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, 20152016
 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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
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
 
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 31, 2015July 29, 2016
Hawaiian Electric Industries, Inc. (Without Par Value) 107,458,641108,195,738 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value) 15,805,327 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, 20152016
 
TABLE OF CONTENTS
 
Page No.  
ii
 
Glossary of Terms
iv
 
Forward-Looking Statements
   
  
PART I. FINANCIAL INFORMATION
1
 
Item 1.
Financial Statements
    
   
Hawaiian Electric Industries, Inc. and Subsidiaries
1
  
Consolidated Statements of Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20152016 and 20142015
2
  
Consolidated Statements of Comprehensive Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20152016 and 20142015
3
  
Consolidated Balance Sheets (unaudited) - SeptemberJune 30, 20152016 and December 31, 20142015
4
  
Consolidated Statements of Changes in Shareholders’ Equity (unaudited) -
ninesix months ended SeptemberJune 30, 20152016 and 20142015
5
  
Consolidated Statements of Cash Flows (unaudited) -
ninesix months ended SeptemberJune 30, 20152016 and 20142015
   
Hawaiian Electric Company, Inc. and Subsidiaries
6
  
Consolidated Statements of Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20152016 and 20142015
6
  
Consolidated Statements of Comprehensive Income (unaudited) -
three and ninesix months ended SeptemberJune 30, 20152016 and 20142015
7
  
Consolidated Balance Sheets (unaudited) - SeptemberJune 30, 20152016 and December 31, 20142015
8
  
Consolidated Statements of Changes in Common Stock Equity (unaudited) -
ninesix months ended SeptemberJune 30, 20152016 and 20142015
9
  
Consolidated Statements of Cash Flows (unaudited) -
ninesix months ended SeptemberJune 30, 20152016 and 20142015
10
  
Notes to Consolidated Financial Statements (unaudited)
6463
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6463
  
HEI consolidated
6968
  
Electric Utilities
79
  
Bank
87
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
88
 
Item 4.
Controls and Procedures
   
  
PART II.
OTHER INFORMATION
89
 
Item 1.
Legal Proceedings
89
 
Item 1A.
Risk Factors
9089
 Item 22.Unregistered Sales of Equity Securities and Use of Proceeds
90
 
Item 5.
Other Information
9190
 
Item 6.
Exhibits
9291
 
Signatures
 

i


Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended SeptemberJune 30, 20152016
GLOSSARY OF TERMS
Terms Definitions
AES Hawaii AES Hawaii, Inc.
AFUDC Allowance for funds used during construction
AOCI Accumulated other comprehensive income/(loss)
ARO Asset 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.
ASC Accounting Standards Codification
ASU Accounting Standards Update
CIP CT-1 Campbell Industrial Park 110 MW combustion turbine No. 1
CIS Customer 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.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities) (dissolved in 2015); 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
DER Distributed Energy Resources
D&O Decision and order
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
EGU Electrical generating unit
EIP 2010 Equity and Incentive Plan, as amended and restated
EPA Environmental Protection Agency — federal
EPS Earnings per share
ERISA Employee Retirement Income Security Act of 1974, as amended
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
FERC Federal 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
GHG Greenhouse 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.
HIE Hawaii Independent Energy, LLC
HEI Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., ASB Hawaii, Inc., HEI Properties, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III (dissolved in 2015) 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
Hpower 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
MATS Mercury 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, merger of Merger Sub I with and into HEI, with HEI surviving, and then merger of HEI with and into Merger Sub II, with Merger Sub II surviving as a wholly owned subsidiary of NEE
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 I NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE
Merger Sub II NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE
MW Megawatt/s (as applicable)
NEE NextEra Energy, Inc.
NEM Net energy metering
NII Net interest income
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 Photovaltaic
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
SAR Stock appreciation right
SEC Securities and Exchange Commission
See Means the referenced material is incorporated by reference
Spin-Off The distribution to HEI shareholders of all of the common stock of ASB Hawaii immediately prior to the Merger
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


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 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:
the successful and timely completion of the proposed Merger with NextEra Energy, Inc. (NEE), which could be materially and adversely affected by, among other things, resolving the litigation brought in connection with the proposed Merger, obtaining (and the timing and terms and conditions of) required governmental and regulatory approvals, and ability to maintain relationships with employees, customers or suppliers, as well as the ability to integrate the businesses;
the ability of ASB to operate successfully after the Spin-Off of its parent ASB Hawaii;
international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB),ASB, which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, the effects of the United Kingdom’s referendum to withdraw from the European Union, unrest, ongoing conflictsthe conflict in North Africa and the Middle East,Syria, terrorist acts by ISIS or others, potential conflict or crisis with North Korea or Iran, developments in the Ukraine 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 and monetary policy;
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) 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 RPSrenewable 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 and business model changes proposed and being developed in response to the four orders that 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’s inclinations on the future of Hawaii’s electric utilities and the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customer interests and the state’s public policy goals; and emphasized the need to “leap ahead” of other states in creating a 21st century generation system and modern transmission and distribution grids;
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 renewable portfolio standards (RPS))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 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
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) 2015 2014 2015 2014 2016 2015 2016 2015
Revenues  
  
  
  
  
  
  
  
Electric utility $648,127
 $803,565
 $1,779,732
 $2,262,056
 $495,395
 $558,163
 $977,447
 $1,131,605
Bank 69,091
 63,536
 199,222
 187,771
 70,749
 65,783
 139,589
 130,131
Other (42) (5) (4) (325) 100
 (34) 168
 38
Total revenues 717,176
 867,096
 1,978,950
 2,449,502
 566,244
 623,912
 1,117,204
 1,261,774
Expenses  
  
  
  
  
  
  
  
Electric utility 565,470
 727,409
 1,573,278
 2,045,166
 424,709
 492,002
 851,435
 1,007,808
Bank 48,289
 43,030
 138,063
 126,778
 50,525
 46,057
 99,771
 89,774
Other 6,322
 4,621
 28,278
 13,125
 5,555
 13,123
 11,692
 21,956
Total expenses 620,081
 775,060
 1,739,619
 2,185,069
 480,789
 551,182
 962,898
 1,119,538
Operating income (loss)  
  
  
  
  
  
  
  
Electric utility 82,657
 76,156
 206,454
 216,890
 70,686
 66,161
 126,012
 123,797
Bank 20,802
 20,506
 61,159
 60,993
 20,224
 19,726
 39,818
 40,357
Other (6,364) (4,626) (28,282) (13,450) (5,455) (13,157) (11,524) (21,918)
Total operating income 97,095
 92,036
 239,331
 264,433
 85,455
 72,730
 154,306
 142,236
Interest expense, net—other than on deposit liabilities and other bank borrowings (19,229) (19,170) (57,235) (58,648) (17,301) (18,906) (37,427) (38,006)
Allowance for borrowed funds used during construction 737
 740
 1,918
 1,877
 760
 682
 1,422
 1,181
Allowance for equity funds used during construction 2,057
 1,937
 5,366
 4,933
 1,997
 1,896
 3,736
 3,309
Income before income taxes 80,660
 75,543
 189,380
 212,595
 70,911
 56,402
 122,037
 108,720
Income taxes 29,516
 27,264
 70,406
 76,302
 26,310
 20,911
 44,611
 40,890
Net income 51,144
 48,279
 118,974
 136,293
 44,601
 35,491
 77,426
 67,830
Preferred stock dividends of subsidiaries 471
 471
 1,417
 1,417
 473
 473
 946
 946
Net income for common stock $50,673
 $47,808
 $117,557
 $134,876
 $44,128
 $35,018
 $76,480
 $66,884
Basic earnings per common share $0.47
 $0.47
 $1.11
 $1.33
 $0.41
 $0.33
 $0.71
 $0.63
Diluted earnings per common share $0.47
 $0.46
 $1.11
 $1.32
 $0.41
 $0.33
 $0.71
 $0.63
Dividends per common share $0.31
 $0.31
 $0.93
 $0.93
 $0.31
 $0.31
 $0.62
 $0.62
Weighted-average number of common shares outstanding 107,457
 102,416
 106,067
 101,768
 107,962
 107,418
 107,791
 105,361
Net effect of potentially dilutive shares 281
 610
 280
 710
 171
 276
 187
 298
Adjusted weighted-average shares 107,738
 103,026
 106,347
 102,478
 108,133
 107,694
 107,978
 105,659
 
The accompanying notes are an integral part of these consolidated financial statements.


1



Hawaiian Electric Industries, Inc. and Subsidiaries
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) 2015 2014 2015 2014 2016 2015 2016 2015
Net income for common stock $50,673
 $47,808
 $117,557
 $134,876
 $44,128
 $35,018
 $76,480
 $66,884
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 ($2,543), $1,094, ($2,382) and ($2,249) for the respective periods 3,851
 (1,657) 3,608
 3,406
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, nil and $1,132 for the respective periods —
 —
 —
 (1,715)
Net unrealized gains (losses) on available-for-sale investment securities arising during the period, net of (taxes) benefits of ($1,925), $2,439, ($6,830) and $161 for the respective periods 2,916
 (3,694) 10,344
 (243)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $238, nil, $238 and nil for the respective periods (360) —
 (360) —
Derivatives qualified as cash flow hedges:  
  
  
  
  
  
  
  
Less: reclassification adjustment to net income, net of tax benefits of $37, $37, $112 and $112 for the respective periods 59
 59
 177
 177
Effective portion of foreign currency hedge net unrealized gains (losses), net of (taxes) benefits of $475, nil, ($163) and nil for the respective periods (745) —
 257
 —
Less: reclassification adjustment to net income, net of tax benefits of nil, $38, $35 and $75 for the respective periods —
 59
 54
 118
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 $3,583, $1,900, $10,760, and $5,438 for the respective periods 5,611
 2,829
 16,850
 8,515
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,243, $1,619, $9,729 and $4,858 for the respective periods (5,091) (2,542) (15,274) (7,627)
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,362, $3,691, $4,619 and $7,177 for the respective periods 3,698
 5,780
 7,236
 11,239
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,166, $3,359, $4,218 and $6,486 for the respective periods (3,401) (5,272) (6,623) (10,183)
Other comprehensive income (loss), net of taxes 4,430
 (1,311) 5,361
 2,756
 2,108
 (3,127) 10,908
 931
Comprehensive income attributable to Hawaiian Electric Industries, Inc. $55,103
 $46,497
 $122,918
 $137,632
 $46,236
 $31,891
 $87,388
 $67,815
 
The accompanying notes are an integral part of these consolidated financial statements.

