidated) have been dismissed, either with or without prejudice.adoption.


32 · Segment financial information
(in thousands)  Electric utility Bank Other Total Electric utility Bank Other Total
Three months ended September 30, 2016  
  
  
  
Three months ended June 30, 2017  
  
  
  
Revenues from external customers $572,208
 $73,708
 $139
 $646,055
 $556,836
 $75,329
 $116
 $632,281
Intersegment revenues (eliminations) 45
 —
 (45) —
 39
 —
 (39) —
Revenues 572,253
 73,708
 94
 646,055
 $556,875
 $75,329
 $77
 $632,281
Income (loss) before income taxes 75,617
 22,727
 80,861
 179,205
 $41,003
 $24,796
 $(6,173) $59,626
Income taxes (benefit) 28,145
 7,623
 15,824
 51,592
 14,860
 8,063
 (2,431) 20,492
Net income (loss) 47,472
 15,104
 65,037
 127,613
 26,143
 16,733
 (3,742) 39,134
Preferred stock dividends of subsidiaries 498
 —
 (27) 471
 499
 —
 (26) 473
Net income (loss) for common stock 46,974
 15,104
 65,064
 127,142
 $25,644
 $16,733
 $(3,716) $38,661
Nine months ended September 30, 2016  
  
  
  
Six months ended June 30, 2017  
  
  
  
Revenues from external customers $1,549,602
 $213,297
 $360
 $1,763,259
 $1,075,402
 $148,185
 $256
 $1,223,843
Intersegment revenues (eliminations) 98
 —
 (98) —
 84
 —
 (84) —
Revenues 1,549,700
 213,297
 262
 1,763,259
 $1,075,486
 $148,185
 $172
 $1,223,843
Income (loss) before income taxes 174,376
 62,545
 64,321
 301,242
 $75,725
 $48,956
 $(13,473) $111,208
Income taxes (benefit) 64,682
 21,483
 10,038
 96,203
 27,618
 16,410
 (6,620) 37,408
Net income (loss) 109,694
 41,062
 54,283
 205,039
 48,107
 32,546
 (6,853) 73,800
Preferred stock dividends of subsidiaries 1,496
 —
 (79) 1,417
 998
 —
 (52) 946
Net income (loss) for common stock 108,198
 41,062
 54,362
 203,622
 $47,109
 $32,546
 $(6,801) $72,854
Total assets (at September 30, 2016) 5,800,826
 6,336,670
 61,489
 12,198,985
Three months ended September 30, 2015  
  
  
  
Total assets (at June 30, 2017) $6,071,155
 $6,610,877
 $11,773
 $12,693,805
Three months ended June 30, 2016  
  
  
  
Revenues from external customers $648,121
 $69,091
 $(36) $717,176
 $495,349
 $70,749
 $146
 $566,244
Intersegment revenues (eliminations) 6
 —
 (6) —
 46
 —
 (46) —
Revenues 648,127
 69,091
 (42) 717,176
 $495,395
 $70,749
 $100
 $566,244
Income (loss) before income taxes 68,894
 20,802
 (9,036) 80,660
 $58,340
 $20,224
 $(7,653) $70,911
Income taxes (benefit) 25,390
 7,351
 (3,225) 29,516
 21,984
 6,939
 (2,613) 26,310
Net income (loss) 43,504
 13,451
 (5,811) 51,144
 36,356
 13,285
 (5,040) 44,601
Preferred stock dividends of subsidiaries 498
 —
 (27) 471
 499
 —
 (26) 473
Net income (loss) for common stock 43,006
 13,451
 (5,784) 50,673
 $35,857
 $13,285
 $(5,014) $44,128
Nine months ended September 30, 2015  
  
  
  
Six months ended June 30, 2016  
  
  
  
Revenues from external customers $1,779,708
 $199,222
 $20
 $1,978,950
 $977,394
 $139,589
 $221
 $1,117,204
Intersegment revenues (eliminations) 24
 —
 (24) —
 53
 —
 (53) —
Revenues 1,779,732
 199,222
 (4) 1,978,950
 $977,447
 $139,589
 $168
 $1,117,204
Income (loss) before income taxes 164,568
 61,159
 (36,347) 189,380
 $98,759
 $39,818
 $(16,540) $122,037
Income taxes (benefit) 60,351
 21,382
 (11,327) 70,406
 36,537
 13,860
 (5,786) 44,611
Net income (loss) 104,217
 39,777
 (25,020) 118,974
 62,222
 25,958
 (10,754) 77,426
Preferred stock dividends of subsidiaries 1,496
 —
 (79) 1,417
 998
 —
 (52) 946
Net income (loss) for common stock 102,721
 39,777
 (24,941) 117,557
 $61,224
 $25,958
 $(10,702) $76,480
Total assets (at December 31, 2015)* 5,672,210
 6,014,755
 95,053
 11,782,018
Total assets (at December 31, 2016) $5,975,428
 $6,421,357
 $28,721
 $12,425,506
 
* See Note 11 for the impact to prior period financial information of the adoption of Accounting Standards Update (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.


43 · Electric utility segment
Revenue taxes. The Utilities’ revenues include amounts for the recovery of various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, the Utilities’ revenue tax payments to the taxing authorities in the period 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). The Utilities included in the thirdsecond quarters of 2017 and 2016 and 2015 and ninesix months ended SeptemberJune 30, 2017 and 2016 and 2015 approximately $51$50 million, $58$44 million, $13896 million and $15987 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.
Recent tax developments. On December 18, 2015, Congress passed, and President Obama signed into law,expense, in the “Protecting Americans from Tax Hikes (PATH) Actunaudited condensed consolidated statements of 2015” and the “Consolidating Appropriations Act, 2016,” providing government funding and a number of significant tax changes.income.
The provision with the greatest impact on the Company is the extension of bonus depreciation. The PATH Act continues 50% bonus depreciation through 2017 and phases down the percentage to 40% in 2018 and 30% in 2019 and then terminates bonus depreciation thereafter. The extension of bonus depreciation resulted in an increase in 2015 tax depreciation of $123 million. 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.
Unconsolidated variable interest entities.

HECO Capital Trust III.  HECO Capital Trust III (Trust III) 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. 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 sheets as of SeptemberJune 30, 20162017 and December 31, 20152016 each 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 statements for the ninesix months ended SeptemberJune 30, 2016 and 2015 each2017 consisted of $2.5$1.7 million of interest income received from the 2004 Debentures; $2.4$1.6 million of distributions to holders of the Trust Preferred Securities; and $75,000$50,000 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 SeptemberJune 30, 20162017, the Utilities had five PPAspower purchase agreements (PPAs) for firm capacity and other PPAs with IPPsindependent power producers (IPPs) and Schedule Q providers (e.g., 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. Purchases from all IPPs were as follows:


  Three months ended September 30 Nine months ended September 30
(in millions) 2016 2015 2016 2015
AES Hawaii $38
 $37
 $112
 $97
Kalaeloa 44
 51
 109
 143
HEP 8
 13
 23
 34
Hpower 19
 18
 52
 50
Puna Geothermal Venture 7
 8
 19
 22
Hawaiian Commercial & Sugar (HC&S) 1
 2
 1
 7
Other IPPs 41
 32
 97
 93
Total IPPs $158
 $161
 $413
 $446
In October 2015 the amended PPA between Maui Electric and HC&S became effective following PUC approval in September 2015. The amended PPA amends the pricing structure and rates for energy sold to Maui Electric, eliminates the capacity payment to HC&S, eliminates Maui Electric’s minimum purchase obligation, provides 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 extends the term of the PPA from 2014 to 2017. In 2016 HC&S requested to terminate the PPA in January of 2017, approximately 1 year early due to HC&S ceasing sugar operations.
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 other IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2015,2016, 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 Partners, L.P. (Kalaeloa) later agreed to provide the information pursuant to the amendments to its PPA (see below). During the negotiations of an amendment to the PPA with AES Hawaii, Inc. (AES Hawaii), management determined that Hawaiian Electric was not the primary beneficiary of AES Hawaii under the existing PPA and an entity owning a wind farm provided information asconsolidation was not required under its PPA.(see below). 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.unaudited condensed consolidated financial statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements,unaudited condensed 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.
Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in Kalaeloa and AES Hawaii by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa and AES Hawaii, respectively. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa or AES Hawaii because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s and AES Hawaii’s economic performance nor the obligation to absorb Kalaeloa’s or AES Hawaii’s expected losses, if any, that could potentially be significant to Kalaeloa or AES Hawaii. Thus, Hawaiian Electric has not consolidated Kalaeloa or AES Hawaii in its unaudited condensed consolidated financial statements.
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.  As of June 30, 2017, purchases from all IPPs were as follows:
  Three months ended June 30 Six months ended June 30
(in millions) 2017 2016 2017 2016
Kalaeloa $48
 $36
 $88
 $65
AES Hawaii 35
 36
 64
 74
HPOWER 16
 17
 33
 33
Puna Geothermal Venture 10
 5
 18
 12
HEP 10
 4
 17
 15
Other IPPs 1
 34
 41
 60
 56
Total IPPs $153
 $139
 $280
 $255
1
Includes wind power, solar power, feed-in tariff projects and other PPAs.
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 megawatts (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.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. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the Kalaeloa PPA prior to October 31, 2017. 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 September 30, 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 has been requested. If approved by the PUC, Amendment No. 3 would increase 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. If Amendment No. 3 is approved by the PUC, payments for energy associated with firm capacity in excess of 180 MW will be at fixed rates not subject to adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to AES Hawaii are fixed in accordance with the PPA and, if approved by the PUC, Amendment No. 3.
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 September 30, 2016, Hawaiian Electric’s accounts payable to AES Hawaii amounted to $13 million.
Commitments and contingencies.
Fuel contracts.The Utilities have contractual agreements to purchase minimum quantities of fuel oil, 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 prices are tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest.
Hawaiian Electric and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to the Low Sulfur Fuel Oil Supply Contract (LSFO Contract) for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on December 31, 2016. The LSFO Contract will be replaced by a new contract with Chevron for LSFO and diesel fuel to meet MATS requirements for the island of Oahu that begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party.
The Utilities are also parties to amended Inter-Island contracts for the supplies of industrial fuel oil and diesel fuels with Chevron and Par Hawaii Refining, LLC (PAR) (formerly known as Hawaii Independent Energy, LLC), respectively, which terminate on December 31, 2016. The Inter-Island contracts will be replaced by a new Inter-Island contract with Chevron for industrial fuel oil, diesel and ultra-low sulfur diesel for the islands of Oahu, Hawaii, Maui and Molokai, which begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party.
Hawaii Electric Light and Chevron are also parties to a terminalling agreement for the island of Hawaii, which begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Currently, terminalling services are provided to Hawaii Electric Light under the Inter-island Fuel Supply Contract with Chevron that expires on December 31, 2016.
The PUC has approved all of the foregoing contracts (LSFO, Inter-Island and Terminalling) and the costs incurred under these contracts are included in the Utilities’ respective ECACs, to the extent such costs are not recovered through the base rates.
The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under Hawaiian Electric’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays PAR (formerly known as Hawaii Independent Energy, LLC) for LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The term of the fuel contract between Kalaeloa and PAR ended on May 31, 2016 and is being extended until terminated by one of the parties.


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 an agreement on anthe 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 includesincluded certain conditions precedent which, if satisfied, will releasewould have released the parties from the claims under the arbitration proceeding. Among the conditions precedent iswas the successful negotiation and PUC approval of an amendment to the existing purchase power agreement and PUC approval of such amendment.PPA.
On

In November 13, 2015, Hawaiian Electric entered into Amendment No. 3 to the AES Hawaii PPA, subject tofor which PUC approval.approval was requested and subsequently denied in January 2017. Approval of Amendment No. 3 provides more favorable pricing for the additional 9 MW than the existing pricing, the benefit of which will be passed on to customers, and among other things, provides (1) for an increase in firm capacity of up to 9 MW (the Additional Capacity) above the 180 MW capacity of the AES Hawaii facility, subject to a demonstration of such increased available capacity, (2) for the payment for the Additional Capacity to include a Priority Peak Capacity Charge, a Non-Peak Capacity Charge, a Priority Peak Energy Charge and a Non-Peak Energy Charge and (3) that AES will make certain operational commitments to improve reliability, and Hawaiian Electric will pay a reliability bonus according to a schedule for reduced Full Plant Trips. On January 22, 2016, Amendment No. 3 was filed with the PUC for approval. If such approval is obtained,would have satisfied the final condition tofor effectiveness of the Settlement Agreement’s releaseAgreement and resolved AES Hawaii's claims. Following the PUC's decision, the parties agreed to extend the stay of the parties from the arbitration claims will be satisfied. The arbitration proceeding, has been stayed to allowwhile settlement discussions continue.
Hu Honua Bioenergy, LLC. In May 2012, Hawaii Electric Light signed a PPA, which the PUC approval proceeding to proceed.
Liquefied natural gas. On May 18, 2016, Hawaiian Electric and Fortis Hawaii Energy Inc. (Fortis Hawaii), an affiliateapproved in December 2013, with Hu Honua Bioenergy, LLC (Hu Honua) for 21.5 MW of Fortis, Inc. (Fortis), entered intorenewable, dispatchable firm capacity fueled by locally grown biomass from a Fuel Supply Agreement (FSA) whereby Fortis Hawaii intended to sell to Hawaiian Electric liquefied natural gas (LNG) to be produced fromfacility on 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 transportationisland 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 toHawaii. Per the terms of the Merger Agreement, NEEPPA, the Hu Honua plant was scheduled to be in service in 2016. However, Hu Honua encountered construction delays, failed to meet its 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 Merger Agreement. Accordingly,PPA on July 19,March 1, 2016. On November 30, 2016, HawaiianHu Honua filed a civil complaint in the United States District Court for the District of Hawaii that included claims purportedly arising out of the termination of Hu Honua’s PPA. On May 26, 2017, Hawaii Electric provided notice ofLight and Hu Honua entered into a settlement agreement that will settle all claims related to the termination of the FSA to Fortis Hawaii, effective immediately, and withdreworiginal PPA. The settlement agreement was contingent on the application for PUCPUC’s approval of the FSA, which included a request for approval to commit approximately $341 million to convert existing generating units to use natural gas,an amended and to commit approximately $117 million for containers to support LNG.restated PPA between Hawaii Electric Light and Hu Honua dated May 5, 2017. In addition, on July 19, 2016, Hawaiian Electric withdrew its applications to2017, the PUC for a waiver fromapproved the competitive bidding processamended and restated PPA. Hu Honua is expected to allow Hawaiian Electric to construct a modern, efficient, combined cycle generation system atbe on-line by 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.end of 2018.
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.
Renewable energy project matters.  In February 2012, the PUC granted Hawaiian Electric’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million. Through December 31, 2013, Hawaiian Electric deferred $3.1 million related to outside contractor service costs incurred with the Oahu 200 MW RFP, and began amortizing such costs over 3 years beginning in July 2014.
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 conclusion 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.
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 projectImplementation 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 replacedenied the Utilities’ existing ERP/EAM system, (2) denyingrequest of the Utilities request to defer the costs forof 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 softwarethese costs of $4.8 millionwere written off 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 approvingapproved the Utilities’ request to commence the ERP/EAM implementation project,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. 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%. Pursuant to the D&O and subsequent orders, the Utilities will beare required to file: the proposed methods of passing on to customers the estimated monetary savings attributable to the project by November 7, 2016;file 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.
On March 31, 2017, the Utilities filed their proposed methods of passing on to customers the estimated monetary savings attributable to the project. These proposed methods continue to be reviewed by the PUC and Consumer Advocate. The ERP/EAM Implementation Project is on schedule. The project starting Februaryis expected to go live by October 1, 2018. As of June 30, 2017, the Project incurred costs of $14.0 million of which $2.5 million were charged to other operation and maintenance (O&M) expense, $1.1 million relate to capital costs and $10.4 million are deferred costs.
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 agreementcontracts, 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. The generating station2016, and the facility is expected to be placed in service in the firstsecond quarter of 2018. Project costs incurred as of June 30, 2017 amounted to $87.8 million. The project costs have been included for recovery in the 2017 test year rate case.
West Loch PV Project. In July 2016, Hawaiian Electric announced plans to build, own and operate a utility-owned, grid-tied 20-MW (ac) solar facility in conjunction with the Department of the Navy at a Navy/Air Force joint base. In June 2017, the PUC approved the expenditure of funds for the project, including Hawaiian Electric’s proposed project cost cap of $67 million and a performance guarantee to provide energy at 9.56 cents/KWH or less. Project costs incurred as of June 30, 2017 amounted to $0.4 million.


In approving the project, the PUC agreed the project is eligible for recovery of costs offset by related net benefits under the Major Project Interim Recovery (MPIR) guidelines (see “Decoupling” section below for MPIR guidelines). The PUC established a procedural schedule for Hawaiian Electric to provide supplemental materials to support meeting the MPIR guidelines for recovery of costs accompanied by system performance guarantee and cost savings sharing mechanisms and for the Consumer Advocate to review and comment on the information filed.  This is first instance in which the PUC is considering a request for recovery pursuant to the MPIR Guidelines.
Hamakua Energy Partners, L.P. (HEP) Asset Purchase Agreement.Agreement. Hawaii Electric Light has been purchasing up to 60 MW (net) of firm capacity from HEP under a power purchase agreement (PPA)PPA that expires on December 30, 2030. The HEP plant currently contributes about 23% of the island of Hawaii’s generating capacity. OnIn 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 byOn May 4, 2017, the PUC denied Hawaii Electric Light’s application for approval of the agreementAsset Purchase Agreement (APA) on the grounds that customer benefits were not sufficiently demonstrated to justify the purchase the existing HEP generating assets will terminate the existing PPA. The elimination of certain required capacity payments under the PPA is expected to resultand in lower costs to customers. Additionally, by owning the plant,July 2017, Hawaii Electric Light willand HEP terminated the APA.
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 ableshared 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 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 manage HEP’s efficient generating units more productively, providing greater flexibility to cycle HEP’s generating units to more effectively managecollect the Hawaii island grid. This increased operational flexibility will be essential to support and facilitateunpaid amounts from Hawaiian Telcom as specified by the joint pole agreement. For Hawaii Electric Light’s efforts to integrate more renewable energy ontoLight, the grid.
An application to approve the project has beenagreement does not specify an alternative dispute resolution process, and thus a complaint for payment was filed with the PUC.Circuit Court in June 2016. Maui Electric has not yet commenced any legal action to recover the delinquent amounts. As of June 30, 2017, total receivables under the joint pole agreement, including interest, from Hawaiian Telcom are $22.1 million ($14.8 million at Hawaiian Electric, $6.0 million at Hawaii Electric Light, and $1.3 million at Maui Electric). Management expects to prevail on these claims but has reserved for the accrued interest of $4.9 million on the receivables.
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 and management anticipates that such activity will continue.
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 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 permit. In the case of Hawaiian Electric’s power plants, there are a number of studies that have yet to 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.
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.
On April 16, 2012, Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay (Petition) that asked the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. On April 21, 2015, the EPA denied Hawaiian Electric's Petition and Hawaiian Electric subsequently filed a lawsuit on June 29, 2015 appealing the EPA’s denial. On April 4, 2016, the D.C. Circuit Court of Appeals granted Hawaiian Electric’s uncontested motion to dismiss the case. Hawaiian Electric has proceeded with the implementation of the MATS Compliance Plan and has met all compliance requirements to date including the April 16, 2016 compliance date. Hawaiian Electric submitted a formal compliance demonstration report to the EPA and DOH on September 23, 2016.
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.
Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric (the Utilities) 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 EPAEnvironmental Protection Agency (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 DOHHawaii Department of Health (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$3.5 million as of SeptemberJune 30, 2016 for2017, representing the probable and reasonably estimated cost to complete 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 SeptemberJune 30, 2016,2017, the reserve account balance recorded by Hawaiian Electric to address the PCB contamination was $4.4$4.9 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 (AES), Hawaiian Electric plans to include the AES facility on Oahu as a partner 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 is working with the DOH on the timing of the EmRP modifications to address these changes in the partnership.
On September 22, 2009, the EPA issued its “Final Mandatory Reporting of Greenhouse Gases Rule,” which requires certain sources that emit GHGs to report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 2015 to the EPA.
The EPA issued the final federal rule for GHG emissions limits for new and existing EGUs, also known as the Clean Power Plan, on August 3, 2015. The Clean Power Plan set interim state-wide emissions limits for EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029, with final limits in effect starting in 2030. The final Clean Power Plan did not set forth guidelines for Alaska, Hawaii, Puerto Rico or Guam, because the EPA did not have enough information to include them at the time the Rule was published. Subsequently, on February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending resolution of several petitions for review in the U.S. Court of Appeals for the D.C. Circuit Court.
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.  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 2016.
Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
  Nine months ended September 30
(in thousands) 2016 2015
Balance, beginning of period $26,848
 $29,419
Accretion expense 10
 18
Liabilities incurred —
 —
Liabilities settled (661) (2,349)
Revisions in estimated cash flows —
 —
Balance, end of period $26,197
 $27,088
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 other operation and maintenance (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 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 return on average common equity (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 will again apply to Hawaiian Electric. On November 1, 2016, Hawaiian Electric filed a motion requesting the current accrual method for the RAM that is in place through the end of 2016, be made permanent. If approved, Hawaiian Electric’s ROACE for 2017 would be 75 basis points better than not getting the request approved. Hawaiian Electric’s request is based on a number of factors including changed circumstances since the PUC’s decision on the RAM revenues in 2011, the original intent of decoupling, and consistency with accrual accounting. The filing also requests the implementation of Hawaiian Electric’s current accrual method for RAM revenues for Hawaii Electric Light and Maui Electric beginning in 2017. The Utilities requested a PUC decision by December 31, 2016 but no later than the end of January 2017 and cannot predict the outcome of the request.


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:
An adjustment to the Rate Base RAM Adjustment to include 90% of the amount of the current RAM Period Rate Base RAM Adjustment that exceeds the Rate Base RAM Adjustment from the prior year, to be 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.
As required, the Utilities have made available to the public, on the Utilities’ websites, performance metrics identified by the PUC. The Utilities are updating the performance metrics on a quarterly basis.
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. On October 26, 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. On October 30, 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 30, 2015 application. Maui Electric determined that the application is 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. On April 18, 2016, Hawaiian Electric modified its October 26, 2015 application to reduce its request to recover revenue requirements associated with 2015 net plant additions from $40.3 million to $35.7 million for the same reason as Maui Electric regarding the extension of bonus depreciation in 2015. On August 3, 2016, the PUC dismissed Hawaiian Electric’s October 26, 2015 Above the RAM Cap application because the application did not also request approval of the commitment of capital expenditures.
On August 25, 2016, Maui Electric filed an application to recover the revenue requirements associated with 2017 plant additions for substations in the total amount of $27.2 million and other associated costs through the RAM above the 2017 RAM Cap.
Annual decoupling filings.  On March 31, 2016, the Utilities submitted to the PUC their annual decoupling filings for tariffed rates that will be effective from June 1, 2016 through May 31, 2017. On May 19, 2016, Hawaii Electric Light amended its annual decoupling filing to update and revise certain cost information. The tariffed rates include: (1) 2016 RAM Revenue Adjustment as determined by the March Order, (2) accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2015 (and associated revenue taxes) to be collected:
($ in millions) Hawaiian Electric Hawaii Electric Light Maui Electric
Annual incremental RAM adjusted revenues $11.0
 $2.3
 $2.4
Annual change in accrued earnings sharing credits $—
 $—
 $0.5
Annual change in accrued RBA balance as of December 31, 2015 (and associated revenue taxes) $(13.6) $(2.5) $(4.3)
Net annual incremental decrease in amount to be collected under the tariffs $(2.6) $(0.2) $(1.4)
Impact on typical residential customer monthly bill (in dollars) * $0.01
 $0.13
 $(0.95)
* Based on a 500 kilowatthour (KWH) bill for Hawaiian Electric, Maui Electric and Hawaii Electric Light. The bill impact for Lanai and Molokai customers is a decrease of $0.76, based on a 400 KWH bill. Although Hawaiian Electric and Hawaii Electric Light have a net annual incremental decrease in amount to be collected under the tariffs, their bills will increase by $0.01 and $0.13, respectively, due to lower anticipated KWH sales.
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.
Potential impact of lava flows. In June 2014, lava from the Kilauea Volcano on the island of Hawaii began flowing toward the town of Pahoa. Hawaii Electric Light monitored utility property and equipment near the affected areas and protected that property and equipment to the extent possible (e.g., building barriers around poles). In March 2015 Hawaii Electric Light filed an application with the PUC requesting approval to defer costs incurred to monitor, prepare for, respond to, and take other actions necessary in connection with the June 2014 Kilauea lava flow such that Hawaii Electric Light can request PUC approval to recover those costs in a future rate case. The Consumer Advocate objected to the request. A PUC decision is pending.
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.


For Hawaiian Electric, 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 September 30, 2016, total receivables under the joint pole agreement, including interest, from Hawaiian Telcom are $20.1 million ($13.7 million at Hawaiian Electric, $5.5 million at Hawaii Electric Light, and $0.9 million at Maui Electric). Management has reserved for the accrued interest on the receivables amounting to $3.9 million. Management expects to prevail on their claims and collect at least $16.2 million.Regulatory proceedings
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 within 120 days itstheir respective Power Supply Improvement Plans (PSIPs), and the PSIPs were filedwhich 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’Utilities' business model with customers’ interests and the state’s public policy goals.
Reliability Standards Working Group. The PUC ordered the Utilities (and in some cases the Kauai Island Utility Cooperative) 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:
including a Distributed Generation Interconnection Plan, -which the Utilities’ Plan wasUtilities 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. The PUC has not yet opened new dockets to address the first and third topics above. To address DER, the second topic, the PUC opened an investigative proceeding on August 21, 2014 (see “DER Investigative Proceeding” below).
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. OnIn July 28, 2015, the PUC issued an order appointing a special advisoradviser to guide, monitor and review the Utility’s Plan design and implementation. OnIn 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 through the Demand-Side Management (DSM) Surcharge, and (2) for approval to defer and recover certain computer software and software development costs for a Demand ResponseDR Management System (DRMS) through the Renewable Energy Infrastructure Program (REIP) Surcharge. The Utilities filed an updated DR Portfolio Plan in February 2017. In July 2016,May 2017, the Utilities filed their reply to the statements of position submitted by the other parties and are awaiting a PUC issued an order indecision.
In the DR Portfolio Tariff proceeding. TheManagement System proceeding, the parties filed statements of position in December 2016 and are awaiting a PUC granted intervenor and participant status to certain movants, made some preliminary observations on the proposed grid service tariffs and supporting modeling efforts, and instructed the Utilities to move forward with the development of DR programs for all islands. The PUC plans to conduct one or more technical conferences and ordered the Utilities to develop an implementation timeline and procedural schedule to enable an end-of-year implementation.decision.
Review of PSIPs. Collectively, the PUC’sPUC's April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities’Utilities' strategies and plans going forward.
In August 2014, the Utilities filed proposed PSIPs for Hawaiian Electric, Maui Electric and Hawaii Electric Lightwith the PUC, as required by the PUC orders issued in April 2014. Updated PSIPs were filed in August 2014.April 2016, pursuant to an order issued by the PUC in November 2015 which included the PUC’s observations and concerns, and comments provided by parties and participants. The Updated PSIPs each includeprovided plans to achieve 100% renewable energy using 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 diversifieddiverse 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 2030.2045. 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 and offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil. In December 2016, 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 lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generatorsreliably integrate an estimated total of 165,000 private systems by 2030, more than double today’s total of 79,000, and lower full service residential customer bills in real dollars.additional grid-scale renewable energy resources.
In November 2015,On July 14, 2017, the PUC issued an order inaccepted the proceeding to reviewUtilities’ PSIP December 2016 Update Report and closed the PSIPs filed. The order provided observations and concerns on the PSIPs submitted. As required by theproceeding. In its order, the PUC provided guidance regarding the implementation of the Utilities’ near-term action plan and future planning activities, requiring the Utilities submittedto file a Proposed Revision Plan in November 2015, which included areport that details an updated resource planning approach and schedule and a work planby March 1, 2018. The PUC order stated that it intends to supplement, amend and updateuse the PSIPs in order to address the PUC’s observationsconjunction with its evaluation of specific filings for approval of capital 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.
In August 2016, the PUC issued an order establishing a procedural schedule to address the Utilities’ April 1, 2016 PSIP updates, which was further modified in an order issued in October 2016. The utilities are required to file an updated PSIP incorporating input from the Parties, develop alternative scenarios and sensitivity analyses and perform iterations on modeling and simulations by December 23, 2016. The final steps in the procedural schedule are for the parties’ submission of their respective statements of position in February 2017. The Utilities will continue to evaluate all options to achieving the state’s 100% renewable energy goal, to stabilize and reduce customer rates and to maintain safe and reliable service.other projects.
Distributed Energy Resources (DER) Investigative ProceedingDER investigative proceedin.g. 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 tocapped the Utilities’ systems. These tariffs replace theUtilities Net Energy Metering (NEM) program.
programs at “existing” levels (i.e., for existing NEM customers and customers who already applied and were waiting for approval), closed their NEM programs to new participants, and approved new options for customers to interconnect DER to their electric grids, including Self Supply and Grid Supply tariff options.  The D&O orderedPUC placed caps on the Utilities, among other things, (a) to collaborate with inverter manufacturers to develop a test plan by December 15, 2015availability of the Grid Supply program.  The Self Supply Program is designed for the highest priority advanced inverter functions that arecustomers who do not UL certified and (b) to complete the circuit-level hosting capacity analysis for all islands in the Utilities’ service territories by December 10, 2015. The DER Phase 2 of this docket began in November 2015 and focused on further developing competitive markets for distributed energy resources, including storage.
On October 21, 2015, The Alliance for Solar Choice, LLC (TASC) filed a complaint in Hawaii state court seeking an order enjoining the PUC from implementing the D&O and declaring that the D&O be reversed, modified and/or remandedexport to the PUC for further proceedings. On January 19, 2016, the Circuit Court entered a final judgment against TASC on all of its claims. TASC has filed a notice of appeal from the final judgment. TASC also filed a second appeal of the D&O directly with the Intermediate Court of Appeals. On April 20, 2016, the Intermediate Court of Appeals approved stipulations to dismiss both appeals with prejudice.grid.
OnIn June 15, 2016, the PUC issued an order approvingapproved the Utilities’Utilities Advanced Inverter Test Plan with, among other conditions, a requirement to supplement the Test Plan to include testing procedures. In addition, the PUC orderedand the Utilities to submitsubmitted the results of the testing described into the Test Plan by December 15, 2016.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 October 3,December 9, 2016, the PUC issued an Order, which, in part, granted five additional motions to intervene and establishes a preliminaryorder, establishing the statement of issues forand 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.
Pursuant to PUC order, in January and February 2017, the Utilities and various DER parties submitted tariff proposals and stipulations to modify existing interim DER option and proposals, and interconnection standards to facilitate or enable interim DER options, as well as provided comments and reply comments on such tariff proposals.
In May 2017, the PUC issued a D&O that approved the parties’ stipulations filed in January and February 2017.  This D&O also instructed the development of smart export proposals and Customer Self-Supply revisions, directed working groups to collaborate to discuss Phase 2 issues, and modified the procedural schedule.  In compliance with the D&O, the Utilities are meeting regularly with the DER parties in various working groups, and preparing for the next upcoming filing on technical track issues on August 7, 2017.


Derivative financial instrument.Decoupling On January 5,.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. 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 return on average common equity (ROACE) allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments.
For the RAM years 2014 - 2016, Hawaiian Electric executed a window forward agreementwas allowed to hedgerecord RAM revenue beginning on January 1 and to bill such amounts from June 1 of the foreign currency risk associated withapplicable year through May 31 of the anticipated purchasefollowing year (current accrual method). Subsequent to 2016, Hawaiian Electric reverted to the RAM provisions initially approved in March 2011—i.e., RAM is both accrued and billed from June 1 of engines from a European manufacturereach year through May 31 of the following year.
2015 decoupling order. On March 31, 2015, the PUC issued an Order (the 2015 Decoupling Order) that modified the RAM portion of the decoupling mechanism to be included as partcapped at the lesser of the SchofieldRAM revenue adjustment as then determined (based on an inflationary adjustment for certain O&M expenses and return on investment for certain rate base changes) and a RAM revenue adjustment calculated based on the cumulative annual compounded increase in Gross Domestic Product Price Index applied to annualized target revenues (the RAM Cap). The 2015 Decoupling Order provided a specific basis for calculating the target revenues until the next rate case, at which time the target revenues will reset. The triennial rate case cycle required under the decoupling mechanism continues to serve as the maximum period between the filing of general rate cases.
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, 2016 and 2017.
Maui Electric's RAM revenues were limited to the RAM Cap in 2015 and 2016; however, the 2017 RAM revenues were below the RAM Cap.
Hawaii Electric Light’s RAM revenues were below the RAM Cap in 2015, 2016 and 2017.
2017 decoupling order. On April 27, 2017, the PUC issued an Order (the 2017 Decoupling Order) that requires the establishment of specific performance incentive mechanisms and provides guidelines for interim recovery of revenues to support major projects placed in service between general rate cases.
On May 30, 2017, the Utilities filed their proposed initial tariffs to implement conventional stand-alone performance incentive mechanisms. The performance incentive mechanisms to be established are:
Service reliability performance standards to include: 1) System Average Interruption Duration Index based on the average customer interruption time and 2) System Average Interruption Frequency Index based on the average number of customer interruptions. Target performance for each is based on each utilities’ historical 10 year average performance with a dead band of one standard deviation. The maximum penalty for each is 20 basis points applied to the common equity share of the rate base approved in the last rate case for each company. However, the maximum penalty for the initial implementation of the approved PIMs would be the 20 basis points applied to the common equity share of rate base used to determine the 2016 RAM Revenue Adjustment (or approximately $3 million for each of the standards in total for the three utilities). The maximum penalty will be updated upon issuance of an interim or final order in a rate case for each company and will remain constant in interim periods. These performance standards have penalties only.
Call Center Performance based on utility call center 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 dead band of 3% above and below the target. The maximum penalty or incentive is 8 basis points applied to the common equity share of the rate base approved in the last rate case for each company, except for the initial implementation which will be 8 basis points applied to the common equity share of rate base used to determine the 2016 RAM Revenue Adjustment (or approximately $1.2 million penalty or incentive in total for the three utilities).
The 2017 Decoupling Order also established guidelines for MPIR. 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 net costs of approved 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 shall 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.


In the 2017 Decoupling Order, the PUC indicated that in pending and subsequent rate cases, the PUC intends to require all fuel expenses and purchased energy expenses be recovered through an appropriately modified energy cost adjustment mechanism rather than through base rates, and will consider adopting processes to periodically reset fuel efficiency measures embedded in the energy cost adjustment mechanism to account for changes in the generating station. This window forward agreement has been designatedsystem.
Annual decoupling filings. On March 31, 2017, the Utilities submitted to the PUC, their annual decoupling filings for tariffed rates that will be effective from June 1, 2017, through May 31, 2018. On May 22, 2017, Maui Electric amended its annual decoupling filing to update and revise certain cost information. The net annual incremental amounts proposed to be collected (refunded), as a cash flow hedge under which a single guaranteed exchange rate agreed uponrevised for Maui Electric, were as follows:
($ in millions) Hawaiian Electric Hawaii Electric Light Maui Electric
2017 Annual incremental RAM adjusted revenues $12.7
 $3.2
 $1.6
Annual change in accrued earnings sharing credits $—
 $—
 $—
Annual change in accrued RBA balance as of December 31, 2016 (and associated revenue taxes) (refunded) $(2.4) $(2.5) $(0.2)
Net annual incremental amount to be collected under the tariffs $10.3
 $0.7
 $1.4
Impact on typical residential customer monthly bill (in dollars) * $0.60
 $0.15
 $0.79
* Based on a certain date500 kilowatthour (KWH) bill 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,”Hawaiian Electric, Maui Electric, and unrealized losses are recorded at fair value as liabilities in “other current liabilities,” bothHawaii Electric Light. The bill impact 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 stationLanai and Molokai customers is expected to be placed in servicean increase of $0.63, based on a 400 KWH bill.
On May 31, 2017, the PUC approved the annual decoupling filings for Hawaiian Electric and Hawaii Electric Light, and as amended on May 22, 2017, for Maui Electric, which went into effect on June 1, 2017.
Hawaiian Electric consolidated 2014 test year abbreviated and 2017 test year rate cases. On December 23, 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 in the first quarterdecoupling order 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 of the PUC’s order. On March 14, 2017, the PUC issued an order to address Hawaiian Electric’s motion, stating that the PUC is not initiating an investigation/enforcement proceeding against Hawaiian Electric regarding its compliance with the decoupling order, and the transfer and consolidation of Hawaiian Electric’s 2014 abbreviated rate case with the 2017 rate case is intended to ensure that ratepayers receive the attendant benefits of Hawaiian Electric’s decision to voluntarily forgo a general rate increase in base rates for its mandated 2014 test year. As directed, on April 12, 2017, Hawaiian Electric filed a supplement to its 2017 rate case filing, addressing the items raised in the order and explaining why Hawaiian Electric’s forgoing of a general rate increase in the 2014 test year should not result in any further adjustments to Hawaiian Electric’s revenue requirement in the 2017 test year.
On April 26, 2017, the PUC issued an Order regarding the supplement to Hawaiian Electric’s 2017 rate case filing, requesting updated pension and OPEB regulatory asset and liability schedules, by May 12, 2017, to reflect the use of the 2014 net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) for the pension and OPEB tracking mechanisms and with amortization of such regulatory assets and liabilities beginning May 1, 2015. On May 12, 2017, Hawaiian Electric filed these schedules and on May 31, 2017, supplemented its May 12, 2017 filing to show the cumulative impact of the 2015-2017 change in employee benefits transferred to capital as a result of the change in the amortization of the pension and OPEB regulatory assets and liabilities.
On June 28, 2017, the PUC issued an order designating the filing date of Hawaiian Electric’s completed rate case application to be May 31, 2017, rather than December 16, 2016, the date of the filing of Hawaiian Electric’s rate case application. The revised date of the completed application coincided with the date that Hawaiian Electric filed supplemental pension-related information described above. On July 28, 2017, the PUC issued a procedural schedule with an interim D&O tentatively scheduled for December 15, 2017, and an evidentiary hearing in early March 2018.
  September 30, 2016 December 31, 2015
(dollars in thousands) Notional amount Fair value Notional amount Fair value
Window forward contract $20,725
 $664
 $—
 $—
ConsolidatingCondensed consolidating financial information. 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 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 and (c) relating to the trust preferred securities of Trust III. 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.


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
Three months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $404,352
 83,105
 84,831
 —
 (35) $572,253
 $394,414
 81,710
 80,765
 —
 (14) $556,875
Expenses                        
Fuel oil 88,676
 14,603
 25,345
 —
 —
 128,624
 99,814
 14,475
 26,970
 —
 —
 141,259
Purchased power 118,751
 22,728
 16,271
 —
 —
 157,750
 116,458
 23,482
 13,127
 —
 —
 153,067
Other operation and maintenance 64,683
 15,017
 15,089
 —
 —
 94,789
 70,961
 17,558
 17,855
 —
 —
 106,374
Depreciation 31,520
 9,449
 5,790
 —
 —
 46,759
 32,723
 9,686
 5,747
 —
 —
 48,156
Taxes, other than income taxes 38,666
 7,836
 8,017
 —
 —
 54,519
 37,619
 7,702
 7,651
 —
 —
 52,972
Total expenses 342,296
 69,633
 70,512
 —
 —
 482,441
 357,575
 72,903
 71,350
 —
 —
 501,828
Operating income 62,056
 13,472
 14,319
 —
 (35) 89,812
 36,839
 8,807
 9,415
 —
 (14) 55,047
Allowance for equity funds used during construction 1,806
 238
 230
 —
 —
 2,274
 2,659
 134
 234
 —
 —
 3,027
Equity in earnings of subsidiaries 14,729
 —
 —
 —
 (14,729) —
 7,936
 —
 —
 —
 (7,936) —
Interest expense and other charges, net (11,903) (2,972) (2,483) —
 35
 (17,323) (12,562) (2,996) (2,670) —
 14
 (18,214)
Allowance for borrowed funds used during construction 669
 91
 94
 —
 —
 854
 988
 55
 100
 —
 —
 1,143
Income before income taxes 67,357
 10,829
 12,160
 —
 (14,729) 75,617
 35,860
 6,000
 7,079
 —
 (7,936) 41,003
Income taxes 20,113
 3,392
 4,640
 —
 —
 28,145
 9,946
 2,235
 2,679
 —
 —
 14,860
Net income 47,244
 7,437
 7,520
 —
 (14,729) 47,472
 25,914
 3,765
 4,400
 —
 (7,936) 26,143
Preferred stock dividends of subsidiaries —
 133
 95
 —
 —
 228
 —
 133
 96
 —
 —
 229
Net income attributable to Hawaiian Electric 47,244
 7,304
 7,425
 —
 (14,729) 47,244
 25,914
 3,632
 4,304
 —
 (7,936) 25,914
Preferred stock dividends of Hawaiian Electric 270
 —
 —
 —
 —
 270
 270
 —
 —
 —
 —
 270
Net income for common stock $46,974
 7,304
 7,425
 —
 (14,729) $46,974
 $25,644
 3,632
 4,304
 —
 (7,936) $25,644

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
Three months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock $46,974
 7,304
 7,425
 —
 (14,729) $46,974
 $25,644
 3,632
 4,304
 —
 (7,936) $25,644
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
  
  
  
  
  
  
Derivatives qualified as cash flow hedges:                        
Effective portion of foreign currency hedge net unrealized loss, net of tax benefits 321
 —
 —
 —
 —
 321
Less: reclassification adjustment to net income, net of tax benefits (173) —
 —
 —
 —
 (173)
Reclassification adjustment to net income, net of tax benefits —
 —
 —
 —
 —
 —
Retirement benefit plans:  
  
  
  
  
  
  
  
  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 3,314
 429
 387
 —
 (816) 3,314
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (3,311) (429) (389) —
 818
 (3,311)
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 3,621
 449
 344
 —
 (793) 3,621
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (3,581) (448) (343) —
 791
 (3,581)
Other comprehensive income (loss), net of taxes 151
 —
 (2) —
 2
 151
 40
 1
 1
 —
 (2) 40
Comprehensive income attributable to common shareholder $47,125
 7,304
 7,423
 —
 (14,727) $47,125
 $25,684
 3,633
 4,305
 —
 (7,938) $25,684


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
Three months ended SeptemberJune 30, 20152016

(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $463,394
 89,817
 94,941
 —
 (25) $648,127
 $347,010
 73,652
 74,758
 —
 (25) $495,395
Expenses                        
Fuel oil 142,194
 17,208
 36,231
 —
 —
 195,633
 62,234
 11,748
 17,917
 —
 —
 91,899
Purchased power 119,302
 26,713
 14,503
 —
 —
 160,518
 103,062
 19,360
 16,636
 —
 —
 139,058
Other operation and maintenance 69,621
 18,936
 15,096
 —
 —
 103,653
 68,197
 15,116
 16,250
 —
 —
 99,563
Depreciation 29,389
 9,313
 5,654
 —
 —
 44,356
 31,522
 9,449
 5,789
 —
 —
 46,760
Taxes, other than income taxes 43,923
 8,455
 8,932
 —
 —
 61,310
 33,414
 6,905
 7,110
 —
 —
 47,429
Total expenses 404,429
 80,625
 80,416
 —
 —
 565,470
 298,429
 62,578
 63,702
 —
 —
 424,709
Operating income 58,965
 9,192
 14,525
 —
 (25) 82,657
 48,581
 11,074
 11,056
 —
 (25) 70,686
Allowance for equity funds used during construction 1,714
 148
 195
 —
 —
 2,057
 1,559
 206
 232
 —
 —
 1,997
Equity in earnings of subsidiaries 11,858
 —
 —
 —
 (11,858) —
 10,883
 —
 —
 —
 (10,883) —
Interest expense and other charges, net (11,468) (2,674) (2,440) —
 25
 (16,557) (10,345) (2,669) (2,114) —
 25
 (15,103)
Allowance for borrowed funds used during construction 605
 53
 79
 —
 —
 737
 587
 79
 94
 —
 —
 760
Income before income taxes 61,674
 6,719
 12,359
 —
 (11,858) 68,894
 51,265
 8,690
 9,268
 —
 (10,883) 58,340
Income taxes 18,398
 2,397
 4,595
 —
 —
 25,390
 15,138
 3,337
 3,509
 —
 —
 21,984
Net income 43,276
 4,322
 7,764
 —
 (11,858) 43,504
 36,127
 5,353
 5,759
 —
 (10,883) 36,356
Preferred stock dividends of subsidiaries —
 133
 95
 —
 —
 228
 —
 133
 96
 —
 —
 229
Net income attributable to Hawaiian Electric 43,276
 4,189
 7,669
 —
 (11,858) 43,276
 36,127
 5,220
 5,663
 —
 (10,883) 36,127
Preferred stock dividends of Hawaiian Electric 270
 —
 —
 —
 —
 270
 270
 —
 —
 —
 —
 270
Net income for common stock $43,006
 4,189
 7,669
 —
 (11,858) $43,006
 $35,857
 5,220
 5,663
 —
 (10,883) $35,857

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
Three months ended SeptemberJune 30, 20152016
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock
 $43,006
 4,189
 7,669
 —
 (11,858) $43,006
 $35,857
 5,220
 5,663
 —
 (10,883) $35,857
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
  
  
  
  
  
  
Derivatives qualified as cash flow hedges:            
Effective portion of foreign currency hedge net unrealized loss, net of tax benefits (745) —
 —
 —
 —
 (745)
Retirement benefit plans:  
  
  
  
  
  
  
  
  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 5,095
 682
 626
 —
 (1,308) 5,095
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (5,091) (683) (627) —
 1,310
 (5,091)
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 3,391
 401
 357
 —
 (758) 3,391
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (3,401) (402) (359) —
 761
 (3,401)
Other comprehensive income (loss), net of taxes 4
 (1) (1) —
 2
 4
 (755) (1) (2) —
 3
 (755)
Comprehensive income attributable to common shareholder $43,010
 4,188
 7,668
 —
 (11,856) $43,010
 $35,102
 5,219
 5,661
 —
 (10,880) $35,102


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
NineSix months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $1,088,537
 229,940
 231,295
 —
 (72) $1,549,700
 $757,257
 160,692
 157,558
 —
 (21) $1,075,486
Expenses                        
Fuel oil 224,995
 40,725
 68,543
 —
 —
 334,263
 197,815
 31,732
 55,982
 —
 —
 285,529
Purchased power 313,730
 58,885
 40,052
 —
 —
 412,667
 216,605
 42,071
 21,515
 —
 —
 280,191
Other operation and maintenance 202,438
 46,574
 49,248
 —
 —
 298,260
 138,239
 33,074
 35,301
 —
 —
 206,614
Depreciation 94,564
 28,347
 17,389
 —
 —
 140,300
 65,445
 19,371
 11,556
 —
 —
 96,372
Taxes, other than income taxes 104,764
 21,632
 21,990
 —
 —
 148,386
 72,659
 15,152
 14,984
 —
 —
 102,795
Total expenses 940,491
 196,163
 197,222
 —
 —
 1,333,876
 690,763
 141,400
 139,338
 —
 —
 971,501
Operating income 148,046
 33,777
 34,073
 —
 (72) 215,824
 66,494
 19,292
 18,220
 —
 (21) 103,985
Allowance for equity funds used during construction 4,771
 571
 668
 —
 —
 6,010
 4,715
 249
 462
 —
 —
 5,426
Equity in earnings of subsidiaries 33,541
 —
 —
 —
 (33,541) —
 16,539
 —
 —
 —
 (16,539) —
Interest expense and other charges, net (34,113) (8,606) (7,087) —
 72
 (49,734) (24,619) (6,000) (5,120) —
 21
 (35,718)
Allowance for borrowed funds used during construction 1,785
 219
 272
 —
 —
 2,276
 1,737
 100
 195
 —
 —
 2,032
Income before income taxes 154,030
 25,961
 27,926
 —
 (33,541) 174,376
 64,866
 13,641
 13,757
 —
 (16,539) 75,725
Income taxes 45,022
 9,075
 10,585
 —
 —
 64,682
 17,217
 5,158
 5,243
 —
 —
 27,618
Net income 109,008
 16,886
 17,341
 —
 (33,541) 109,694
 47,649
 8,483
 8,514
 —
 (16,539) 48,107
Preferred stock dividends of subsidiaries —
 400
 286
 —
 —
 686
 —
 267
 191
 —
 —
 458
Net income attributable to Hawaiian Electric 109,008
 16,486
 17,055
 —
 (33,541) 109,008
 47,649
 8,216
 8,323
 —
 (16,539) 47,649
Preferred stock dividends of Hawaiian Electric 810
 —
 —
 —
 —
 810
 540
 —
 —
 —
 —
 540
Net income for common stock $108,198
 16,486
 17,055
 —
 (33,541) $108,198
 $47,109
 8,216
 8,323
 —
 (16,539) $47,109

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
NineSix months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock $108,198
 16,486
 17,055
 —
 (33,541) $108,198
 $47,109
 8,216
 8,323
 —
 (16,539) $47,109
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
  
  
  
  
  
  
Derivatives qualified as cash flow hedges:            
Effective portion of foreign currency hedge net unrealized gain, net of taxes 578
 —
 —
 —
 —
 578
Less: reclassification adjustment to net income, net of tax benefits (173) —
 —
 —
 —
 (173)
Derivatives qualifying as cash flow hedges:            
Reclassification adjustment to net income, net of tax benefits 454
 —
 —
 —
 —
 454
Retirement benefit plans:  
  
  
  
  
  
  
  
  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 9,941
 1,288
 1,162
 —
 (2,450) 9,941
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (9,934) (1,289) (1,166) —
 2,455
 (9,934)
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 7,239
 952
 810
 —
 (1,762) 7,239
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (7,194) (951) (810) —
 1,761
 (7,194)
Other comprehensive income (loss), net of taxes 412
 (1) (4) —
 5
 412
 499
 1
 —
 —
 (1) 499
Comprehensive income attributable to common shareholder $108,610
 16,485
 17,051
 —
 (33,536) $108,610
 $47,608
 8,217
 8,323
 —
 (16,540) $47,608


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
NineSix months ended SeptemberJune 30, 20152016

(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $1,254,142
 261,604
 264,057
 —
 (71) $1,779,732
 $684,185
 146,835
 146,464
 —
 (37) $977,447
Expenses                        
Fuel oil 364,875
 56,834
 96,961
 —
 —
 518,670
 136,319
 26,122
 43,198
 —
 —
 205,639
Purchased power 329,922
 73,161
 42,726
 —
 —
 445,809
 194,979
 36,157
 23,781
 —
 —
 254,917
Other operation and maintenance 206,133
 51,493
 48,893
 —
 —
 306,519
 137,755
 31,557
 34,159
 —
 —
 203,471
Depreciation 88,167
 27,938
 16,735
 —
 —
 132,840
 63,044
 18,898
 11,599
 —
 —
 93,541
Taxes, other than income taxes 119,603
 24,783
 25,054
 —
 —
 169,440
 66,098
 13,796
 13,973
 —
 —
 93,867
Total expenses 1,108,700
 234,209
 230,369
 —
 —
 1,573,278
 598,195
 126,530
 126,710
 —
 —
 851,435
Operating income 145,442
 27,395
 33,688
 —
 (71) 206,454
 85,990
 20,305
 19,754
 —
 (37) 126,012
Allowance for equity funds used during construction 4,418
 458
 490
 —
 —
 5,366
 2,965
 333
 438
 —
 —
 3,736
Equity in earnings of subsidiaries 29,174
 —
 —
 —
 (29,174) —
 18,812
 —
 —
 —
 (18,812) —
Interest expense and other charges, net (33,996) (7,946) (7,299) —
 71
 (49,170) (22,210) (5,634) (4,604) —
 37
 (32,411)
Allowance for borrowed funds used during construction 1,557
 164
 197
 —
 —
 1,918
 1,116
 128
 178
 —
 —
 1,422
Income before income taxes 146,595
 20,071
 27,076
 —
 (29,174) 164,568
 86,673
 15,132
 15,766
 —
 (18,812) 98,759
Income taxes 43,064
 7,210
 10,077
 —
 —
 60,351
 24,909
 5,683
 5,945
 —
 —
 36,537
Net income 103,531
 12,861
 16,999
 —
 (29,174) 104,217
 61,764
 9,449
 9,821
 —
 (18,812) 62,222
Preferred stock dividends of subsidiaries —
 400
 286
 —
 —
 686
 —
 267
 191
 —
 —
 458
Net income attributable to Hawaiian Electric 103,531
 12,461
 16,713
 —
 (29,174) 103,531
 61,764
 9,182
 9,630
 —
 (18,812) 61,764
Preferred stock dividends of Hawaiian Electric 810
 —
 —
 —
 —
 810
 540
 —
 —
 —
 —
 540
Net income for common stock $102,721
 12,461
 16,713
 —
 (29,174) $102,721
 $61,224
 9,182
 9,630
 —
 (18,812) $61,224

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
NineSix months ended SeptemberJune 30, 20152016
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock
 $102,721
 12,461
 16,713
 —
 (29,174) $102,721
 $61,224
 9,182
 9,630
 —
 (18,812) $61,224
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
Other comprehensive income, net of taxes:  
  
  
  
  
  
Derivatives qualifying as cash flow hedges:            
Effective portion of foreign currency hedge net unrealized gain, net of taxes 257
 —
 —
 —
 —
 257
Retirement benefit plans:  
  
  
  
  
  
  
  
  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 15,285
 2,046
 1,878
 —
 (3,924) 15,285
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (15,274) (2,050) (1,882) —
 3,932
 (15,274)
Other comprehensive income (loss), net of taxes 11
 (4) (4) —
 8
 11
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 6,627
 859
 775
 —
 (1,634) 6,627
Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (6,623) (860) (777) —
 1,637
 (6,623)
Other comprehensive income, net of taxes 261
 (1) (2) —
 3
 261
Comprehensive income attributable to common shareholder $102,732
 12,457
 16,709
 —
 (29,166) $102,732
 $61,485
 9,181
 9,628
 —
 (18,809) $61,485


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet (unaudited)
SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consoli-
dating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consoli-
dating
adjustments
 Hawaiian Electric
Consolidated
Assets  
  
  
  
  
  
  
  
  
  
  
  
Property, plant and equipment                        
Utility property, plant and equipment  
  
  
  
  
  
  
  
  
  
  
  
Land $43,945
 6,214
 3,016
 —
 —
 $53,175
 $43,971
 6,191
 3,016
 —
 —
 $53,178
Plant and equipment 4,148,099
 1,234,234
 1,101,229
 —
 —
 6,483,562
 4,318,460
 1,267,529
 1,125,429
 —
 —
 6,711,418
Less accumulated depreciation (1,362,474) (503,109) (478,018) —
 —
 (2,343,601) (1,423,042) (518,266) (488,789) —
 —
 (2,430,097)
Construction in progress 197,715
 18,503
 20,390
 —
 —
 236,608
 232,965
 16,734
 22,739
 —
 —
 272,438
Utility property, plant and equipment, net 3,027,285
 755,842
 646,617
 —
 —
 4,429,744
 3,172,354
 772,188
 662,395
 —
 —
 4,606,937
Nonutility property, plant and equipment, less accumulated depreciation 5,761
 82
 1,531
 —
 —
 7,374
 5,763
 115
 1,532
 —
 —
 7,410
Total property, plant and equipment, net 3,033,046
 755,924
 648,148
 —
 —
 4,437,118
 3,178,117
 772,303
 663,927
 —
 —
 4,614,347
Investment in wholly owned subsidiaries, at equity 570,358
 —
 —
 —
 (570,358) —
 553,764
 —
 —
 —
 (553,764) —
Current assets  
  
  
  
  
  
  
  
  
  
  
  
Cash and cash equivalents 9,821
 7,008
 6,047
 101
 —
 22,977
 29,988
 7,104
 5,389
 101
 —
 42,582
Advances to affiliates —
 18,500
 15,500
 —
 (34,000) —
 —
 4,100
 1,000
 —
 (5,100) —
Customer accounts receivable, net 93,253
 21,646
 19,519
 —
 —
 134,418
 88,614
 18,847
 18,700
 —
 —
 126,161
Accrued unbilled revenues, net 69,753
 12,904
 12,510
 —
 —
 95,167
 74,640
 14,166
 14,790
 —
 —
 103,596
Other accounts receivable, net 11,469
 2,852
 2,316
 —
 (12,008) 4,629
 9,707
 2,471
 1,042
 —
 (9,536) 3,684
Fuel oil stock, at average cost 45,298
 6,885
 12,297
 —
 —
 64,480
 51,489
 8,135
 12,768
 —
 —
 72,392
Materials and supplies, at average cost 32,676
 8,424
 16,256
 —
 —
 57,356
 30,716
 8,852
 17,531
 —
 —
 57,099
Prepayments and other 28,073
 4,484
 3,548
 —
 (460) 35,645
 25,695
 7,294
 3,602
 —
 (251) 36,340
Regulatory assets 67,042
 4,582
 3,057
 —
 —
 74,681
 65,891
 3,981
 4,295
 —
 —
 74,167
Total current assets 357,385
 87,285
 91,050
 101
 (46,468) 489,353
 376,740
 74,950
 79,117
 101
 (14,887) 516,021
Other long-term assets  
  
  
  
  
  
  
  
  
  
  
  
Regulatory assets 594,723
 111,715
 98,656
 —
 —
 805,094
 638,480
 119,108
 106,522
 —
 —
 864,110
Unamortized debt expense 193
 33
 41
 —
 —
 267
 497
 84
 109
 —
 —
 690
Other 42,872
 12,786
 13,336
 —
 —
 68,994
 48,164
 13,778
 14,045
 —
 —
 75,987
Total other long-term assets 637,788
 124,534
 112,033
 —
 —
 874,355
 687,141
 132,970
 120,676
 —
 —
 940,787
Total assets $4,598,577
 967,743
 851,231
 101
 (616,826) $5,800,826
 $4,795,762
 980,223
 863,720
 101
 (568,651) $6,071,155
Capitalization and liabilities  
  
  
  
  
  
  
  
  
  
  
  
Capitalization  
  
  
  
  
  
  
  
  
  
  
  
Common stock equity $1,766,727
 299,276
 270,981
 101
 (570,358) $1,766,727
 $1,803,506
 291,760
 261,903
 101
 (553,764) $1,803,506
Cumulative preferred stock—not subject to mandatory redemption 22,293
 7,000
 5,000
 —
 —
 34,293
 22,293
 7,000
 5,000
 —
 —
 34,293
Long-term debt, net 875,573
 213,673
 190,081
 —
 —
 1,279,327
 915,208
 213,677
 189,960
 —
 —
 1,318,845
Total capitalization 2,664,593
 519,949
 466,062
 101
 (570,358) 3,080,347
 2,741,007
 512,437
 456,863
 101
 (553,764) 3,156,644
Current liabilities  
  
  
  
  
  
  
  
  
  
  
  
Short-term borrowings from non-affiliates 43,990
 —
 —
 —
 —
 43,990
Short-term borrowings from affiliate 55,000
 —
 —
 —
 (34,000) 21,000
 5,100
 —
 —
 —
 (5,100) —
Accounts payable 79,341
 14,844
 13,312
 —
 —
 107,497
 123,986
 19,796
 18,593
 —
 —
 162,375
Interest and preferred dividends payable 17,863
 4,034
 4,048
 —
 (11) 25,934
 13,584
 3,806
 2,113
 —
 (6) 19,497
Taxes accrued 115,245
 27,669
 24,822
 —
 (460) 167,276
 98,156
 23,394
 20,964
 —
 (251) 142,263
Regulatory liabilities —
 1,777
 1,210
 —
 —
 2,987
 126
 713
 2,044
 —
 —
 2,883
Other 46,326
 9,856
 12,568
 —
 (11,997) 56,753
 38,964
 8,920
 14,786
 —
 (9,530) 53,140
Total current liabilities 313,775
 58,180
 55,960
 —
 (46,468) 381,447
 323,906
 56,629
 58,500
 —
 (14,887) 424,148
Deferred credits and other liabilities  
  
  
  
  
  
  
  
  
  
  
  
Deferred income taxes 510,457
 105,574
 98,213
 —
 315
 714,559
 542,109
 111,616
 106,023
 —
 224
 759,972
Regulatory liabilities 274,070
 91,897
 31,525
 —
 —
 397,492
 297,006
 98,844
 32,897
 —
 —
 428,747
Unamortized tax credits 57,058
 15,774
 14,962
 —
 —
 87,794
 59,537
 16,246
 15,603
 —
 —
 91,386
Defined benefit pension and other postretirement benefit plans liability 396,468
 67,415
 72,029
 —
 —
 535,912
 435,614
 73,246
 78,858
 —
 —
 587,718
Other 50,068
 13,436
 14,595
 —
 (315) 77,784
 49,798
 13,803
 15,959
 —
 (224) 79,336
Total deferred credits and other liabilities 1,288,121
 294,096
 231,324
 —
 —
 1,813,541
 1,384,064
 313,755
 249,340
 —
 —
 1,947,159
Contributions in aid of construction 332,088
 95,518
 97,885
 —
 —
 525,491
 346,785
 97,402
 99,017
 —
 —
 543,204
Total capitalization and liabilities $4,598,577
 967,743
 851,231
 101
 (616,826) $5,800,826
 $4,795,762
 980,223
 863,720
 101
 (568,651) $6,071,155


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet (unaudited)
December 31, 20152016
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consoli-
dating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consoli-
dating
adjustments
 Hawaiian Electric
Consolidated
Assets  
  
  
  
  
  
  
  
  
  
  
  
Property, plant and equipment                        
Utility property, plant and equipment  
  
  
  
  
  
  
  
  
  
  
  
Land $43,557
 6,219
 3,016
 —
 —
 $52,792
 $43,956
 6,181
 3,016
 —
 —
 $53,153
Plant and equipment 4,026,079
 1,212,195
 1,077,424
 —
 —
 6,315,698
 4,241,060
 1,255,185
 1,109,487
 —
 —
 6,605,732
Less accumulated depreciation (1,316,467) (486,028) (463,509) —
 —
 (2,266,004) (1,382,972) (507,666) (478,644) —
 —
 (2,369,282)
Construction in progress 147,979
 11,455
 15,875
 —
 —
 175,309
 180,194
 12,510
 19,038
 —
 —
 211,742
Utility property, plant and equipment, net 2,901,148
 743,841
 632,806
 —
 —
 4,277,795
 3,082,238
 766,210
 652,897
 —
 —
 4,501,345
Nonutility property, plant and equipment, less accumulated depreciation 5,659
 82
 1,531
 —
 —
 7,272
 5,760
 115
 1,532
 —
 —
 7,407
Total property, plant and equipment, net 2,906,807
 743,923
 634,337
 —
 —
 4,285,067
 3,087,998
 766,325
 654,429
 —
 —
 4,508,752
Investment in wholly owned subsidiaries, at equity
 556,528
 —
 —
 —
 (556,528) —
 550,946
 —
 —
 —
 (550,946) —
Current assets  
  
  
  
  
  
  
  
  
  
  
  
Cash and cash equivalents 16,281
 2,682
 5,385
 101
 —
 24,449
 61,388
 10,749
 2,048
 101
 —
 74,286
Advances to affiliates —
 15,500
 7,500
 —
 (23,000) —
 —
 3,500
 10,000
 —
 (13,500) —
Customer accounts receivable, net 93,515
 20,508
 18,755
 —
 —
 132,778
 86,373
 20,055
 17,260
 —
 —
 123,688
Accrued unbilled revenues, net 60,080
 12,531
 11,898
 —
 —
 84,509
 65,821
 13,564
 12,308
 —
 —
 91,693
Other accounts receivable, net 16,421
 1,275
 1,674
 —
 (8,962) 10,408
 7,652
 2,445
 1,416
 —
 (6,280) 5,233
Fuel oil stock, at average cost 49,455
 8,310
 13,451
 —
 —
 71,216
 47,239
 8,229
 10,962
 —
 —
 66,430
Materials and supplies, at average cost 30,921
 6,865
 16,643
 —
 —
 54,429
 29,928
 7,380
 16,371
 —
 —
 53,679
Prepayments and other 25,505
 9,091
 2,295
 —
 (251) 36,640
 16,502
 5,352
 2,179
 —
 (933) 23,100
Regulatory assets 63,615
 4,501
 4,115
 —
 —
 72,231
 60,185
 3,483
 2,364
 —
 —
 66,032
Total current assets 355,793
 81,263
 81,716
 101
 (32,213) 486,660
 375,088
 74,757
 74,908
 101
 (20,713) 504,141
Other long-term assets  
  
  
  
  
  
  
  
  
  
  
  
Regulatory assets 608,957
 114,562
 100,981
 —
 —
 824,500
 662,232
 120,863
 108,324
 —
 —
 891,419
Unamortized debt expense 359
 74
 64
 —
 —
 497
 151
 23
 34
 —
 —
 208
Other 47,731
 14,693
 13,062
 —
 —
 75,486
 43,743
 13,573
 13,592
 —
 —
 70,908
Total other long-term assets 657,047
 129,329
 114,107
 —
 —
 900,483
 706,126
 134,459
 121,950
 —
 —
 962,535
Total assets $4,476,175
 954,515
 830,160
 101
 (588,741) $5,672,210
 $4,720,158
 975,541
 851,287
 101
 (571,659) $5,975,428
Capitalization and liabilities  
  
  
  
  
  
  
  
  
  
  
  
Capitalization  
  
  
  
  
  
  
  
  
  
  
  
Common stock equity $1,728,325
 292,702
 263,725
 101
 (556,528) $1,728,325
 $1,799,787
 291,291
 259,554
 101
 (550,946) $1,799,787
Cumulative preferred stock—not subject to mandatory redemption 22,293
 7,000
 5,000
 —
 —
 34,293
 22,293
 7,000
 5,000
 —
 —
 34,293
Long-term debt, net 875,163
 213,580
 189,959
 —
 —
 1,278,702
 915,437
 213,703
 190,120
 —
 —
 1,319,260
Total capitalization 2,625,781
 513,282
 458,684
 101
 (556,528) 3,041,320
 2,737,517
 511,994
 454,674
 101
 (550,946) 3,153,340
Current liabilities  
  
  
  
  
    
  
  
  
  
  
Short-term borrowings from affiliate 23,000
 —
 —
 —
 (23,000) —
 13,500
 —
 —
 —
 (13,500) —
Accounts payable 84,631
 17,702
 12,513
 —
 —
 114,846
 86,369
 18,126
 13,319
 —
 —
 117,814
Interest and preferred dividends payable 15,747
 4,255
 3,113
 —
 (4) 23,111
 15,761
 4,206
 2,882
 —
 (11) 22,838
Taxes accrued 131,668
 30,342
 29,325
 —
 (251) 191,084
 120,176
 28,100
 25,387
 —
 (933) 172,730
Regulatory liabilities —
 1,030
 1,174
 —
 —
 2,204
 —
 2,219
 1,543
 —
 —
 3,762
Other 41,083
 8,760
 13,194
 —
 (8,958) 54,079
 41,352
 7,637
 12,501
 —
 (6,269) 55,221
Total current liabilities 296,129
 62,089
 59,319
 —
 (32,213) 385,324
 277,158
 60,288
 55,632
 —
 (20,713) 372,365
Deferred credits and other liabilities  
  
  
  
  
    
  
  
  
  
  
Deferred income taxes 466,133
 100,681
 87,706
 —
 286
 654,806
 524,433
 108,052
 100,911
 —
 263
 733,659
Regulatory liabilities 254,033
 84,623
 30,683
 —
 —
 369,339
 281,112
 93,974
 31,845
 —
 —
 406,931
Unamortized tax credits 54,078
 15,406
 14,730
 —
 —
 84,214
 57,844
 15,994
 15,123
 —
 —
 88,961
Defined benefit pension and other postretirement benefit plans liability 409,021
 69,893
 74,060
 —
 —
 552,974
 444,458
 75,005
 80,263
 —
 —
 599,726
Other 51,273
 13,243
 13,916
 —
 (286) 78,146
 49,191
 13,024
 14,969
 —
 (263) 76,921
Total deferred credits and other liabilities 1,234,538
 283,846
 221,095
 —
 —
 1,739,479
 1,357,038
 306,049
 243,111
 —
 —
 1,906,198
Contributions in aid of construction 319,727
 95,298
 91,062
 —
 —
 506,087
 348,445
 97,210
 97,870
 —
 —
 543,525
Total capitalization and liabilities $4,476,175
 954,515
 830,160
 101
 (588,741) $5,672,210
 $4,720,158
 975,541
 851,287
 101
 (571,659) $5,975,428