2



Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Balance Sheets (unaudited) 
(dollars in thousands) September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015
Assets  
  
  
  
Cash and cash equivalents $228,417
 $175,542
 $257,208
 $300,478
Accounts receivable and unbilled revenues, net 305,448
 313,696
 224,179
 242,766
Available-for-sale investment securities, at fair value 785,837
 550,394
 894,021
 820,648
Stock in Federal Home Loan Bank, at cost 10,678
 69,302
 11,218
 10,678
Loans receivable held for investment, net 4,487,130
 4,389,033
 4,699,623
 4,565,781
Loans held for sale, at lower of cost or fair value 5,598
 8,424
 6,217
 4,631
Property, plant and equipment, net of accumulated depreciation of $2,318,227 and $2,250,950 at the respective dates 4,317,121
 4,148,774
Property, plant and equipment, net of accumulated depreciation of $2,387,013 and $2,339,319 at the respective dates 4,482,990
 4,377,658
Regulatory assets 897,948
 905,264
 885,114
 896,731
Other 453,099
 542,523
 436,479
 480,457
Goodwill 82,190
 82,190
 82,190
 82,190
Total assets $11,573,466
 $11,185,142
 $11,979,239
 $11,782,018
Liabilities and shareholders’ equity  
  
  
  
Liabilities  
  
  
  
Accounts payable $152,896
 $186,425
 $130,160
 $138,523
Interest and dividends payable 25,914
 25,336
 23,490
 26,042
Deposit liabilities 4,825,954
 4,623,415
 5,232,203
 5,025,254
Short-term borrowings—other than bank 171,992
 118,972
 115,985
 103,063
Other bank borrowings 368,593
 290,656
 272,887
 328,582
Long-term debt, net—other than bank 1,506,546
 1,506,546
 1,578,842
 1,578,368
Deferred income taxes 643,951
 633,570
 712,199
 680,877
Regulatory liabilities 362,251
 344,849
 391,003
 371,543
Contributions in aid of construction 495,667
 466,432
 516,750
 506,087
Defined benefit pension and other postretirement benefit plans liability 607,682
 632,845
 578,651
 589,918
Other 456,726
 531,230
 426,594
 471,828
Total liabilities 9,618,172
 9,360,276
 9,978,764
 9,820,085
Preferred stock of subsidiaries - not subject to mandatory redemption 34,293
 34,293
 34,293
 34,293
Commitments and contingencies (Notes 4 and 5) 

 

 

 

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: 107,458,641 shares and 102,565,266 shares at the respective dates 1,627,259
 1,521,297
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,187,063 shares and 107,460,406 shares at the respective dates 1,647,138
 1,629,136
Retained earnings 315,759
 296,654
 334,398
 324,766
Accumulated other comprehensive loss, net of tax benefits (22,017) (27,378) (15,354) (26,262)
Total shareholders’ equity 1,921,001
 1,790,573
 1,966,182
 1,927,640
Total liabilities and shareholders’ equity $11,573,466
 $11,185,142
 $11,979,239
 $11,782,018
 
The accompanying notes are an integral part of these consolidated financial statements.

3

Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Changes in Shareholders’ Equity (unaudited) 
 Common stock Retained 
Accumulated
other
comprehensive
   Common stock Retained 
Accumulated
other
comprehensive
  
(in thousands, except per share amounts) Shares Amount Earnings income (loss) Total 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 —
 —
 76,480
 —
 76,480
Other comprehensive income, net of taxes —
 —
 —
 10,908
 10,908
Issuance of common stock, net 727
 18,002
 —
 —
 18,002
Common stock dividends ($0.62 per share) —
 —
 (66,848) —
 (66,848)
Balance, June 30, 2016 108,187
 $1,647,138
 $334,398
 $(15,354) $1,966,182
Balance, December 31, 2014 102,565
 $1,521,297
 $296,654
 $(27,378) $1,790,573
 102,565
 $1,521,297
 $296,654
 $(27,378) $1,790,573
Net income for common stock —
 —
 117,557
 —
 117,557
 —
 —
 66,884
 —
 66,884
Other comprehensive income, net of taxes —
 —
 —
 5,361
 5,361
 —
 —
 —
 931
 931
Issuance of common stock, net 4,894
 105,962
 —
 —
 105,962
 4,882
 105,272
 —
 —
 105,272
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
Balance, December 31, 2013 101,260
 $1,488,126
 $255,030
 $(16,750) $1,726,406
Net income for common stock —
 —
 134,876
 —
 134,876
Other comprehensive income, net of taxes —
 —
 —
 2,756
 2,756
Issuance of common stock, net 1,302
 31,130
 —
 —
 31,130
Common stock dividends ($0.93 per share) —
 —
 (94,711) —
 (94,711)
Balance, September 30, 2014 102,562
 $1,519,256
 $295,195
 $(13,994) $1,800,457
Common stock dividends ($0.62 per share) —
 —
 (65,140) —
 (65,140)
Balance, June 30, 2015 107,447
 $1,626,569
 $298,398
 $(26,447) $1,898,520
 
The accompanying notes are an integral part of these consolidated financial statements.


4



Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited)
Nine months ended September 30 2015 2014
Six months ended June 30 2016 2015
(in thousands)        
Cash flows from operating activities  
  
  
  
Net income $118,974
 $136,293
 $77,426
 $67,830
Adjustments to reconcile net income to net cash provided by operating activities  
  
  
  
Depreciation of property, plant and equipment 137,721
 129,574
 97,148
 91,731
Other amortization 12,080
 5,081
 4,840
 4,792
Provision for loan losses 5,436
 3,566
 9,519
 2,439
Loans receivable originated and purchased, held for sale (226,081) (102,523) (98,004) (168,921)
Proceeds from sale of loans receivable, held for sale 231,509
 106,918
 98,457
 173,267
Increase in deferred income taxes 2,723
 50,296
Deferred income taxes 21,738
 (4,463)
Share-based compensation expense 4,780
 7,200
 2,011
 3,769
Excess tax benefits from share-based payment arrangements (1,012) (271) (383) (984)
Allowance for equity funds used during construction (5,366) (4,933) (3,736) (3,309)
Change in cash overdraft —
 (1,038) —
 193
Other 2,982
 1,777
Changes in assets and liabilities  
  
  
  
Decrease (increase) in accounts receivable and unbilled revenues, net 8,248
 (18,943)
Decrease in fuel oil stock 35,942
 15,784
Decrease in accounts receivable and unbilled revenues, net 12,894
 44,489
Decrease (increase) in fuel oil stock 9,644
 (2,362)
Increase in regulatory assets (23,458) (17,531) (11,752) (19,976)
Decrease in accounts, interest and dividends payable (34,171) (51,199)
Increase in accounts, interest and dividends payable 20,837
 8,504
Change in prepaid and accrued income taxes and utility revenue taxes (8,458) (2,044) 622
 (4,390)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability 418
 (2,594)
Increase in defined benefit pension and other postretirement benefit plans liability 95
 218
Change in other assets and liabilities (38,033) (56,326) (18,878) (26,232)
Net cash provided by operating activities 221,252
 197,310
 225,460
 168,372
Cash flows from investing activities  
  
  
  
Available-for-sale investment securities purchased (326,965) (130,578) (176,598) (208,110)
Principal repayments on available-for-sale investment securities 96,053
 52,678
 102,716
 63,568
Proceeds from sale of available-for-sale investment securities —
 79,564
 16,423
 —
Purchase of stock from Federal Home Loan Bank (1,600) —
 (2,773) —
Redemption of stock from Federal Home Loan Bank 60,223
 17,482
 2,233
 58,623
Net increase in loans held for investment (101,771) (184,766) (155,930) (23,206)
Proceeds from sale of commercial loans 14,105
 —
Proceeds from sale of real estate acquired in settlement of loans 1,258
 2,930
 553
 1,258
Proceeds from sale of real estate held-for-sale 7,280
 —
Capital expenditures (276,186) (260,616) (203,631) (206,816)
Contributions in aid of construction 34,627
 21,740
 16,810
 19,089
Other 4,084
 674
 1,106
 3,819
Net cash used in investing activities (502,997) (400,892) (384,986) (291,775)
Cash flows from financing activities  
  
  
  
Net increase in deposit liabilities 202,539
 161,320
 206,949
 179,856
Net increase in short-term borrowings with original maturities of three months or less 53,020
 45,094
 12,922
 5,571
Net increase (decrease) in retail repurchase agreements 67,934
 (6,306) (27,158) 13,508
Proceeds from other bank borrowings 50,000
 90,000
 55,835
 10,000
Repayments of other bank borrowings (40,000) (65,000) (84,369) —
Proceeds from issuance of long-term debt —
 125,000
 75,000
 —
Repayment of long-term debt —
 (100,000) (75,000) —
Excess tax benefits from share-based payment arrangements 1,012
 271
 383
 984
Net proceeds from issuance of common stock 104,437
 26,910
 7,668
 104,469
Common stock dividends (98,452) (94,674) (55,591) (65,140)
Preferred stock dividends of subsidiaries (1,417) (1,417) (946) (946)
Other (4,453) (5,097) 563
 246
Net cash provided by financing activities 334,620
 176,101
 116,256
 248,548
Net increase (decrease) in cash and cash equivalents 52,875
 (27,481) (43,270) 125,145
Cash and cash equivalents, beginning of period 175,542
 220,036
 300,478
 175,542
Cash and cash equivalents, end of period $228,417
 $192,555
 $257,208
 $300,687
The accompanying notes are an integral part of these consolidated financial statements.