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Changes in Common Stock Equity (unaudited)
NineSix months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Balance, December 31, 2015 $1,728,325
 292,702
 263,725
 101
 (556,528) $1,728,325
Balance, December 31, 2016 $1,799,787
 291,291
 259,554
 101
 (550,946) $1,799,787
Net income for common stock 108,198
 16,486
 17,055
 —
 (33,541) 108,198
 47,109
 8,216
 8,323
 —
 (16,539) 47,109
Other comprehensive income (loss), net of taxes 412
 (1) (4) —
 5
 412
Other comprehensive income, net of taxes 499
 1
 —
 —
 (1) 499
Common stock dividends (70,199) (9,906) (9,795) —
 19,701
 (70,199) (43,884) (7,748) (5,973) —
 13,721
 (43,884)
Common stock issuance expenses (9) (5) —
 —
 5
 (9) (5) —
 (1) —
 1
 (5)
Balance, September 30, 2016 $1,766,727
 299,276
 270,981
 101
 (570,358) $1,766,727
Balance, June 30, 2017 $1,803,506
 291,760
 261,903
 101
 (553,764) $1,803,506
 
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Changes in Common Stock Equity (unaudited)
NineSix months ended SeptemberJune 30, 2015
2016  
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Balance, December 31, 2014 $1,682,144
 281,846
 256,692
 101
 (538,639) $1,682,144
Balance, December 31, 2015 $1,728,325
 292,702
 263,725
 101
 (556,528) $1,728,325
Net income for common stock 102,721
 12,461
 16,713
 —
 (29,174) 102,721
 61,224
 9,182
 9,630
 —
 (18,812) 61,224
Other comprehensive income (loss), net of taxes 11
 (4) (4) —
 8
 11
 261
 (1) (2) —
 3
 261
Common stock dividends (67,804) (7,515) (11,382) —
 18,897
 (67,804) (46,800) (6,604) (6,530) —
 13,134
 (46,800)
Common stock issuance expenses (8) —
 (1) —
 1
 (8) (4) (4) —
 —
 4
 (4)
Balance, September 30, 2015 $1,717,064
 286,788
 262,018
 101
 (548,907) $1,717,064
Balance, June 30, 2016 $1,743,006
 295,275
 266,823
 101
 (562,199) $1,743,006


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Cash Flows (unaudited)
NineSix months ended SeptemberJune 30, 20162017
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Cash flows from operating activities  
  
  
  
  
  
  
  
  
  
  
  
Net income $109,008
 16,886
 17,341
 —
 (33,541) $109,694
 $47,649
 8,483
 8,514
 —
 (16,539) $48,107
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
  
    
  
  
  
  
  
Equity in earnings of subsidiaries (33,616) —
 —
 —
 33,541
 (75) (16,589) —
 —
 —
 16,539
 (50)
Common stock dividends received from subsidiaries 19,776
 —
 —
 —
 (19,701) 75
 13,771
 —
 —
 —
 (13,721) 50
Depreciation of property, plant and equipment 94,564
 28,347
 17,389
 —
 —
 140,300
 65,445
 19,371
 11,556
 —
 —
 96,372
Other amortization 2,462
 1,366
 1,552
 —
 —
 5,380
 1,875
 905
 1,482
 —
 —
 4,262
Deferred income taxes 41,005
 4,529
 10,085
 —
 29
 55,648
 15,060
 3,590
 4,988
 —
 (39) 23,599
Tax credits, net 4,314
 464
 478
 —
 —
 5,256
Allowance for equity funds used during construction (4,771) (571) (668) —
 —
 (6,010) (4,715) (249) (462) —
 —
 (5,426)
Other (1,389) (302) (331) —
 —
 (2,022) 1,089
 699
 (173) —
 —
 1,615
Changes in assets and liabilities:  
  
  
  
  
  
  
  
  
  
  
  
Decrease (increase) in accounts receivable 328
 (2,716) (1,313) —
 3,046
 (655) (5,100) 1,182
 (1,067) —
 3,256
 (1,729)
Increase in accrued unbilled revenues (9,673) (373) (612) —
 —
 (10,658) (8,819) (602) (2,482) —
 —
 (11,903)
Decrease in fuel oil stock 4,157
 1,425
 1,154
 —
 —
 6,736
Decrease (increase) in materials and supplies (1,755) (1,559) 387
 —
 —
 (2,927)
Decrease (increase) in fuel oil stock (4,250) 94
 (1,806) —
 —
 (5,962)
Increase in materials and supplies (788) (1,472) (1,160) —
 —
 (3,420)
Decrease (increase) in regulatory assets (2,474) (150) 373
 —
 —
 (2,251) 11,378
 (1,575) (1,624) —
 —
 8,179
Increase (decrease) in accounts payable (2,628) 143
 1,809
 —
 —
 (676)
Change in prepaid and accrued income and utility revenue taxes (7,324) 2,230
 (4,472) —
 (29) (9,595)
Increase in accounts payable 39,954
 3,291
 8,392
 —
 —
 51,637
Change in prepaid and accrued income taxes, tax credits and revenue taxes (29,430) (6,290) (4,725) —
 (465) (40,910)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability 449
 40
 (129) —
 —
 360
 355
 26
 (79) —
 —
 302
Change in other assets and liabilities (10,548) 2,856
 (2,571) —
 (3,046) (13,309) (12,727) 129
 1,807
 —
 (3,256) (14,047)
Net cash provided by operating activities 201,885
 52,615
 40,472
 —
 (19,701) 275,271
 114,158
 27,582
 23,161
 —
 (14,225) 150,676
Cash flows from investing activities  
  
  
  
  
  
  
  
  
  
  
  
Capital expenditures (188,415) (37,835) (24,454) —
 —
 (250,704) (153,554) (24,744) (23,782) —
 —
 (202,080)
Contributions in aid of construction 18,181
 2,691
 2,696
 —
 —
 23,568
 14,078
 1,870
 1,623
 —
 —
 17,571
Other 901
 169
 30
 —
 —
 1,100
 4,820
 619
 307
 —
 504
 6,250
Advances from affiliates —
 (3,000) (8,000) —
 11,000
 —
 —
 (600) 9,000
 —
 (8,400) —
Net cash used in investing activities (169,333) (37,975) (29,728) —
 11,000
 (226,036) (134,656) (22,855) (12,852) —
 (7,896) (178,259)
Cash flows from financing activities  
  
  
  
  
  
  
  
  
  
  
  
Common stock dividends (70,199) (9,906) (9,795) —
 19,701
 (70,199) (43,884) (7,748) (5,973) —
 13,721
 (43,884)
Preferred stock dividends of Hawaiian Electric and subsidiaries (810) (400) (286) —
 —
 (1,496) (540) (267) (191) —
 —
 (998)
Proceeds from issuance of special purpose revenue bonds 162,000
 28,000
 75,000
 —
 

 265,000
Funds transferred for redemption of special purpose revenue bonds (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 less 32,000
 —
 —
 —
 (11,000) 21,000
 35,590
 —
 —
 —
 8,400
 43,990
Other (3) (8) (1) —
 —
 (12) (2,068) (357) (804) —
 —
 (3,229)
Net cash used in financing activities (39,012) (10,314) (10,082) —
 8,701
 (50,707) (10,902) (8,372) (6,968) —
 22,121
 (4,121)
Net increase (decrease) in cash and cash equivalents (6,460) 4,326
 662
 —
 —
 (1,472) (31,400) (3,645) 3,341
 —
 —
 (31,704)
Cash and cash equivalents, beginning of period 16,281
 2,682
 5,385
 101
 —
 24,449
 61,388
 10,749
 2,048
 101
 —
 74,286
Cash and cash equivalents, end of period $9,821
 7,008
 6,047
 101
 —
 $22,977
 $29,988
 7,104
 5,389
 101
 —
 $42,582


Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Cash Flows (unaudited)
NineSix months ended SeptemberJune 30, 20152016
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other
subsidiaries		 Consolidating
adjustments		 Hawaiian Electric
Consolidated		 Hawaiian Electric Hawaii Electric Light Maui Electric Other
subsidiaries		 Consolidating
adjustments		 Hawaiian Electric
Consolidated
Cash flows from operating activities  
  
  
  
  
  
  
  
  
  
  
  
Net income $103,531
 12,861
 16,999
 —
 (29,174) $104,217
 $61,764
 9,449
 9,821
 —
 (18,812) $62,222
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
  
  
  
  
  
  
  
  
Equity in earnings of subsidiaries (29,249) —
 —
 —
 29,174
 (75) (18,862) —
 —
 —
 18,812
 (50)
Common stock dividends received from subsidiaries 18,972
 —
 —
 —
 (18,897) 75
 13,184
 —
 —
 —
 (13,134) 50
Depreciation of property, plant and equipment 88,167
 27,938
 16,735
 —
 —
 132,840
 63,044
 18,898
 11,599
 —
 —
 93,541
Other amortization 2,029
 1,331
 1,639
 —
 —
 4,999
 1,919
 911
 963
 —
 —
 3,793
Deferred income taxes 46,493
 907
 10,497
 —
 314
 58,211
 23,954
 2,538
 5,623
 —
 3
 32,118
Tax credits, net 3,680
 372
 195
 —
 —
 4,247
Allowance for equity funds used during construction (4,418) (458) (490) —
 —
 (5,366) (2,965) (333) (438) —
 —
 (3,736)
Impairment of utility assets 3,380
 724
 724
     4,828
Other 221
 (286) (261) 

 

 (326) 1,383
 1,611
 (12) —
 —
 2,982
Changes in assets and liabilities:                        
Decrease (increase) in accounts receivable (4,226) (2,071) 43
 —
 1,790
 (4,464)
Decrease in accrued unbilled revenues 6,283
 3,696
 3,817
 —
 —
 13,796
Decrease in accounts receivable 14,177
 2,007
 729
 —
 (231) 16,682
Decrease (increase) in accrued unbilled revenues (2,941) 634
 (908) —
 —
 (3,215)
Decrease in fuel oil stock 25,019
 5,358
 5,565
 —
 —
 35,942
 6,015
 924
 2,705
 —
 —
 9,644
Decrease (increase) in materials and supplies (759) (1,615) 651
 —
 —
 (1,723)
Increase in regulatory assets (19,138) (3,944) (376) —
 —
 (23,458)
Decrease in accounts payable (34,476) (4,070) (1,829) —
 —
 (40,375)
Change in prepaid and accrued income and utility revenue taxes (52,505) (2,276) (6,540) —
 (314) (61,635)
Increase in defined benefit pension and other postretirement benefit plans liability —
 —
 331
 —
 —
 331
Increase in materials and supplies (1,748) (708) (26) —
 —
 (2,482)
Decrease (increase) in regulatory assets (3,974) 2,138
 1,159
 —
 —
 (677)
Increase in accounts payable 17,150
 208
 6,069
 —
 —
 23,427
Change in prepaid and accrued income taxes, tax credits and revenue taxes (21,371) (192) (6,626) —
 (3) (28,192)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability 299
 27
 (89) —
 —
 237
Change in other assets and liabilities (16,847) 722
 (2,563) —
 (1,790) (20,478) (11,803) 11
 (659) —
 231
 (12,220)
Net cash provided by operating activities 136,157
 39,189
 45,137
 —
 (18,897) 201,586
 139,225
 38,123
 29,910
 —
 (13,134) 194,124
Cash flows from investing activities  
  
  
  
  
  
  
  
  
  
  
  
Capital expenditures (204,406) (34,048) (27,067) —
 —
 (265,521) (152,283) (27,436) (17,613) —
 —
 (197,332)
Contributions in aid of construction 30,153
 2,940
 1,534
 —
 —
 34,627
 12,824
 1,605
 2,381
 —
 —
 16,810
Other 583
 124
 71
 —
 —
 778
 132
 169
 30
 —
 —
 331
Advances from affiliates 4,100
 —
 (2,500) —
 (1,600) —
 —
 (3,000) (11,000) —
 14,000
 —
Net cash used in investing activities (169,570) (30,984) (27,962) —
 (1,600) (230,116) (139,327) (28,662) (26,202) —
 14,000
 (180,191)
Cash flows from financing activities  
  
  
  
  
    
  
  
  
  
  
Common stock dividends (67,804) (7,515) (11,382) —
 18,897
 (67,804) (46,800) (6,604) (6,530) —
 13,134
 (46,800)
Preferred stock dividends of Hawaiian Electric and subsidiaries (810) (400) (286) —
 —
 (1,496) (540) (267) (191) —
 —
 (998)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 97,495
 1,500
 (5,600) —
 1,600
 94,995
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 50,995
 —
 —
 —
 (14,000) 36,995
Other (219) (3) (1) —
 —
 (223) 8
 (8) —
 —
 —
 —
Net cash provided by (used in) financing activities 28,662
 (6,418) (17,269) —
 20,497
 25,472
 3,663
 (6,879) (6,721) —
 (866) (10,803)
Net increase (decrease) in cash and cash equivalents (4,751) 1,787
 (94) —
 —
 (3,058) 3,561
 2,582
 (3,013) —
 —
 3,130
Cash and cash equivalents, beginning of period 12,416
 612
 633
 101
 —
 13,762
 16,281
 2,682
 5,385
 101
 —
 24,449
Cash and cash equivalents, end of period $7,665
 2,399
 539
 101
 —
 $10,704
 $19,842
 5,264
 2,372
 101
 —
 $27,579




54 · Bank segment

Selected financial information
American Savings Bank, F.S.B.
Statements of Income Data (unaudited)
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in thousands) 2016 2015 2016 2015 2017 2016 2017 2016
Interest and dividend income  
  
  
  
  
  
  
  
Interest and fees on loans $50,444
 $46,413
 $148,571
 $137,646
 $52,317
 $49,690
 $103,059
 $98,127
Interest and dividends on investment securities 4,759
 4,213
 14,219
 10,570
 6,763
 4,443
 13,743
 9,460
Total interest and dividend income 55,203
 50,626
 162,790
 148,216
 59,080
 54,133
 116,802
 107,587
Interest expense  
  
  
  
  
  
  
  
Interest on deposit liabilities 1,871
 1,355
 5,154
 3,881
 2,311
 1,691
 4,414
 3,283
Interest on other borrowings 1,464
 1,515
 4,416
 4,468
 824
 1,467
 1,640
 2,952
Total interest expense 3,335
 2,870
 9,570
 8,349
 3,135
 3,158
 6,054
 6,235
Net interest income 51,868
 47,756
 153,220
 139,867
 55,945
 50,975
 110,748
 101,352
Provision for loan losses 5,747
 2,997
 15,266
 5,436
 2,834
 4,753
 6,741
 9,519
Net interest income after provision for loan losses 46,121
 44,759
 137,954
 134,431
 53,111
 46,222
 104,007
 91,833
Noninterest income  
  
  
  
  
  
  
  
Fees from other financial services 5,599
 5,639
 16,799
 16,544
 5,810
 5,701
 11,420
 11,200
Fee income on deposit liabilities 5,627
 5,883
 16,045
 16,622
 5,565
 5,262
 10,993
 10,418
Fee income on other financial products 2,151
 2,096
 6,563
 6,088
 1,971
 2,207
 3,837
 4,412
Bank-owned life insurance 1,616
 1,021
 3,620
 3,062
 1,925
 1,006
 2,908
 2,004
Mortgage banking income 2,347
 1,437
 5,096
 5,327
 587
 1,554
 1,376
 2,749
Gains on sale of investment securities, net —
 —
 598
 —
 —
 598
 —
 598
Other income, net 1,165
 2,389
 1,786
 3,363
 391
 288
 849
 621
Total noninterest income 18,505
 18,465
 50,507
 51,006
 16,249
 16,616
 31,383
 32,002
Noninterest expense  
  
  
  
  
  
  
  
Compensation and employee benefits 22,844
 22,728
 67,197
 66,813
 24,742
 21,919
 47,979
 44,353
Occupancy 3,991
 4,128
 12,244
 12,250
 4,185
 4,115
 8,339
 8,253
Data processing 3,150
 3,032
 9,599
 9,101
 3,207
 3,277
 6,487
 6,449
Services 2,427
 2,556
 8,093
 7,730
 2,766
 2,755
 5,126
 5,666
Equipment 1,759
 1,608
 5,193
 4,999
 1,771
 1,771
 3,519
 3,434
Office supplies, printing and postage 1,483
 1,511
 4,431
 4,297
 1,527
 1,583
 3,062
 2,948
Marketing 747
 934
 2,507
 2,619
 839
 899
 1,356
 1,760
FDIC insurance 907
 809
 2,704
 2,393
 822
 913
 1,550
 1,797
Other expense 4,591
 5,116
 13,948
 14,076
 4,705
 5,382
 9,016
 9,357
Total noninterest expense 41,899
 42,422
 125,916
 124,278
 44,564
 42,614
 86,434
 84,017
Income before income taxes 22,727
 20,802
 62,545
 61,159
 24,796
 20,224
 48,956
 39,818
Income taxes 7,623
 7,351
 21,483
 21,382
 8,063
 6,939
 16,410
 13,860
Net income $15,104
 $13,451
 $41,062
 $39,777
 $16,733
 $13,285
 $32,546
 $25,958



American Savings Bank, F.S.B.
Statements of Comprehensive Income Data (unaudited)
  Three months ended September 30 Nine months ended September 30
(in thousands) 2016 2015 2016 2015
Net income $15,104
 $13,451
 $41,062
 $39,777
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 $1,417, $(2,543), $(5,413) and $(2,382) for the respective periods (2,147) 3,851
 8,197
 3,608
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, $238 and nil for the respective periods —
 —
 (360) —
Retirement benefit plans:  
  
  
  
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $144, $249, $421 and $763 for the respective periods 219
 376
 638
 1,155
Other comprehensive income (loss), net of taxes (1,928) 4,227
 8,475
 4,763
Comprehensive income $13,176
 $17,678
 $49,537
 $44,540

  Three months ended June 30 Six months ended June 30
(in thousands) 2017 2016 2017 2016
Net income $16,733
 $13,285
 $32,546
 $25,958
Other comprehensive income, net of taxes:  
  
  
  
Net unrealized gains on available-for-sale investment securities:  
  
  
  
Net unrealized gains on available-for-sale investment securities arising during the period, net of taxes of $1,334, $1,925, $1,482 and $6,830, respectively 2,021
 2,915
 2,244
 10,344
Reclassification adjustment for net realized gains included in net income, net of taxes of nil, $238, nil and $238, respectively —
 (360) —
 (360)
Retirement benefit plans:  
  
  
  
Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $133, $140, $537 and $277, respectively 202
 211
 814
 419
Other comprehensive income, net of taxes 2,223
 2,766
 3,058
 10,403
Comprehensive income $18,956
 $16,051
 $35,604
 $36,361


American Savings Bank, F.S.B.
Balance Sheets Data (unaudited)
(in thousands) June 30, 2017 December 31, 2016
Assets  
  
  
  
Cash and due from banks  
 $128,609
  
 $137,083
Interest-bearing deposits   37,049
   52,128
Restricted cash   —
   1,764
Available-for-sale investment securities, at fair value  
 1,302,886
  
 1,105,182
Stock in Federal Home Loan Bank, at cost  
 11,706
  
 11,218
Loans receivable held for investment  
 4,744,634
  
 4,738,693
Allowance for loan losses  
 (56,356)  
 (55,533)
Net loans  
 4,688,278
  
 4,683,160
Loans held for sale, at lower of cost or fair value  
 5,261
  
 18,817
Other  
 354,898
  
 329,815
Goodwill  
 82,190
  
 82,190
Total assets  
 $6,610,877
  
 $6,421,357
         
Liabilities and shareholder’s equity  
  
  
  
Deposit liabilities—noninterest-bearing  
 $1,694,150
  
 $1,639,051
Deposit liabilities—interest-bearing  
 4,030,236
  
 3,909,878
Other borrowings  
 188,130
  
 192,618
Other  
 101,974
  
 101,635
Total liabilities  
 6,014,490
  
 5,843,182
Commitments and contingencies  
 

  
 

Common stock  
 1
  
 1
Additional paid in capital   344,062
   342,704
Retained earnings  
 271,739
  
 257,943
Accumulated other comprehensive loss, net of tax benefits  
  
  
  
Net unrealized losses on securities $(5,687)  
 $(7,931)  
Retirement benefit plans (13,728) (19,415) (14,542) (22,473)
Total shareholder’s equity  
 596,387
  
 578,175
Total liabilities and shareholder’s equity  
 $6,610,877
  
 $6,421,357
         
Other assets  
  
  
  
Bank-owned life insurance  
 $146,122
  
 $143,197
Premises and equipment, net  
 108,158
  
 90,570
Prepaid expenses  
 4,632
  
 3,348
Accrued interest receivable  
 16,949
  
 16,824
Mortgage-servicing rights  
 9,181
  
 9,373
Low-income housing equity investments   48,596
   47,081
Real estate acquired in settlement of loans, net  
 1,554
  
 1,189
Other  
 19,706
  
 18,233
   
 $354,898
  
 $329,815
Other liabilities  
  
  
  
Accrued expenses  
 $34,451
  
 $36,754
Federal and state income taxes payable  
 6,336
  
 4,728
Cashier’s checks  
 24,191
  
 24,156
Advance payments by borrowers  
 10,334
  
 10,335
Other  
 26,662
  
 25,662
   
 $101,974
  
 $101,635
(in thousands) September 30, 2016 December 31, 2015
Assets  
  
  
  
Cash and due from banks  
 $109,591
  
 $127,201
Interest-bearing deposits   103,989
   93,680
Available-for-sale investment securities, at fair value  
 996,984
  
 820,648
Stock in Federal Home Loan Bank, at cost  
 11,218
  
 10,678
Loans receivable held for investment  
 4,734,638
  
 4,615,819
Allowance for loan losses  
 (58,737)  
 (50,038)
Net loans  
 4,675,901
  
 4,565,781
Loans held for sale, at lower of cost or fair value  
 26,743
  
 4,631
Other  
 330,054
  
 309,946
Goodwill  
 82,190
  
 82,190
Total assets  
 $6,336,670
  
 $6,014,755
         
Liabilities and shareholder’s equity  
  
  
  
Deposit liabilities—noninterest-bearing  
 $1,570,613
  
 $1,520,374
Deposit liabilities—interest-bearing  
 3,810,108
  
 3,504,880
Other borrowings  
 265,388
  
 328,582
Other  
 106,396
  
 101,029
Total liabilities  
 5,752,505
  
 5,454,865
Commitments and contingencies  
 

  
 

Common stock  
 1
  
 1
Additional paid in capital   342,234
   340,496
Retained earnings  
 250,726
  
 236,664
Accumulated other comprehensive loss, net of tax benefits  
  
  
  
Net unrealized gains (losses) on securities $5,965
  
 $(1,872)  
Retirement benefit plans (14,761) (8,796) (15,399) (17,271)
Total shareholder’s equity  
 584,165
  
 559,890
Total liabilities and shareholder’s equity  
 $6,336,670
  
 $6,014,755
         
Other assets  
  
  
  
Bank-owned life insurance  
 $141,262
  
 $138,139
Premises and equipment, net  
 91,354
  
 88,077
Prepaid expenses  
 4,072
  
 3,550
Accrued interest receivable  
 15,489
  
 15,192
Mortgage-servicing rights  
 9,191
  
 8,884
Low-income housing equity investments   48,474
   37,793
Real estate acquired in settlement of loans, net  
 219
  
 1,030
Other  
 19,993
  
 17,281
   
 $330,054
  
 $309,946
Other liabilities  
  
  
  
Accrued expenses  
 $37,671
  
 $30,705
Federal and state income taxes payable  
 13,971
  
 13,448
Cashier’s checks  
 24,923
  
 21,768
Advance payments by borrowers  
 5,531
  
 10,311
Other  
 24,300
  
 24,797
   
 $106,396
  
 $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.


Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of $16588 million and $100 million, respectively, as of SeptemberJune 30, 20162017 and $229$93 million and $100 million, respectively, as of December 31, 20152016.
Available-for-sale investment securities.  The major components of investment securities were as follows:
 Amortized cost Gross unrealized gains Gross unrealized losses 
Estimated fair
value
   Gross unrealized losses Amortized cost Gross unrealized gains Gross unrealized losses 
Estimated fair
value
 Gross unrealized losses
 Less than 12 months 12 months or longer Less than 12 months 12 months or longer
(dollars in thousands) Number of issues 
Fair 
value
 Amount Number of issues 
Fair 
value
 Amount Number of issues 
Fair 
value
 Amount Number of issues 
Fair 
value
 Amount
September 30, 2016  
  
  
  
    
  
    
  
June 30, 2017  
  
  
  
    
  
    
  
Available-for-sale                                        
U.S. Treasury and federal agency obligations $186,287
 $3,125
 $(40) $189,372
 1
 $9,988
 $(12) 1
 $3,834
 $(28) $187,289
 $947
 $(1,653) $186,583
 16
 $104,417
 $(1,532) 1
 $3,186
 $(121)
Mortgage-related securities- FNMA, FHLMC and GNMA 800,794
 7,782
 (964) 807,612
 18
 134,687
 (323) 13
 51,458
 (641) 1,109,613
 2,202
 (10,939) 1,100,876
 98
 759,643
 (9,658) 13
 43,296
 (1,281)
Mortgage revenue bond 15,427
 —
 —
 15,427
 —
 —
 —
 —
 —
 —
 $987,081
 $10,907
 $(1,004) $996,984
 19
 $144,675
 $(335) 14
 $55,292
 $(669) $1,312,329
 $3,149
 $(12,592) $1,302,886
 114
 $864,060
 $(11,190) 14
 $46,482
 $(1,402)
December 31, 2015                    
December 31, 2016                    
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) $193,515
 $920
 $(2,154) $192,281
 18
 $123,475
 $(2,010) 1
 $3,485
 $(144)
Mortgage-related securities- FNMA, FHLMC and GNMA 610,522
 3,564
 (6,397) 607,689
 38
 305,785
 (2,866) 25
 125,817
 (3,531) 909,408
 1,742
 (13,676) 897,474
 88
 709,655
 (12,143) 13
 47,485
 (1,533)
Mortgage revenue bond 15,427
 —
 —
 15,427
 —
 —
 —
 —
 —
 —
 $823,756
 $4,589
 $(7,697) $820,648
 51
 $388,838
 $(3,732) 28
 $143,195
 $(3,965) $1,118,350
 $2,662
 $(15,830) $1,105,182
 106
 $833,130
 $(14,153) 14
 $50,970
 $(1,677)
ASB does not believe that the investment securities that were in an unrealized loss position at SeptemberJune 30, 2016,2017, represent an other-than-temporary impairment.impairment (OTTI). 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 investmentU.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 the quarters and six month periods ended SeptemberJune 30, 20162017 and 2015.2016.
U.S. Treasury, and 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:
September 30, 2016 Amortized cost Fair value
June 30, 2017 Amortized cost Fair value
(in thousands)        
Due in one year or less $—
 $—
 $9,992
 $9,993
Due after one year through five years 87,165
 88,754
 77,151
 77,307
Due after five years through ten years 78,222
 79,534
 85,724
 85,258
Due after ten years 20,900
 21,084
 29,849
 29,452
 186,287
 189,372
 202,716
 202,010
Mortgage-related securities-FNMA,FHLMC and GNMA 800,794
 807,612
Mortgage-related securities-FNMA, FHLMC and GNMA 1,109,613
 1,100,876
Total available-for-sale securities $987,081
 $996,984
 $1,312,329
 $1,302,886
Proceeds and gross realized gains from the sale of available-for-sale investment securities were $16.4 million and $0.6 million, respectively, for the three and six months ended June 30, 2016. Gross realized losses recognized during the three and


six months ended June 30, 2016 were not material. No available-for-sale investment securities were sold during the three and six month periods ended June 30, 2017.
Loans receivable. The components of loans receivable were summarized as follows:
 June 30, 2017 December 31, 2016
(in thousands) 
  
Real estate: 
  
Residential 1-4 family$2,061,549
 $2,048,051
Commercial real estate808,900
 800,395
Home equity line of credit883,135
 863,163
Residential land16,009
 18,889
Commercial construction116,548
 126,768
Residential construction10,759
 16,080
Total real estate3,896,900
 3,873,346
Commercial649,657
 692,051
Consumer201,199
 178,222
Total loans4,747,756
 4,743,619
Less: Deferred fees and discounts(3,122) (4,926)
          Allowance for loan losses(56,356) (55,533)
Total loans, net$4,688,278
 $4,683,160
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.


Allowance for loan losses. 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 loans Consumer loans Unallo-cated Total 
Residential
1-4 family
 
Commercial real
estate
 Home
equity line of credit		 Residential land Commercial construction Residential construction Commercial loans Consumer loans Unallo-cated Total
Three months ended September 30, 2016  
  
  
  
  
  
  
  
  
  
Three months ended June 30, 2017  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $4,384
 $13,561
 $7,836
 $1,689
 $6,993
 $12
 $17,085
 $3,771
 $—
 $55,331
 $2,781
 $16,504
 $5,417
 $1,479
 $7,257
 $11
 $14,902
 $7,646
 $—
 $55,997
Charge-offs (373) —
 (108) —
 —
 —
 (833) (1,879) —
 (3,193) —
 —
 —
 (92) —
 —
 (752) (2,390) —
 (3,234)
Recoveries 92
 —
 15
 187
 —
 —
 347
 211
 —
 852
 49
 —
 39
 15
 —
 —
 299
 357
 —
 759
Provision 154
 1,289
 (248) 23
 179
 (2) 2,457
 1,895
 —
 5,747
 300
 2,336
 71
 (138) (2,551) (2) 103
 2,715
 —
 2,834
Ending balance $4,257
 $14,850
 $7,495
 $1,899
 $7,172
 $10
 $19,056
 $3,998
 $—
 $58,737
 $3,130
 $18,840
 $5,527
 $1,264
 $4,706
 $9
 $14,552
 $8,328
 $—
 $56,356
Three months ended September 30, 2015  
  
  
  
  
  
  
  
  
  
Three months ended June 30, 2016  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $4,291
 $10,420
 $6,613
 $2,103
 $2,575
 $18
 $17,469
 $2,876
 $—
 $46,365
 $4,593
 $11,806
 $7,172
 $1,740
 $6,164
 $12
 $16,991
 $3,848
 $—
 $52,326
Charge-offs (138) —
 (185) —
 —
 —
 (126) (1,271) —
 (1,720) (15) —
 —
 —
 —
 —
 (962) (1,528) —
 (2,505)
Recoveries 45
 —
 33
 34
 —
 —
 279
 241
 —
 632
 35
 —
 16
 16
 —
 —
 425
 265
 —
 757
Provision 285
 987
 446
 (73) 944
 (5) (920) 1,333
 —
 2,997
 (229) 1,755
 648
 (67) 829
 —
 631
 1,186
 —
 4,753
Ending balance $4,483
 $11,407
 $6,907
 $2,064
 $3,519
 $13
 $16,702
 $3,179
 $—
 $48,274
 $4,384
 $13,561
 $7,836
 $1,689
 $6,993
 $12
 $17,085
 $3,771
 $—
 $55,331
Nine months ended September 30, 2016  
  
  
  
  
  
  
  
  
  
Six months ended June 30, 2017  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $4,186
 $11,342
 $7,260
 $1,671
 $4,461
 $13
 $17,208
 $3,897
 $—
 $50,038
 $2,873
 $16,004
 $5,039
 $1,738
 $6,449
 $12
 $16,618
 $6,800
 $—
 $55,533
Charge-offs (433) —
 (108) —
 —
 —
 (3,138) (4,977) —
 (8,656) (6) —
 (14) (92) —
 —
 (2,262) (5,200) —
 (7,574)
Recoveries 144
 —
 46
 306
 —
 —
 907
 686
 —
 2,089
 58
 —
 130
 218
 —
 —
 596
 654
 —
 1,656
Provision 360
 3,508
 297
 (78) 2,711
 (3) 4,079
 4,392
 —
 15,266
 205
 2,836
 372
 (600) (1,743) (3) (400) 6,074
 —
 6,741
Ending balance $4,257
 $14,850
 $7,495
 $1,899
 $7,172
 $10
 $19,056
 $3,998
 $—
 $58,737
 $3,130
 $18,840
 $5,527
 $1,264
 $4,706
 $9
 $14,552
 $8,328
 $—
 $56,356
September 30, 2016                    
June 30, 2017                    
Ending balance: individually evaluated for impairment $1,625
 $161
 $1,040
 $951
 $—
 $—
 $4,734
 $2
   $8,513
 $1,332
 $73
 $275
 $480
 $—
 $—
 $939
 $30
   $3,129
Ending balance: collectively evaluated for impairment $2,632
 $14,689
 $6,455
 $948
 $7,172
 $10
 $14,322
 $3,996
 $—
 $50,224
 $1,798
 $18,767
 $5,252
 $784
 $4,706
 $9
 $13,613
 $8,298
 $—
 $53,227
Financing Receivables:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Ending balance $2,054,460
 $774,349
 $859,952
 $19,666
 $140,758
 $15,073
 $717,450
 $158,065
   $4,739,773
 $2,061,549
 $808,900
 $883,135
 $16,009
 $116,548
 $10,759
 $649,657
 $201,199
   $4,747,756
Ending balance: individually evaluated for impairment $21,566
 $3,762
 $5,886
 $4,428
 $—
 $—
 $28,685
 $11
   $64,338
 $19,188
 $1,289
 $6,684
 $2,589
 $—
 $—
 $4,283
 $68
   $34,101
Ending balance: collectively evaluated for impairment $2,032,894
 $770,587
 $854,066
 $15,238
 $140,758
 $15,073
 $688,765
 $158,054
   $4,675,435
 $2,042,361
 $807,611
 $876,451
 $13,420
 $116,548
 $10,759
 $645,374
 $201,131
   $4,713,655
Nine months ended September 30, 2015  
  
  
  
  
  
  
  
  
  
Six months ended June 30, 2016  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $4,662
 $8,954
 $6,982
 $1,875
 $5,471
 $28
 $14,017
 $3,629
 $—
 $45,618
 $4,186
 $11,342
 $7,260
 $1,671
 $4,461
 $13
 $17,208
 $3,897
 $—
 $50,038
Charge-offs (352) —
 (205) —
 —
 —
 (928) (3,196) —
 (4,681) (60) —
 —
 —
 —
 —
 (2,305) (3,098) —
 (5,463)
Recoveries 112
 —
 72
 219
 —
 —
 726
 772
 —
 1,901
 52
 —
 31
 119
 —
 —
 560
 475
 —
 1,237
Provision 61
 2,453
 58
 (30) (1,952) (15) 2,887
 1,974
 —
 5,436
 206
 2,219
 545
 (101) 2,532
 (1) 1,622
 2,497
 —
 9,519
Ending balance $4,483
 $11,407
 $6,907
 $2,064
 $3,519
 $13
 $16,702
 $3,179
 $—
 $48,274
 $4,384
 $13,561
 $7,836
 $1,689
 $6,993
 $12
 $17,085
 $3,771
 $—
 $55,331
December 31, 2015                    
December 31, 2016                    
Ending balance: individually evaluated for impairment $1,453
 $—
 $442
 $891
 $—
 $—
 $3,527
 $7
   $6,320
 $1,352
 $80
 $215
 $789
 $—
 $—
 $1,641
 $6
   $4,083
Ending balance: collectively evaluated for impairment $2,733
 $11,342
 $6,818
 $780
 $4,461
 $13
 $13,681
 $3,890
 $—
 $43,718
 $1,521
 $15,924
 $4,824
 $949
 $6,449
 $12
 $14,977
 $6,794
 $—
 $51,450
Financing Receivables:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Ending balance $2,069,665
 $690,561
 $846,294
 $18,229
 $100,796
 $14,089
 $758,659
 $123,775
   $4,622,068
 $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 $22,457
 $1,188
 $3,225
 $5,683
 $—
 $—
 $21,119
 $13
   $53,685
 $19,854
 $1,569
 $6,158
 $3,629
 $—
 $—
 $20,539
 $10
   $51,759
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
 $2,028,197
 $798,826
 $857,005
 $15,260
 $126,768
 $16,080
 $671,512
 $178,212
   $4,691,860
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. 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:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in thousands) 
Commercial
real estate
 
Commercial
construction
 Commercial 
Commercial
real estate
 
Commercial
construction
 Commercial 
Commercial
real estate
 
Commercial
construction
 Commercial 
Commercial
real estate
 
Commercial
construction
 Commercial
Grade:  
  
  
  
  
  
  
  
  
  
  
  
Pass $681,712
 $114,325
 $643,547
 $642,410
 $86,991
 $703,208
 $660,015
 $92,069
 $602,903
 $701,657
 $102,955
 $614,139
Special mention 58,411
 —
 17,654
 7,710
 13,805
 7,029
 95,656
 22,500
 19,429
 65,541
 —
 25,229
Substandard 34,226
 26,433
 54,156
 40,441
 —
 47,975
 53,229
 1,979
 27,325
 33,197
 23,813
 52,683
Doubtful —
 —
 2,093
 —
 —
 447
 —
 —
 —
 —
 —
 —
Loss —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Total $774,349
 $140,758
 $717,450
 $690,561
 $100,796
 $758,659
 $808,900
 $116,548
 $649,657
 $800,395
 $126,768
 $692,051

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
 
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
September 30, 2016  
  
  
  
  
  
  
June 30, 2017  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $4,293
 $1,626
 $10,576
 $16,495
 $2,037,965
 $2,054,460
 $—
 $2,308
 $2,694
 $5,411
 $10,413
 $2,051,136
 $2,061,549
 $—
Commercial real estate —
 —
 —
 —
 774,349
 774,349
 —
 —
 —
 —
 —
 808,900
 808,900
 —
Home equity line of credit 827
 787
 674
 2,288
 857,664
 859,952
 —
 502
 494
 1,516
 2,512
 880,623
 883,135
 —
Residential land —
 —
 541
 541
 19,125
 19,666
 393
 —
 —
 305
 305
 15,704
 16,009
 —
Commercial construction —
 —
 —
 —
 140,758
 140,758
 —
 —
 —
 —
 —
 116,548
 116,548
 —
Residential construction —
 —
 —
 —
 15,073
 15,073
 —
 —
 —
 —
 —
 10,759
 10,759
 —
Commercial 681
 997
 19
 1,697
 715,753
 717,450
 —
 1,486
 614
 1,096
 3,196
 646,461
 649,657
 —
Consumer 1,708
 636
 813
 3,157
 154,908
 158,065
 —
 2,266
 1,305
 863
 4,434
 196,765
 201,199
 —
Total loans $7,509
 $4,046
 $12,623
 $24,178
 $4,715,595
 $4,739,773
 $393
 $6,562
 $5,107
 $9,191
 $20,860
 $4,726,896
 $4,747,756
 $—
December 31, 2015  
  
  
  
  
  
  
December 31, 2016  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $4,967
 $3,289
 $11,503
 $19,759
 $2,049,906
 $2,069,665
 $—
 $5,467
 $2,338
 $3,505
 $11,310
 $2,036,741
 $2,048,051
 $—
Commercial real estate —
 —
 —
 —
 690,561
 690,561
 —
 2,416
 —
 —
 2,416
 797,979
 800,395
 —
Home equity line of credit 896
 706
 477
 2,079
 844,215
 846,294
 —
 1,263
 381
 1,342
 2,986
 860,177
 863,163
 —
Residential land —
 —
 415
 415
 17,814
 18,229
 —
 —
 —
 255
 255
 18,634
 18,889
 —
Commercial construction —
 —
 —
 —
 100,796
 100,796
 —
 —
 —
 —
 —
 126,768
 126,768
 —
Residential construction —
 —
 —
 —
 14,089
 14,089
 —
 —
 —
 —
 —
 16,080
 16,080
 —
Commercial 125
 223
 878
 1,226
 757,433
 758,659
 —
 413
 510
 1,303
 2,226
 689,825
 692,051
 —
Consumer 1,383
 593
 644
 2,620
 121,155
 123,775
 —
 1,945
 1,001
 963
 3,909
 174,313
 178,222
 —
Total loans $7,371
 $4,811
 $13,917
 $26,099
 $4,595,969
 $4,622,068
 $—
 $11,504
 $4,230
 $7,368
 $23,102
 $4,720,517
 $4,743,619
 $—



The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due and TDR loans was as follows:
(in thousands) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Real estate:  
  
  
  
Residential 1-4 family $20,929
 $20,554
 $12,270
 $11,154
Commercial real estate 3,762
 1,188
 —
 223
Home equity line of credit 2,404
 2,254
 4,306
 3,080
Residential land 776
 970
 915
 878
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial 23,588
 20,174
 1,972
 6,708
Consumer 1,157
 895
 1,501
 1,282
Total nonaccrual loans $52,616
 $46,035
 $20,964
 $23,325
Real estate:        
Residential 1-4 family $—
 $—
 $—
 $—
Commercial real estate —
 —
 —
 —
Home equity line of credit —
 —
 —
 —
Residential land 393
 —
 —
 —
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial —
 —
 —
 —
Consumer —
 —
 —
 —
Total accruing loans 90 days or more past due $393
 $—
 $—
 $—
Real estate:        
Residential 1-4 family $13,308
 $13,962
 $13,112
 $14,450
Commercial real estate —
 —
 1,289
 1,346
Home equity line of credit 4,501
 2,467
 4,548
 4,934
Residential land 3,258
 4,713
 1,674
 2,751
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial 4,673
 1,104
 2,692
 14,146
Consumer —
 —
 68
 10
Total troubled debt restructured loans not included above $25,740
 $22,246
 $23,383
 $37,637



The total carrying amount and the total unpaid principal balance of impaired loans were as follows:
 September 30, 2016 Three months ended September 30, 2016 Nine months ended September 30, 2016 June 30, 2017 Three months ended June 30, 2017 Six months ended June 30, 2017
(in thousands) 
Recorded
investment
 
Unpaid
principal
balance
 
Related
Allowance
 
Average
recorded
investment
 
Interest
income
recognized*
 
Average
recorded
investment
 
Interest
income
recognized*
 
Recorded
investment
 
Unpaid
principal
balance
 
Related
Allowance
 
Average
recorded
investment
 
Interest
income
recognized*
 
Average
recorded
investment
 
Interest
income
recognized*
With no related allowance recorded  
  
  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $10,137
 $11,473
 $—
 $10,069
 $65
 $10,378
 $268
 $9,364
 $9,963
 $—
 $9,304
 $76
 $9,429
 $160
Commercial real estate 1,351
 1,645
 —
 1,206
 —
 1,177
 —
 —
 —
 —
 143
 11
 182
 11
Home equity line of credit 1,300
 1,695
 —
 1,220
 6
 1,035
 15
 2,287
 2,707
 —
 2,401
 51
 2,203
 65
Residential land 1,608
 2,304
 —
 1,521
 16
 1,532
 47
 1,249
 1,788
 —
 1,075
 8
 1,016
 34
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 6,624
 7,637
 —
 14,352
 141
 9,240
 154
 1,592
 4,267
 —
 1,949
 2
 3,428
 8
Consumer —
 —
 —
 10
 —
 3
 —
 —
 —
 —
 1
 —
 —
 —
 $21,020
 $24,754
 $—
 $28,378
 $228
 $23,365
 $484
 $14,492
 $18,725
 $—
 $14,873
 $148
 $16,258
 $278
With an allowance recorded  
  
  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $11,429
 $11,632
 $1,625
 $11,800
 $119
 $11,933
 $356
 $9,824
 $10,027
 $1,332
 $10,054
 $117
 $10,051
 $236
Commercial real estate 2,411
 2,482
 161
 2,444
 —
 1,939
 —
 1,289
 1,289
 73
 1,292
 14
 1,296
 28
Home equity line of credit 4,587
 4,657
 1,040
 4,165
 36
 3,470
 91
 4,397
 4,425
 275
 4,372
 47
 4,467
 96
Residential land 2,819
 2,819
 951
 2,915
 44
 3,090
 165
 1,340
 1,340
 480
 1,532
 24
 1,804
 61
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 22,061
 22,434
 4,734
 11,433
 65
 15,075
 275
 2,691
 2,691
 939
 2,562
 68
 4,915
 469
Consumer 11
 11
 2
 11
 —
 12
 —
 68
 68
 30
 68
 1
 49
 1
 $43,318
 $44,035
 $8,513
 $32,768
 $264
 $35,519
 $887
 $19,609
 $19,840
 $3,129
 $19,880
 $271
 $22,582
 $891
Total  
  
  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $21,566
 $23,105
 $1,625
 $21,869
 $184
 $22,311
 $624
 $19,188
 $19,990
 $1,332
 $19,358
 $193
 $19,480
 $396
Commercial real estate 3,762
 4,127
 161
 3,650
 —
 3,116
 —
 1,289
 1,289
 73
 1,435
 25
 1,478
 39
Home equity line of credit 5,887
 6,352
 1,040
 5,385
 42
 4,505
 106
 6,684
 7,132
 275
 6,773
 98
 6,670
 161
Residential land 4,427
 5,123
 951
 4,436
 60
 4,622
 212
 2,589
 3,128
 480
 2,607
 32
 2,820
 95
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 28,685
 30,071
 4,734
 25,785
 206
 24,315
 429
 4,283
 6,958
 939
 4,511
 70
 8,343
 477
Consumer 11
 11
 2
 21
 —
 15
 —
 68
 68
 30
 69
 1
 49
 1
 $64,338
 $68,789
 $8,513
 $61,146
 $492
 $58,884
 $1,371
 $34,101
 $38,565
 $3,129
 $34,753
 $419
 $38,840
 $1,169



  December 31, 2015 Three months ended September 30, 2015 Nine months ended September 30, 2015
(in thousands) 
Recorded
investment
 
Unpaid
principal
balance
 
Related
allowance
 
Average
recorded
investment
 
Interest
income
recognized*
 
Average
recorded
investment
 
Interest
income
recognized*
With no related allowance recorded  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $10,596
 $11,805
 $—
 $11,159
 $119
 $11,301
 $274
Commercial real estate 1,188
 1,436
 —
 —
 74
 362
 74
Home equity line of credit 707
 948
 —
 498
 1
 444
 3
Residential land 1,644
 2,412
 —
 2,280
 29
 2,647
 125
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 5,671
 6,333
 —
 4,250
 3
 5,659
 144
Consumer —
 —
 —
 —
 —
 —
 —
  $19,806
 $22,934
 $—
 $18,187
 $226
 $20,413
 $620
With an allowance recorded  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $11,861
 $11,914
 $1,453
 $11,451
 $174
 $11,585
 $430
Commercial real estate —
 —
 —
 —
 —
 1,985
 —
Home equity line of credit 2,518
 2,579
 442
 2,048
 13
 1,295
 27
Residential land 4,039
 4,117
 891
 3,971
 74
 4,435
 241
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 15,448
 16,073
 3,527
 18,487
 106
 10,942
 192
Consumer 13
 13
 7
 14
 —
 15
 —
  $33,879
 $34,696
 $6,320
 $35,971
 $367
 $30,257
 $890
Total  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $22,457
 $23,719
 $1,453
 $22,610
 $293
 $22,886
 $704
Commercial real estate 1,188
 1,436
 —
 —
 74
 2,347
 74
Home equity line of credit 3,225
 3,527
 442
 2,546
 14
 1,739
 30
Residential land 5,683
 6,529
 891
 6,251
 103
 7,082
 366
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 21,119
 22,406
 3,527
 22,737
 109
 16,601
 336
Consumer 13
 13
 7
 14
 —
 15
 —
  $53,685
 $57,630
 $6,320
 $54,158
 $593
 $50,670
 $1,510
  December 31, 2016 Three months ended June 30, 2016 Six months ended June 30, 2016
(in thousands) 
Recorded
investment
 
Unpaid
principal
balance
 
Related
allowance
 
Average
recorded
investment
 
Interest
income
recognized*
 
Average
recorded
investment
 
Interest
income
recognized*
With no related allowance recorded  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $9,571
 $10,400
 $—
 $10,672
 $152
 $10,532
 $203
Commercial real estate 223
 228
 —
 1,152
 —
 1,163
 —
Home equity line of credit 1,500
 1,900
 —
 1,038
 9
 943
 9
Residential land 1,218
 1,803
 —
 1,484
 15
 1,537
 31
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 6,299
 8,869
 —
 8,369
 7
 5,818
 13
Consumer —
 —
 —
 —
 —
 —
 —
  $18,811
 $23,200
 $—
 $22,715
 $183
 $19,993
 $256
With an allowance recorded  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $10,283
 $10,486
 $1,352
 $11,982
 $115
 $12,000
 $237
Commercial real estate 1,346
 1,346
 80
 2,519
 —
 1,686
 —
Home equity line of credit 4,658
 4,712
 215
 3,299
 28
 3,122
 55
Residential land 2,411
 2,411
 789
 2,977
 54
 3,177
 121
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 14,240
 14,240
 1,641
 16,821
 180
 16,896
 210
Consumer 10
 10
 6
 12
 —
 12
 —
  $32,948
 $33,205
 $4,083
 $37,610
 $377
 $36,893
 $623
Total  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
Residential 1-4 family $19,854
 $20,886
 $1,352
 $22,654
 $267
 $22,532
 $440
Commercial real estate 1,569
 1,574
 80
 3,671
 —
 2,849
 —
Home equity line of credit 6,158
 6,612
 215
 4,337
 37
 4,065
 64
Residential land 3,629
 4,214
 789
 4,461
 69
 4,714
 152
Commercial construction —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
Commercial 20,539
 23,109
 1,641
 25,190
 187
 22,714
 223
Consumer 10
 10
 6
 12
 —
 12
 —
  $51,759
 $56,405
 $4,083
 $60,325
 $560
 $56,886
 $879
*Since loan was classified as impaired.
 
Troubled debt restructurings.  A loan modification is deemed to be a troubled debt restructuring (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 collectabilitycollectibility 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-yearthree-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 the second quarters and first six months of 2017 and 2016 and the impact on the allowance for loan losses were as follows:
  Three months ended September 30, 2016 Nine months ended September 30, 2016
  Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance
(dollars in thousands)  Pre-modification Post-modification (as of period end)  Pre-modification Post-modification (as of period end)
Troubled debt restructurings  
  
  
    
  
  
  
Real estate:  
  
  
    
  
  
  
Residential 1-4 family 2
 $251
 $251
 $46
 11
 $2,239
 $2,351
 $305
Commercial real estate —
 —
 —
 —
 —
 —
 —
 —
Home equity line of credit 12
 1,268
 1,268
 237
 30
 2,705
 2,705
 492
Residential land —
 —
 —
 —
 1
 120
 121
 —
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
Commercial 6
 3,462
 3,462
 53
 14
 20,119
 20,119
 723
Consumer —
 —
 —
 —
 —
 —
 —
 —
  20
 $4,981
 $4,981
 $336
 56
 $25,183
 $25,296
 $1,520



  Three months ended June 30, 2017 Six months ended June 30, 2017
  Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance
(dollars in thousands)  Pre-modification Post-modification (as of period end)  Pre-modification Post-modification (as of period end)
Troubled debt restructurings  
  
  
    
  
  
  
Real estate:  
  
  
    
  
  
  
Residential 1-4 family 2
 $360
 $360
 $—
 5
 $872
 $880
 $45
Commercial real estate —
 —
 —
 —
 —
 —
 —
 —
Home equity line of credit 5
 298
 298
 59
 13
 524
 510
 93
Residential land —
 —
 —
 —
 —
 —
 —
 —
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
Commercial —
 —
 —
 —
 1
 342
 342
 —
Consumer —
 —
 —
 —
 1
 59
 59
 27
  7
 $658
 $658
 $59
 20
 $1,797
 $1,791
 $165
 Three months ended September 30, 2015 Nine months ended September 30, 2015 Three months ended June 30, 2016 Six months ended June 30, 2016
 Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance Number of contracts 
Outstanding recorded 
investment1
 Net increase in allowance
(dollars in thousands) Pre-modification Post-modification (as of period end) Pre-modification Post-modification (as of period end) Pre-modification Post-modification (as of period end) Pre-modification Post-modification (as of period end)
Troubled debt restructurings  
  
  
      
  
    
  
  
      
  
  
Real estate:  
  
  
      
  
    
  
  
      
  
  
Residential 1-4 family 3
 $860
 $866
 $1
 10
 $2,055
 $2,079
 $48
 5
 $891
 $885
 $98
 9
 $1,988
 $2,100
 $259
Commercial real estate —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Home equity line of credit 10
 943
 943
 140
 32
 2,062
 2,062
 300
 8
 768
 768
 181
 18
 1,437
 1,437
 255
Residential land —
 —
 —
 —
 —
 —
 —
 —
 1
 120
 121
 —
 1
 120
 121
 —
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 2
 1,208
 1,208
 16
 6
 1,461
 1,461
 94
 5
 457
 457
 145
 8
 16,657
 16,657
 670
Consumer —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 15
 $3,011
 $3,017
 $157
 48
 $5,578
 $5,602
 $442
 19
 $2,236
 $2,231
 $424
 36
 $20,202
 $20,315
 $1,184
1
The reported balances include loans that became TDR during the period, and were fully paid-off, charged-off, or sold prior to period end.


Loans modified in TDRs that experienced a payment default of 90 days or more induring the indicated periods,second quarters and first six months of 2017 and 2016, and for which the payment of default occurred within one year of the modification, were as follows:
 Three months ended September 30, 2016 Nine months ended September 30, 2016 Three months ended June 30, 2017 Six months ended June 30, 2017
(dollars in thousands) Number of contracts Recorded investment 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 $239
 1 $239
 1 $222
 2 $523
Commercial real estate — —
 — —
 — —
 — —
Home equity line of credit — —
 — —
 — —
 — —
Residential land — —
 — —
 — —
 — —
Commercial construction — —
 — —
 — —
 — —
Residential construction — —
 — —
 — —
 ��� —
Commercial — —
 1 25
 — —
 — —
Consumer — —
 — —
 — —
 — —
 1 $239
 2 $264
 1 $222
 2 $523
 Three months ended September 30, 2015 Nine months ended September 30, 2015 Three months ended June 30, 2016 Six months ended June 30, 2016
(dollars in thousands) Number of contracts Recorded investment 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 $488
Commercial real estate — —
 — —
 — —
 — —
Home equity line of credit 1 7
 1 7
 — —
 — —
Residential land — —
 — —
 — —
 — —
Commercial construction — —
 — —
 — —
 — —
Residential construction — —
 — —
 — —
 — —
Commercial — —
 — —
 1 26
 1 26
Consumer — —
 — —
 — —
 — —
 1 $7
 1 $7
 1 $26
 2 $514
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 $2.5nil and $2.6 million at SeptemberJune 30, 20162017. and December 31, 2016, respectively.
The Company had $4.6 million and $3.6 million of consumer mortgage loans collateralized by residential real estate property that were in the process of foreclosure at June 30, 2017 and December 31, 2016, respectively.
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 proceeds from the sale of residential mortgages of $70.0$39.3 million and $58.2$58.1 million for the three months ended SeptemberJune 30, 2017 and 2016 and 2015 and $168.5$79.9 million and $231.5$98.5 million for the ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, respectively, and recognized gains on such sales of $2.4$0.6 million and $1.4$1.5 million for the three months ended SeptemberJune 30, 2017 and 2016 and 2015 and $5.1$1.4 million and $5.3$2.7 million for the ninesix months ended SeptemberJune 30, 20162017 and 20152016, respectively.
There were no repurchased mortgage loans for the three and six months ended SeptemberJune 30, 20162017 and 2015 and nine months ended September 30, 2016 and 2015.2016. The repurchase reserve was $0.1 million and $0.1 million as of SeptemberJune 30, 20162017 and 2015, respectively.2016.
Mortgage servicing fees, a component of other income, net, were $0.7 million and $0.9 million for both the three months ended SeptemberJune 30, 2017 and 2016 and 2015 and $2.1$1.5 million and $2.7$1.4 million for the ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, respectively.


Changes in the carrying value of mortgage servicing rights were as follows:
(in thousands) 
Gross
carrying amount1
 
Accumulated amortization1
 Valuation allowance Net
carrying amount
September 30, 2016 $16,475
 $(7,284) $—
 $9,191
December 31, 2015 14,531
 (5,647) —
 8,884
(in thousands) 
Gross
carrying amount1
 
Accumulated amortization1
 Valuation allowance Net
carrying amount
June 30, 2017 $18,069
 $(8,888) $—
 $9,181
December 31, 2016 17,271
 (7,898) —
 9,373
1 Reflects the impact of loans paid in full.

Changes related to mortgage servicing rights were as follows:
 Three months ended June 30 Six months ended June 30
(in thousands)2016
 2015
 2017 2016 2017 2016
Mortgage servicing rights           
Balance, January 1$8,884
 $11,749
Beginning balance $9,294
 $8,857
 $9,373
 $8,884
Amount capitalized1,944
 2,636
 362
 665
 798
 1,120
Amortization(1,637) (2,123) (475) (506) (990) (988)
Other-than-temporary impairment—
 (4) —
 —
 —
 —
Carrying amount before valuation allowance, September 309,191
 12,258
Carrying amount before valuation allowance 9,181
 9,016
 9,181
 9,016
Valuation allowance for mortgage servicing rights           
Balance, January 1—
 209
Beginning balance —
 —
 —
 —
Provision (recovery)—
 (205) —
 —
 —
 —
Other-than-temporary impairment—
 (4) —
 —
 —
 —
Balance, September 30—
 —
Ending balance —
 —
 —
 —
Net carrying value of mortgage servicing rights$9,191
 $12,258
 $9,181
 $9,016
 $9,181
 $9,016
ASB capitalizes mortgage servicing rights acquired through either the purchase or originationupon the sale 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“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 mortgage servicing rights used in the impairment analysis were as follows:
(dollars in thousands) September 30, 2016
 December 31, 2015
 June 30, 2017
 December 31, 2016
Unpaid principal balance $1,160,266
 $1,097,314
 $1,208,404
 $1,188,380
Weighted average note rate 4.00% 4.05% 3.95% 3.96%
Weighted average discount rate 9.4% 9.6% 10.0% 9.4%
Weighted average prepayment speed 12.4% 9.3% 8.8% 8.5%


The sensitivity analysis of fair value of MSRMSRs to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions was as follows:
(dollars in thousands) September 30, 2016
 December 31, 2015
 June 30, 2017
 December 31, 2016
Prepayment rate:        
25 basis points adverse rate change $(533) $(561) $(939) $(567)
50 basis points adverse rate change (952) (1,104) (2,048) (1,154)
Discount rate:        
25 basis points adverse rate change (90) (111) (115) (128)
50 basis points adverse rate change (179) (220) (227) (254)

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.
Other borrowings.  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 a 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
 
Gross amount of
recognized liabilities
 
Gross amount offset in
the Balance Sheet
 
Net amount of liabilities presented
in the Balance Sheet
Repurchase agreements            
September 30, 2016 $165 $— $165
December 31, 2015 229 — 229
June 30, 2017 $88 $— $88
December 31, 2016 93 — 93
 Gross amount not offset in the Balance Sheet Gross amount not offset in the Balance Sheet
(in millions) 
 
Liabilities presented
in the Balance Sheet
 
Financial
instruments
 
Cash
collateral
pledged
 
 Net amount of liabilities presented
in the Balance Sheet
 
Financial
instruments
 
Cash
collateral
pledged
September 30, 2016  
  
  
June 30, 2017  
  
  
Financial institution $50
 $53
 $—
 $—
 $—
 $—
Government entities 14
 16
 —
 —
 —
 —
Commercial account holders 101
 135
 —
 88
 120
 —
Total $165
 $204
 $—
 $88
 $120
 $—
December 31, 2015  
  
  
December 31, 2016  
  
  
Financial institution $50
 $56
 $—
 $—
 $—
 $—
Government entities 56
 61
 —
 14
 15
 —
Commercial account holders 123
 144
 —
 79
 101
 —
Total $229
 $261
 $—
 $93
 $116
 $—
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.
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:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in thousands) Notional amount Fair value Notional amount Fair value Notional amount Fair value Notional amount Fair value
Interest rate lock commitments $40,700
 $843
 $22,241
 $384
 $22,737
 $126
 $25,883
 $421
Forward commitments 43,500
 (163) 23,644
 (29) 22,925
 88
 30,813
 (177)
ASB’s derivative financial instruments, their fair values and balance sheet location were as follows:
Derivative Financial Instruments Not Designated as Hedging Instruments 1
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in thousands)  Asset derivatives 
 Liability
derivatives
  Asset derivatives  Liability
derivatives		  Asset derivatives 
 Liability
derivatives
  Asset derivatives  Liability
derivatives
Interest rate lock commitments $843
 $—
 $384
 $—
 $142
 $16
 $445
 $24
Forward commitments 1
 164
 1
 30
 88
 —
 8
 185
 $844
 $164
 $385
 $30
 $230
 $16
 $453
 $209
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 theASB’s statements of income:
Derivative Financial Instruments Not Designated as Hedging Instruments
Location of net gains (losses) recognized in the Statement of Income
 Three months ended September 30 Nine months ended September 30 Location of net gains (losses) recognized in the Statement of Income Three months ended June 30 Six months ended June 30
(in thousands) 2016 2015 2016 2015 2017 2016 2017 2016
Interest rate lock commitmentsMortgage banking income $48
 $139
 $459
 $195
 Mortgage banking income $(191) $140
 $(295) $411
Forward commitmentsMortgage banking income 103
 (117) (134) (18) Mortgage banking income 192
 (74) 265
 (237)
 $151
 $22
 $325
 $177
 $1
 $66
 $(30) $174
Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $18.1$14.3 million and $10.1$14.0 million at SeptemberJune 30, 20162017 and December 31, 2015,2016, respectively. These unfunded commitments were unconditional and legally binding and are recorded in other liabilities with a corresponding increase in other assets. Cash contributions and payments made on commitments to LIHTC investment partnerships are classified as operating activities in the Company’s consolidated statements of cash flows. As of SeptemberJune 30, 2016,2017, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investment partnerships.
Contingencies.  ASB is 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, ASB cannot rule out the possibility that such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.
5 · Credit agreements and long-term debt
Credit agreements. HEI and Hawaiian Electric each entered into a separate agreement with a syndicate of eight financial institutions (the HEI Facility and Hawaiian Electric Facility, respectively, and together, the Facilities), effective July 3, 2017, to


amend and restate their respective previously existing revolving unsecured credit agreements. The $150 million HEI Facility extended the term of the facility to June 30, 2022. The $200 million Hawaiian Electric Facility has an initial term that expires on June 29, 2018, but its term will extend to June 30, 2022, if and when approved by the PUC during the initial term. As of June 30, 2017 and December 31, 2016, no amounts were outstanding under the previously existing facilities.
The 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.
Changes in long-term debt. On June 29, 2017, the Department of Budget and Finance of the State of Hawaii (Department) for the benefit of the Utilities, issued, at par:
 Refunding Series 2017A Special Purpose Revenue BondsRefunding Series 2017B Special Purpose Revenue Bonds
Aggregate principal amount$125 million$140 million
Fixed coupon interest rate3.10%4.00%
Maturity dateMay 1, 2026March 1, 2037
Department loaned the proceeds to:  
Hawaiian Electric$62 million$100 million
Hawaii Electric Light$8 million$20 million
Maui Electric$55 million$20 million

Proceeds from the sale were applied to redeem at par bonds previously issued by the Department for the benefit of the Utilities:
 Refunding Series 2007B Special Purpose Revenue BondsSeries 2007A Special Purpose Revenue Bonds
Aggregate principal amount$125 million$140 million
Fixed coupon interest rate4.60%4.65%
Maturity dateMay 1, 2026March 1, 2037
6 · Shareholders’ equity
Accumulated other comprehensive income/(loss).Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:
 HEI Consolidated Hawaiian Electric Consolidated
 (in thousands) Net unrealized gains (losses) on securities  Unrealized gains (losses) on derivatives Retirement benefit plans AOCI Unrealized gains (losses) on derivatives Retirement benefit plans AOCI
Balance, December 31, 2016$(7,931) $(454) $(24,744) $(33,129) $(454) $132
 $(322)
Current period other comprehensive income2,244
 454
 657
 3,355
 454
 45
 499
Balance, June 30, 2017$(5,687) $—
 $(24,087) $(29,774) $—
 $177
 $177
Balance, December 31, 2015$(1,872) $(54) $(24,336) $(26,262) $—
 $925
 $925
Current period other comprehensive income9,984
 311
 613
 10,908
 257
 4
 261
Balance, June 30, 2016$8,112
 $257
 $(23,723) $(15,354) $257
 $929
 $1,186


Reclassifications out of AOCI were as follows:
  Amount reclassified from AOCI Amount reclassified from AOCI  
  Three months ended June 30 Six months ended June 30 Affected line item in the
(in thousands) 2017 2016 2017 2016  Statements of Income / Balance Sheets
HEI consolidated          
Net realized gains on securities included in net income $—
 $(360) $—
 $(360) Revenues-bank (net gains on sales of securities)
Derivatives qualifying as cash flow hedges:  
  
  
  
  
Window forward contracts —
 —
 454
 —
 
Construction in progress-electric utilities (losses on window forward contracts - see Note 3 for additional details)
Interest rate contracts (settled in 2011) —
 —
 —
 54
 Interest expense
Retirement benefit plans:  
  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 3,930
 3,698
 7,851
 7,236
 See Note 7 for additional details
Impact of D&Os of the PUC included in regulatory assets (3,581) (3,401) (7,194) (6,623) See Note 7 for additional details
Total reclassifications $349
 $(63) $1,111
 $307
  
Hawaiian Electric consolidated          
Derivatives qualifying as cash flow hedges:          
Window forward contracts $—
 $—
 $454
 $—
 
Construction in progress (losses on window forward contracts - see Note 3 for additional details)
Retirement benefit plans:    
    
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 3,621
 3,391
 7,239
 6,627
 See Note 7 for additional details
Impact of D&Os of the PUC included in regulatory assets (3,581) (3,401) (7,194) (6,623) See Note 7 for additional details
Total reclassifications $40
 $(10) $499
 $4
  



67 · Retirement benefits
Defined benefit pension and other postretirement benefit plans information.  For the first ninesix months of 20162017, the Company contributed $4933 million ($48 million(nearly all by the Utilities) to its pension and other postretirement benefit plans, compared to $6633 million ($6532 million by the Utilities) in the first ninesix months of 2015.2016. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 20162017 is $65$67 million ($6466 million by the Utilities, $1 million by HEI and nil by ASB), compared to $8865 million ($8664 million by the Utilities, $21 million by HEI and nil by ASB) in 20152016. In addition, the Company expects to pay directly $3$2 million ($1 million by the Utilities) of benefits in 20162017, compared to $12 million ($0.41 million by the Utilities) paid in 20152016.
The components of net periodic benefit costNPPC and NPBC for HEI consolidated and Hawaiian Electric consolidated were as follows:
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
 Pension benefits Other benefits Pension benefits Other benefits Pension benefits Other benefits Pension benefits Other benefits
(in thousands) 2016 2015 2016 2015 2016 2015 2016 2015 2017 2016 2017 2016 2017 2016 2017 2016
HEI consolidated                                
Service cost $15,126
 $16,577
 $831
 $982
 $45,430
 $49,683
 $2,499
 $2,945
 $15,870
 $14,913
 $847
 $832
 $32,364
 $30,304
 $1,687
 $1,668
Interest cost 20,396
 19,229
 2,417
 2,254
 61,154
 57,731
 7,254
 6,757
 20,361
 20,481
 2,315
 2,363
 40,577
 40,758
 4,726
 4,837
Expected return on plan assets (24,640) (22,126) (3,064) (2,912) (73,920) (66,426) (9,207) (8,753) (25,646) (24,616) (3,104) (3,091) (51,367) (49,280) (6,170) (6,143)
Amortization of net prior service loss (gain) (15) 1
 (449) (448) (43) 3
 (1,345) (1,345)
Amortization of net prior service gain (13) (14) (448) (448) (27) (28) (897) (896)
Amortization of net actuarial loss 6,228
 9,191
 200
 450
 18,605
 27,608
 603
 1,346
 6,707
 6,408
 199
 116
 13,220
 12,377
 565
 403
Net periodic benefit cost 17,095
 22,872
 (65) 326
 51,226
 68,599
 (196) 950
Net periodic pension/benefit cost 17,279
 17,172
 (191) (228) 34,767
 34,131
 (89) (131)
Impact of PUC D&Os (4,653) (10,017) 336
 (60) (13,464) (29,994) 1,008
 (180) (4,867) (4,765) 527
 483
 (10,023) (8,811) 673
 672
Net periodic benefit cost (adjusted for impact of PUC D&Os) $12,442
 $12,855
 $271
 $266
 $37,762
 $38,605
 $812
 $770
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os) $12,412
 $12,407
 $336
 $255
 $24,744
 $25,320
 $584
 $541
Hawaiian Electric consolidated                                
Service cost $14,699
 $16,066
 $821
 $967
 $44,097
 $48,197
 $2,463
 $2,902
 $15,436
 $14,465
 $841
 $820
 $31,530
 $29,398
 $1,676
 $1,642
Interest cost 18,702
 17,632
 2,334
 2,175
 56,106
 52,897
 7,003
 6,525
 18,726
 18,801
 2,231
 2,280
 37,315
 37,404
 4,558
 4,669
Expected return on plan assets (22,908) (20,635) (3,023) (2,873) (68,725) (61,906) (9,072) (8,621) (23,935) (22,885) (3,056) (3,046) (47,946) (45,817) (6,073) (6,049)
Amortization of net prior service loss (gain) 3
 10
 (451) (450) 10
 30
 (1,353) (1,352) 2
 3
 (451) (451) 4
 7
 (902) (902)
Amortization of net actuarial loss 5,674
 8,342
 198
 438
 17,020
 25,028
 595
 1,315
 6,190
 5,885
 192
 113
 12,196
 11,346
 551
 397
Net periodic benefit cost 16,170
 21,415
 (121) 257
 48,508
 64,246
 (364) 769
Net periodic pension/benefit cost 16,419
 16,269
 (243) (284) 33,099
 32,338
 (190) (243)
Impact of PUC D&Os (4,653) (10,017) 336
 (60) (13,464) (29,994) 1,008
 (180) (4,867) (4,765) 527
 483
 (10,023) (8,811) 673
 672
Net periodic benefit cost (adjusted for impact of PUC D&Os) $11,517
 $11,398
 $215
 $197
 $35,044
 $34,252
 $644
 $589
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os) $11,552
 $11,504
 $284
 $199
 $23,076
 $23,527
 $483
 $429
HEI consolidated recorded retirement benefits expense of $2617 million ($2315 million by the Utilities) and $2718 million ($2216 million by the Utilities) in the first ninesix months of 20162017 and 2015,2016, respectively, and charged the remaining net periodic benefit cost primarily to electric utility plant.
The Utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the issuance of the PUC’s D&O in the respective utility’s next rate case.
Defined contribution plans information.  For the first ninesix months of 20162017 and 2015,2016, the Company’s expenses for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan were $4.13.3 million and $4.02.8 million, respectively, and cash contributions were $4.64.0 million and $4.33.7 million, respectively. For the first ninesix months of 20162017 and 2015,2016, the Utilities’ expenses for its defined contribution pension plan under the HEIRSP were $1.2$1.0 million and $1.1$0.8 million, respectively, and cash contributions were $1.2$1.0 million and $1.1$0.8 million, respectively.