5



Hawaiian Electric Company, Inc. and Subsidiaries
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) 2015 2014 2015 2014 2016 2015 2016 2015
Revenues $648,127
 $803,565
 $1,779,732
 $2,262,056
 $495,395
 $558,163
 $977,447
 $1,131,605
Expenses  
  
  
  
  
  
  
  
Fuel oil 195,633
 309,432
 518,670
 865,989
 91,899
 146,231
 205,639
 323,037
Purchased power 160,518
 192,882
 445,809
 546,121
 139,058
 149,284
 254,917
 285,291
Other operation and maintenance 103,653
 108,313
 306,519
 295,483
 99,563
 98,864
 203,471
 202,866
Depreciation 44,356
 41,594
 132,840
 124,790
 46,760
 44,241
 93,541
 88,484
Taxes, other than income taxes 61,310
 75,188
 169,440
 212,783
 47,429
 53,382
 93,867
 108,130
Total expenses 565,470
 727,409
 1,573,278
 2,045,166
 424,709
 492,002
 851,435
 1,007,808
Operating income 82,657
 76,156
 206,454
 216,890
 70,686
 66,161
 126,012
 123,797
Allowance for equity funds used during construction 2,057
 1,937
 5,366
 4,933
 1,997
 1,896
 3,736
 3,309
Interest expense and other charges, net (16,557) (16,414) (49,170) (48,989) (15,103) (16,288) (32,411) (32,613)
Allowance for borrowed funds used during construction 737
 740
 1,918
 1,877
 760
 682
 1,422
 1,181
Income before income taxes 68,894
 62,419
 164,568
 174,711
 58,340
 52,451
 98,759
 95,674
Income taxes 25,390
 23,042
 60,351
 64,686
 21,984
 19,111
 36,537
 34,961
Net income 43,504
 39,377
 104,217
 110,025
 36,356
 33,340
 62,222
 60,713
Preferred stock dividends of subsidiaries 228
 228
 686
 686
 229
 229
 458
 458
Net income attributable to Hawaiian Electric 43,276
 39,149
 103,531
 109,339
 36,127
 33,111
 61,764
 60,255
Preferred stock dividends of Hawaiian Electric 270
 270
 810
 810
 270
 270
 540
 540
Net income for common stock $43,006
 $38,879
 $102,721
 $108,529
 $35,857
 $32,841
 $61,224
 $59,715
The accompanying notes are an integral part of these 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.
The accompanying notes are an integral part of these consolidated financial statements.

Hawaiian Electric Company, Inc. and Subsidiaries
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) 2015 2014 2015 2014 2016 2015 2016 2015
Net income for common stock $43,006
 $38,879
 $102,721
 $108,529
 $35,857
 $32,841
 $61,224
 $59,715
Other comprehensive income, net of taxes:  
  
  
  
Other comprehensive income (loss), net of taxes:  
  
  
  
Derivatives qualified as cash flow hedges:        
Effective portion of foreign currency hedge net unrealized gains (losses), net of (taxes) benefits of $475, nil, ($163) and nil for the respective periods (745) —
 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 of $3,245, $1,626, $9,735 and $4,878 for the respective periods 5,095
 2,552
 15,285
 7,659
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,243, $1,619, $9,729 and $4,858 for the respective periods (5,091) (2,542) (15,274) (7,627)
Other comprehensive income, net of taxes 4
 10
 11
 32
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,160, $3,349, $4,221 and $6,490 for the respective periods 3,391
 5,257
 6,627
 10,190
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,166, $3,359, $4,218 and $6,486 for the respective periods (3,401) (5,272) (6,623) (10,183)
Other comprehensive income (loss), net of taxes (755) (15) 261
 7
Comprehensive income attributable to Hawaiian Electric Company, Inc. $43,010
 $38,889
 $102,732
 $108,561
 $35,102
 $32,826
 $61,485
 $59,722
The accompanying notes are an integral part of these consolidated financial statements.


6


Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Balance Sheets (unaudited)
(dollars in thousands, except par value) September 30,
2015		 December 31,
2014		 June 30,
2016		 December 31,
2015
Assets  
  
  
  
Property, plant and equipment        
Utility property, plant and equipment  
  
  
  
Land $52,283
 $52,299
 $53,175
 $52,792
Plant and equipment 6,216,114
 6,009,482
 6,411,544
 6,315,698
Less accumulated depreciation (2,246,614) (2,175,510) (2,314,743) (2,266,004)
Construction in progress 196,681
 158,616
 230,143
 175,309
Utility property, plant and equipment, net 4,218,464
 4,044,887
 4,380,119
 4,277,795
Nonutility property, plant and equipment, less accumulated depreciation of $1,228 and $1,227 at respective dates 6,562
 6,563
Nonutility property, plant and equipment, less accumulated depreciation of $1,230 and $1,229 at respective dates 7,375
 7,272
Total property, plant and equipment, net 4,225,026
 4,051,450
 4,387,494
 4,285,067
Current assets  
  
  
  
Cash and cash equivalents 10,704
 13,762
 27,579
 24,449
Customer accounts receivable, net 162,468
 158,484
 116,265
 132,778
Accrued unbilled revenues, net 123,578
 137,374
 87,724
 84,509
Other accounts receivable, net 4,763
 4,283
 4,546
 10,408
Fuel oil stock, at average cost 70,104
 106,046
 61,572
 71,216
Materials and supplies, at average cost 58,973
 57,250
 56,911
 54,429
Prepayments and other 46,891
 66,383
 21,879
 36,640
Regulatory assets 79,950
 71,421
 90,471
 72,231
Total current assets 557,431
 615,003
 466,947
 486,660
Other long-term assets  
  
  
  
Regulatory assets 817,998
 833,843
 794,643
 824,500
Unamortized debt expense 7,586
 8,323
 344
 497
Other 75,951
 81,838
 72,425
 75,486
Total other long-term assets 901,535
 924,004
 867,412
 900,483
Total assets $5,683,992
 $5,590,457
 $5,721,853
 $5,672,210
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
 $105,388
 $105,388
Premium on capital stock 578,930
 578,938
 578,926
 578,930
Retained earnings 1,032,690
 997,773
 1,057,506
 1,043,082
Accumulated other comprehensive income, net of income taxes-retirement benefit plans 56
 45
Accumulated other comprehensive income, net of income taxes 1,186
 925
Common stock equity 1,717,064
 1,682,144
 1,743,006
 1,728,325
Cumulative preferred stock — not subject to mandatory redemption 34,293
 34,293
 34,293
 34,293
Long-term debt, net 1,206,546
 1,206,546
 1,279,123
 1,278,702
Total capitalization 2,957,903
 2,922,983
 3,056,422
 3,041,320
Commitments and contingencies (Note 4) 

 

 

 

Current liabilities  
  
  
  
Short-term borrowings from non-affiliates 94,995
 —
 36,995
 —
Accounts payable 124,779
 163,934
 106,521
 114,846
Interest and preferred dividends payable 25,078
 22,316
 21,309
 23,111
Taxes accrued 193,575
 250,402
 141,148
 191,084
Regulatory liabilities 347
 632
 3,368
 2,204
Other 75,450
 65,146
 53,347
 54,079
Total current liabilities 514,224
 502,430
 362,688
 385,324
Deferred credits and other liabilities  
  
  
  
Deferred income taxes 625,422
 602,872
 689,482
 654,806
Regulatory liabilities 361,904
 344,217
 387,635
 369,339
Unamortized tax credits 83,648
 79,492
 89,176
 84,214
Defined benefit pension and other postretirement benefit plans liability 570,028
 595,395
 541,656
 552,974
Other 75,196
 76,636
 78,044
 78,146
Total deferred credits and other liabilities 1,716,198
 1,698,612
 1,785,993
 1,739,479
Contributions in aid of construction 495,667
 466,432
 516,750
 506,087
Total capitalization and liabilities $5,683,992
 $5,590,457
 $5,721,853
 $5,672,210
 The accompanying notes are an integral part of these consolidated financial statements.

7



Hawaiian Electric Company, Inc. and Subsidiaries
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, 2015 15,805
 $105,388
 $578,930
 $1,043,082
 $925
 $1,728,325
Net income for common stock —
 —
 —
 61,224
 —
 61,224
Other comprehensive income, net of taxes —
 —
 —
 —
 261
 261
Common stock dividends —
 —
 —
 (46,800) —
 (46,800)
Common stock issuance expenses —
 —
 (4) —
 —
 (4)
Balance, June 30, 2016 15,805
 $105,388
 $578,926
 $1,057,506
 $1,186
 $1,743,006
Balance, December 31, 2014 15,805
 $105,388
 $578,938
 $997,773
 $45
 $1,682,144
 15,805
 $105,388
 $578,938
 $997,773
 $45
 $1,682,144
Net income for common stock —
 —
 —
 102,721
 —
 102,721
 —
 —
 —
 59,715
 —
 59,715
Other comprehensive income, net of taxes —
 —
 —
 —
 11
 11
 —
 —
 —
 —
 7
 7
Common stock dividends —
 —
 —
 (67,804) —
 (67,804) —
 —
 —
 (45,203) —
 (45,203)
Common stock issuance expenses —
 —
 (8) —
 —
 (8) —
 —
 (5) —
 —
 (5)
Balance, September 30, 2015 15,805
 $105,388
 $578,930
 $1,032,690
 $56
 $1,717,064
Balance, December 31, 2013 15,429
 $102,880
 $541,452
 $948,624
 $608
 $1,593,564
Net income for common stock —
 —
 —
 108,529
 —
 108,529
Other comprehensive income, net of taxes —
 —
 —
 —
 32
 32
Common stock dividends —
 —
 —
 (66,369) —
 (66,369)
Common stock issuance expenses —
 —
 (5) —
 —
 (5)
Balance, September 30, 2014 15,429
 $102,880
 $541,447
 $990,784
 $640
 $1,635,751
Balance, June 30, 2015 15,805
 $105,388
 $578,933
 $1,012,285
 $52
 $1,696,658
 
The accompanying notes are an integral part of these consolidated financial statements.