78 · 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 SeptemberJune 30, 20162017, approximately 3.43.3 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 0.4 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).
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 SeptemberJune 30, 20162017, there were 121,19885,428 shares remaining available for future issuance under the 2011 Director Plan.
Share-based compensation expense and the related income tax benefit were as follows:
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
HEI consolidated                
Share-based compensation expense 1
 $1.6
 $1.0
 $3.6
 $4.8
 $2.2
 $1.0
 $3.3
 $2.0
Income tax benefit 0.5
 0.3
 1.2
 1.7
 0.8
 0.4
 1.2
 0.7
Hawaiian Electric consolidated                
Share-based compensation expense 1
 0.5
 0.1
 1.0
 1.3
 0.7
 0.3
 1.1
 0.6
Income tax benefit 0.2
 —
 0.4
 0.5
 0.3
 0.1
 0.4
 0.2
1 
For the three months and ninesix months ended SeptemberJune 30, 2017 and 2016, the Company has not capitalized any share-based compensation. $0.03 million and $0.12 million of this share-based compensation expense was capitalized in the three and nine months ended September 30, 2015.

Stock awards. No nonemployee director stock grants were awarded from January 1 to September 29,June 30, 2016. Nonemployee director awards totaling $0.2 million were paid in cash in July 2016. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:
 Nine months ended September 30 Three months ended June 30 Six months ended June 30
($ in millions) 2016 2015 2017 2016 2017 2016
Shares granted 19,846
 28,246
 35,000
 —
 35,770
 —
Fair value $0.6
 $0.8
 $1.1
 $—
 $1.2
 $—
Income tax benefit 0.2
 0.3
 0.4
 —
 0.5
 —
The number of shares issued to each nonemployee directordirectors of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI Common Stock on the grant date.
Stock appreciation rights.  As of September 30, 2016 and December 31, 2015, there were no remaining SARs outstanding.
SARs activity and statistics were as follows:
 Three months ended September 30 Nine months ended September 30
(dollars in thousands, except prices)2015 2015
Shares underlying SARs exercised—
 80,000
Weighted-average price of shares exercised$—
 $26.18
Intrinsic value of shares exercised 1
—
 502
Tax benefit realized for the deduction of exercises—
 82
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 stock units.  Information about HEI’s grants of restricted stock units was as follows:
Three months ended September 30 Nine months ended September 30Three months ended June 30 Six months ended June 30
2016 2015 2016 20152017 2016 2017 2016
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period225,752
 $29.59
 252,302
 $28.35
 210,634
 $28.82
 261,235
 $25.77
236,036
 $31.42
 226,537
 $29.59
 220,683
 $29.57
 210,634
 $28.82
Granted766

30.65
 690
 30.91
 95,048

29.91
 85,772

33.69
896

33.06
 —
 —
 97,873

33.47
 94,282

29.90
Vested(4,419) 27.26
 (19,840) 25.35
 (83,583) 27.88
 (99,891) 25.69
(7,370) 29.17
 (785) 27.88
 (88,994) 28.88
 (79,164) 27.91
Forfeited(2,352) 29.69
 (14,316) 25.82
 (2,352) 29.69
 (28,280) 26.66
(23,079) 31.50
 —
 —
 (23,079) 31.50
 —
 —
Outstanding, end of period219,747
 $29.64
 218,836
 $28.79
 219,747
 $29.64
 218,836
 $28.79
206,483
 $31.50
 225,752
 $29.59
 206,483
 $31.50
 225,752
 $29.59
Total weighted-average grant-date fair value of shares granted ($ millions)$—
   $—
   $2.8
   $2.9
  $—
   $—
   $3.3
   $2.8
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.


For the first six months of 2017 and 2016, total restricted stock units that vested and related dividends had a fair value of $3.3 million and $2.6 million, respectively, and the related tax benefits were $1.2 million and $0.9 million, respectively.
As of SeptemberJune 30, 2016,2017, there was $4.4$5.4 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 2.6 years.
For the first nine months of 2016 and 2015, total restricted stock units that vested and related dividends had a fair value of $2.7 million and $3.7 million, respectively, and the related tax benefits were $0.9 million and $1.1 million, respectively.2.8 years.
Long-term incentive plan payable in stock.  The 2014-20162017-2019 long-term incentive plan (LTIP) provides for performance awards under the original EIP of shares of HEI common stock based on the satisfaction of performance goals, considered to beincluding a market condition and service conditions.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.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 LTIP performance goals for the LTIP period includes awards with a market condition goal is based on HEI’s total shareholder return to shareholders (TRS) of HEI stock as a percentile(TSR) compared to the Edison Electric Institute Index over the three-yearthree-year period. In addition, the 2014-2016 LTIP hasThe other performance condition goals relatedrelate to levels of HEI consolidatedEPS growth, 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.ASB’s efficiency ratio. The 2015-2017 and the 2016-2018 LTIPLTIPs provide for performance awards payable in cash, and thus are not included in the tables below.
LTIP linked to TRSTSR.  Information about HEI’s LTIP grants linked to TRSTSR was as follows:
Three months ended September 30 Nine months ended September 30Three months ended June 30 Six months ended June 30
2016 2015 2016 20152017 2016 2017 2016
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period83,947
 $22.95
 163,423
 $27.63
 162,500
 $27.66
 257,956
 $28.45
36,971
 $39.51
 83,947
 $22.95
 83,106
 $22.95
 162,500
 $27.66
Granted (target level)—
 —
 —
 —
 —
 —
 —

—
233
 39.51
 —
 —
 37,204
 39.51
 —

—
Vested (issued or unissued and cancelled)—
 —
 —
 —
 (78,553) 32.69
 (75,915) 30.71
—
 —
 —
 —
 (83,106) 22.95
 (78,553) 32.69
Forfeited(175) 22.95
 —
 —
 (175) 22.95
 (18,618) 26.41
(3,434) 39.51
 —
 —
 (3,434) 39.51
 —
 —
Outstanding, end of period83,772
 $22.95
 163,423
 $27.63
 83,772
 $22.95
 163,423
 $27.63
33,770
 $39.51
 83,947
 $22.95
 33,770
 $39.51
 83,947
 $22.95
Total weighted-average grant-date fair value of shares granted ($ millions)$—
   $—
   $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:
2017
Risk-free interest rate1.46%
Expected life in years3
Expected volatility20.1%
Range of expected volatility for Peer Group15.4% to 26.0%
Grant date fair value (per share)$39.51
For the ninesix months ended SeptemberJune 30, 20162017, total vested LTIP awards linked to TSR and 2015,related dividends had a fair value of $1.9 million and the related tax benefits were $0.7 million. For the six months ended June 30, 2016, all vested shares in the table above were unissued and cancelled (i.e., lapsed) because the TRSTSR goal was not met.
As of SeptemberJune 30, 2016,2017, there was $0.1$1.1 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS.TSR. The cost is expected to be recognized over a weighted-average period of 0.32.5 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:
Three months ended September 30 Nine months ended September 30Three months ended June 30 Six months ended June 30
2016 2015 2016 20152017 2016 2017 2016
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period113,550
 $25.18
 220,158
 $26.00
 222,647
 $26.02
 364,731
 $26.01
147,888
 $33.48
 113,550
 $25.18
 109,816
 $25.18
 222,647
 $26.02
Granted (target level)—
 —
 —

—
 —
 —
 —

—
930
 32.58
 —

—
 148,818
 33.47
 —

—
Vested (issued)—
 —
 —
 —
 (109,097) 26.89
 (121,249) 26.05
—
 —
 —
 —
 (109,816) 25.18
 (109,097) 26.89
Cancelled—
 —
 (14,050) 26.89
 —
 —
 (14,050) 26.89
Forfeited(699) 25.19
 —
 —
 (699) 25.19
 (23,324) 25.85
(13,740) 33.48
 —
 —
 (13,740) 33.48
 —
 —
Outstanding, end of period112,851
 $25.18
 206,108
 $25.94
 112,851
 $25.18
 206,108
 $25.94
135,078
 $33.47
 113,550
 $25.18
 135,078
 $33.47
 113,550
 $25.18
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)$—
   $—
   $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.
For the ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $3.6$4.2 million and $4.7$3.6 million and the related tax benefits were $1.4$1.6 million and $1.8$1.4 million, respectively.
As of SeptemberJune 30, 2016,2017, there was $0.2$3.8 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS.TSR. The cost is expected to be recognized over a weighted-average period of 0.32.5 years.
8 9 · Shareholders’ equity Income taxes
        The Company’s ETRs (combined federal and state income tax rates) for the second quarters of 2017 and 2016 were 34% and 37%, respectively, and for the first six months of 2017 and 2016 were 34% and 37%, respectively. The ETR was lower for the three months and six months ended June 30, 2017 compared to the same periods in 2016 due in part to 2016 nondeductible merger- and spin-off-related expenses. Also, in the first quarter of 2017, the Company recognized excess tax benefits on share-based compensation after the adoption of ASU No. 2016-09.
        Hawaiian Electric’s ETRs for the second quarters of 2017 and 2016 were 36% and 38%, respectively, and for the first six months of 2017 and 2016 were 36% and 37%, respectively. The lower ETR was due in part to the recognition of excess tax benefits on share-based compensation after the adoption of ASU No. 2016-09.
Equity forward transactionRecent tax developments. .  On March 19, 2013, HEI entered into an equity forward transactionThe extension of bonus depreciation under the “Protecting Americans from Tax Hikes (PATH) Act of 2015” continues to be the most significant recent tax change. The PATH Act provides 50% bonus depreciation through 2017, phases down the percentage to 40% in connection with a public offering on that date2018 and 30% in 2019 and then terminates bonus depreciation thereafter. Tax depreciation is expected to increase by approximately $120 million in 2017 due to bonus depreciation, which has the effect of 6.1 million sharesincreasing accumulated deferred tax liabilities. However, the rate 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 connectiongrowth of accumulated deferred tax liabilities is decreasing over time as book depreciation “catches up” with the resulting additional 0.9 million shares of HEI common stock.tax depreciation taken in the past.
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 Accounting Standards Codification (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.


Accumulated other comprehensive income.10 Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:· Cash flows
 HEI Consolidated Hawaiian Electric Consolidated
 (in thousands) Net unrealized gains (losses) on securities  Unrealized gains (losses) on derivatives  Retirement benefit plans AOCI  Unrealized gains on derivatives Retirement benefit plans AOCI
Balance, December 31, 2015$(1,872) $(54) $(24,336) $(26,262) $—
 $925
 $925
Current period other comprehensive income7,837
 459
 943
 9,239
 405
 7
 412
Balance, September 30, 2016$5,965
 $405
 $(23,393) $(17,023) $405
 $932
 $1,337
Balance, December 31, 2014$462
 $(289) $(27,551) $(27,378) $—
 $45
 $45
Current period other comprehensive income3,608
 177
 1,576
 5,361
 —
 11
 11
Balance, September 30, 2015$4,070
 $(112) $(25,975) $(22,017) $—
 $56
 $56
Six months ended June 30 2017 2016
(in millions)    
Supplemental disclosures of cash flow information  
  
HEI consolidated    
Interest paid to non-affiliates $46
 $43
Income taxes paid (including refundable credits) 21
 14
Income taxes refunded (including refundable credits) —
 45
Hawaiian Electric consolidated    
Interest paid to non-affiliates 36
 31
Income taxes paid (including refundable credits) 8
 —
Income taxes refunded (including refundable credits) —
 20
Supplemental disclosures of noncash activities  
  
HEI consolidated    
Common stock dividends reinvested in HEI common stock (financing)1
 —
 11
Loans transferred from held for investment to held for sale (investing) 9
 —
Common stock issued (gross) for director and executive/management compensation (financing)2
 11
 6
HEI consolidated and Hawaiian Electric consolidated    
Electric utility property, plant and equipment    
Estimated fair value of noncash contributions in aid of construction (investing) 2
 8
Change in unpaid invoices and accruals for capital expenditures (investing) (7) (32)
Reclassifications out1The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.
2The amounts shown represent the market value of AOCI were as follows:common stock issued for director and executive/management compensation and withheld to satisfy statutory tax liabilities.
  Amount reclassified from AOCI  
  Three months ended September 30 Nine months ended September 30 Affected line item in the
(in thousands) 2016 2015 2016 2015  Statement of Income
HEI consolidated          
Net realized gains on securities $—
 $—
 $(360) $—
 Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges  
  
  
  
  
Window forward contracts (173) —
 (173) —
 Revenues-electric utility (gains on window forward)
Interest rate contracts (settled in 2011) —
 59
 54
 177
 Interest expense
Retirement benefit plan items  
  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 3,641
 5,611
 10,877
 16,850
 See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets (3,311) (5,091) (9,934) (15,274) See Note 6 for additional details
Total reclassifications $157
 $579
 $464
 $1,753
  
Hawaiian Electric consolidated          
Derivatives qualified as cash flow hedges          
Window forward contracts $(173) $—
 $(173) $—
 Revenues (gains on window forward)
Retirement benefit plan items    
    
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 3,314
 5,095
 9,941
 15,285
 See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets (3,311) (5,091) (9,934) (15,274) See Note 6 for additional details
Total reclassifications $(170) $4
 $(166) $11
  

911 · 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 and goodwill.
Fair value measurement and disclosure valuation methodology. FollowingThe 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 the CompanyASB 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 Company’sASB’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.
The fair value of the mortgage revenue bond 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. Residential mortgage loansLoans carried at the lower of cost or market 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. ASB transferred $6.1 million of loans receivable out of Level 3 into Level 2 due to changes in the observability of significant inputs during the six months ended June 30, 2017. The related gain from the fair value adjustment of loans sold was not material in the three and six months ended June 30, 2017.
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


along with various forecast valuation assumptions including prepayment forecasts, to determine the discount rate. These assumptions are derived from internal and third party sources. Noting 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 rights 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 their 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 deposits. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.
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—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 remaining maturities.
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 contractcontracts. The estimated fair value of the Utilities’ window forward contracts 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.


   Estimated fair value   Estimated fair value
 Carrying or notional amount 
Quoted
 prices in
active markets
for identical assets
 
Significant
 other observable
 inputs
 
Significant
unobservable
inputs
   Carrying or notional amount 
Quoted prices in
active markets
for identical assets
 
Significant
 other observable
 inputs
 
Significant
unobservable
inputs
  
(in thousands) (Level 1) (Level 2) (Level 3) Total (Level 1) (Level 2) (Level 3) Total
September 30, 2016  
  
  
  
  
June 30, 2017  
  
  
  
  
Financial assets  
  
  
  
  
  
  
  
  
  
Money market funds $45,030
 $—
 $45,030
 $—
 $45,030
HEI consolidated          
Available-for-sale investment securities 996,984
 —
 996,984
 —
 996,984
 $1,302,886
 $—
 $1,287,459
 $15,427
 $1,302,886
Stock in Federal Home Loan Bank 11,218
 —
 11,218
 —
 11,218
 11,706
 —
 11,706
 —
 11,706
Loans receivable, net 4,702,644
 —
 26,784
 4,923,457
 4,950,241
 4,693,539
 —
 5,261
 4,836,804
 4,842,065
Mortgage servicing rights 9,191
 —
 —
 10,971
 10,971
 9,181
 —
 —
 12,270
 12,270
Bank-owned life insurance 141,262
 —
 141,262
 —
 141,262
 146,122
 —
 146,122
 —
 146,122
Derivative assets 62,581
 —
 1,508
 —
 1,508
 58,120
 47
 798
 —
 845
The Utilities’ derivative assets (included in amount above) 20,725
 —
 664
 —
 664
Hawaiian Electric consolidated          
Derivative assets-window forward contracts 15,995
 —
 615
 —
 615
Financial liabilities  
  
  
  
    
  
  
  
  
HEI consolidated          
Deposit liabilities 5,380,721
 —
 5,384,924
 —
 5,384,924
 5,724,386
 —
 5,721,882
 —
 5,721,882
Short-term borrowings—other than bank 49,789
 —
 49,789
 —
 49,789
Other bank borrowings 265,388
 —
 267,892
 —
 267,892
 188,130
 —
 188,513
 —
 188,513
Long-term debt, net—other than bank 1,579,065
 —
 1,741,707
 —
 1,741,707
 1,618,647
 —
 1,740,479
 —
 1,740,479
The Utilities’ long-term debt, net (included in amount above) 1,279,327
 —
 1,432,766
 —
 1,432,766
Derivative liabilities 42,344
 121
 43
 —
 164
 8,263
 —
 246
 —
 246
December 31, 2015  
  
  
  
  
Hawaiian Electric consolidated          
Short-term borrowings 43,990
 —
 43,990
 —
 43,990
Long-term debt, net 1,318,845
 —
 1,434,528
 —
 1,434,528
Derivative liabilities-window forward contracts 4,726
 —
 230
 —
 230
December 31, 2016  
  
  
  
  
Financial assets  
  
  
  
  
  
  
  
  
  
HEI consolidated          
Money market funds $10
 $—
 $10
 $—
 $10
 $13,085
 $—
 $13,085
 $—
 $13,085
Available-for-sale investment securities 820,648
 —
 820,648
 —
 820,648
 1,105,182
 —
 1,089,755
 15,427
 1,105,182
Stock in Federal Home Loan Bank 10,678
 —
 10,678
 —
 10,678
 11,218
 —
 11,218
 —
 11,218
Loans receivable, net 4,570,412
 —
 4,639
 4,744,886
 4,749,525
 4,701,977
 —
 13,333
 4,839,493
 4,852,826
Mortgage servicing rights 8,884
 —
 —
 11,790
 11,790
 9,373
 —
 —
 13,216
 13,216
Bank-owned life insurance 138,139
 —
 138,139
 —
 138,139
 143,197
 —
 143,197
 —
 143,197
Derivative assets 22,616
 —
 385
 —
 385
 23,578
 —
 453
 —
 453
Financial liabilities  
  
  
  
    
  
  
  
  
HEI consolidated          
Deposit liabilities 5,025,254
 —
 5,024,500
 —
 5,024,500
 5,548,929
 —
 5,546,644
 —
 5,546,644
Short-term borrowings—other than bank 103,063
 —
 103,063
 —
 103,063
 —
 —
 —
 —
 —
Other bank borrowings 328,582
 —
 333,392
 —
 333,392
 192,618
 —
 193,991
 —
 193,991
Long-term debt, net—other than bank* 1,578,368
 —
 1,669,087
 —
 1,669,087
The Utilities’ long-term debt, net (included in amount above)* 1,278,702
 —
 1,363,766
 —
 1,363,766
Long-term debt, net—other than bank 1,619,019
 —
 1,704,717
 —
 1,704,717
Derivative liabilities 23,269
 15
 15
 —
 30
 53,852
 129
 823
 —
 952
Hawaiian Electric consolidated          
Long-term debt, net 1,319,260
 —
 1,399,490
 —
 1,399,490
Derivative liabilities-window forward contracts 20,734
 —
 743
 —
 743
* See Note 11 for the impact to prior period financial information of the adoption of ASU No. 2015-03.


Fair value measurements on a recurring basis.  Assets and liabilities measured at fair value on a recurring basis were as follows:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
 Fair value measurements using Fair value measurements using Fair value measurements using Fair value measurements using
(in thousands) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Money market funds (“other” segment) $—
 $45,030
 $—
 $—
 $10
 $—
 $—
 $—
 $—
 $—
 $13,085
 $—
Available-for-sale investment securities (bank segment)  
  
  
  
  
  
  
  
  
  
  
  
Mortgage-related securities-FNMA, FHLMC and GNMA $—
 $807,612
 $—
 $—
 $607,689
 $—
 $—
 $1,100,876
 $—
 $—
 $897,474
 $—
U.S. Treasury and federal agency obligations —
 189,372
 —
 —
 212,959
 —
 —
 186,583
 —
 —
 192,281
 —
Mortgage revenue bond —
 —
 15,427
 —
 —
 15,427
 $—
 $996,984
 $—
 $—
 $820,648
 $—
 $—
 $1,287,459
 $15,427
 $—
 $1,089,755
 $15,427
Derivative assets  
  
  
  
  
  
  
  
  
  
  
  
Interest rate lock commitments 1
 $—
 $843
 $—
 $—
 $384
 $—
Forward commitments 1
 —
 1
 —
 —
 1
 —
Window forward contract 2
 —
 664
 —
 —
 —
 —
Interest rate lock commitments (bank segment) 1
 $—
 $142
 $—
 $—
 $445
 $—
Forward commitments (bank segment) 1
 47
 41
 —
 —
 8
 —
Window forward contract (electric utility segment)2
 —
 615
 —
 —
 —
 —
 $—
 $1,508
 $—
 $—
 $385
 $—
 $47
 $798
 $—
 $—
 $453
 $—
Derivative liabilities 1
            
Forward commitments $121
 $43
 $—
 $15
 $15
 $—
Derivative liabilities            
Interest rate lock commitments (bank segment) 1
 $—
 $16
 $—
 $—
 $24
 $—
Forward commitments (bank segment) 1
 —
 —
 —
 129
 56
 —
Window forward contracts (electric utility segment)2
 —
 230
 —
 —
 743
 —
 $—
 $246
 $—
 $129
 $823
 $—
1  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 Asset derivativesDerivatives are included in other currentnoncurrent regulatory assets and/or 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 quartersix months ended SeptemberJune 30, 2016.2017.
The changes in Level 3 assets and liabilities measured at fair value on a recurring basis were as follows:
  Three months ended June 30  Six months ended June 30 
Mortgage revenue bond 20172016 20172016
(in thousands)      
Beginning balance $15,427
$—
 $15,427
$—
Principal payments received —
—
 —
—
Purchases —
—
 —
—
Unrealized gain (loss) included in other comprehensive income —
—
 —
—
Ending balance $15,427
$—
 $15,427
$—
ASB holds one mortgage revenue bond 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 June 30, 2017, the weighted average discount rate was 2.820% 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.
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   Fair value measurements
(in thousands)  Balance Level 1 Level 2 Level 3 Balance Level 1 Level 2 Level 3
September 30, 2016        
June 30, 2017        
Loans $1,258
 $—
 $—
 $1,258
December 31, 2016        
Loans $1,382
 $—
 $—
 $1,382
 2,767
 —
 —
 2,767
Real estate acquired in settlement of loans 219
 —
 —
 219
 1,189
 —
 —
 1,189
December 31, 2015        
Loans 178
 —
 —
 178
Real estate acquired in settlement of loans 1,030
 —
 —
 1,030
 AtFor six months ended SeptemberJune 30, 20162017 and 2015,2016, there were no adjustments to fair value for ASB’s loans held for sale which were carried at the lower of cost or fair value.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)
   
Significant unobservable
 input value (1)
($ in thousands) Fair value Valuation technique Significant unobservable input Range 
Weighted
Average
 Fair value Valuation technique Significant unobservable input Range 
Weighted
Average
September 30, 2016   
June 30, 2017   
Residential loan $448
 Fair value of collateral Appraised value less 7% selling cost N/A (2)
Commercial loan 810
 Sales price Sales price N/A (2)
Total loans $1,258
       
   
December 31, 2016   
Residential loans $2,468
 Sales price Sales price 95-100% 97%
Residential loans $1,370
 Fair value of property or collateral Appraised value less 7% selling costs 42-91% 64% 287
 Fair value of property or collateral Appraised value less 7% selling cost 42-65% 61%
Home equity lines of credit 12
 Fair value of property or collateral Appraised value less 7% selling costs N/A (2) 12
 Fair value of property or collateral Appraised value less 7% selling cost N/A (2)
Total loans $1,382
        $2,767
       
Real estate acquired in settlement of loans $219
 Fair value of property or collateral Appraised value less 7% selling costs 100% 100% $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 costs N/A (2)
Home equity lines of credit 128
 Fair value of property or collateral Appraised value less 7% selling costs 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 loan 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.

1012 · Cash flowsTermination of proposed merger and other matters
Nine months ended September 30 2016 2015
(in millions)    
Supplemental disclosures of cash flow information  
  
HEI consolidated    
Interest paid to non-affiliates $61
 $61
Income taxes paid 19
 62
Income taxes refunded 45
 55
Hawaiian Electric consolidated    
Interest paid to non-affiliates 43
 43
Income taxes paid —
 13
Income taxes refunded 20
 12
Supplemental disclosures of noncash activities  
  
HEI consolidated    
Common stock dividends reinvested in HEI common stock (financing) 1
 17
 —
Loans transferred from held for investment to held for sale (investing) 14
 —
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing) 1
 5
Obligations to fund low income housing investments (operating) 14
 1
HEI consolidated and Hawaiian Electric consolidated    
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing) (7) 1
1On 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 amounts shown representMerger Agreement contemplated that, prior to the Merger, HEI would distribute to its shareholders all of the common stock dividends reinvested in HEI common stock underof ASB Hawaii, Inc. (ASB Hawaii), the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions. From January 6, 2016, HEI satisfiedparent company of ASB (such distribution referred to as the share purchase requirementsSpin-Off).
The closing of the DRIPMerger was subject to various conditions, including receipt of regulatory approval from the PUC. In July 2016: (1) the PUC dismissed NEE and Hawaiian Electric’s application requesting approval of the proposed Merger, (2) NEE terminated the Merger Agreement and (3) pursuant to the terms of the Merger Agreement, 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 new issuancesJune 30, 2016 ($8 million), less merger- and Spin-Off-related expenses incurred in 2016 ($6 million) (all net of its common stock. In 2015, HEI satisfied such requirements with cash through open market purchasestax impacts). The Spin-Off of its common stock.

ASB Hawaii was cancelled as it was cross-conditioned on the merger consummation.

11 · Recent accounting pronouncements
Revenues from contracts.In May 2014,2016, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers: (Topic 606).” The core principleUtilities had filed an application for approval of an liquefied natural gas (LNG) supply and transport agreement and LNG-related capital equipment, which application was conditioned on the PUC’s approval of the guidance in ASU No. 2014-09 is that an entity should recognize revenue to depictproposed Merger. Subsequently, the transfer of promised goods or services to customers in an amount that reflectsUtilities terminated the consideration to whichLNG agreement and withdrew the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps:  (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.
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) nor the impact of adoption on its results of operations, financial condition or liquidity.
Debt issuance costs. application. 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 financial condition and had no impact on the Company’s results of operations or liquidity.Hawaiian Electric


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 will be revised in the SEC Form 10-K for the year ended December 31, 2016.
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. For example, all excess tax benefits and tax deficiencies should be recognized as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax cash flows as an operating activity on the statement of cash flows; an entity can make an accounting policy election to account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and the cash payments made to taxing authorities on the employees’ behalf for withheld shares should be classified as financing activities on the statement of cash flows.
The Company plans to adopt ASU 2016-09 in the first quarter of 2017 and has not yet determined the impact of adoption. Provisions requiring recognition of excess tax benefits and tax deficiencies in the income statement will be applied prospectively. Provisionsexpenses related to the timingterminated LNG agreement of when excess$1 million, net of tax benefits, are recognized, minimum statutory withholding requirements and forfeitures will be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of January 1, 2017. Provisions related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement will be applied retrospectively. Provisions related to the presentation of excess tax benefits on the statement of cash flows will be applied either using a prospective transition method or a retrospective transition method.
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 costeach 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.


12 · Credit agreements and long-term debt
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 September 30, 2016, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. The HEI Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it 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 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, as of August 3, 2016. 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 does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it 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 41% for Hawaii Electric Light and 41% for Maui Electric as of September 30, 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 September 30, 2016, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.
The credit 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.
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 1.23% through September 30, 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.


13 · Related party transactions
For general management and administrative services in the third quarters of 2016 and 2015 and nine months ended September 30, 2016 and 2015, HEI charged the Utilities $0.7 million, $1.7 million, $5.2 million and $4.9 million, respectively, and HEI charged ASB $0.3 million, $0.5 million, $1.8 million and $1.7 million, 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. As of September 30, 2016, Hawaiian Electric’s short-term borrowings from HEI were $21 million.
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 Vice Chairperson 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:
 Three months ended September 30 Nine months ended September 30
(in millions)2016 2015 2016 2015
HEI consolidated       
HMSA costs$7
 $8
 $21
 $22
HMSA expense*5
 6
 15
 16
HDS costs1
 1
 2
 2
HDS expense*1
 1
 2
 2
Hawaiian Electric consolidated       
HMSA costs5
 6
 17
 17
HMSA expense*3
 4
 10
 11
HDS costs1
 1
 2
 2
HDS expense*—
 —
 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).second quarters.
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and Hawaiian Electric’s 20152016 Form 10-K and should be read in conjunction with such discussion and the 20152016 annual consolidated financial statements of HEI and Hawaiian Electric and notes thereto included in HEI’s and Hawaiian Electric’s 20152016 Form 10-K, as well as the quarterly (as of and for the three and ninesix months ended SeptemberJune 30, 2016)2017) financial statements and notes thereto included in this Form 10-Q.


HEI consolidated
RESULTS OF OPERATIONS
(in thousands, except per Three months ended September 30 %  Three months ended June 30 % 
share amounts) 2016 2015 change Primary reason(s)* 2017 2016 change Primary reason(s)*
Revenues $646,055
 $717,176
 (10) Decrease for the electric utility segment, partly offset by increase for the bank segment $632,281
 $566,244
 12
 Increases for the electric utility and bank segments
Operating income 105,442
 97,095
 9
 Increases for the electric utility and bank segments, partly offset by higher loss for the “other” segment 75,896
 85,455
 (11) Decrease for the electric utility segment, partly offset by an increase at the bank segment and lower losses for the “other” segment
Merger termination fee 90,000
 —
 NM
 See Note 2 of the Consolidated Financial Statements.
Net income for common stock 127,142
 50,673
 151
 Merger termination fee at corporate (in the “other” segment) and higher net income for the electric utility and bank segments 38,661
 44,128
 (12) Lower net income for the electric utility segment, partly offset by higher net income at the bank segment and lower net loss for the “other” segment
Basic earnings per common share $1.17
 $0.47
 149
 Higher net income, partly offset by the impact of higher weighted average shares outstanding $0.36
 $0.41
 (12) Lower net income and the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding 108,268
 107,457
 1
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans 108,750
 107,962
 1
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

(in thousands, except per Nine months ended September 30 %  Six months ended June 30 % 
share amounts) 2016 2015 change Primary reason(s)* 2017 2016 change Primary reason(s)*
Revenues $1,763,259
 $1,978,950
 (11) Decrease for the electric utility segment, partly offset by increase for the bank segment $1,223,843
 $1,117,204
 10
 Increases for the electric utility and bank segments
Operating income 259,748
 239,331
 9
 Increases at all segments 143,758
 154,306
 (7) Decrease for the electric utility segment, partly offset by an increase at the bank segment and lower losses for the “other” segment
Merger termination fee 90,000
 —
 NM
 See Note 2 of the Consolidated Financial Statements.
Net income for common stock 203,622
 117,557
 73
 Merger termination fee at corporate (in the “other” segment) and higher net income for the electric utility and bank segments 72,854
 76,480
 (5) Lower net income for the electric utility segment, partly offset by higher net income at the bank segment and lower net loss for the “other” segment
Basic earnings per common share $1.89
 $1.11
 70
 Higher net income, partly offset by the impact of higher weighted average shares outstanding $0.67
 $0.71
 (6) Lower net income and the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding 107,951
 106,067
 2
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans 108,712
 107,791
 1
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

* Also, see segment discussions which follow.
NM Not meaningful

Notes:  The Company’s effective tax rates (combined federal and state income tax rates) for the third quarters of 2016 and 2015 were 29% and 37%, respectively, and for the first nine months of 2016 and 2015 were 32% and 37%, respectively. The effective tax rate was lower for the quarter and nine months ended September 30, 2016 compared to the same periods in 2015 due primarily to tax benefits recognized on previously nondeductible merger- and spin-off-related expenses and other tax benefits recognized as a result of moving out of a federal net operating loss position.
HEI’s consolidated ROACE was 12.3%12.1% for the twelve months ended SeptemberJune 30, 20162017 and 8.1%8.8% for the twelve months ended SeptemberJune 30, 2015.2016. The higher ROACE for the twelve months ended June 30, 2017 was largely due to the merger termination fee received in July 2016.
Dividends.  The payout ratios for the first ninesix months of 20162017 and full year 20152016 were 49%93% and 82%54%, respectively. HEI currently expects to maintain its 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 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 the first nine monthshalf of 20162017 with higher visitorcontinued strong growth. Visitor expenditures increased 8.7% and arrivals as compared to the same period a year ago. Visitor arrivals increased 2.6% and expenditures increased 3.7% in the first nine months4.3% compared to the same time period of 2015. Thein 2016. Looking ahead, the Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the fourththird quarter of 2017 to increase by 3.7% over the third quarter of 2016 to slightlydriven primarily by an increase by 0.3% over the fourth quarter of 2015. The modest change is a result of stable U.S. West markets and growth in seats from U.S.the East Coast and Asian countries, other than Japan, being offset by declines for all other regions (Japan, Canada, Oceania and other).Japan.
Hawaii’s preliminary unemployment rate remained relatively stable at 3.3%2.7% in September 2016,June 2017, lower than the state’s 3.4%3.1% rate in September 2015June 2016 and the September 2016June 2017 national unemployment rate of 5.0%4.4%.
Hawaii real estate activity, as indicated by the home saleresale market, experienced growth in median sales prices and closed sales for the first nine months of 2016 relative to the same time period in 2015.2017. Median sales prices for single family residential homes and condominiums on Oahu increased 5.2%through June 2017 were higher by 3.2% and 8.7%3.6%, respectively, over the first nine monthssame time period in 2016. The number of 2015. Closedclosed sales for both single family residential homes and condominiums increasedthrough June of 2017 were also up compared to same time period of 2016 by 4.8%4.4% and 9.0%6.0%, respectively, over the first nine months of 2015.respectively.
Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. InFollowing steady price increases through 2016, the third quarterprice of 2016, prices for crude oil has remained relatively stable with only a slight average price increase relative tothrough the prior quarter.first five months of 2017.
Information received sinceAt its June 2017 meeting, the July 2016 Federal Open Market Committee (FOMC) meeting indicates thatagain increased the labor market remains strongfederal funds rate target. The FOMC raised the target range of “0.75% to 1%” to “1.0% to 1.25%”. The FOMC has indicated a slipping in the inflation rate to 1.4% is temporary and household spending has been growing. However, fixed business investment has continuedis expected to be weak and inflation has continuedrebound to remain below the FOMC target of 2%. In the September 21, 2016 meeting, the FOMC reaffirmed its federal funds rate target of 0.25% to 0.5%.
Overall, HawaiiHawaii’s economy is expected to seebe buoyed by a continuationstrong tourism industry. Risks remain stemming from geopolitical uncertainty and its impact on tourism and from the impact of the moderate expansion experienced in the first nine months of 2016. Tourism gains are forecasted to be marginally higher than in 2015. Construction remains high, as activity is expected to continue in 2016 as plannedfinancial markets on real estate development and permitted building continues and as new recently approved projects begin.
Recent tax developments. See “Recent tax developments” in Note 4 and income taxes paid and refunded in Note 10 of the Consolidated Financial Statements.
Retirement benefits.  For the first nine months of 2016, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a return, net of investment management fees, of 9.9%. Included in this return is the return on ASB’s plan assets, which are managed with a liability driven investment strategy. For the first nine months of 2016, ASB’s defined benefit pension plan assets generated a return, net of investment management fees, of 15.1%, due primarily to the lower interest rate environment since the investments were purchased. The market value of the Company’s defined benefit pension and other postretirement benefit plans’ assets as of September 30, 2016 and December 31, 2015 was $1.6 billion (including $1.4 billion for the Utilities) and $1.4 billion (including $1.3 billion for the Utilities), respectively.
The net periodic pension cost is higher than the ERISA minimum required contribution for 2016 as it was for 2015. Therefore, to satisfy the requirements of the Utilities’ pension tracking mechanism, net periodic pension cost will be the basis of the cash funding for 2016 as it was for 2015. The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2016 will be $65 million ($64 million by the Utilities, $1 million by HEI and nil by ASB), compared to $88 million in 2015. The 2016 contribution is expected to fully satisfy the minimum contribution requirements, including requirements of the Utilities’ pension and OPEB tracking mechanisms and the plans’ funding policies. The decline in the 2016 contribution from 2015 is largely due to the increase in the discount rate and a downward revision to the Mortality Improvement Scale, which resulted in a decline in net periodic pension cost.
The following table reflects the sensitivity of the qualified defined benefit pension projected benefit obligation (PBO) as of December 31, 2016 associated with a change in the pension benefits discount rate actuarial assumption by the indicated basis points and constitutes “forward-looking statements.”
Change in 4.60%Impact on HEIImpact on the
Actuarial Assumptionassumption in basis pointsconsolidated PBOUtilities PBO
Pension benefits discount rate- 100/+100$320 million/$(250) million$300 million/$(234) million
In October 2016, the Society of Actuaries (SOA) released MP-2016 (mortality improvement scale), an update from MP-2014, to reflect three additional years of U.S. population mortality experience data. Application of MP-2016, as published,


will result in lower future pension and OPEB plan obligations, costs and required contribution amounts. The Company is currently evaluating whether to adopt the use of MP-2016 in its measurement of its pension and OPEB plan obligations at December 31, 2016. The Company used the SOA published tables and improvement scales for December 31, 2014 and December 31, 2015 measurements. The Internal Revenue Service is evaluating mortality assumptions for purposes of developing prescribed tables for ERISA minimum funding purposes. The earliest the Company anticipates a change in IRS methodology is January 1, 2018. Since December 31, 2014, the Company is using different mortality assumptions for ERISA funding versus financial reporting and accounting.
Commitments and contingencies.  See Note 4, “Electric utility segment” and Note 5, “Bank segment,” of the Consolidated Financial Statements.
Recent accounting pronouncements.  See Note 11, “Recent accounting pronouncements,” of the Consolidated Financial Statements.sales.
“Other” segment.
  Three months ended September 30 Nine months ended September 30  
(in thousands) 2016 2015 2016 2015 Primary reason(s)
Revenues $94
 $(42) $262
 $(4)  
Operating income (loss) (7,097) (6,364) (18,621) (28,282) Lower merger and spin-off-related expenses (including expense reimbursements from NEE and insurers) in the first nine months of 2016 (see below)
Merger termination fee 90,000
 —
 90,000
 —
 See Note 2 of the Consolidated Financial Statements.
Net income (loss) 65,064
 (5,784) 54,362
 (24,941) Merger termination fee and $8 million of tax benefits on previously non-deductible expenses related to the previously proposed merger with NEE and spin-off of ASBH
  Three months ended June 30 Six months ended June 30  
(in thousands) 2017 2016 2017 2016 Primary reason(s)
Revenues $77
 $100
 $172
 $168
  
Operating loss (3,947) (5,455) (9,183) (11,524) Second quarter and first six months of 2016 merger and spin-off-related expenses (see below), partly offset by higher other administrative and general expenses in the second quarter and first six months of 2017
Net loss (3,716) (5,014) (6,801) (10,702) Lower operating loss, lower interest expense (first six months) and higher tax benefits (first six months) (due to non-deductibility of certain merger- and spin-off-related expenses in the first six months of 2016 and the recognition of excess tax benefits on share-based compensation after the adoption of ASU No. 2016-09 on January 1, 2017)
The “other” business segment includes results of the stand-alone corporate operations of HEI and ASB Hawaii, Inc. (ASBH), both holding companies; HEI Properties, Inc., a company which held passive, venture capital investments (all of which have been sold or abandoned prior to its dissolution in December 2015)2015 and final winding up in June 2017); and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999;1999, but has remaining employee benefit payments; as well as eliminations of intercompany transactions. For the third quarter and first nine months of 2016, merger and spin-off related expenses (net of $6 million of reimbursements from NEE and insurers) recorded at HEI contributed $2 million and $5 million to operating losses, respectively. Expenses recorded at HEI related to the previously proposed merger with NEE and spin-off of ASBH amounted to $2$2.0 million and $15$3.5 million for the thirdsecond quarter and first ninesix months of 2015,ended June 30, 2016, respectively. See Note 2,12, “Termination of proposed merger and other matters,matters.”



FINANCIAL CONDITION
Liquidity and capital resources.  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:
(dollars in millions) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Short-term borrowings—other than bank $—
 —% $103
 3% $50
 1% $—
 —%
Long-term debt, net—other than bank 1,579
 43
 1,578
 43
 1,619
 43
 1,619
 43
Preferred stock of subsidiaries 34
 1
 34
 1
 34
 1
 34
 1
Common stock equity 2,068
 56
 1,928
 53
 2,075
 55
 2,067
 56
 $3,681
 100% $3,643
 100% $3,778
 100% $3,720
 100%
HEI’s short-term borrowings and HEI’s line of credit facility were as follows:


 Average balance Balance Average balance Balance
(in millions)  Nine months ended September 30, 2016 September 30, 2016 December 31, 2015 Six months ended June 30, 2017 June 30, 2017 December 31, 2016
Short-term borrowings 1
  
  
  
  
  
  
Commercial paper $58
 $—
 $103
 $1
 $6
 $—
Line of credit draws —
 —
 —
 —
 —
 —
Undrawn capacity under HEI’s line of credit facility   150
 150
   150
 150
 
1 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.” The maximum amount of HEI’s external short-term borrowings during the first ninesix months of 20162017 was $103$6.0 million. As of October 28, 2016,July 27, 2017, HEI had no$7.3 million of outstanding commercial paper, and its line of credit facility was undrawn.
HEI has a $150 million line of credit facility, as amended and restated on April 2, 2014, of $150 million.facility. See Note 125 of the Condensed Consolidated Financial Statements.
From March 6, 2014 through January 5,December 7, 2016 to date, HEI satisfied the share purchase requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances. From January 6 through September 30, 2016, HEI satisfied its share purchase requirements for the plans through new issuances, except that from June 2 through August 9, 2016, HEI satisfied the share purchase requirements of the HEIRSP and ASB 401(k) Plan through open market purchases of its common stock. For the first nine months of 2016, the Company raised $28 million through the new issuances of approximately 0.9 million shares of common stock under the DRIP, HEIRSP and ASB 401(k) Plan.
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 and such borrowed shares were sold pursuant to an HEI registered public offering. See Note 8 of the Consolidated Financial Statements. In March 2015, HEI issued the 4.7 million shares remaining under the equity forward transactions 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 12 of the Consolidated Financial Statements.
In December 2014, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities.
As of October 28, 2016, the Fitch Ratings, Inc. (Fitch), Moody's Investors Service’s (Moody's) and Standard & Poor’s (S&P) ratings of HEI were as follows:
FitchMoody’sS&P
Long-term issuer default and senior unsecured debt; senior unsecured debt; and corporate credit; respectivelyBBB*BBB-
Commercial paperF3P-3A-3
OutlookStableStableStable
*    Not rated.
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.
On July 19, 2016, S&P affirmed HEI’s ‘BBB-’ long-term issuer credit and other ratings, and removed the ratings from CreditWatch with positive implications. HEI’s outlook is stable. S&P stated that “the rating actions reflect the termination of the company’s [HEI’s] planned merger with NextEra, which would have led to higher ratings for HEI.”
On July 20, 2016, Fitch affirmed HEI’s long-term issuer default rating at ‘BBB’ following the termination of the merger agreement with NextEra Energy, Inc. and removed the ratings from Rating Watch Positive. HEI’s outlook is stable. Fitch stated that “the rating affirmation reflects Fitch’s view that the political and regulatory framework in Hawaii, while adverse to the proposed merger with NextEra, will remain ultimately supportive of HECO’s [Hawaiian Electric’s] credit profile as the utility


faces rising penetration of distributed generation and a capital intensive fleet modernization plan….HEI’s ratings are supported, in turn, by the credit profile of its subsidiaries: HECO [Hawaiian Electric] and American Savings Bank FSB (ASB).”
On August 3, 2016, Moody’s downgraded HEI’s short-term rating for commercial paper from P-2 to P-3. HEI’s outlook is stable. Moody’s noted, “[t]he downgrade of HEI’s commercial paper rating to P-3 reflects HEI’s heavy dependence on HECO [Hawaiian Electric]. Although HEI also owns American Savings Bank, we view HECO [Hawaiian Electric] as the primary credit and ratings driver of the parent company.” A Moody’s VP-Senior Credit Officer stated, “[t]he ratings downgrade is prompted by our concern that HECO [Hawaiian Electric] will continue to face significant challenges in transforming its generation base to 100% renewable sources in an unpredictable and highly political regulatory environment.  We believe that the regulatory environment could become contentious as this transformation is executed despite recently falling customer bills, driven by lower fuel oil prices, and the company’s decision to moderate its still significant capital expenditure program.”   
For the first ninesix months of 2016,2017, net cash provided by operating activities of HEI consolidated was $409 million (including a $90 million termination fee paid by NEE).$186 million. Net cash used by investing activities for the same period was $536$399 million, primarily due to Hawaiian Electric’s consolidated capital expenditures and ASB’s purchases of ASB’s investment securities and net increasesincrease in ASB’s loans held for investment, partly offset by ASB’s receipt of repayments and calls offrom investment securities, proceeds from the sale of commercial loans and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $111$145 million as a result of several factors, including increases in short-term borrowings and ASB’s deposit liabilities, proceeds from other bank borrowings and net increases in ASB’s deposit liabilities and proceeds from the issuance of HEI common stock,retail purchase agreements, partly offset by the payment of common stock dividends and net decreases in short-term borrowings,repayments of other bank borrowings and retail repurchase agreements.borrowings. Also included in cash provided by financing activities were proceeds from the issuance of special purpose revenue bonds (SPRBs), which were offset by the transfer of funds to a trustee for the redemption of previously issued SPRBs. 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 and capital resources” sections below.) During the first ninesix months of 2016,2017, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $47$44 million and $18$19 million, respectively.


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 the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 47, to 48, 62 to 64, and 7473 to 7675 of HEI’s MD&A included in Part II, Item 7 of HEI’s 20152016 Form 10-K.
Additional factors that may affect future results and financial condition are described on pages iv and v under “Cautionary Note Regarding Forward-Looking Statements.”
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.
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—that is, management believes that these policies 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.
For information about these material estimates and critical accounting policies, see pages 48 to 49, 64 to 65, and 7675 to 7978 of HEI’s MD&A included in Part II, Item 7 of HEI’s 20152016 Form 10-K.


Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
Electric utility
RESULTS OF OPERATIONS
Results.
Three months ended September 30 Increase  
2016 2015 (decrease) (dollars in millions, except per barrel amounts)
$572
 $648
 $(76)  
Revenues. Net decrease largely due to:
     $(59) lower fuel prices
     (17) lower KWH generated
     (4) lower purchased power expense
     4
 higher RAM
129
 196
 (67)  
Fuel oil expense. Decrease due to lower fuel cost and lower KWH generated
158
 161
 (3)  
Purchased power expense. Decrease due to lower purchased power energy prices
95
 104
 (9)  
Operation and maintenance expenses. Decrease due to:
     (5) write off of ERP software costs in 2015
     (3) lower overhaul costs due to fewer overhauls performed
     (1) lower LNG consultant costs
101
 106
 (5)  
Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
90
 83
 7
  
Operating income. Increase due to an overall decrease in expenses
47
 43
 4
  
Net income for common stock. Increase due to higher operating income
        
2,372
 2,468
 (96)  Kilowatthour sales (millions)
72.3
 74.9
 (2.6)  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,496
 1,711
 (215)  Cooling degree days (Oahu)
$57.72
 $81.35
 $(23.63)  Average fuel oil cost per barrel
Three months ended June 30 Increase  
2017 2016 (decrease) (dollars in millions, except per barrel amounts)
$557
 $495
 $62
   
Revenues. Net increase largely due to:
      $55
 
higher fuel oil prices1
      11
 
higher purchased power energy costs2
      (8) lower RAM revenues due to expiration of 2013 settlement agreement that allowed the accrual of RAM revenues on January 1 (vs. June 1) for years 2014 to 2016 at Hawaiian Electric
      3
 higher PPAC revenues
      2
 higher RAM revenues
      (3) lower KWH generated
141
 92
 49
   
Fuel oil expense. Increase due to higher fuel oil prices
153
 139
 14
   
Purchased power expense. Increase due to higher fuel oil prices
106
 100
 6
   
Operation and maintenance expenses. Net increase due to:
      1
 higher overhaul costs due to timing
      1
 ERP project costs commencing in 2017
      1
 higher maintenance costs
      1
 Grid modernization consultant costs
      1
 write off of portion of deferred Geothermal RFP costs
      1
 Property damage reserve for customer claim in 2017
      (1) LNG consulting costs incurred in 2016 to negotiate an LNG contract that was subsequently terminated following HEI/NextEra merger termination
101
 94
 7
   
Other expenses. Increase due to higher revenue taxes from higher revenue, coupled with higher depreciation expense for plant investments in 2016
55
 71
 (16)   
Operating income. Decrease due to lower RAM revenues and higher O&M and depreciation expenses
26
 36
 (10)   
Net income for common stock. Decrease due to lower operating income, partially offset by resulting lower income taxes.
         
2,150
 2,156
 (6)   
Kilowatthour sales (millions)4
1,278
 1,257
 21
   Cooling degree days (Oahu)
$69.86
 $44.98
 $24.88
   
Average fuel oil cost per barrel1



Nine months ended September 30 Increase  
2016 2015 (decrease) (dollars in millions, except per barrel amounts)
$1,550
 $1,780
 $(230)  
Revenues. Net decrease largely due to:
     $(191) lower fuel prices
     (37) lower purchased power expense
     (13) lower KWH generated
     12
 higher RAM
334
 519
 (185)  
Fuel oil expense. Decrease largely due to lower fuel prices and lower KWH generated
413
 446
 (33)  
Purchased power expense. Decrease due to lower purchased power energy prices
298
 307
 (8)  
Operation and maintenance expenses. Net decrease due to:
     (6) 
lower transmission, distribution and generation costs due to:
-lower vegetation management costs,
-less boiler and steam maintenance work,
-storm repair costs incurred in 2015 and
-less MATS compliance costs
     (5) write off of ERP software costs in 2015
     (1) 2015 Smart Grid costs
     (1) lower bad debt reserve for one customer account
     4
 higher PSIP consultant costs
     2
 higher LNG consultant costs
289
 302
 (13)  
Other expenses. Net decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
216
 206
 10
  
Operating income. Increase due to an overall decrease in expenses
108
 103
 5
  
Net income for common stock. Increase due to higher operating income
        
6,613
 6,656
 (43)  Kilowatthour sales (millions)
69.8
 70.2
 (0.4)  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
3,637
 3,687
 (50)  Cooling degree days (Oahu)
$52.06
 $79.13
 $(27.07)  Average fuel oil cost per barrel
459,590
 457,051
 2,539
  Customer accounts (end of period)
Six months ended June 30 Increase  
2017 2016 (decrease) (dollars in millions, except per barrel amounts)
$1,075
 $977
 $98
   
Revenues. Net increase largely due to:
      $90
 
higher fuel oil prices1
      33
 
higher purchased power energy costs2
      (20) lower RAM revenues due to expiration of 2013 settlement agreement that allowed the accrual of RAM revenues on January 1 (vs. June 1) for years 2014 to 2016 at Hawaiian Electric
      3
 higher RAM revenues
      (2) lower PPAC revenues
      (3) lower KWH purchased
      (2) lower KWH generated
286
 206
 80
   
Fuel oil expense. Increase due to higher fuel oil prices
280
 255
 25
   
Purchased power expense. Increase due to higher fuel oil prices
207
 203
 4
   
Operation and maintenance expenses. Net increase due to:
      2
 higher overhaul costs due to timing
      2
 ERP project costs commencing in 2017
      2
 
higher maintenance costs

      1
 
Grid modernization consultant costs

      1
 
write off of portion of deferred Geothermal RFP costs

      1
 
Property damage reserve for customer claim in 2017

      1
 
additional reserves for environmental costs in 20173
      (4) PSIP consulting costs incurred in 2016, in order to complete the PSIP update in April 2016
      (3) LNG consulting costs incurred in 2016 to negotiate an LNG contract that was subsequently terminated following HEI/NextEra merger termination
199
 187
 12
   
Other expenses. Increase due to higher revenue taxes from higher revenue, coupled with higher depreciation expense for plant investments in 2016
104
 126
 (22)   
Operating income. Decrease due to lower RAM revenues and higher O&M and depreciation expenses
47
 61
 (14)   
Net income for common stock. Decrease due to lower operating income, partially offset by resulting lower income taxes.
         
4,188
 4,241
 (53)   
Kilowatthour sales (millions)4
2,162
 2,141
 21
   Cooling degree days (Oahu)
$67.78
 $49.05
 $18.73
   
Average fuel oil cost per barrel1
460,858
 458,893
 1,965
   Customer accounts (end of period)
Notes:  The Utilities effective tax rates (combined federal and state income tax rates) for the third quarters of 2016 and 2015 and for the first nine months of 2016 and 2015 were 37%.
1The 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.
2The rate schedules 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.
3Increase reserve for additional costs for investigation of PCB contamination onshore and offshore of Waiau Power Plant
4KWH sales were lower when compared to the same quarter in the prior year due largely to continued energy efficiency and conservation efforts by customers and increasing levels of private customer-sited renewable generation.
Hawaiian Electric’s consolidated ROACE was 8.1%7.2% for the twelve months ended SeptemberJune 30, 20162017, and 7.9%8.0% for the twelve months ended SeptemberJune 30, 2015.2016.
The Utilities’ consolidated KWH sales have declined each year since 2007. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the Utilities’ full year 20162017 KWH sales are expected to be below the 20152016 level.
Other operation and maintenance expenses (excluding expense covered by surcharges or by third parties) for 2016 are expected to be 2% lower than 2015 as a result of continued cost containment efforts and because 2015 included expenses that are not expected to be incurred in 2016.

The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of SeptemberJune 30, 20162017 amounted to $4 billion, of which approximately 25% related to production PPE, 66% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 2%11% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission. See “Adequacy of supply” below.
See “Economic conditions” in the “HEI Consolidated” section above.
Executive overview and strategy. The Utilities provide electricity on all the principal islands in the state other than Kauai 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, flexible and dynamic electric grid that enables an optimal mix of distributed energy resources (such as private rooftop solar), demand response and grid-scale resources to achieve the statutory goal of 100% renewable energy by 2045.
Transition to renewable energy. The Utilities continue to make significant progress in implementing their renewable energy


strategies to support Hawaii’s efforts to reduce its dependence on oil. The Utilities are committed to assisting the State of Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy by 2045. Hawaii’s RPSRenewable Portfolio Standards (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 DSMdemand-side management (DSM) 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. The Utilities' RPS for 20152016 was 23%, exceedingabout 26% and on its way to achieving the 20152020 RPS goal and theof 30%. The Utilities led the nation in 2016 and 2015 in the percentage of its customers who have installed PV systems. (See "Developments in renewable energy efforts” below).
In 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed proposed Power Supply Improvement Plans (PSIPs) with the PUC, as required by PUC orders issued in April 2014 (see “April 2014 regulatory orders” in Note 4 of the Consolidated Financial Statements).2014. 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, 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 services to customers (e.g., community solar, microgrids and voluntary “demand response” programs). In December 2016, the Utilities filed a PSIP Update Report as ordered by the PUC. The PUC issued an order in August 2016 establishing a procedural schedule requiring a further updateupdated plans describe greater and faster expansion of the PSIPsUtilities’ 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 December 1, 2016. The order was further modified in an order issued in October 2016. The utilities are required to file an updated PSIP incorporating input from the Parties, develop alternative scenarios2030, more than double today’s total of 79,000, and sensitivity analyses, and perform iterations on modeling and simulations by December 23, 2016.additional grid-scale renewable energy resources. The Utilities willalready 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, the December 2016 update does not include the use of 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 continue replacing fossil fuel generation with renewables over the next five years as federal tax incentives for renewables begin to phase out. An interisland cable is not in the near-term plan, which states that its costs and benefits should continue to evaluate all options to achievingbe evaluated. In July 2017, the state’s 100% renewable energy goal, to stabilizePUC accepted the Utilities’ PSIP December 2016 Update Report and reduce customer rates, and to maintain safe and reliable service.closed the proceeding. See “April 2014 regulatory orders” in Note 3 of the Condensed Consolidated Financial Statements.
On October 1, 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed a proposed community-based renewable energyCBRE program and tariff with the PUC that willwould 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. The program, if approved by the PUC, would allow customers to buy an interest in electricity generated by community renewable projects on 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 June 2016,February 2017, the PUC issued a proposed CBRE Program Framework and a draftProposed Model Tariff Language, which significantly increased the scope of the program. Under the proposed CBRE Program Framework, the CBRE program andwill 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 Tranche A of the CBRE Phase 1 Program, the Utilities' primary role is to serve as the program administrator. In Tranche B, the Utilities and other participating parties filed comments onare allowed to develop 9 MW in the draft program. As partservice territories, 75% of the investigatory docket, on September 28, 2016,capacity is reserved for low-to-moderate income subscribers. In March 2017, the PUC held an informalUtilities submitted comments to the Program Framework, which identified certain concerns should the proposed CBRE Program Framework be adopted and requested a technical conference before a decision is issued. In June 2017, a technical conference with the parties to establishPUC was completed with the Utilities, the Consumer Advocate and facilitate a constructive dialogue toward the development of a comprehensive community-based renewable energy program and tariff.
industry stakeholders. The Utilities are pursuingawaiting the transition to renewable energy in a manner that will help stabilize customer bills as they become less dependentPUC’s decision on costly and price-volatile fossil fuel, ensure reliable service as more intermittent renewables are integrated to the grid and enable more options for customers as distributed technologies advance. To achieve 100% renewables by 2045, the Utilities seek to achieve a diversified mix of renewable resources, including utility scale and distributed resources. Under the state’s renewable energy strategy, there has been exponential growth in recent years in variable generation (e.g. solar and wind) on Hawaii’s island grids. As more generating resources are added to the Utilities' electric systems and as customers reduce their energy usage, the ability to accommodate additional generating resources and to accept energy from existing resources is becoming more challenging. As a result, there is a growing risk that energy production from generating resources may need to be curtailed and the interconnection of additional resources will need to be closely evaluated. Much of this variable generation is in the form of distributed generators interconnected at distribution circuits that cannot be directly controlled by system operators. As a consequence, grid resiliency in response to events that cause significant frequency and/or voltage excursions has weakened, and the prospects for larger and more frequent service outages have increased. As part of its transition, the Utilities have been progressively making changes in their operating practices, are making investments in grid modernization technologies, and are working with the solar industry to mitigate these risks and continue the integration of more renewable energy.CBRE program.
After launching a smart grid customer engagement plan during 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 turned on,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.
In March 2016, the Utilities sought PUC approval to commit funds for an expansion of the smart grid project. The proposed smart grid project is expectedwas estimated to cost $340 million and to be implemented over 5 years (beginning inyears. On January 4, 2017, for Oahu and 2018 for the Hawaii Island and Maui County). The Utilities are awaiting a PUC procedural order for the proceeding.
Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented bydismissing the application without prejudice and directing the Utilities in 2011to submit a Grid Modernization Strategy.
The PUC indicated that the overall goal of the Grid Modernization Strategy is to deploy modern grid investments at an appropriate priority, sequence and


2012. The decoupling model implemented delinks revenues from sales pace to cost-effectively maximize flexibility, minimize the risk of redundancy and includes annual rate adjustments for certain O&M expensesobsolescence, deliver customer benefits and rate base changes.enable greater DER and renewable energy integration. 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 toJune 30, 2017, the Utilities filed an initial draft of the Grid Modernization Strategy. The draft strategy describes how new technology will help triple private rooftop solar and their ratepayersmake use of rapidly evolving products including storage and are inadvanced inverters. The first segment of the public interest. On March 31, 2015,modernization is estimated at about $205 million over six years. The Utilities will continue to get feedback from customers and stakeholders as they refine the PUC issued an Order to make certain modifications tostrategy for the decoupling mechanism. final filing due on August 29, 2017.
Decoupling. See "Decoupling" in Note 43 of the Condensed Consolidated Financial Statements for a discussion of changes to the RAM mechanism. Under decoupling, as modified by the PUC, the most significant drivers for improving earnings are:
•completing major capital projects within PUC approved amounts and on schedule;
•managing O&M expense and capital additions relative to authorized RAM adjustments; and
•achieving regulatory outcomes that cover O&M requirements and rate base items not recovered in the RAMs.
Actual and PUC-allowed (ascomponent of September 30, 2016) returns were as follows:decoupling.
% Return on rate base (RORB)* ROACE** Rate-making ROACE***
Twelve months ended September 30, 2016 Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric
Utility returns 7.31
 7.61
 7.28
 7.94
 8.46
 8.45
 8.91
 8.82
 8.74
PUC-allowed returns 8.11
 8.31
 7.34
 10.00
 10.00
 9.00
 10.00
 10.00
 9.00
Difference (0.80) (0.70) (0.06) (2.06) (1.54) (0.55) (1.09) (1.18) (0.26)
*       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.
The approval of decoupling by the PUC has helped the Utilities to gradually improve their ROACEs when compared to the period prior to the implementation of decoupling. This in turn will facilitate the Utilities’ ability to effectively raise capital for needed infrastructure investments. However, the Utilities continue to expect an ongoing structural gap between their PUC-allowed ROACEs and the ROACEs actually achieved due to the following:
•the timing of general rate case decisions,
the effective date for financial reporting purposes of June 1 (rather than January 1) for the RAMs for Hawaii Electric Light and Maui Electric currently, and for Hawaiian Electric beginning in 2017 (see “Decoupling” in Note 4 of the Consolidated Financial Statements),
•plant additions not recoverable through the RAM or other mechanism outside of the RAM cap,
the modification to the RBA interest rate per the PUC's February 2014 decision on decoupling (as discussed in Note 4 of the Consolidated Financial Statements), and
•the PUC’s consistent exclusion of certain expenses from rates.
The structural gap in 2016 is expected to be 90 to 110 basis points. Factors which impact the range of the structural gap include the actual sales impacting the size of the RBA regulatory asset, the actual level of plant additions in any given year relative to the amount recoverable through the RAM, and the timing, nature and size of any general rate case. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the Utilities. Items not likely to be covered by the annual RAMs include the changes in rate base for the regulatory asset for pension contributions in excess of the pension amount in rates, investments in software projects, changes in fuel inventory and O&M and capital additions in excess of indexed escalations. The specific magnitude of the impact will depend on various factors, including changes in the required annual pension contribution, the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.
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'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. TheResults for 2016 and 2015 did not trigger the earnings sharesharing mechanism was not triggered for any of the utilities in 2015.Utilities. 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.
Annual decoupling filingsRegulated Returns..  See “Decoupling”Actual and PUC-allowed (as of June 30, 2017) returns were as follows:
% Return on rate base (RORB)* ROACE** Rate-making ROACE***
Twelve months ended June 30, 2017 Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric
Utility returns 6.77
 6.71
 6.83
 7.25
 6.91
 7.50
 7.99
 7.54
 7.96
PUC-allowed returns 8.11
 8.31
 7.34
 10.00
 10.00
 9.00
 10.00
 10.00
 9.00
Difference (1.34) (1.60) (0.51) (2.75) (3.09) (1.50) (2.01) (2.46) (1.04)
*      Based on recorded operating income and average rate base, both adjusted for items not included in Note 4determining 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.
The gap between PUC-allowed ROACEs and the ROACEs actually achieved is primarily due to: the consistent exclusion of certain expenses from rates, the recognition of annual RAM revenues on June 1 annually rather than on January 1, the low RBA interest rate (currently a short-term debt rate rather than the actual cost of capital), O&M increases and return on capital additions since the last rate case in excess of indexed escalations, and the portion of the Consolidated Financial Statements forpension regulatory asset not earning a discussionreturn due to pension contributions and pension costs in excess of the 2016 annual decoupling filings.pension amount in rates.


The PUC approved a two-year special medical needs pilot program, which will provide residential customers who depend on life support a discounted non-fuel energy charge. The program will be effective from April 1, 2017 to March 31, 2019, with a maximum savings of $20 per month per participant and limited to 2,000 participants. The discount will not be reflected as part of the target adjusted revenues in the RBA Provision.
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. 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. 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.
The PUC issued several important regulatory decisions during the last few years, including a number of interim and final rate case decisions. The following table summarizes certain details of each utility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advocate reached a settlement that they proposed to the PUC and the details of any granted interim and final PUC D&O increases.
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)
    
  
  
  
  
  
      
  
  
  
  
  
  
Request 7/30/10 $113.5
 6.6
 10.75
 8.54
 $1,569
 56.29
 Yes 7/30/10 $113.5
 6.6
 10.75
 8.54
 $1,569
 56.29
 Yes
Interim increase 7/26/11 53.2
 3.1
 10.00
 8.11
 1,354
 56.29
   7/26/11 53.2
 3.1
 10.00
 8.11
 1,354
 56.29
  
Interim increase (adjusted) 4/2/12 58.2
 3.4
 10.00
 8.11
 1,385
 56.29
   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
   5/21/12 58.8
 3.4
 10.00
 8.11
 1,386
 56.29
  
Final increase 9/1/12 58.1
 3.4
 10.00
 8.11
 1,386
 56.29
   9/1/12 58.1
 3.4
 10.00
 8.11
 1,386
 56.29
  
2014 (2)
 6/27/14                          
Request 6/27/14             
2017 (3)
    
  
  
  
  
  
      
  
  
  
  
  
  
Request 12/16/16 $106.4
 6.9
 10.60
 8.28
 $2,002
 57.36
 
Hawaii Electric Light    
  
  
  
  
  
      
  
  
  
  
  
  
2010 (4)
    
  
  
  
  
  
      
  
  
  
  
  
  
Request 12/9/09 $20.9
 6.0
 10.75
 8.73
 $487
 55.91
 Yes 12/9/09 $20.9
 6.0
 10.75
 8.73
 $487
 55.91
 Yes
Interim increase 1/14/11 6.0
 1.7
 10.50
 8.59
 465
 55.91
   1/14/11 6.0
 1.7
 10.50
 8.59
 465
 55.91
  
Interim increase (adjusted) 1/1/12 5.2
 1.5
 10.50
 8.59
 465
 55.91
   1/1/12 5.2
 1.5
 10.50
 8.59
 465
 55.91
  
Final increase 4/9/12 4.5
 1.3
 10.00
 8.31
 465
 55.91
   4/9/12 4.5
 1.3
 10.00
 8.31
 465
 55.91
  
2013 (5)
    
  
  
  
  
  
      
  
  
  
  
  
  
Request 8/16/12 $19.8
 4.2
 10.25
 8.30
 $455
 57.05
   8/16/12 $19.8
 4.2
 10.25
 8.30
 $455
 57.05
  
Closed 3/27/13  
  
  
  
  
  
   3/27/13  
  
  
  
  
  
  
2016 (6)
                          
Request 9/19/16 $19.3
 6.5
 10.60
 8.44
 $479
 57.12
  9/19/16 $19.3
 6.5
 10.60
 8.44
 $479
 57.12
 Yes
Statements of Probable Entitlement (which will be superceded by any PUC interim D&O)
             
Hawaii Electric Light 7/21/17 11.1
 3.8
 9.75
 7.94
 482
 56.69
 
Consumer Advocate 7/21/17 9.9
 3.4
 9.5
 7.8
 482
 56.69
 
Maui Electric    
  
  
  
  
  
      
  
  
  
  
  
  
2012 (7)
    
  
  
  
  
  
      
  
  
  
  
  
  
Request 7/22/11 $27.5
 6.7
 11.00
 8.72
 $393
 56.85
 Yes 7/22/11 $27.5
 6.7
 11.00
 8.72
 $393
 56.85
 Yes
Interim increase 6/1/12 13.1
 3.2
 10.00
 7.91
 393
 56.86
   6/1/12 13.1
 3.2
 10.00
 7.91
 393
 56.86
  
Final increase 8/1/13 5.3
 1.3
 9.00
 7.34
 393
 56.86
   8/1/13 5.3
 1.3
 9.00
 7.34
 393
 56.86
  
2015 (8)
 12/30/14                          
Request 12/30/14             
2018 (9)
             
 
Note:  The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of 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)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 final D&O, which reflected the approval of decoupling and cost-recovery mechanisms, and 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.
(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 2013 Agreement (described below),Consumer Advocate, which was approved by the PUC in March 2013, the rate case was withdrawn and the docket has beenwas closed.
(6)Parties settled on all issues except whether the stipulated ROACE of 9.75% should be reduced by up to 25 basis points for the impact of decoupling. Hawaii Electric Light’s position is that the ROACE that should be used to calculate the interim increase is 9.75% and the Consumer Advocate’s position is that the ROACE that should be used to calculate the interim should be 9.50%. Parties filed separate statement of probable entitlement. The table shows each party’s proposed interim revenue increase based on their respective proposed ROACE. See also “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 onThe final D&O includingapproved an increase in annual revenue of $5.3 million, which was $7.8 million less than the refundinterim increase in annual revenues that had been in effect since June 1, 2012. Maui Electric refunded to customers inapproximately $9.7 million (which included interest accrued) between September 2013 and October 2013 required as a result of the final D&O, in Note 4 of the Consolidated Financial Statements.early November 2013.
(8)See “Maui Electric 2015 test year rate case” below.
(9)See “Maui Electric 2018 test year rate case” below.
Hawaiian Electric 2014 test year rate case.  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.
Management cannot predict whetherOn December 27, 2016, the PUC will acceptissued an order consolidating the filings for this abbreviated filing to satisfy Hawaiian Electric’s obligation to file a rate case in 2014, whether additional material will be required or whetherwith the Hawaiian Electric will be required to proceed with a traditional2017 test year rate proceeding.case and closed the docket.
See “Hawaiian Electric consolidated 2014 test year abbreviated and 2017 test year cases” in Note 3 of the Condensed Consolidated Financial Statements.
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 foregoingforgoing the opportunity to seek a general rate increase. If Maui Electric stated that, if it 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 indicated normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%.
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 orto be submitted, whether Maui Electric will be required to proceed with a traditional rate proceeding.proceeding or whether the rate case will be consolidated into the 2018 rate case filing.
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 outproposed an expansion of the range of fuel usage efficiencies under which fuel costs would be fully passed through to customers, and an additional trigger that it has increased its usewould allow a re-establishment 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.fuel usage efficiency targets under certain conditions. In addition, Hawaii Electric Light also proposed revenue adjustmentsan equal sharing of fuel expenses outside the fuel usage efficiency target range.