8



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited) 
Nine months ended September 30 2015 2014
Six months ended June 30 2016 2015
(in thousands)        
Cash flows from operating activities  
  
  
  
Net income $104,217

$110,025
 $62,222

$60,713
Adjustments to reconcile net income to net cash provided by operating activities  

 
  

 
Depreciation of property, plant and equipment 132,840

124,790
 93,541

88,484
Other amortization 9,827

4,289
 3,793

3,220
Increase in deferred income taxes 58,211

67,392
Deferred income taxes 32,118

33,320
Change in tax credits, net 4,247

5,816
 5,004

4,461
Allowance for equity funds used during construction (5,366)
(4,933) (3,736)
(3,309)
Change in cash overdraft —

(1,038) —

193
Other (2,022) 1,777
Changes in assets and liabilities  

 
  

 
Increase in accounts receivable (4,464)
(19,731)
Decrease in accrued unbilled revenues 13,796

971
Decrease in fuel oil stock 35,942

15,784
Decrease in accounts receivable 16,682

16,955
Decrease (increase) in accrued unbilled revenues (3,215)
27,930
Decrease (increase) in fuel oil stock 9,644

(2,362)
Increase in materials and supplies (1,723)
(1,595) (2,482)
(105)
Increase in regulatory assets (23,458)
(17,531) (677)
(19,976)
Decrease in accounts payable (40,375)
(53,280)
Decrease (increase) in accounts payable 23,427

(4,371)
Change in prepaid and accrued income taxes and revenue taxes (61,635)
(18,075) (28,192)
(63,613)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability 331

(748)
Increase in defined benefit pension and other postretirement benefit plans liability 237

221
Change in other assets and liabilities (20,804)
(41,969) (12,220)
(15,862)
Net cash provided by operating activities 201,586

170,167
 194,124

127,676
Cash flows from investing activities  
  
  
  
Capital expenditures (265,521) (253,718) (197,332) (199,143)
Contributions in aid of construction 34,627
 21,740
 16,810
 19,089
Other 778
 713
 331
 511
Net cash used in investing activities (230,116) (231,265) (180,191) (179,543)
Cash flows from financing activities  
  
  
  
Common stock dividends (67,804) (66,369) (46,800) (45,203)
Preferred stock dividends of Hawaiian Electric and subsidiaries (1,496) (1,496) (998) (998)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 94,995
 84,987
 36,995
 88,993
Other (223) (462) —
 (217)
Net cash provided by financing activities 25,472
 16,660
Net decrease in cash and cash equivalents (3,058) (44,438)
Net cash provided by (used in) financing activities (10,803) 42,575
Net increase (decrease) in cash and cash equivalents 3,130
 (9,292)
Cash and cash equivalents, beginning of period 13,762
 62,825
 24,449
 13,762
Cash and cash equivalents, end of period $10,704
 $18,387
 $27,579
 $4,470
The accompanying notes are an integral part of these consolidated financial statements.


9



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1 · Basis of presentation
The accompanying unaudited 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 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 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 as amended by Amendment No. 1 on Form 10-K/A, for the year ended December 31, 20142015.
In the opinion of HEI’s and Hawaiian Electric’s management, the accompanying unaudited 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, 20152016 and December 31, 20142015, the results of their operations for the three and ninesix months ended SeptemberJune 30, 20152016 and 2014,2015 and their cash flows for the ninesix months ended SeptemberJune 30, 20152016 and 2014.2015. All such adjustments are of a normal recurring nature, unless otherwise disclosed below or elsewhere in this Form 10-Q  (see “Revision of previously issued financial statements” below) or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year.
Prior period financial statements reflect the retrospective application
2 · Termination of Accounting Standards Update (ASU) No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which was adopted as of January 1, 2015 and did not have a material impact on the Company’s financial condition or results of operations. See “Investments in qualified affordable housing projects” in Note 11.
Revision of previously issued financial statements. Management discovered that the Utilities’ capital expenditures on HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows did not correctly account for the beginning of period unpaid invoices and accruals (that were paid in cash during the period) and is revising its previously filed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 to correct for such misstatement by adjusting cash used for “Capital expenditures” (investing activity) and change in accounts payable (operating activity).
Management also discovered that the eliminating journal entry to offset the Hawaiian Electric consolidated net operating loss deferred tax asset did not properly reflect the adjustment on the components of income taxes (current and deferred federal income taxes) and is revising its previously filed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 to correct for such misstatement by adjusting “Increase in deferred income taxes” and “Change in other assets and liabilities” (operating activities).
Management determined it needed to correct the presentation for share-based compensation expense on the Company’s Consolidated Statement of Cash Flows, resulting in a corresponding change in the “Change in other assets and liabilities” amount.
These revisions to correct for such misstatementsproposed merger and other immaterial items do not impact HEI’s and Hawaiian Electric’s previously reported overall net change in cash and cash equivalents in their Consolidated Statements of Cash Flows for any period presented. Additionally, these revisions do not impact HEI’s and Hawaiian Electric’s Consolidated Balance Sheets or Consolidated Statements of Income for any period presented. The Company and Hawaiian Electric have concluded that the impact of the misstatements is not material to the previously issued Consolidated Statements of Cash Flows for the nine months ended September 30, 2014.

10


The table below illustrates the effects of the revisions on the previously filed financial statements:
   As previously
 As
  
(in thousands)  filed
 revised
  Difference
Nine months ended September 30, 2014      
Consolidated Statements of Cash Flows      
HEI consolidated      
Cash flows from operating activities      
Other amortization $5,454
 $5,081
 $(373)
Increase in deferred income taxes (1) 49,270
 50,296
 1,026
Share-based compensation expense —
 7,200
 7,200
Decrease in accounts, interest and dividends payable (75,812) (51,199) 24,613
Change in other assets and liabilities (1) (47,760) (56,326) (8,566)
Net cash provided by operating activities 173,410
 197,310
 23,900
Cash flows from investing activities      
Capital expenditures (236,003) (260,616) (24,613)
Cash flows from investing activities-Other (39) 674
 713
Net cash used in investing activities (376,992) (400,892) (23,900)
Hawaiian Electric consolidated      
Cash flows from operating activities      
Other amortization 4,662
 4,289
 (373)
Decrease in accounts payable (77,893) (53,280) 24,613
Change in other assets and liabilities (41,629) (41,969) (340)
Net cash provided by operating activities 146,267
 170,167
 23,900
Cash flows from investing activities      
Capital expenditures (229,105) (253,718) (24,613)
Cash flows from investing activities-Other —
 713
 713
Net cash used in investing activities (207,365) (231,265) (23,900)
Note 10      
HEI consolidated and Hawaiian Electric consolidated      
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing) (in millions) 40
 15
 (25)
(1) As previously filed and adjusted by ASU No. 2014-01 (see Note 11).
2 · Proposed Mergermatters
On December 3, 2014, HEI, NextEra Energy, Inc., a Florida corporation (NEE), NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE (Merger Sub II) and NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE (Merger Sub I), entered into an Agreement and Plan of Merger (the Merger Agreement). The Merger Agreement providesprovided for Merger Sub I to merge with and into HEI (the Initial Merger), with HEI surviving, and then for HEI to merge with and into Merger Sub II, with Merger Sub II surviving as a wholly owned subsidiary of NEE (the Merger). The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and to be tax-free to HEI shareholders.
Pursuant to the Merger Agreement upon the closing of the Merger, each issued and outstanding share of HEI common stock will automatically be converted into the right to receive 0.2413 shares of common stock of NEE (the Exchange Ratio). No adjustment to the Exchange Ratio is made in the Merger Agreement for any changes in the market price of either HEI or NEE common stock between December 3, 2014 and the closing of the Merger.
The Merger Agreement contemplatescontemplated that, immediately prior to the closing of the Merger, HEI willwould distribute to its shareholders all of the issued and outstanding shares of common stock of ASB Hawaii, Inc. (ASB Hawaii), the direct parent company of ASB (such distribution referred to as the Spin-Off), with ASB Hawaii becoming a new public company. In addition, the Merger Agreement contemplates that, immediately prior to the closing of the Merger, HEI will pay its shareholders a special dividend of $0.50 per share.
The closing of the Merger iswas subject to various conditions, including, among others, (i) the approval of holders of 75% of the outstanding shares of HEI common stock, (ii) effectiveness of the registration statement for the NEE common stock to be issued in the Initial Merger and the listing of such shares on the New York Stock Exchange, (iii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iv) receipt of all required regulatory approvalsapproval from among others, the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission and the Hawaii Public Utilities

11


Commission (v) the absence of any law or judgment in effect or pending in which a governmental entity has imposed or is seeking to impose a legal restraint that would prevent or make illegal the closing of the Merger, (vi) the absence of any material adverse effect with respect to either HEI or NEE, (vii) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement, (viii) receipt by each of HEI and NEE of a tax opinion of its counsel regarding the tax treatment of the transactions contemplated by the Merger Agreement, (ix) effectiveness of the ASB Hawaii registration statement necessary to consummate the Spin-Off, and (x) the determination by each of HEI and NEE that, upon completion of the Spin-Off, HEI will no longer be a savings and loan holding company or be deemed to control ASB for purposes of the Home Owners' Loan Act. The Spin-Off will be subject to various conditions, including, among others, the approval of the Federal Reserve Board (FRB).
The Merger Agreement contains customary representations, warranties and covenants of HEI and NEE.
The Merger Agreement contains certain termination rights for both HEI and NEE, including the right of either party to terminate the Merger Agreement if the Merger has not been consummated by December 3, 2015 (subject to a 6-month extension if required to obtain necessary regulatory approvals), and further provides that upon termination of the Merger Agreement under specified circumstances NEE would be required to pay HEI a termination fee of $90 million and reimburse HEI for up to $5 million of its documented out-of-pocket expenses incurred in connection with the Merger Agreement.
On March 26, 2015, NEE’s Form S-4, which registers NEE common stock expected to be issued in the Initial Merger, was declared effective. HEI Shareholders approved the proposed merger agreement with NEE on June 10, 2015.
On March 30, 2015, ASB Hawaii filed its Form 10, the registration statement for the ASB Hawaii shares expected to be distributed in the Spin-Off.
On August 7, 2015, each of HEI and NEE filed their respective notifications pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act), with the U.S. Department of Justice and Federal Trade Commission. On September 8, 2015, the mandatory, pre-merger waiting period under the HSR Act expired. Accordingly, the condition to the closing of the Merger with respect to the expiration of the applicable waiting period under the HSR Act has been satisfied.
PUC application(PUC). In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger (under which Hawaiian Electric would become a wholly-owned indirect subsidiary of NEE). The application also requests modification of certain conditions agreed to by HEI andOn July 15, 2016, the PUC in 1982 fordismissed the merger and corporate restructuring of Hawaiian Electric, and confirmation that with approvalapplication without prejudice.
On July 16, 2016, pursuant to the terms of the Merger Agreement, NEE provided written notice to HEI indicating that NEE was terminating the recommendationsMerger Agreement effective immediately. 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 third quarter of 2016, HEI will recognize for financial reporting purposes the termination fee and reimbursement of expenses (net of taxes), additional tax benefits of approximately $7.8 million on the previously non-tax-deductible merger- and spin-off-related expenses incurred through June 30, 2016, and merger- and spin-off-related expenses incurred in the 1995 Dennis Thomas Report (resulting from a proceeding to review the relationship between HEI and Hawaiian Electric and any impactthird quarter of HEI’s then diversified activities2016 (net of tax benefits). The Spin-Off of ASB Hawaii was cancelled as it was cross-conditioned on the Utilities) will no longer be applicable.merger consummation.
On May 18, 2016, the Utilities filed an application for an LNG supply and transport agreement and LNG-related capital equipment to utilize natural gas at certain designated facilities, and two applications to commit funds for and waive from the PUC’s Framework for Competitive Bidding the Kahe Combined Cycle Generating Unit project. The application includes a commitment that, for at least four years following the completionthree filings were conditioned on PUC approval of the transaction, Hawaiian Electric will not submit anyUtilities’ and NextEra Energy’s joint application for approval of a merger between the two parties. On July 19, 2016, the Utilities filed withdrawals of these three applications, seeking a general base rate increase and will reduce the RAM, which amounts to approximately $60 million in cumulative savings for customers, over the four-year base rate moratorium, subject to certain exceptions and conditions, includingnoting that the following remain in effect:  the revenue balancing account (RBA) and RAM tariff provisions, the Renewable Energy Infrastructure Program, and Renewable Energy Infrastructure Surcharge, the integrated resource planning/DSM Recovery tariff provisions, the ECAC tariff provisions, the PPA tariff provision and the Pension and OPEB tracker mechanism. Various parties, including governmental, environmental and commercial interests, have been allowed to intervene in the proceeding.
Twenty-eight interveners filed testimonies in the docket in July 2015. Eleven interveners recommendedbecause the merger application approval condition was not be approved, eleven recommended approval only with conditions, and six didsatisfied, the underlying projects would not specifically make a recommendation either way. The Consumer Advocate filed its testimonies on August 10, 2015, stating thatgo forward.  On July 21, 2016, the Applicants have not justified that the proposed transaction is in the public interest but that if the Consumer Advocate’s recommended conditions were adopted, the results would reflect substantial net benefits that would support a finding that the proposed transaction is in the public interest. Among its recommended conditions was a rate plan to permanently reduce the Utilities’ rates by approximately $62 million annually. On August 31, 2015, the applicants filed their responsive testimonies, offering a number of additional commitments, including:
subject to PUC approval, completing full smart meter deployment toissued orders closing all customers by December 31, 2019
reflecting 100% of all net non-fuel O&M savings achieved by the Utilities and limiting non-fuel O&M expenses to levels no higher than the non-fuel O&M in 2014, adjusted for inflation, in the revenue requirements in the first rate case following the four-year rate case moratorium
establishing a funding mechanism of $2.5 million per year during the four-year rate case moratorium to be used for purposes in the public interest at the PUC’s discretion and direction
commiting to corporate giving of at least $2.2 million for a minimum of 10 years post-closing

12


committing to not selling the Utilities or their holding company for at least 10 years post-closing
On October 7, 2015, the other parties filed rebuttal testimonies. On October 16, 2015, the Applicants filed surrebuttal testimonies. Evidentiary hearings are scheduled from November 30 to December 16, 2015.
Other requests.  On January 29, 2015, HEI submitted its application to the FERC requesting all necessary authorization to consummate the transactions contemplated by the Merger Agreement. The FERC issued its order authorizing the proposed merger on March 27, 2015.
On February 1, 2015, HEI submitted a letter to the FRB advising the FRB of its intent to seek deregistration as a Savings & Loan Holding Company (SLHC).
Pending litigation and other matters.three dockets.
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, eight purported class action complaints were filed in the Circuit Court of the First Circuit for the State of Hawaii by alleged stockholders of HEI against HEI, Hawaiian Electric (in one complaint), the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuits are captioned as follows: Miller v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2531-12 KTN (December 15, 2014) (the Miller Action); Walsh v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2541-12 JHC (December 15, 2014) (the Walsh Action); Stein v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2555-12 KTN (December 17, 2014) (the Stein Action); Brown v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2643-12 RAN (December 30, 2014) (the Brown Action); Cohn v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2642-12 KTN (December 30, 2014) (the Cohn State Action); Guenther v. Watanabe, et al., Case No. 15-1-003-01 ECN (January 2, 2015) (the Guenther Action); Hudson v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0013-01 JHC (January 5, 2015) (the Hudson Action); Grieco v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0094-01 KKS (January 21, 2015) (the Grieco Action). On January 12, 2015, plaintiffs in the Miller Action, the Walsh Action, the Stein Action, the Brown Action, the Guenther Action, and the Hudson Action filed a motion to consolidate their actions and to appoint co-lead counsel. The Court held a hearing on this motion on February 13, 2015 and granted consolidation and appointment of co-lead counsel on March 6, 2015. On March 10, 2015, plaintiffs in the consolidated state action filed an amended complaint, and added J.P. Morgan Securities, LLC (JP Morgan), which was HEI’s financial advisor for the Merger, as a defendant. On March 17, 2015, plaintiffs in the consolidated state action moved for limited expedited discovery. After limited discovery, the parties in the consolidated state action stipulated and the Court ordered that the deadline for defendants to respond to the amended complaint is extended indefinitely.  On April 30, 2015, the Court consolidated the seven state actions under the caption, In re ConsolidatedHEI Shareholder Cases. On January 23, 2015, the Cohn State Action was voluntarily dismissed. Thereafter, the same alleged stockholder plaintiffOn January 27, 2015, Cohn filed a purported class action complaintcaptioned Cohn v. Hawaiian Electric Industries, Inc., et al., Civil No. 15-00029-JMS-RLP in the United States District Court for the District of Hawaii against HEI, the individual directors of HEI, NEE and NEE'sNEE’s acquisition subsidiaries. The lawsuit is captioned as Cohn v. Hawaiian Electric Industries, Inc. et al., 15-cv-00029-JMS-KSC (January 27, 2015)subsidiaries (the Cohn Federal Action). On May 28,February 13, 2015, the state court orally granted the plaintiffs’ motions to consolidate the seven state court actions and appoint co-lead counsel and entered a written order granting the motions on March 6, 2015. On March 10, 2015, plaintiffs filed a first consolidated complaint in state court that added as a defendant J.P. Morgan Securities, LLC (JP Morgan), the financial advisor to HEI for the Merger, and deleted Hawaiian Electric Company, Inc. as a defendant and concurrently served a first request for production of documents on HEI and the individual directors. On March 17, 2015, plaintiffs filed a motion for limited expedited discovery in the consolidated state action and thereafter on March 25, 2015 withdrew their request for limited discovery and first request for production of documents as a result of the parties’ agreement to conduct certain specified limited discovery which included a stipulated confidentiality agreement and protective order protecting the confidentiality of certain information exchanged between the parties agreedin connection with discovery in the consolidated action that was filed on April 6, 2015. On April 15 and 17, 2015, a deposition of a representative of HEI and a representative of JP Morgan were taken, respectively. On April 21, 2015, plaintiffs confirmed the cancellation of the preliminary injunction hearing that had been scheduled for May 5, 2015 in the consolidated action and on April 23, 2015, the state court entered a stipulation and order to extend indefinitely the time to answer or otherwise respond to the first amended consolidated complaint. On April 30, 2015, the state court entered a consolidated case management order confirming the consolidated treatment of the state actions for purposes of case management, pretrial discovery, procedural and other matters. On May 27, 2015, the federal court entered a stipulation and order approving the stipulation of the parties to stay the CohenCohn Federal Action pending the outcomeresolution of the state court consolidated action and administratively closing the Cohn Federal Action without prejudice to any party. On May 29, 2015, the state court entered a stipulated order amending the consolidated caption to read IN RE Consolidated HEI Shareholder Cases, Master File No. Civil No. 1CC15-1-HEI, to add JP Morgan as a named defendant in each individual action, add the caption for the Grieco Action, and remove Hawaiian Electric Company, Inc. from the caption in the Brown Action. In October 2015, several depositions of HEI representatives were taken in the state consolidated action. On February 9, 2016, plaintiffs filed an ex parte motion for second extension of time to file the pretrial statement in the state consolidated action from February 15, 2016 to August 15, 2016.
Following the termination of the Merger Agreement, a stipulation and order for dismissal with prejudice of all claims and parties was entered by the court in the Cohn Federal Action on July 22, 2016. The consolidated state action.court actions remain pending.
The pending consolidated state court actions allege, among other things, that members of HEI's Board of Directors (Board) breached their fiduciary duties in connection with the proposed transaction, and that the Merger Agreement involvesinvolved an unfair price, was the product of an inadequate sales process, and containscontained unreasonable deal protection devices that purportedly precludeprecluded competing offers. The complaints further allege that HEI, NEE and/or its acquisition subsidiaries aided and abetted the purported breaches of fiduciary duty. The plaintiffs in the pending consolidated state actions also allege that JP Morgan had a conflict of interest in advising HEI because JP Morgan and its affiliates had business ties to and investments in NEE. The consolidated state action also alleges that the HEI Board violated its fiduciary duties by omitting material facts from the Registration Statement on Form S-4.
The plaintiffs in these lawsuits seek, among other things, (i) a declaration that the Merger Agreement was entered into in breach of HEI's directors' fiduciary duties, (ii) an injunction enjoining the HEI Board from consummating the Merger, (iii) an order directing the HEI Board to exercise their duties to obtain a transaction which is in the best interests of HEI's stockholders, (iv) a rescission of the Merger to the extent that it is consummated, and/or (v) damages suffered as a result of the defendants' alleged actions. Plaintiffs in the consolidated state action also allege that JP Morgan had a conflict of interest in advising HEI because JP Morgan and its affiliates had business ties to and investments in NEE. The consolidated state action also alleges that the HEI board of directors violated its fiduciary duties by omitting material facts from the Registration Statement on Form S-4. In addition, the Cohn Federal Action alleges that the HEI board of directors violated its fiduciary duties and federal securities laws by omitting material facts from the Registration Statement on Form S-4.