The PUC held public hearings for this rate case in December 2016. On April 13, 2017, the PUC issued an order allowing the County of Hawaii to recover costs associated withparticipate in the acquisitionproceeding and operationdenying the motions to intervene of two other parties.
On April 28, 2017, the Consumer Advocate filed its testimony in the proceeding, recommending an increase of $2.7 million over revenues at current effective rates (for a 0.9% increase in revenues), based on a 7.29% rate of return (which incorporates a return on equity of 8.75%). On May 25, 2017, the County of Hawaii filed its testimony in the proceeding, recommending reforms in rate design in an effort to support both renewable resources and the financial viability of the power plant currently owned by Hamakua Energy Partners, L.P.transmission and distribution infrastructure that is needed to support those resources.
On June 23, 2017, Hawaii Electric Light requested approvalfiled its rebuttal testimonies, proposing an increase of $16.0 million over revenues at current effective rates based on a rate of return of 8.42% and a return on equity of 10.6%.
On July 11, 2017, Hawaii Electric Light and the Consumer Advocate filed a Stipulated Settlement Letter, which documented agreements reached with the Consumer Advocate on all of the acquisitionissues in the proceeding, except for the narrowed rate of ROACE issue of whether the stipulated ROACE should be reduced from 9.75% (by up to 25 basis points) based solely on the impact of decoupling, considering current circumstances and relevant precedents. The Parties agree that this power plant innarrowed issue is to be addressed through the submission of opening and closing briefs, without the need for an evidentiary hearing on the ROACE issue. On July 14, 2017, the PUC issued a letter canceling previously scheduled evidentiary hearings. On July 21, 2017, the Parties filed separate application.statements of probable entitlement, proposing the amount of interim revenue increase according to their respective proposed ROACE. See table above. According to State law, an interim D&O should be issued by August 21, 2017.
Hawaiian Electric 2017 test year rate case. On SeptemberDecember 16, 2016, Hawaiian Electric filed an application with the PUC a Notice of Intent to file an application for a general rate increase of $106.4 million over 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 an additional $20.6 million when the Schofield Generation Station is placed in service, which is expected in the second quarter of 2018. As in Hawaii Electric Light’s rate increase application filed in September 2016, Hawaiian Electric’s application is taking steps toward innovative ratemaking by proposing implementation of PBR mechanisms related to its performance in areas of customer service, reliability and communication relating to the private rooftop solar interconnection process. Hawaiian Electric proposed an expansion of the range of fuel usage efficiencies under which fuel costs would be fully passed through to customers, and an additional trigger that would allow a re-establishment of fuel usage efficiency targets under certain conditions. On February 22, 2017, the PUC held public hearings for this rate case. On June 28, 2017, the PUC issued an order denying motions to intervene but allowing limited participant status to six organizations. The procedural schedule for this rate case on or beforeincludes an interim D&O tentatively scheduled for December 15, 2017 and an evidentiary hearing in early March 2018.
See “Hawaiian Electric consolidated 2014 test year abbreviated and 2017 test year cases” in Note 3 of the Condensed Consolidated Financial Statements.
Maui Electric 2018 test year rate case. On June 9, 2017, Maui Electric filed a notice of intent with the PUC to file a general rate case application by December 30, 2016, utilizing2017 for a 2017 calendar2018 test year.


Hawaiian Electric’s The rate case filing is required to satisfy the obligation to file a general rate case under the triennialthree-year rate case cycle established by the PUC in the decoupling final D&O.&O in the decoupling proceeding.
Integrated resource planning and April 2014 regulatory ordersPerformance-based regulation. See “April 2014In the Hawaii Electric Light 2016 test year rate case, and the Hawaiian Electric 2017 test year rate case, the Utilities recommended that a separate investigatory docket be opened to evaluate PBR on a broader scale that can be implemented across the Utilities, and to fully develop a comprehensive PBR Framework.  PBR refers to different ways in which regulators have modified their regulatory orders”approach in Note 4an attempt to strengthen financial incentives for Utilities to achieve desired outcomes.  In the Consolidated Financial Statements.its April 27, 2017 order in the Decoupling Investigative proceeding, the PUC stated that it would initiate a separate investigative docket to examine a full range of Performance Incentive Mechanism and PBR options.
Depreciation docket.  In December 2016, the Utilities filed an application with the PUC for approval of changes in the depreciation and amortization rates and amortization period for contributions in aid of construction (CIAC).  The application requests that the effective date of implementation of the change in depreciation and amortization rates and revised CIAC amortization period, as recommended by the 2015 Book Depreciation Study, coincide with the effective date of interim base rates (that include the increased expenses resulting from the new depreciation and amortization rates and change in CIAC amortization period) to be established in each of the Utilities’ next general rate cases or the effective date of the decoupling RBA Rate Adjustment that incorporates the new depreciation and amortization rates for each utility, whichever is sooner.


Developments in renewable energy efforts.  Developments in the Utilities’ efforts to further their renewable energy strategy include renewable energy projects discussed in Note 3 of the Condensed Consolidated Financial Statements and the following:
In July 2011, the PUC directed Hawaiian Electric to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP, ordering that Hawaiian Electric shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order.
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 are currently in discussions regarding the possibility of reinstating the PPA under revised terms and conditions.
In August 2012, the battery facility at a 30-MW Kahuku wind farm experienced a fire. After the interconnection infrastructure was rebuilt and voltage regulation equipment was installed, the facility came up to full output in January 2014. An application for PUC approval of an amendment to the PPA was filed in April 2014 and the PUC approved the amendment in June 2016.
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 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.
In May 2013, Maui Electric requested a waiver from the PUC Competitive Bidding Framework to conduct negotiations for a PPA for approximately 4.5 to 6.0 MW of firm power from a proposed Mahinahina Energy Park, LLC project, fueled with biofuel. The PUC approved the waiver request, provided that an executed PPA must be filed for PUC approval by February 2015. The parties did not execute a PPA by the PUC deadline. In September 2015, Anaergia Services, Maui Energy park and Maui Resource Recovery Facility filed a Petition for Declaratory Order, asking the PUC to find that Hawaiian Electric and Maui Electric have violated Hawaii state law and clear legislative policy by wrongfully refusing and failing to forward several bona fide requests for preferential rates for the purchase of firm renewable energy produced in conjunction with agricultural activities to the PUC for approval. The PUC held a hearing in March 2016. In April 2016, the PUC’s Hearing Officer issued a recommended D&O that confirms Maui Electric abided by state law and the PUC concurred with that recommendation in their D&O issued in September 2016.
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 NPM for the 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. 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 is expected to be placed into service by August 31, 2019.
In July 2015, the PUC approved the PPA for the 27.6 MW Waianae Solar project that is being developed by Eurus Energy America. ItThe project achieved commercial operations in January 2017 and is expected to be in service at the end of 2016, at which time it will benow the largest solar project in Hawaii.
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 2, LLC and SSA Solar of HI 3, LLC)LLC, respectively), each for a 2.87-MW solar facility. In February 2016, the PUC approved both PPAs, subject to certain conditions and modifications. The guaranteed commercial operations date for the facilities was December 31, 2016, however both projects are experiencing delays and are expected to be completed by the end of the fourth quarter in 2017.   
In September 2015, the PUC approved Hawaiian Electric’s 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC (PBT) to supply 2 million to 3 million gallons of biodiesel at CIP CT-1Campbell Industrial Park combustion turbine No. 1 (CIP CT-1) and the Honolulu International Airport Emergency Power Facility beginning in November 2015. Renewable Energy GroupThe PBT contract is set to expire on November 2, 2018. PBT also has supplied 3 million to 7 million gallons per year to CIP CT-1 under itsa spot buy contract with Hawaiian Electric set to expire November 2016. The


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, has beenwhich was recently extended from November 2016 to November 2017 asthrough June 2018. REG Marketing & Logistics Group, LLC has a contingency supply contract with Hawaiian Electric to also supply biodiesel to CIP CT-1 in the event PBT is not able to supply necessary quantities. This contingency contract has been extended to November 2018, and will continue with no volume purchase requirements.
In October 2015,On April 28, 2017 Hawaiian Electric issued a Biofuel Supply Request for Proposal for 3.1 million gallons of biofuel per year for three years, to commence as early as November 2018 to be used as fuel for power generation at Hawaiian Electric’s Schofield Generating Station, the Utilities filed with the PUC a proposal for a Community-Based Renewable Energy programHonolulu International Airport Emergency Power Facility and tariff that would allow customers who cannot, or chose not to, take advantage of 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 June 2016, the PUC proposed a draft program, and the Utilities andany other participating parties filed commentsgenerating unit on the draft program. As part of the investigatory docket, on September 28, 2016, the PUC held an informal technical conference with the parties to establish and facilitate a constructive dialogue toward the development of a comprehensive community-based renewable energy program and tariff.Oahu, as necessary.
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.2022.
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, Hawaiian Electric filed with the PUC a request to waive the $67 million project from the Competitive Bidding Framework and to approve expenditures for the project. The renewable energy generated by the solar facility will feed into Oahu’s electrical grid at a cost of 9.54 cents per kilowatt-hour.
The Utilities began accepting energy from feed-in tariff projects in 2011. As of SeptemberJune 30, 2016,2017, there were 2330 MW, 3 MW and 4 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
As of SeptemberJune 30, 2016,2017, there were approximately 293325 MW, 6975 MW and 7786 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, Customer Grid Supply (CGS) and Customer Self Supply (CSS).
Other regulatory matters.  In additionSupply. As of June 30, 2017, an estimated 27% of single family homes on the islands the Utilities serve have installed private rooftop solar systems, and an estimated 29% of single family homes have installed, or have been approved to the items below, also see Note 4install, private rooftop solar systems. As of June 30, 2017, approximately 16% of the Consolidated Financial Statements.Utilities' total customers have solar systems.    
On January 5, 2017, Hawaiian Electric issued an Onshore Wind Expression of Interest requesting expressions of interest from 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 January 6, 2017, Hawaii Electric Light and Maui Electric requested the PUC Commissioner.to open dockets to allow them to seek proposals for new renewable energy generation on the islands of Hawaii, Maui, Molokai, and Lanai.
On June 29,December 12, 2016, the Governor appointed Thomas GorakUtilities issued a request for information asking interested landowners to provide information about properties on an interim basisOahu, Hawaii Island, Maui, Molokai and Lanai available for utility-scale renewable energy projects or for growing biofuel feedstock. Responses have been accepted and are being evaluated.
Hawaiian Electric had PPAs to replace PUC Commissioner Michael Champley, whose term expired on June 30, 2016.  Mr. Gorak served as the PUC’s Chief Counsel from September 2013 to June 2016. His termpurchase solar energy with three affiliates of SunEdison. 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 for solar energy on Oahu with Waipio PV, LLC for 45.9 MW, Lanikuhana Solar, LLC for 14.7 MW and Kawailoa Solar, LLC for 49.0 MW. On July 27, 2017, the PUC Commissioner began on July 1, 2016 and isapproved the three NRG PPAs, subject to Senate confirmationmodifications and conditions. The three projects are expected to be in service by the 2017 legislative session.

end of 2019.
Adequacy of supply.
Hawaiian Electric. In January 2016,2017, Hawaiian Electric filed its 20162017 Adequacy of Supply (AOS) letter, which indicated that based on its May 2015October 2016 sales and peak forecast for the 2016 to 2017 - 2021 time period, Hawaiian Electric’sElectric's generation capacity will be sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2017.2018, 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 Plant in January 2014 and anticipates deactivating two additional fossil fuel units at its Waiau Power Plant in the 2022 timeframe. Hawaiian Electric is proceeding with futureacquired new firm capacity additions in coordination with the commissioning of the State of Hawaii Department of TransportationTransportation’s emergency power facility in 2016, andJune 2017. Hawaiian Electric is proceeding with a future firm capacity addition with the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, including black start capabilities, generation security project on federal lands, which is expected to be in service in the firstsecond quarter of 2018. Hawaiian Electric is continuing negotiations with two 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 Kalaeloa 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 2016,2017, Hawaii Electric Light filed its 20162017 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 20182019 is sufficient to meet reasonably expected demands for service and provide for


reasonable reserves for emergencies. The 2016 AOS letter also indicated that the Company's Shipman plant in Hilo was retired in 2015.
Additional generation from other renewable resources could be added in the 2020-20252018-2025 timeframe.
Maui Electric. In January 2016,2017, Maui Electric filed its 20162017 AOS letter, which indicated that Maui Electric’s generation capacity for the islands of Lanai and Molokai for the next three years is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. The 20162017 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 the Kahului Power Plant.
In February 2014, Maui Electric deactivated two fossil fuel generating units, with a combined rating 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. Due 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. In consideration ofConsidering 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 generating 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.
April 2014 regulatory orders. In April 2014,Maui, but in February 2017 Maui Electric requested the PUC issued four ordersto suspend the proceeding until the progress in the demand response programs and the DR portfolio proceeding can be further evaluated.


Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that collectively provide certain key policy, resource planning,could have positive or negative effects on the Utilities and operational directives to the Utilities.their customers. See “April 2014 regulatory orders”“Recent tax developments” in Note 49 of the Condensed Consolidated Financial Statements. Also, 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.
Commitments and contingencies.Clean Water Act Section 316(b). See Note 4On August 14, 2014, the EPA published in the Federal Register the final regulations required by section 316(b) of the Consolidated Financial Statements.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 permit. Hawaiian Electric submitted the final site specific studies for the Honolulu and Waiau power plants to the DOH in December 2016, and the final site specific study for Kahe will be submitted to the DOH no later than October 2017. Hawaiian Electric will work with the DOH to identify the appropriate compliance methods for the 316(b) rule.
Recent accounting pronouncements.Mercury Air Toxics Standards. On February 16, 2012, the 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 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 its MATS Compliance Plan and has met all compliance requirements to date.
PUC Commissioner.  See Note 11, “Recent accounting pronouncements,”On May 19, 2017, the Governor appointed James Griffin as an interim PUC Commissioner, subject to Senate confirmation. Mr. Griffin was a researcher and a faculty member at the Hawaii Natural Energy Institute at the University of Hawaii at Manoa. He also previously served as Chief of Policy and Research at the Consolidated Financial Statements.PUC.
FINANCIAL CONDITION
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, retirement benefits and other cash requirements in the foreseeable future.
Hawaiian Electric’s consolidated capital structure was as follows:
(dollars in millions) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Short-term borrowings $21
 1% $—
 —% $44
 1% $—
 —%
Long-term debt, net 1,279
 41
 1,279
 42
 1,319
 41
 1,319
 42
Preferred stock 34
 1
 34
 1
 34
 1
 34
 1
Common stock equity 1,767
 57
 1,728
 57
 1,804
 57
 1,800
 57
 $3,101
 100% $3,041
 100% $3,201
 100% $3,153
 100%
 


Information about Hawaiian Electric’s short-term borrowings (other than from Hawaii Electric Light and Maui Electric) and Hawaiian Electric’s line of credit facility were as follows:


 Average balance Balance Average balance Balance
(in millions) Nine months ended September 30, 2016 September 30, 2016 December 31, 2015 Six months ended June 30, 2017 June 30, 2017 December 31, 2016
Short-term borrowings 1
  
  
  
  
  
  
Commercial paper $18
 $—
 $—
 $3
 $44
 $—
Line of credit draws —
 —
 —
 —
 —
 —
Borrowings from HEI 3
 21
 —
 —
 —
 —
Undrawn capacity under line of credit facility   200
 200
   200
 200
 
1   The maximum amount of Hawaiian Electric’s external short-term borrowings by Hawaiian Electric during the first ninesix months of 20162017 was $61$44 million. As of SeptemberJune 30, 2016,2017, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $18.5$4.1 million and $15.5$1.0 million, respectively. As of October 28, 2016,July 27, 2017, Hawaiian Electric had no$33 million of outstanding commercial paper, no draws under its line of credit facility and no borrowings from HEI. Also, as of October 28, 2016,July 27, 2017, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $18.5$6.6 million and $15.5$4.5 million, respectively. Intercompanyrespectively, which intercompany borrowings are eliminated in consolidation.
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 termfacility. See Note 5 of the credit facility to April 2, 2019. See Note 12 of theCondensed Consolidated Financial Statements.
Special purpose revenue bonds (SPRBs) have been issued by the Department of Budget and Finance of the State of Hawaii (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 of principal and interest due on the Series 2007A and Refunding Series 2007B SPRBs are insured by Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013 FGIC’s plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of FGIC, which at the time the insured obligations were issued were higher than the ratings of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.
In May 2015, up to $80 million of Special Purpose Revenue Bonds (SPRBs)SPRBs ($70 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, prior to June 30, 2020 to finance the utilities’Utilities’ capital improvement programs.
In June 2015,On April 28, 2017, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with the PUC for approval to issue and sell each utility’s common stock in one or more sales in 2016 (Hawaiian Electric’s sale to HEI 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.
Hawaiian Electric and Maui Electric havereceived PUC approval to issue in 2016 unsecured obligations bearing taxable interest (Hawaiian Electricand/or refunding SPRBs with principal amounts totaling up to $70$252 million, $88 million and Maui Electric up$75 million, respectively, to $20 million),refinance three series of outstanding revenue bonds. The approval is limited to 2017, and an expedited approval procedure will apply for refinancings during January 2018 through December 2020. Pursuant to this approval, on June 29, 2017, the Department issued, at par, Refunding Series 2017A SPRBs in the aggregate principal amount of $125 million with a maturity of May 1, 2026 and Refunding Series 2017B SPRBs in the proceeds expected to be used, as applicable, 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 paymentaggregate principal amount of $140 million with a maturity of March 1, 2037. See Note 5 of the capital expenditures.Condensed Consolidated Financial Statements.
In August 2016,On January 26, 2017, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with theobtained PUC for approval to issue, on or before December 31, 2017, unsecured obligations bearing taxable interest (Hawaiian Electric up to $100 million, Hawaii Electric Light up to $10 million and Maui Electric up to $30 million), with the proceeds expected to be used, as applicable, 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 the capital expenditures.
On November 2, 2016,In March 2017 and amended in April 2017, the Utilities requested PUC approval to issue and sell each utility’s common stock through December 31, 2021 (Hawaiian Electric’s sale/s to HEI of up to $150 million and Hawaii Electric Light’s and Maui Electric’s sale/s to Hawaiian Electric of up to $10 million each) and the purchase of Hawaii Electric Light and Maui Electric filed an application with the PUC for approval to issue unsecured obligations bearing taxable interest and/or refunding SPRBs prior tocommon stock by Hawaiian Electric through December 31, 2020 to refinance three series of outstanding revenue bonds up to $252 million, $88 million and $75 million, respectively.


As of October 28, 2016, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:
FitchMoody’sS&P
Long-term issuer default, issuer and corporate 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**
OutlookStableStableStable
*    Not rated.
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.
On July 19, 2016, S&P affirmed Hawaiian Electric’s ‘BBB-’ long-term issuer credit and other ratings, and removed the ratings from CreditWatch with positive implications. The outlook is stable. S&P stated that “the rating actions reflect the termination of the company’s [HEI’s] planned merger with NextEra, which would have led to higher ratings for HEI.”
On July 20, 2016, Fitch affirmed Hawaiian Electric’s long-term issuer default rating at ‘BBB+’ with a stable outlook. Fitch stated that “the rating affirmation reflects Fitch’s view that the political and regulatory framework in Hawaii, while adverse to the proposed merger with NextEra, will remain ultimately supportive of HECO’s [Hawaiian Electric’s] credit profile as the utility faces rising penetration of distributed generation and a capital intensive fleet modernization plan.”
On August 3, 2016, Moody’s downgraded Hawaiian Electric’s senior unsecured debt rating from Baa1 to Baa2 and downgraded other ratings. Hawaiian Electric’s outlook is stable. A Moody’s VP-Senior Credit Officer stated, “[t]he ratings downgrade is prompted by our concern that HECO [Hawaiian Electric] will continue to face significant challenges in transforming its generation base to 100% renewable sources in an unpredictable and highly political regulatory environment. We believe that the regulatory environment could become contentious as this transformation is executed despite recently falling customer bills, driven by lower fuel oil prices, and the company’s decision to moderate its still significant capital expenditure program.”   2021.
Cash flows. Nine months ended September 30, 2016 compared to nine months ended September 30, 2015. The following table reflects the changes in cash flows for the comparative periods:six months ended June 30, 2017 compared to the six months ended June 30, 2016:
Nine months ended September 30  Six months ended June 30,  
(in thousands)2016 2015 Change2017 2016 Change
Net cash provided by operating activities$275,271
 $201,586
 $73,685
$150,676
 $194,124
 $(43,448)
Net cash used in investing activities(226,036) (230,116) 4,080
(178,259) (180,191) 1,932
Net cash provided by (used in) financing activities(50,707) 25,472
 (76,179)
Net cash used in financing activities(4,121) (10,803) 6,682
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 )from) net income.
The increasedecrease in net cash provided by operating activities was impacted by the following:
HigherLower cash from aan increase in accounts receivable due to timing and increase in fuel prices.


Lower cash from an increase in fuel oil stock due to higher fuel prices.
Lower cash from an increase in unbilled revenues due to higher fuel prices.
Lower cash from refund of federal income taxes in 2016 due to the extension ofbased on bonus depreciation enacted in the fourth quarter of 2015 and lower revenue taxes paid resultingthat was subsequently received in 2016 (similar treatment was not granted in the fourth quarter of 2016).
And partially offset by an increase in net cash from lower revenues due largely to lower fuel prices.operating activities provided by the following:
Lower payments for fuel oil and the timing of various payments (see change in “DecreaseHigher cash from an increase in accounts payable” on the Hawaiian Electric Consolidated Statements of Cash Flows)

payable due to higher fuel prices.
Net cash used in investing activities. The decreaseincrease in net cash used in investing activities was driven primarily by decreaseda capital goods tax credit, partially offset by an increase in capital expenditures offset by lower proceeds from contributions in aid of construction.related to construction activities.


Net cash provided by (used in)used in financing activities. Financing activities providedprovide supplemental cash for both day-to-day operations and capital requirements for the first nine months of 2015, but used cash in the same period of 2016.as needed. The changesdecrease in net cash provided by (used in)used in financing activities primarily is a reflection of the the lowerreflect higher proceeds from short-term borrowings.

The Utilities’2017 forecast capital expenditures. For 2017, the Utilities forecast $420 million of net capital expenditures, estimate for 2016 is currently $340 million, which excludes the HEP acquisition in 2016, based on the PUC extension of the procedural schedule for the approval into January 2017.  The actual net capital expenditures could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the 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 borrowings from affiliates and existing cash and cash equivalents are expected to provide the forecasted $340$420 million needed for the net capital expenditures in 20162017 as well as to pay down commercial paper or other short termshort-term borrowings, fund any unanticipated expenditures not included in the 20162017 forecast such as increases in the costs or acceleration of the construction of capital projects, 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.



Bank
 Three months ended September 30 Increase   Three months ended June 30 Increase  
(in millions) 2016 2015 (decrease) Primary reason(s) 2017 2016 (decrease) Primary reason(s)
Interest income $55
 $51
 $4
 The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the three months ended September 30, 2016 increased by $253 million compared to the same period in 2015 as average commercial real estate, consumer, home equity lines of credit and residential balances increased by $225 million, $42 million, $36 million and $12 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased by $63 million primarily due to a decrease in the syndicated national credit loan portfolio. The yield on earning assets increased by 6 basis points as the adjustable rate loans repriced upward with the increase in the prime rate at end of 2015 and there was a shift in mix of the loan portfolio with the growth of the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 12 basis points. The average investment securities portfolio balance increased by $166 million due to the use of excess liquidity to purchase investments. $59
 $54
 $5
 The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the three months ended June 30, 2017 increased by $24 million compared to the same period in 2016 as average consumer, commercial real estate and home equity lines of credit balances increased by $60 million, $50 million and $21 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased by $99 million primarily due to a decrease in the syndicated national credit loan portfolio. The yield on earning assets increased by 7 basis points due to a shift in the mix of the loan portfolio with the growth in the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 19 basis points and repricing of adjustable rate commercial loans with the increase in the interest rate environment. The average investment securities portfolio balance increased by $389 million due to the use of excess liquidity to purchase investments. The yield on the investment securities portfolio increased by 14 basis points as new investment purchase yields were higher due to the increase in short-term interest rates.
Noninterest income 19
 18
 1
 Noninterest income increased slightly for the three months ended September 30, 2016 compared to noninterest income for the same period in 2015 as higher mortgage banking income and bank-owned life insurance income was largely offset by a lower gain on sale of real estate. 16
 17
 (1) Noninterest income decreased slightly for the three months ended June 30, 2017 compared to noninterest income for the three months ended June 30, 2016 due to lower mortgage banking income partly offset by higher bank owned life insurance income. Prior year’s noninterest income included gains on sales of securities with no similar sales in 2017.
Revenues 74
 69
 5
  75
 71
 4
 
Interest expense 3
 3
 —
 Interest expense was flat as growth in the deposit liabilities was primarily in low rate core deposits, which had a minimal impact to interest expense. Average deposit balances for the three months ended September 30, 2016 increased by $477 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $333 million and $144 million, respectively. Other borrowings decreased by $79 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 3 basis points. 3
 3
 —
 Interest expense was flat for the three months ended June 30, 2017 compared to the same period in 2016 as higher interest expense from the growth in term certificates was offset by lower interest expense on other borrowings as a result of lower repurchase agreements. Average deposit balances for the three months ended June 30, 2017 increased by $487 million compared to the same period in 2016 due to an increase in core deposits and term certificates of $327 million and $160 million, respectively. Other borrowings decreased by $84 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate decreased by 2 basis points.
Provision for loan losses 6
 3
 3
 The provision for loan losses increased by $2.8 million primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for commercial loans due to downgrades of specific commercial credits and additional reserves for the consumer loan portfolio. Delinquency rates have decreased from 0.58% at September 30, 2015 to 0.51% at September 30, 2016. The net charge-off ratio for the three months ended September 30, 2016 was 0.20% compared to a net charge-off ratio of 0.10% for the same period in 2015. The increase in net charge-offs were primarily due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing and loan charge-offs related to specific commercial borrowers. 3
 5
 (2) The provision for loan losses decreased by $1.9 million for the three months ended June 30, 2017 compared to the provision for loan losses for the three months ended June 30, 2016. The provision for loan losses for 2017 was primarily due to increased loan loss reserves for the consumer loan portfolio. The provision for loan losses for 2016 was primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for commercial loans due to downgrades of specific commercial credits. Delinquency rates have decreased from 0.49% at June 30, 2016 to 0.44% at June 30, 2017. The annualized net charge-off ratio for the three months ended June 30, 2017 was 0.21% compared to an annualized net charge-off ratio of 0.15% for the same period in 2016. The increase in net charge-offs were due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing.
Noninterest expense 42
 42
 —
 Noninterest expense for the three months ended September 30, 2016 was flat compared to the same period in 2015. 45
 43
 2
 The increase in noninterest expense for the three months ended June 30, 2017 compared to the same period in 2016 was primarily due to higher compensation and employee benefits expenses as a result of higher performance-based compensation costs and higher employee benefit costs. Prior year’s noninterest expense included costs related to the replacement and upgrade of the electronic banking platform.
Expenses 51
 48
 3
  51
 51
 —
 
Operating income 23
 21
 2
 Higher net interest income and noninterest income was partly offset by higher provision loan losses. 24
 20
 4
 Higher net interest income and lower provision for loan losses was partly offset by higher noninterest expenses and lower noninterest income.
Net income 15
 13
 2
  17
 13
 4
 



 Nine months ended September 30 Increase   Six months ended June 30 Increase  
(in millions) 2016 2015 (decrease) Primary reason(s) 2017 2016 (decrease) Primary reason(s)
Interest income $163
 $148
 $15
 The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the nine months ended September 30, 2016 increased by $232 million compared to the same period in 2015 as average commercial real estate, home equity lines of credit, consumer and residential balances increased by $208 million, $33 million, $25 million and $16 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased $52 million primarily due to a decrease in syndicated national credit loan portfolio. The yield on earning assets increased by 8 basis points as adjustable rate loans repriced upward with the increase in the prime rate at end of 2015 and there was a shift in the mix of the loan portfolio with the growth in the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 11 basis points. The average investment securities portfolio balance increased by $242 million due to the use of excess liquidity to purchase investments. The average FHLB stock balance decreased by $28 million as FHLB stock in excess of the required holdings was repurchased by the FHLB. $117
 $108
 $9
 The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the six months ended June 30, 2017 increased by $60 million compared to the same period in 2016 as average commercial real estate, consumer and home equity lines of credit balances increased by $76 million, $60 million and $19 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased by $89 million primarily due to a decrease in the syndicated national credit loan portfolio. The yield on earning assets increased by 6 basis points due to a shift in the mix of the loan portfolio with the growth in the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 16 basis points and repricing of adjustable rate commercial loans with the increase in the interest rate environment. The average investment securities portfolio balance increased by $347 million due to the use of excess liquidity to purchase investments. The yield on the investment securities portfolio increased by 10 basis points as new investment purchase yields were higher due to the increase in short-term interest rates.
Noninterest income 50
 51
 (1) Noninterest income decreased slightly for the nine months ended September 30, 2016 compared to noninterest income for the nine months ended September 30, 2015 as higher gain on sale of securities and higher fee income on other financial products were more than offset by lower gain on sale of real estate and lower deposit fee income. 31
 32
 (1) Noninterest income decreased slightly for the six months ended June 30, 2017 compared to noninterest income for the six months ended June 30, 2016 due to lower mortgage banking income partly offset by higher bank-owned life insurance income.
Revenues 213
 199
 14
  148
 140
 8
 
Interest expense 10
 9
 1
 The increase in interest expense for the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to the increase in term certificates. Average deposit balances for the nine months ended September 30, 2016 increased by $418 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $321 million and $97 million, respectively. Other borrowings decreased by $33 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 2 basis points. 6
 6
 —
 Interest expense was flat for the six months ended June 30, 2017 compared to the same period in 2016 as higher interest expense from the growth in term certificates was offset by lower interest expense on other borrowings as a result of lower repurchase agreements. Average deposit balances for the six months ended June 30, 2017 increased by $511 million compared to the same period in 2016 due to an increase in core deposits and term certificates of $350 million and $161 million, respectively. Other borrowings decreased by $100 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate decreased by 3 basis points.
Provision for loan losses 15
 5
 10
 The provision for loan losses increased by $9.8 million primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for commercial loans due to downgrades of specific commercial credits. The provision for loan losses for the nine months ended September 30, 2015 included the reversal of the Pahoa lava reserves. Delinquency rates have decreased from 0.58% at September 30, 2015 to 0.51% at September 30, 2016. The net charge-off ratio for the nine months ended September 30, 2016 was 0.19% compared to a net charge-off ratio of 0.08% for the same period in 2015. The increase in net charge-offs were due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing and loan charge-offs related to specific commercial borrowers. 7
 10
 (3) The provision for loan losses decreased by $2.8 million for the six months ended June 30, 2017 compared to the provision for loan losses for the six months ended June 30, 2016. The provision for loan losses for 2017 was primarily due to increased loan loss reserves for the consumer loan portfolio and additional loan loss reserves for the commercial real estate loan portfolio due to the downgrade of a commercial real estate relationship. The provision for loan losses for 2016 was primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for commercial loans due to downgrades of specific commercial credits. Delinquency rates have decreased from 0.49% at June 30, 2016 to 0.44% at June 30, 2017. The annualized net charge-off ratio for the six months ended June 30, 2017 was 0.25% compared to an annualized net charge-off ratio of 0.18% for the same period in 2016. The increase in net charge-offs were due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing.
Noninterest expense 126
 124
 2
 The increase in noninterest expense for the nine months ended September 30, 2016 was primarily due to the costs related to the replacement and upgrade of the electronic banking platform. 86
 84
 2
 The increase in noninterest expense for the six months ended June 30, 2017 compared to the same period in 2016 was primarily due to higher compensation and employee benefits expenses as a result of higher performance-based compensation costs and higher employee benefit costs. Prior year’s noninterest expense included costs related to the replacement and upgrade of the electronic banking platform.
Expenses 151
 138
 13
  99
 100
 (1) 
Operating income 62
 61
 1
 Higher net interest income was largely offset by higher provision loan losses, lower noninterest income and higher noninterest expense. 49
 40
 9
 Higher net interest income and lower provision for loan losses was partly offset by higher noninterest expenses and lower noninterest income.
Net income 41
 40
 1
  33
 26
 7
 

                       See Note 54 of the Condensed Consolidated Financial Statements and “Economic conditions” in the “HEI Consolidated” section above.
                       ASB continues to maintain its low-risk profile, strong balance sheet and straightforward community banking business model.