HEI and Hawaiian Electric believe the allegations ofin the complaints are without merit and intend to defend these lawsuits vigorously.are moot as a result of the termination of the Merger Agreement.

13


3 · Segment financial information
(in thousands)  Electric utility Bank Other Total Electric utility Bank Other Total
Three months ended September 30, 2015  
  
  
  
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
Assets (at September 30, 2015) 5,683,992
 5,855,497
 33,977
 11,573,466
Three months ended September 30, 2014  
  
  
  
Total assets (at June 30, 2016) 5,721,853
 6,188,090
 69,296
 11,979,239
Three months ended June 30, 2015  
  
  
  
Revenues from external customers $803,559
 $63,536
 $1
 $867,096
 $558,156
 $65,783
 $(27) $623,912
Intersegment revenues (eliminations) 6
 —
 (6) —
 7
 —
 (7) —
Revenues 803,565
 63,536
 (5) 867,096
 558,163
 65,783
 (34) 623,912
Income (loss) before income taxes 62,419
 20,506
 (7,382) 75,543
 52,451
 19,726
 (15,775) 56,402
Income taxes (benefit) 23,042
 7,253
 (3,031) 27,264
 19,111
 6,875
 (5,075) 20,911
Net income (loss) 39,377
 13,253
 (4,351) 48,279
 33,340
 12,851
 (10,700) 35,491
Preferred stock dividends of subsidiaries 498
 —
 (27) 471
 499
 —
 (26) 473
Net income (loss) for common stock 38,879
 13,253
 (4,324) 47,808
 32,841
 12,851
 (10,674) 35,018
Nine months ended September 30, 2014  
  
  
  
Six months ended June 30, 2015  
  
  
  
Revenues from external customers $2,262,038
 $187,771
 $(307) $2,449,502
 $1,131,587
 $130,131
 $56
 $1,261,774
Intersegment revenues (eliminations) 18
 —
 (18) —
 18
 —
 (18) —
Revenues 2,262,056
 187,771
 (325) 2,449,502
 1,131,605
 130,131
 38
 1,261,774
Income (loss) before income taxes 174,711
 60,994
 (23,110) 212,595
 95,674
 40,357
 (27,311) 108,720
Income taxes (benefit) 64,686
 21,806
 (10,190) 76,302
 34,961
 14,031
 (8,102) 40,890
Net income (loss) 110,025
 39,188
 (12,920) 136,293
 60,713
 26,326
 (19,209) 67,830
Preferred stock dividends of subsidiaries 1,496
 —
 (79) 1,417
 998
 —
 (52) 946
Net income (loss) for common stock 108,529
 39,188
 (12,841) 134,876
 59,715
 26,326
 (19,157) 66,884
Assets (at December 31, 2014) 5,590,457
 5,566,222
 28,463
 11,185,142
Total assets (at December 31, 2015)* 5,672,210
 6,014,755
 95,053
 11,782,018
 
* 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 and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.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 and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.nominal.

14



4 · 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 2016 and 2015 and 2014 and the ninesix months ended SeptemberJune 30, 2016 and 2015 and 2014 approximately $58$44 million, $74$50 million, $15987 million and $203101 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, the “Protecting Americans from Tax Hikes (PATH) Act of 2015” and the “Consolidating Appropriations Act, 2016,” providing government funding and a number of significant tax changes.
The Utilities adoptedprovision with the safe harbor guidelinesgreatest 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 is expected to result in an increase in 2015 and 2016 tax depreciation of approximately $117 million and $126 million, respectively.
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 respect to network (transmission and distribution) assets in 2011 and, in June 2013, the IRS released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. Management has adopted a method consistent with this guidance in its 2014 tax return filed in September 2015.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, 20152016 and December 31, 20142015 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, 20152016 and 20142015 each 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, 20152016, the Utilities had sixfive PPAs for firm capacity and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kilowatts or less 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:

15



 Three months ended September 30 Nine months ended September 30 Three months ended June 30 Six months ended June 30
(in millions) 2015 2014 2015 2014 2016 2015 2016 2015
AES Hawaii $37
 $38
 $97
 $107
 $36
 $26
 $74
 $60
Kalaeloa 51
 73
 143
 214
 36
 48
 65
 92
HEP 13
 16
 34
 36
 4
 10
 15
 21
Hpower 18
 18
 50
 50
 17
 16
 33
 32
Puna Geothermal Venture 8
 10
 22
 36
 5
 7
 12
 14
Hawaiian Commercial & Sugar (HC&S) 2
 2
 7
 50
 —
 3
 —
 5
Other IPPs 32
 36
 93
 53
 41
 39
 56
 61
Total IPPs $161
 $193
 $446
 $546
 $139
 $149
 $255
 $285
 
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 IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2014,2015, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities. If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs.
Kalaeloa Partners, L.P.  In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 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, the term of which coincides with the PPA.customer. 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 upcoming end of the PPA term inthat ended on May 23, 2016. The PPA will automatically extendextends 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. A significant factor affecting the level of expected lossesThe energy payments paid by Hawaiian Electric could potentially absorb is the fact that Hawaiian Electric’s exposure towill fluctuate as fuel price variability is limited to the remaining term of the PPA as compared to the

16


facility’s remaining useful life. Although Hawaiian Electric absorbs fuel price variability for the remaining term of the PPA,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 SeptemberJune 30, 2015,2016, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $1310 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 not include any O&M component or be 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 June 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 October 2017. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest.
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 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC approved the recovery of costs incurred under this contract on April 30, 2013.
On August 27, 2014, Chevron Products Company (Chevron) and Hawaiian Electric entered into a first amendment of their Low Sulfur Fuel Oil Supply Contract, which was approved by the PUC in March 2015.LSFO Contract. The Amendmentamendment reduces the price of fuel above certain volumes, allows for increases in the volume of fuel, and modifies the specification of certain petroleum products supplied under the contract. In addition, Chevron agreed to supply a blend of low sulfur fuel oil (LSFO)LSFO and diesel as soon as January 2016 (for supply through the end of the contract term, December 31, 2016) to help Hawaiian Electric meet more stringent Environmental Protection Agency (EPA)EPA air emission requirements known as Mercury and Air Toxics Standards. In March 2015, the amendment was approved by the PUC.
The Utilities are also parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Hawaii Independent Energy, LLC, (HIE), respectively, which were scheduled to end December 31, 2015. 2015, but have been extended through December 31, 2016. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.
In August 2014, Chevron and the Utilities entered into a third amendment to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract (Inter-island Fuel Supply Contract), which amendment extended the term of the contract through December 31, 2016 and provided for automatic renewal for annual terms thereafter unless earlier terminated by either party. In February 2015, Hawaiian Electric executed a similar extension, through December 31, 2016, of the corresponding Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract with HIE.
In June 2015, the Utilities issued Requests for Proposals (RFP) for most of their fuel needs with supplies beginning in 2017 after the expiration of Chevron LSFO and Chevron/HIE Interisland contracts on December 31, 2016. Proposals were received in July 20152015.


On February 18, 2016, Hawaiian Electric and newChevron entered into a fuel supply contract for LSFO, diesel and fuel to meet MATS requirements (2016 LSFO Contract) for the island of Oahu which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Also on February 18, 2016, the Utilities and Chevron entered into a supply contract for industrial fuel oil, diesel and ultra-low sulfur diesel (Petroleum Fuels Contract) for the islands of Oahu, Maui, Molokai and the island of Hawaii , which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Finally, on February 18, 2016, Hawaii Electric Light and Chevron entered into a fuels terminalling agreement which terminates on December 31, 2019 for the island of Hawaii and may automatically renew for annual terms thereafter unless earlier terminated by either party. Currently, terminalling services are provided for under the Inter-island Fuel Supply Contract with Chevron that expires on December 31, 2016. Each of these contracts which would be subject toare for a term of three years and become effective upon PUC approval, which approval has been requested by an application filed in February 2016, and each contract can be terminated if PUC approval is not received by October 1, 2016. Additionally, Chevron is required to comply with the agreed upon fuel specifications as set forth in the 2016 LSFO Contract and the Petroleum Fuels Contract.
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 HIE for LSFO under a Facility Fuel Supply Contract (fuel contract) between them (assigned to HIE upon its purchase of the assets of Tesoro Hawaii Corp. as described above). The term of the fuel contract between Kalaeloa and HIE ended on May 31, 2016 and is being extended until terminated by one of the parties.
The costs incurred under the Utilities’ fuel contracts are expectedincluded in their respective ECACs, to be executed by December 31, 2015.the extent such costs are not recovered through the Utilities’ base rates.
AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended, 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. However,2013, but Hawaiian Electric and AES Hawaii hadwere not been able to reach agreement on an amendment. In June 2015, AES Hawaii filed an arbitration demand regarding a dispute about whether Hawaiian Electric was obligated to buy up to 9 MW of additional capacity based on a 1992 letter. Hawaiian Electric believes the claim asserted in the arbitration demand is without merit and has responded to the arbitration demand. Indemand and, in October 2015, AES Hawaii and Hawaiian Electric entered into a Settlement Agreement to stay the arbitration proceeding through February 15, 2016.proceeding. The Settlement Agreement includes certain conditions precedent which, if satisfied, will release the parties offrom the claims under the arbitration proceeding. Among the conditions precedent is the successful negotiation of an amendment to the existing purchase power agreement and PUC approval of such amendment.
On November 13, 2015, Hawaiian Electric entered into Amendment No. 3 to the AES Hawaii PPA, subject to PUC approval. Amendment No. 3 hasprovides more favorable pricing for the additional 9 MW than the existing pricing, the benefit of which iswill 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.
There are other conditions precedent, which are still required On January 22, 2016, Amendment No. 3 was filed with the PUC for approval. If such approval is obtained, the final condition to be satisfied under the Settlement Agreement.Agreement’s release of the parties from the arbitration claims will be satisfied. The arbitration proceeding has been stayed to allow the PUC approval proceeding to proceed.
Liquefied natural gas. On May 31, 2015 the previous August 2014 agreement with18, 2016, Hawaiian Electric and Fortis BCHawaii Energy Inc. (Fortis Hawaii), an affiliate of Fortis, Inc. (Fortis) for liquefaction capacity for, entered into a Fuel Supply Agreement (FSA) whereby Fortis Hawaii intended to sell to Hawaiian Electric liquefied natural gas (LNG) was supersededto be produced from the LNG facilities on Tilbury Island in Delta, British Columbia, Canada. Pursuant to the FSA, Fortis Hawaii had arranged, or planned to arrange, for the transportation of gas for delivery to, and liquefaction at, the Tilbury LNG facilities, including with respect to the transport and delivery of LNG across a liquefaction Headsjetty at such facilities, for the purchase and storage of Agreement byLNG at such LNG facilities and between FortisBC Holdings Inc. andfor the transportation of LNG to delivery points in Hawaii for the benefit of Hawaiian Electric Company, Inc.and its subsidiaries. The agreement, which isFSA was subject to approval by the PUC and to the satisfaction of certain conditions precedent, including the consummation of the merger between HEI and NEE. On July 16, 2016, pursuant to the terms of the Merger Agreement, NEE terminated the Merger Agreement. Accordingly, on July 19, 2016, Hawaiian Electric provided notice of termination of the FSA to Fortis Hawaii, effective immediately, and withdrew the application for PUC approval other regulatory approvalsof the FSA, which included a request for approval to commit approximately $341 million to convert existing generating units to use natural gas, and permits, and other conditions precedent before it becomes effective, providesto commit approximately $117 million for LNG liquefaction capacity purchases of 700,000 tonnes per year for the first five years, 600,000 tonnes per year for the next five years, and 500,000 tonnes per year for the last ten years. Fortis must also obtain regulatory and other approvals for the agreementcontainers to

17


become effective. The Fortis agreement is assignable and can be assigned support LNG. In addition, on July 19, 2016, Hawaiian Electric withdrew its applications to the selected bidder inPUC for a waiver from the Utilities’ RFP forcompetitive bidding process to allow Hawaiian Electric to construct a modern, efficient, combined cycle generation system at the supply of containerizedKahe power plant that would utilize LNG and to commit $859 million for such project. Hawaiian Electric will help ensure that liquefaction capacity is available at pricing that management believes will lower customer bills.continue to evaluate


all options to modernize generation using a cleaner fuel to bring price stability and support adding renewable energy for its customers.
Utility projects.  Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, 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 next Hawaii Electric Light 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 its Enterprise Information System Roadmap to the PUC in June 2014 and refiled an application for an ERP/EAM implementation project in July 2014 with an estimated cost of $82.4 million. The refiled application addressed the concerns raised by the PUC, inabout the initial application, regarding the benefits to customers of completing this project. The estimated cost of the project included the cost of ERP software that had been purchased and recorded as a deferred cost.
To address the Consumer Advocate’s positonposition that the proceeding should be stayed to determine if the project as proposed in the application is reasonable and necessary for future operations as an indirect NEE subsidiary, in May 2015, the Utilities filed a report describing the impact the pending merger with NEE would have on the scope, costs and benefits of the ERP/EAM project. The report indicated that the two viable courses of action for replacing its current system are Option A (to proceed with the project as initially scoped in the Application,Application), and Option B (to move the Utilities to NEE’s existing ERP/EAM solutions). Option B is estimated to cost approximately $20.8 million less than Option A, but can only be pursued if the merger is approved. The Utilities requested the PUC to approve the commencement of work on Option B if the merger is approved; and in the alternative, Option A if the merger is not approved.
In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the existing ERP/EAM system, (2) denying the Utilities request to defer the costs for the ERP software purchased in 2012 and (2)(3) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under Options B or A.
In the D&O, the PUC denied the Utilities request to defer the cost for the ERP software purchased in 2012. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015.
The D&O requires2015, and pursuant to the remaining procedural schedule in the docket, in April 2016: (1) the Utilities to file their bottom-up low-level benefits analysis for both Options A and B, and specifiedfiled additional information required as parton the cost and benefits of the their Cost/Benefit Analysis, which will be due by April 8, 2016.
Management cannot predictproject, (2) the further outcomeConsumer Advocate filed comments on that additional information and (3) the Utilities filed a reply to the Consumer Advocate’s comments. There are no steps remaining in the procedural schedule, and with the termination of this proceeding.the Merger Agreement, Option B is no longer available. The Utilities are awaiting the issuance of a final D&O.
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


$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 iswas required to take all necessary steps to lock in the lowest possible exchange rate. On January 5, 2016, Hawaiian Electric executed a window forward agreement which lowered the cost of the engine contract by $9.7 million, resulting in a revised project cost cap of $157.3 million. The generating station is now expected to be placed in service in the first quarter of 2018.
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.

18


Mercury Air Toxics Standards. On February 16, 2012, the Federal RegisterEPA published the EPA’s final rule establishing the EPA’s 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 establishesestablished the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, Hawaiian Electric hasreceived 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. The usefuels, 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 lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date ofchanges.
On April 16, 2016.2012, Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay dated April 16, 2012, which(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.Petition and Hawaiian Electric appealed the EPA’s denial of the Petition. Onsubsequently filed a lawsuit on June 29, 2015 the U.S. Supreme Court found that theappealing EPA’s determination that it was appropriate and “necessary” to regulate hazardous air pollutants from power plants was flawed because the EPA did not take the costs of compliance into account. The Supreme Court sent the MATS rule case back todenial. On April 4, 2016, the D.C. Circuit Court of Appeals for further proceedings. The likely timeframe for actiongranted 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 is on schedule to submit the formal compliance demonstration report by the Circuit Court is December 2015. Pending action by the Circuit Court, Hawaiian Electric will continue with its plan to comply with the MATS requirements by April 16, 2016.October 13, 2016 deadline.
On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the1-Hour Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provideStandard. On August 1, 2015, the states additional flexibility and timeEPA published the Data Requirements Rule for their development of one-hour sulfur dioxidethe 2010 1-Hour Sulfur Dioxide (SO22)) Primary National Ambient Air Quality Standard (NAAQS) implementation plans. In August 2015,. Hawaiian Electric is working with the DOH to gather data EPA publishedrequires through the final data requirements rule for states to characterize their air quality in relation to the one-hourinstallation and operation of two new 1-hour SO2 NAAQS. Under this rule,air quality monitoring stations on the EPA expectsisland 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 designate areas as attaining, or not attaining,maintain the one-hourNAAQS and comply with the new 1-Hour SO2 NAAQSRule in December 2017 or December 2020, depending on whether the area was characterized through modeling or monitoring.its State Implementation Plan.
Recent Settlements. Hawaiian Electric will work withresolved outstanding claims raised by the DOH in implementing the one-hour SO2 NAAQSU.S. Fish and in developing cost-effective strategies for NAAQS compliance, if needed.
Depending upon the rules and guidance developed for compliance with the more stringent NAAQS, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts and their timing are not determinable at this time. Additionally, the combined effects of the CWA 316(b) regulations, the MATS ruleWildlife Service (USFWS) and the more stringent NAAQS may contribute to a decision to retire or deactivate certain generating units earlier than anticipated.
Hawaii Department of Land and Natural Resources, Division of Forestry and Wildlife (DOFAW) in March 2016. The USFWS and DOFAW had alleged that Hawaiian Electric Hawaiiviolated the Endangered Species Act of 1973 in April of 2011, by clearing vegetation and impacting the habitat for Achatinella mustelina, an endangered Hawaiian tree snail, while servicing its facilities on Mt. Kaala on Oahu. In the respective final settlements resolving the governments’ claims, Hawaiian Electric Lightdid not admit any liability, but paid a penalty of $250 to the U.S. Fish and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases intoWildlife Service, and provided $200,000 to the environment associated with current or previous operations. The Utilities reportDivision of Forestry and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of respondingWildlife to such releases identified to date will not have a material adverse effect, individually orrebuild an aging predator-proof snail enclosure in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.Pahole Natural Area Reserve.


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) assertingalleging potential violations of the Prevention of Significant Deterioration and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The parties are continuing to negotiate toward a resolution of the DOJ’s claims. As part of the ongoing negotiations,In correspondence dated November 4, 2014, the DOJ also identified potential violations by Hawaiian Electric at its Kahe facility and proposed in November 2014resolving 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 are currently reviewingcontinue to negotiate with the proposal,DOJ to resolve these issues, but are unable to estimate the amount or effect of a consent decree, if any, at this time.
Former Molokai Electric Company generation site.  In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface.subsurface soil at the Site. Although Maui Electric never operated at the Site and operations there had stopped four years beforeor owned the merger, inSite property, after discussions with the EPA and the DOH Maui Electric agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants.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$3.6 million as of SeptemberJune 30, 20152016 for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. The final site investigation plan was submitted to the DOH and EPA in December 2014 for their approval. The DOH formally approved the investigation plan on September 14, 2015. The EPA determined that their formal approval is not required until the next phase of work that determines cleanup actions for the site. Sampling of the site per the investigation plan will proceed after securing required permits and access agreements.