                       ASB’s return on average assets, return on average equity and net interest margin were as follows:
 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(percent) 2016 2015 2016 2015 2017 2016 2017 2016
Return on average assets 0.97
 0.92
 0.89
 0.92
 1.02
 0.86
 1.00
 0.85
Return on average equity 10.36
 9.73
 9.50
 9.69
 11.25
 9.22
 11.04
 9.06
Net interest margin 3.57
 3.53
 3.59
 3.52
 3.68
 3.58
 3.68
 3.60
Average balance sheet and net interest margin.  The following tables providesprovide a summary of average balances including major categories of interest, earninginterest-earning assets and interest-bearing liabilities:
Three months ended September 30 2016 2015
 Three months ended June 30
 2017 2016
(dollars in thousands) Average
balance		 
Interest
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1 
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1
 income/
expense
 Yield/
rate (%)
Assets:  
  
  
  
  
  
  
  
  
  
  
  
Interest-earning deposits $97,885
 $124
 0.50
 $111,574
 $72
 0.25
 $46,507
 $121
 1.03
 $64,821
 $81
 0.49
FHLB Stock 11,218
 54
 1.89
 10,748
 14
 0.51
FHLB stock 11,759
 57
 1.96
 11,284
 44
 1.58
Available-for-sale investment securities 928,698
 4,581
 1.97
 762,572
 4,127
 2.17
            
Taxable 1,267,945
 6,481
 2.04
 894,684
 4,318
 1.93
Non-taxable 15,427
 160
 4.11
 —
 —
 —
Total available-for-sale investment securities 1,283,372
 6,641
 2.07
 894,684
 4,318
 1.93
Loans                        
Residential 1-4 family 2,077,135
 22,044
 4.24
 2,065,421
 22,493
 4.36
 2,070,450
 22,163
 4.28
 2,075,255
 22,201
 4.28
Commercial real estate 888,886
 9,113
 4.08
 663,805
 6,690
 4.00
 917,019
 9,722
 4.21
 867,266
 8,716
 4.01
Home equity line of credit 864,589
 7,204
 3.31
 828,096
 6,684
 3.20
 877,462
 7,248
 3.31
 856,960
 6,989
 3.28
Residential land 18,764
 282
 6.00
 17,876
 268
 5.97
 16,111
 217
 5.38
 18,758
 285
 6.08
Commercial 750,366
 7,327
 3.87
 813,475
 7,376
 3.58
 663,200
 7,090
 4.27
 762,247
 7,595
 3.99
Consumer 159,226
 4,474
 11.18
 117,699
 2,902
 9.79
 202,914
 5,877
 11.62
 142,955
 3,904
 10.98
Total loans 1,2
 4,758,966
 50,444
 4.22
 4,506,372
 46,413
 4.10
Total interest-earning assets 1
 5,796,767
 55,203
 3.80
 5,391,266
 50,626
 3.74
Total loans 2,3
 4,747,156
 52,317
 4.40
 4,723,441
 49,690
 4.21
Total interest-earning assets 2
 6,088,794
 59,136
 3.88
 5,694,230
 54,133
 3.81
Allowance for loan losses (55,480)  
  
 (46,726)  
  
 (56,715)  
  
 (52,749)  
  
Non-interest-earning assets 514,120
  
  
 486,995
  
  
 534,581
  
  
 503,617
  
  
Total assets $6,255,407
  
  
 $5,831,535
  
  
 $6,566,660
  
  
 $6,145,098
  
  
Liabilities and shareholder’s equity:  
  
  
  
  
  
  
  
  
  
  
  
Savings $2,139,863
 $358
 0.07
 $1,990,016
 $319
 0.06
 $2,274,832
 $386
 0.07
 $2,099,422
 $343
 0.07
Interest-bearing checking 837,480
 43
 0.02
 784,265
 35
 0.02
 908,864
 59
 0.03
 834,821
 42
 0.02
Money market 161,149
 52
 0.13
 164,200
 52
 0.13
 146,962
 45
 0.12
 165,433
 52
 0.13
Time certificates 597,537
 1,418
 0.94
 453,460
 949
 0.83
 679,866
 1,821
 1.07
 520,151
 1,254
 0.97
Total interest-bearing deposits 3,736,029
 1,871
 0.20
 3,391,941
 1,355
 0.16
 4,010,524
 2,311
 0.23
 3,619,827
 1,691
 0.19
Advances from Federal Home Loan Bank 100,000
 792
 3.10
 101,739
 794
 3.05
 101,335
 788
 3.08
 101,648
 785
 3.06
Securities sold under agreements to repurchase 161,652
 672
 1.63
 238,822
 721
 1.18
 95,740
 36
 0.15
 179,559
 682
 1.51
Total interest-bearing liabilities 3,997,681
 3,335
 0.33
 3,732,502
 2,870
 0.30
 4,207,599
 3,135
 0.30
 3,901,034
 3,158
 0.32
Non-interest bearing liabilities:  
  
    
  
    
  
  
  
  
  
Deposits 1,572,821
  
   1,440,136
  
   1,664,592
  
  
 1,568,725
  
  
Other 101,759
  
   105,804
  
   99,710
  
  
 98,678
  
  
Shareholder’s equity 583,146
  
   553,093
  
   594,759
  
  
 576,661
  
  
Total liabilities and shareholder’s equity $6,255,407
  
   $5,831,535
  
   $6,566,660
  
  
 $6,145,098
  
  
Net interest income  
 $51,868
    
 $47,756
    
 $56,001
  
  
 $50,975
  
Net interest margin (%) 3
  
  
 3.57
  
  
 3.53
Net interest margin (%) 4
  
  
 3.68
  
  
 3.58



Nine months ended September 30 2016 2015
 Six months ended June 30
 2017 2016
(dollars in thousands) Average
balance		 
Interest
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1 
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1
 income/
expense
 Yield/
rate (%)
Assets:  
  
  
  
  
  
  
  
  
  
  
  
Interest-earning deposits $80,738
 $304
 0.50
 $133,343
 $253
 0.25
 $69,421
 $307
 0.88
 $72,070
 $180
 0.49
FHLB Stock 11,094
 142
 1.71
 39,372
 59
 0.20
FHLB stock 11,498
 105
 1.85
 11,031
 88
 1.61
Available-for-sale investment securities 892,726
 13,773
 2.06
 650,645
 10,258
 2.10
            
Taxable 1,206,272
 13,130
 2.18
 874,542
 9,192
 2.10
Non-taxable 15,427
 310
 4.00
 —
 —
 —
Total available-for-sale investment securities 1,221,699
 13,440
 2.20
 874,542
 9,192
 2.10
Loans                        
Residential 1-4 family 2,076,308
 66,565
 4.27
 2,059,921
 67,714
 4.38
 2,071,931
 43,789
 4.23
 2,075,890
 44,521
 4.29
Commercial real estate 854,977
 25,993
 4.04
 646,769
 19,251
 3.97
 913,940
 19,134
 4.18
 837,837
 16,880
 4.02
Home equity line of credit 857,652
 21,058
 3.28
 824,510
 19,683
 3.19
 872,973
 14,364
 3.32
 854,145
 13,854
 3.26
Residential land 18,577
 843
 6.05
 17,347
 830
 6.38
 17,057
 495
 5.80
 18,482
 561
 6.07
Commercial 753,783
 22,294
 3.93
 805,333
 21,847
 3.61
 666,741
 14,245
 4.30
 755,510
 14,967
 3.96
Consumer 143,514
 11,818
 11.00
 118,974
 8,321
 9.35
 195,158
 11,032
 11.40
 135,572
 7,344
 10.89
Total loans 1,2
 4,704,811
 148,571
 4.21
 4,472,854
 137,646
 4.10
Total interest-earning assets 1
 5,689,369
 162,790
 3.81
 5,296,214
 148,216
 3.73
Total loans 2,3
 4,737,800
 103,059
 4.36
 4,677,436
 98,127
 4.20
Total interest-earning assets 2
 6,040,418
 116,911
 3.88
 5,635,079
 107,587
 3.82
Allowance for loan losses (52,902)  
  
 (46,295)  
  
 (56,477)  
  
 (51,599)  
  
Non-interest-earning assets 505,014
  
  
 488,103
  
  
 527,302
  
  
 500,412
  
  
Total assets $6,141,481
  
  
 $5,738,022
  
  
 $6,511,243
  
  
 $6,083,892
  
  
Liabilities and shareholder’s equity:  
  
  
  
  
  
  
  
  
  
  
  
Savings $2,095,975
 $1,034
 0.07
 $1,967,446
 $928
 0.06
 $2,261,549
 $760
 0.07
 $2,073,790
 $676
 0.07
Interest-bearing checking 831,412
 127
 0.02
 776,100
 102
 0.02
 897,346
 114
 0.03
 828,345
 84
 0.02
Money market 164,596
 157
 0.13
 163,659
 152
 0.12
 151,293
 92
 0.12
 166,338
 105
 0.13
Time certificates 539,314
 3,836
 0.95
 442,224
 2,699
 0.82
 670,717
 3,448
 1.04
 509,884
 2,418
 0.95
Total interest-bearing deposits 3,631,297
 5,154
 0.19
 3,349,429
 3,881
 0.15
 3,980,905
 4,414
 0.22
 3,578,357
 3,283
 0.18
Advances from Federal Home Loan Bank 101,232
 2,363
 3.07
 100,586
 2,353
 3.09
 100,671
 1,563
 3.09
 101,854
 1,571
 3.05
Securities sold under agreements to repurchase 182,671
 2,053
 1.48
 216,066
 2,115
 1.29
 94,713
 77
 0.16
 193,296
 1,381
 1.42
Total interest-bearing liabilities 3,915,200
 9,570
 0.32
 3,666,081
 8,349
 0.30
 4,176,289
 6,054
 0.29
 3,873,507
 6,235
 0.32
Non-interest bearing liabilities:  
  
  
  
  
  
  
  
  
  
  
  
Deposits 1,549,467
  
  
 1,413,351
  
  
 1,646,275
  
  
 1,537,660
  
  
Other 100,210
  
  
 111,175
  
  
 98,875
  
  
 99,427
  
  
Shareholder’s equity 576,604
  
  
 547,415
  
  
 589,804
  
  
 573,298
  
  
Total liabilities and shareholder’s equity $6,141,481
  
  
 $5,738,022
  
  
 $6,511,243
  
  
 $6,083,892
  
  
Net interest income  
 $153,220
  
  
 $139,867
  
  
 $110,857
  
  
 $101,352
  
Net interest margin (%) 3
  
  
 3.59
  
  
 3.52
Net interest margin (%) 4
  
  
 3.68
  
  
 3.60
1    
Includes loans heldInterest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.06 million and nil for sale, at lower of cost or fair value.the three months ended June 30, 2017 and 2016, respectively and $0.1 million and nil for the six months ended June 30, 2017 and 2016, respectively.
2 Includes loans held for sale, at lower of cost or fair value.
23    
Includes recognition of deferred loan fees of $0.6 million and $0.6$0.7 million for the three months ended SeptemberJune 30, 2017 and 2016 and 2015, respectively, and $2.1$1.1 million and $1.9$1.5 million for the ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.
34   
Defined as net interest income as a percentage of average total interest-earning assets.
Earning assets, interest-bearingcosting liabilities 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 interest-bearingcosting liabilities. The interest rate environment has been impacted by disruptions in the financial markets over a period of several years and theseyears. These conditions had a negative impact onhave begun to moderate with the interest rate increases in the past year which resulted in an increase in ASB’s net interest margin during that period. With the recent interest increase by the Feds, ASB’s 2016 year-to-dateincome and net interest margin has increased compared to the same period in the prior year.margin.
                       The loan portfolioLoan originations and mortgage-related 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. The composition of ASB’s loans receivable was as follows:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(dollars in thousands) Balance % of total Balance % of total Balance % of total Balance % of total
Real estate:  
  
  
  
  
  
  
  
Residential 1-4 family $2,054,460
 43.4
 $2,069,665
 44.8
 $2,061,549
 43.4
 $2,048,051
 43.2
Commercial real estate 774,349
 16.3
 690,561
 14.9
 808,900
 17.1
 800,395
 16.9
Home equity line of credit 859,952
 18.1
 846,294
 18.3
 883,135
 18.6
 863,163
 18.2
Residential land 19,666
 0.4
 18,229
 0.4
 16,009
 0.3
 18,889
 0.4
Commercial construction 140,758
 3.0
 100,796
 2.2
 116,548
 2.5
 126,768
 2.7
Residential construction 15,073
 0.3
 14,089
 0.3
 10,759
 0.2
 16,080
 0.3
Total real estate, net 3,864,258
 81.5
 3,739,634
 80.9
 3,896,900
 82.1
 3,873,346
 81.7
Commercial 717,450
 15.2
 758,659
 16.4
 649,657
 13.7
 692,051
 14.6
Consumer 158,065
 3.3
 123,775
 2.7
 201,199
 4.2
 178,222
 3.7
 4,739,773
 100.0
 4,622,068
 100.0
 4,747,756
 100.0
 4,743,619
 100.0
Less: Deferred fees and discounts (5,135)  
 (6,249)  
 (3,122)  
 (4,926)  
Allowance for loan losses (58,737)  
 (50,038)  
 (56,356)  
 (55,533)  
Total loans, net $4,675,901
  
 $4,565,781
  
 $4,688,278
  
 $4,683,160
  
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 home equity lines of credit (HELOC) that were originated during the period of rapid home price appreciation between 2003 and 2007 as they have reached, or are starting to reach, 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 the HELOC originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older equity lines represent 4%2% of the portfolio and are included in the amortizing balances identified in the loan portfolio table above.
below.
  June 30, 2017 December 31, 2016
Outstanding balance of home equity loans (in thousands) $883,135
 $863,163
Percent of portfolio in first lien position 46.2 % 45.1%
Annualized net charge-off (recovery) ratio (0.03)% 0.01%
Delinquency ratio 0.28 % 0.35%
 September 30, 2016 December 31, 2015
Outstanding balance (in thousands)$859,952
 $846,294
Percent of portfolio in first lien position44.1% 42.9%
Net charge-off ratio0.01% 0.02%
Delinquency ratio0.27% 0.25%
     End of draw period – interest only Current     End of draw period – interest only Current
September 30, 2016 Total Interest only 2016-2017 2018-2020 Thereafter amortizing
June 30, 2017 Total Interest only 2017-2018 2019-2021 Thereafter amortizing
Outstanding balance (in thousands) $859,952
 $657,203
 $9,543
 $134,302
 $513,358
 $202,749
 $883,135
 $701,709
 $62,453
 $101,546
 $537,710
 $181,426
% of total 100% 76% 1% 15% 60% 24% 100% 79% 7% 11% 61% 21%
 
                       As of September 30, 2016, theThe HELOC portfolio comprised 18%19% 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 rate term loan with a 20-year amortization period. This product type comprises 96%79% of the total HELOC portfolio and is the current product offering. Within this product type, borrowersBorrowers 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 rate loan with level principal and interest payments. As of SeptemberJune 30, 20162017, approximately 20%19% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option.
Loan portfolio risk elements.  See Note 54 of the Condensed Consolidated Financial Statements.


Available-for-sale investment securities.  ASB’s investment portfolio was comprised as follows:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(dollars in thousands) Balance % of total Balance % of total Balance % of total Balance % of total
U.S. Treasury and federal agency obligations $189,372
 19% $212,959
 26% $186,583
 14% $192,281
 18%
Mortgage-related securities — FNMA, FHLMC and GNMA 807,612
 81
 607,689
 74
 1,100,876
 85
 897,474
 81
Mortgage revenue bond 15,427
 1
 15,427
 1
Total available-for-sale investment securities $996,984
 100% $820,648
 100% $1,302,886
 100% $1,105,182
 100%
Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. government.
Deposits and other borrowings.  Deposits continue to be the largest source of funds for ASB 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 for deposits and the low level of short-term interest rates. Advances from the FHLB of Des Moines and securities sold under agreements to repurchase continue to be additional sources of funds. As of SeptemberJune 30, 20162017, and December 31, 2016, ASB’s funding sourcescosting liabilities consisted of 95%97% deposits and 5%3% other borrowings compared to 94% deposits and 6% other borrowings as of December 31, 2015.borrowings. The weighted average cost of deposits for the first ninesix months of 2017 and 2016 was 0.16% and 2015 was 0.13% and 0.11%, respectively.
Federal Home Loan Bank Mergerof Des Moines. InAs of June 30, 2017 and December 31, 2016, ASB had $100 million of advances outstanding at the second quarterFHLB of 2015,Des Moines. As of June 30, 2017, the unused borrowing capacity with the FHLB of Des Moines 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.was $1.8 billion. The FHLB of Des Moines will continue to be a source of liquidity for ASB.
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 SeptemberJune 30, 20162017, ASB had an unrealized gain,loss, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $6.0$5.7 million compared to an unrealized loss, net of taxes, of $1.9$7.9 million at December 31, 2015.2016. See “Item 3. Quantitative and qualitative disclosures about market risk” for a discussion of ASB’s interest rate risk sensitivity.
During the first ninesix months of 2017, ASB recorded a provision for loan losses of $6.7 million primarily due to increased loan loss reserves for the consumer loan portfolio and additional loan loss reserves for the commercial real estate loan portfolio due to the downgrade of a commercial real estate relationship. During the first six months of 2016, ASB recorded a provision for loan losses of $15.3$9.5 million primarily due to increased loss reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for commercial loans due to downgrades of specific commercial credits. During the first nine months of 2015, ASB recorded a provision for loan losses of $5.4 million primarily due to loan loss reserves for the commercial real estate and commercial loan portfolios due to downgrades of specific credits, partly offset by the reversal of the Pahoa lava reserves and commercial loan payoffs. Financial stress on ASB’s customers may result in higher levels of delinquencies and losses.
 Nine months ended September 30 
Year ended
December 31,
 Six months ended June 30 
Year ended
December 31,
(in thousands) 2016 2015 2015 2017 2016 2016
Allowance for loan losses, January 1 $50,038
 $45,618
 $45,618
 $55,533
 $50,038
 $50,038
Provision for loan losses 15,266
 5,436
 6,275
 6,741
 9,519
 16,763
Less: net charge-offs 6,567
 2,780
 1,855
 5,918
 4,226
 11,268
Allowance for loan losses, end of period $58,737
 $48,274
 $50,038
 $56,356
 $55,331
 $55,533
Ratio of net charge-offs during the period to average loans outstanding (annualized) 0.19% 0.08% 0.04% 0.25% 0.18% 0.24%
We maintain a reserve for credit losses that consists of two components, the allowance for loan losses and a reserve for unfunded loan commitments (unfunded reserve). The level of the reserve for unfunded reserveloan commitments is adjusted by recording an expense or recovery in other noninterest expense. As of SeptemberJune 30, 20162017 and December 31, 2015,2016, the reserve for unfunded loan commitments was $1.8$1.7 million and $1.7$1.8 million, respectively.    
Legislation and regulation.  ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC)OCC and the 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.”


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 transferred on July 21, 2011 to the OCC, the FDIC, the 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 imposesimposed 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 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 reviewing 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 havehas 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.
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 address 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 SeptemberJune 30, 20162017, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.0%12.4%, a Tier-1 capital ratio of 12.0%12.4%, a Total capital ratio of 13.3%13.7% and a Tier-1 leverage ratio of 8.6%8.5%.
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 Department of Defense (DOD) amended its regulation that implements the Military Lending Act (MLA), which became effective on October 3, 2016. The DOD amended its regulation primarily for the purpose of extending the protections of the MLA to a broader range of closed-end and open-end credit products. 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 been subject to the requirements of the Regulation Z, namely: credit offered or extended to a covered borrower primarily for personal, family or household purposes and that is (i) subject 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 willwas 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 reviewing its pay schedules currentlyin voluntary compliance with the final rule.
Arbitration Agreements. Pursuant to determine necessary actionssection 1028(b) of the Dodd-Frank Act, on July 19, 2017, the Bureau issued a final rule to regulate arbitration agreements in contracts for compliance.specified consumer financial product and services. First, the final rule prohibits




Commitmentscovered providers of certain consumer financial products and contingencies.services from using an agreement with a consumer that provides for arbitration of any future dispute between the parties to bar the consumer from filing or participating in a class action concerning the covered consumer financial product or service. Second, the final rule requires covered providers that are involved in arbitration pursuant to a pre-dispute arbitration agreement to submit specified arbitral records to the Bureau and also to submit specified court records. See Note 5 ofThis regulation is effective September 18, 2017. ASB is currently evaluating the Consolidated Financial Statements.
Potential impact of lava flows.In June 2014, lava from the Kilauea Volcanothis final rule on the island of Hawaii began flowing toward the town of Pahoa. ASB had been monitoring its loan exposure on properties most likely to be impacted by the projected path of the lava flow. At March 31, 2015, the outstanding amount of the residential, commercial real estate and home equity lines of credit loans collateralized by property in areas most likely affected by the lava flow totaled $13 million. For residential 1-4 mortgages in the area, ASB required lava insurance to cover the dwelling replacement cost as a condition of making the loan. As of December 31, 2014, ASB provided $1.8 million reserves for a commercial real estate loan impacted by the lava flows. Although the lava threat was downgraded from a warning to a watch in March 2015 and the immediate threat to homes and businesses in Pahoa had receded, the lava flow remained active upslope and the reserves for the commercial real estate loan remained in place at March 31, 2015. In May 2015, the flow front near Pahoa remained cold and hard, no longer threatening any homes or businesses. All major tenants of the commercial center had returned by the end of March, and property occupancy stabilized soon thereafter. As a result, at the end of May 2015 the commercial real estate loan was restored to performing status and the reserves for lava risk were reversed.agreements.
FINANCIAL CONDITION
Liquidity and capital resources.
(dollars in millions) September 30, 2016 December 31, 2015 % change June 30, 2017 December 31, 2016 % change
Total assets $6,337
 $6,015
 5
 $6,611
 $6,421
 3
Available-for-sale investment securities 997
 821
 21
 1,303
 1,105
 18
Loans receivable held for investment, net 4,676
 4,566
 2
 4,688
 4,683
 —
Deposit liabilities 5,381
 5,025
 7
 5,724
 5,549
 3
Other bank borrowings 265
 329
 (19) 188
 193
 (3)
As of SeptemberJune 30, 20162017, ASB was one of Hawaii’s largest financial institutions based on assets of $6.3$6.6 billion and deposits of $5.4$5.7 billion.
As of SeptemberJune 30, 20162017, ASB’s unused FHLB borrowing capacity was approximately $1.8 billion. As of SeptemberJune 30, 20162017, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.9$1.8 billion. CommitmentsAs of June 30, 2017, the Company did not have commitments to lend to borrowers whose loan terms have been modified in troubled debt restructurings totaled $2.5 million at September 30, 2016.restructurings. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
For the ninesix months ended SeptemberJune 30, 2016,2017, net cash provided by ASB’s operating activities was $42$46 million. Net cash used during the same period by ASB’s investing activities was $310$221 million, primarily due to purchases of investment securities of $354$296 million, a net increase in loans receivable of $175$20 million and additions to premises and equipment of $8$20 million, partly offset by receipt of repayments and calls offrom investment securities of $173$100 million, proceeds from the sale of investments securities of $16 million and proceeds from the sale of loans of commercial loans of $38$13 million and a decrease in restricted cash of $2 million. Net cash provided by financing activities during this period was $260$152 million, primarily due to increases in deposit liabilities of $355$175 million and a net increase in retail repurchase agreements of $9 million, partly offset by repayments of securities sold under agreements to repurchase of $14 million and $19 million in common stock dividends to HEI (through ASB Hawaii).
For the six months ended June 30, 2016, net cash provided by ASB’s operating activities was $25 million. Net cash used during the same period by ASB’s investing activities was $205 million, primarily due to purchases of investment securities of $177 million, a net increase in loans receivable of $156 million and additions to premises and equipment of $6 million, partly offset by receipt of repayments and calls of investment securities of $103 million, proceeds from the sale of investment securities of $16 million and proceeds from the sale of commercial loans of $14 million. Net cash provided by financing activities during this period was $134 million, primarily due to increases in deposit liabilities of $207 million, partly offset by a net decrease in retail repurchase agreements of $21$27 million, maturities of securities sold under agreements to repurchase of $42 million, a net decrease in escrow deposits of $5$29 million and $27$18 million in common stock dividends to HEI (through ASB Hawaii).
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 SeptemberJune 30, 20162017, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a Common equity Tier-1 ratio of 12.0%12.4% (6.5%), a Tier-1 capital ratio of 12.0%12.4% (8.0%), a Total capital ratio of 13.3%13.7% (10.0%) and a Tier-1 leverage ratio of 8.6%8.5% (5.0%). As of December 31, 2015,2016, ASB was well-capitalized with a Commoncommon equity Tier-1 ratio of 12.1%12.2%, Tier-1 capital ratio of 12.1%12.2%, a Total capital ratio of 13.3%13.4% and a Tier-1 leverage ratio of 8.8%8.6%. All dividends are subject to review by the OCC and FRB approval is required beforeand receipt of a letter from the FRB communicating the agencies’ non-objection to the payment of any dividend ASB canproposes to declare and pay a dividend or otherwise make a capital distribution to HEI (through ASB Hawaii).


Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see HEI’s and Hawaiian Electric’s Quantitative and Qualitative Disclosures About Market Risk in Part II, Item 7A of HEI’s 20152016 Form 10-K (pages 8079 to 82)81).
ASB’s interest-rate risk sensitivity measures as of SeptemberJune 30, 20162017 and December 31, 20152016 constitute “forward-looking statements” and were as follows:
Change in interest rates 
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)
(basis points) September 30, 2016 December 31, 2015 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016 June 30, 2017 December 31, 2016
+300 2.0% 1.6% (1.5)% (9.3)% 2.6% 1.9% (7.6)% (8.0)%
+200 0.8
 0.6
 0.9
 (5.3) 1.7
 0.8
 (4.1) (4.6)
+100 —
 (0.1) 1.9
 (1.9) 0.8
 —
 (1.1) (1.6)
-100 (0.2) (0.5) (6.7) (1.2) (1.4) (0.5) (3.5) (1.6)
Management believes that ASB’s interest rate risk position as of SeptemberJune 30, 20162017 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was more asset sensitive for all rate increases as of SeptemberJune 30, 20162017 compared to December 31, 2015. The2016. Interest income increased due to the growth of the investment portfolio and higher income from the commercial and HELOC loan portfolios due to an increase in the short-term LIBOR and prime rates. In addition, the repricing assumptionassumptions of certain core deposits wascommercial loans were updated, andwhich resulted in slower repricing of those deposit balancesa net increase in the twelve-month simulation period. This shift to less rate sensitive deposits increased ASB’s asset sensitivity.NII.
ASB’s base EVE increased to $1.0$1.12 billion as of SeptemberJune 30, 20162017, compared to $974 million$1.09 billion as of December 31, 20152016, due to the growth and mix of the balance sheet. Assets increased by $322 millionThe growth of the investment portfolio was funded with the increase in core deposits. The upward shift in short term rates resulted in the market valuation of assets exceeding the growth and valuation of funding liabilities.
The change in EVE sensitivity to rising rates became less sensitivedeclined as of SeptemberJune 30, 20162017 compared to December 31, 2015 as2016. During the duration of assets shortened while the duration of liabilities lengthened. The downward shift in the yield curve led to faster prepayment expectations and shortened the durationsfirst half of the fixed rate mortgage andyear, the purchase of intermediate-termed duration investment portfolios. On the liability side of the balance sheet,securities was funded by longer duration core deposits, grew by $190 million with the mix shifting to longer duration products. Additionally, the behavior (decay and repricing) assumptions of certain core deposits were updated, resulting in longer duration deposit liabilities.a net decrease in EVE sensitivity.
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 indicative 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 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.
Item 4. Controls and Procedures
HEI:
Disclosure Controls and Procedures
The Company maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.


As of September 30, 2016, anAn evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective, as of September 30, 2016,the end of the period covered by the report, at the reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in internal control over financial reporting during the thirdsecond quarter of 20162017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Hawaiian Electric:
Disclosure Controls and Procedures
Hawaiian Electric maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by Hawaiian Electric in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to Hawaiian Electric’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
As of September 30, 2016, anAn evaluation was performed under the supervision and with the participation of Hawaiian Electric’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Hawaiian Electric’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including Hawaiian Electric’s Chief Executive Officer and Chief Financial Officer, concluded that Hawaiian Electric’s disclosure controls and procedures were effective, as of September 30, 2016,the end of the period covered by the report, at the reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in internal control over financial reporting during the thirdsecond quarter of 20162017 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.
PART II - OTHER INFORMATION

Item 1. Legal Proceedings
The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s and Hawaiian Electric’s 20152016 Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this Form 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2,3 and 4 and 5 of the Condensed Consolidated Financial Statements) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including Hawaiian Electric and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.
Item 1A. Risk Factors
For information about Risk Factors, see pages 25 to 35 of HEI’s and Hawaiian Electric’s 20152016 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and the Condensed Consolidated Financial Statements herein. Also, see “Cautionary Note Regarding Forward-Looking Statements” on pages iv and v herein. After the termination of the Merger Agreement, certain of the “Risk Factors Relating to the Merger” described on pages 25 and 26 of the Form 10-K may no longer be relevant. Also, there are risks that the termination of the Merger with NEE and the associated loss of NEE’s resources, expertise and support (e.g., financial and technological), could have negative impacts, including potentially higher costs and longer lead times to increase levels of renewable energy and to complete projects like ERP/ERM and smart grids, and a higher cost of capital.


Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of HEI common shares were made during the second quarter to satisfy the requirements of certain plans as follows:
ISSUER PURCHASES OF EQUITY SECURITIES
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
April 1 to 30, 2017 39,114
 $33.51 — NA
May 1 to 31, 2017 33,303
 $32.87 — NA
June 1 to 30, 2017 193,655
 $33.64 — 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 purchased,” all of the 39,114 shares, 23,773 of the 33,303 shares and 168,855 of the 193,655 shares were purchased for the DRIP; none of the 39,114 shares, 8,800 of the 33,303 shares and 21,300 of the 193,655 shares were purchased for the HEIRSP; and the remainder was 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.

Item 5. Other Information
A.           Ratio of earnings to fixed charges.
Nine months ended September 30 Years ended December 31 Six months ended June 30 Years ended December 31
2016 2015 2015 2014 2013 2012 2011 2017 2016 2016 2015 2014 2013 2012
HEI and Subsidiaries 
  
  
  
  
  
  
  
  
  
  
  
  
  
Excluding interest on ASB deposits5.34
 3.68
 3.68
 3.80
 3.55
 3.30
 3.24
 3.31
 3.64
 5.05
 3.68
 3.80
 3.55
 3.30
Including interest on ASB deposits5.04
 3.54
 3.54
 3.65
 3.42
 3.15
 3.04
 3.11
 3.46
 4.75
 3.54
 3.65
 3.42
 3.15
Hawaiian Electric and Subsidiaries4.18
 4.03
 3.97
 4.04
 3.72
 3.37
 3.52
 2.90
 3.76
 4.11
 3.97
 4.04
 3.72
 3.37
 
See HEI Exhibit 12.1 and Hawaiian Electric Exhibit 12.2.


Item 6. Exhibits
 
HEI Exhibit.10.1Second 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
HEI Exhibit 12.1 
Hawaiian Electric Industries, Inc. and Subsidiaries
Computation of ratio of earnings to fixed charges, ninesix months ended SeptemberJune 30, 20162017 and 20152016 and years ended December 31, 2016, 2015, 2014, 2013 2012 and 20112012
   
HEI Exhibit 31.1 Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)
   
HEI Exhibit 31.2 Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. AjelloGregory C. Hazelton (HEI Chief Financial Officer)
   
HEI Exhibit 32.1 HEI Certification Pursuant to 18 U.S.C. Section 1350
   
HEI Exhibit 101.INS XBRL Instance Document
   
HEI Exhibit 101.SCH XBRL Taxonomy Extension Schema Document
   
HEI Exhibit 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
   
HEI Exhibit 101.DEF XBRL Taxonomy Extension Definition Linkbase Document
   
HEI Exhibit 101.LAB XBRL Taxonomy Extension Label Linkbase Document
   
HEI Exhibit 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
   
Hawaiian Electric Exhibit 102 Letter agreementTermination Agreement, dated July 28, 201614, 2017, by and executed August 1, 2016 extending the termamong Hamakua Energy Partners, L.P. and Hamakua Land Partnership, L.L.P. and Hawaii Electric Light Company, Inc.
Hawaiian Electric Exhibit 10.2Second Amended and Restated Credit Agreement, dated as of the Power Purchase Agreement (PPA) betweenJune 30, 2017, among Hawaiian Electric Company, Inc., as Borrower, the Lenders Party Hereto and Kalaeloa Partners, L.P. datedWells Fargo Bank, National Association, as Syndication Agent, and Bank of October 14, 1988 (as amended)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
   
Hawaiian Electric Exhibit 12.2 
Hawaiian Electric Company, Inc. and Subsidiaries
Computation of ratio of earnings to fixed charges, ninesix months ended SeptemberJune 30, 20162017 and 20152016 and years ended December 31, 2016, 2015, 2014, 2013 2012 and 20112012
   
Hawaiian Electric Exhibit 31.3 Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Alan M. Oshima (Hawaiian Electric Chief Executive Officer)
   
Hawaiian Electric Exhibit 31.4 Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (Hawaiian Electric Chief Financial Officer)
   
Hawaiian Electric Exhibit 32.2 Hawaiian Electric Certification Pursuant to 18 U.S.C. Section 1350

SIGNATURES
 
Pursuant to the requirements 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 signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.
 
HAWAIIAN ELECTRIC INDUSTRIES, INC. HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant) (Registrant)
   
   
By/s/ Constance H. Lau By/s/ Alan M. Oshima
 Constance H. Lau  Alan M. Oshima
 President and Chief Executive Officer  President and Chief Executive Officer
 (Principal Executive Officer of HEI)  (Principal Executive Officer of Hawaiian Electric)
   
   
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  Senior Vice President
 Chief Financial Officer  and Chief Financial Officer
 (Principal Financial and Accounting  (Principal Financial Officer of Hawaiian Electric)
 Officer of HEI)  
   
   
Date: November 4, 2016August 3, 2017 Date: November 4, 2016August 3, 2017


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