19


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.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, and is asking Hawaiian Electric to engage in negotiations regarding the financing and undertaking of future response actions to address the sediment contamination offshore from the Waiau Power Plant. The extent of the contamination, the appropriate remedial measures to address it, and Hawaiian Electric’s potential responsibility for any associated costs, including any past costs incurred by the Navy, have not yet been determined.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. The Navy’s study identified elevated levels of PCBs in the sediment in East Loch of Pearl Harbor offshore from the Waiau Power Plant. The Navyand 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 Navy has indicated that additional data collection is necessary and will be conducted as partextent of the contamination, the appropriate remedial design,measures to address it and that the results will be used to finalize the remediation plan and to better define the areas where remediation is necessary to reduce the potential environmental risks. Hawaiian Electric has requested to participate with the Navy in the preparation of the remedial design for the contaminated sediment offshore from the Waiau Power Plant, and in particular in the development of the work plan for additional data collection, and refinement of the environmental risk analysis, the final remedy, and the response costs for the offshore area. To date, Hawaiian Electric’s role in the development of the remedial design and responsepotential responsibility for any associated costs is uncertain.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. Sampling of outfall sediments at the Waiau Power Plant was completed in accordance with the SAP in December 2015, and additional onshore soil sampling was completed in June 2016. The extent of the onshore contamination, the appropriate remedial measures to address it and any associated costs have not yet been determined.
In December 2014,As of June 30, 2016, the reserve account balance recorded by Hawaiian Electric recorded a reserve of $0.8 million for investigation of certain onshore areas at the Waiau Power Plant that may have, in the past, contributed to address the PCB contamination inwas $4.5 million. The reserve represents the probable and reasonably estimable cost to complete the onshore and offshore sedimentinvestigations and for ongoing review and assessmentthe remediation of the Navy’s remediation plan forPCB 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.
Hawaiian Electric has also conducted a search for other potential sources of sediment contamination in the Waiau area that are unrelated to electric power generation at its Waiau Power Plant. Hawaiian Electric has identified a potential source east of the plant: a former Naval Reserve (a Formerly Used Defense Site (FUDS)) where a used drum storage area, a waste oil burning pit, and an oil/water separator were operated by the Navy from the 1940s until approximately 1962. This FUDS is located on the property currently occupied by the City and County (C&C) of Honolulu’s Neal S. Blaisdell Park. To further assess this former Naval Reserve site, Hawaiian Electric has requested environmental investigation reports, environmental data, and permits for this property and the adjacent Waimalu Stream (e.g., dredging permits and related environmental impact assessments and studies) from several federal and state agencies, as well as the C&C of Honolulu. The contribution of PCBs to sediment contamination in East Loch from this potential source has not yet been determined.
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 action by the State and 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, became law in Hawaii.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, pursuant to Act 234 and the corresponding regulations,GHG rule require affected sources that(that have the potential to emit GHGs in excess of established thresholds are requiredthresholds) 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. Hawaiian Electric, Maui Electric, and Hawaii Electric Light2015, demonstrating how they will comply. The Utilities have a total of 11 facilities affected by the state GHG rule. Hawaiian Electric made use of the partnering provisions in the DOH GHG rule to prepare a single Emissions Reduction Plan that covers all 11 of the Utilities’ affected facilities, and has 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 Emissions Reduction Plan. 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 State GHG is aligned with the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and creates new thresholds for GHG emissions from new and existing stationary source facilities. 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.

20



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 sources emittingemit GHGs above certain threshold levels monitor andto report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 20132015 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules to address GHG emissions from stationary sources, like the Utilities’ EGUs.
As part of President Obama’s Climate Action Plan, the EPA has been directed to adopt GHG emission limits for new and existing EGUs. The EPA issued the final federal rule for GHG emission reductions fromemissions limits for new and existing EGUs, also known as the Clean Power Plan, on August 3, 2015. The final federal GHG rule for existing EGUs setsClean 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;2029, with final limits will apply fromin effect starting in 2030. The EPAfinal Clean Power Plan did not issue finalset forth guidelines for Alaska, Hawaii, Puerto Rico or Guam, because the Best System of Emission Reduction established forEPA did not have enough information to include them at the contiguous states is not appropriate for these locations. The EPA said it will work withtime the state and territorial governments for Alaska, Hawaii, Puerto Rico, and Guam and other stakeholders to gather additional information regardingRule was published. Subsequently, on February 9, 2016, the emissions reduction measures available in these jurisdictions, particularly with respect to renewable generation. Hawaiian Electric plans to participate in this process. Management’s latest assessmentU.S. Supreme Court granted a stay of the Clean Power Plan is that the continued growthpending resolution of renewable power generation and the expected implementation of LNG by the Utilitiesseveral petitions for review in the future will significantly reduce the compliance costs and riskU.S. Court of Appeals for the Utilities. To date, no timetable has been established by the EPA to develop GHG emission limits for Alaska, Hawaii, Puerto Rico, or Guam.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 but not limited to, 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 are also working with the State of Hawaii and other entitieswill continue to pursue the use of LNG as a cleaner and lower-cost fuelfuels to replace, at least in part, the petroleum oil that would otherwise be used.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 significant activity and expenditures occurring in 2014 in partial settlement of these liabilities. Both removal projects are expected to continue through 2015.2016.

21


Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
 Nine months ended September 30 Six months ended June 30
(in thousands) 2015 2014 2016 2015
Balance, beginning of period $29,419
 $43,106
 $26,848
 $29,419
Accretion expense 18
 816
 7
 12
Liabilities incurred —
 —
 —
 —
Liabilities settled (2,349) (11,338) (259) (1,881)
Revisions in estimated cash flows —
 —
 —
 —
Balance, end of period $27,088
 $32,584
 $26,596
 $27,550


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,investments. Under the decoupling tariff approved in 2011, the annual RAM is accrued and has resultedbilled 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. After 2016, the RAM provisions approved in an improvement in the Utilities’ under-earning situation that had existed prior2011 will again apply to the implementation of decoupling.Hawaiian Electric.
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 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.

22


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.
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 Hawai‘i 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.
On May 28, 2015, the PUC issued an Order (the May Order) related to the Utilities’ revised annual decoupling filing for tariffed rates submitted on April 15, 2015. The May Order ruled on the specific matters identified by the PUC in its information requests and by the Consumer Advocate in its Statement of Position. As a result of the May Order, on June 3, 2015, the Utilities filed revised tariff rates reflecting a reduction to the RAM portion of the tariff filing. The revision was made primarily to adjust the RAM to reflect reduced operations and maintenance expenses associated with the Utilities’ change in estimate related to the allocation of indirect costs implemented in 2014, and to exclude the GDPPI factor on the depreciation expense portion for the calculation of the 2015 RAM Cap. The May Order also requires a one-time adjustment to customers for the impact of bonus tax depreciation enacted in December 2014 on the RAM revenues used for the 2014 tariff filing.
The revised 2015 annual incremental RAM revenues for the Utilities amounts to $11.1 million compared to the $26.2 million filed on April 15, 2015 and the $31.6 million filed on March 31, 2015 based on the methodology prior to its modification in the March Order. The tariffed rates, which became effective on June 8, 2015, also include the collection or refund of the accrued RBA balance and associated revenue taxes as of December 31, 2014 and any accrued earnings sharing mechanism credits. The net refund to be provided by the three Utilities under the revised tariffs amounts to $0.4 million, compared to a collection of $14.7 million under the tariffs filed on April 15, 2015. Below is a summary of the 2015 incremental impact by company.
($ in millions) Hawaiian Electric Hawaii Electric Light Maui Electric
Annual incremental RAM adjusted revenues $8.1
 $1.5
 $1.5
Annual change in accrued earnings sharing credits to be refunded $—
 $—
 $(0.1)
Annual change in accrued RBA balance as of December 31, 2014 (and associated revenue taxes) to be collected $(9.2) $0.1
 $(2.2)
Net annual incremental amount to be collected under the tariffs $(1.1) $1.5
 $(0.8)
Impact on typical residential customer monthly bill (in dollars) * $(0.09) $0.88
 $(0.13)
Note: Columns may not foot due to rounding
* 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 $0.11, based on a 400 KWH bill.
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.
The MayIn accordance with the March Order, indicates the PUC will review the change in estimate related to the allocation of indirect costs in a separate docket, and that the change will remain subject to adjustment pending the outcome of the review. Management cannot predict

23


the outcome of this review or the further outcome of this proceeding or the ultimate impact of the proceeding on the results of operation of the Utilities or the net financial impact on the Utilities and HEI.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 November 2015, the Consumer Advocate filed preliminary statements of position (PSOPs) on these two applications, recommending that the PUC reject the applications. In December 2015, the Utilities filed responses to the Consumer Advocate’s PSOPs, pointing out that the PUC had already authorized the filing of such applications for recovery of capital costs above the RAM Cap and requesting that the PUC proceed with review of the applications. 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 $35.7 million for the same reason as Maui Electric regarding the extension of bonus depreciation in 2015.
Annual decoupling filings.  On March 31, 2016, the Utilities submitted to the PUC their annual decoupling filings for tariffed rates that will be effective from June 1, 2016 through May 31, 2017. On May 19, 2016, Hawaii Electric Light amended its annual decoupling filing to update and revise certain cost information. The tariffed rates include: (1) 2016 RAM Revenue Adjustment as determined by the March Order, (2) accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2015 (and associated revenue taxes) to be collected:
($ 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)
Note: Columns may not foot due to rounding
* 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 June 30, 2016, total receivables, including interest, from Hawaiian Telcom are $19.2 million ($13.3 million at Hawaiian Electric, $5.6 million at Hawaii Electric Light, and $0.3 million at Maui Electric). Management has reserved for the accrued interest on the receivables amounting to $3.5 million. Management expects to prevail on their claims and collect at least $15.7 million.
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 four orders are 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 its respective Power Supply Improvement Plans (PSIPs), and the PSIPs were filed in August 2014. The PUC also provided its inclinations on the future of Hawaii’s electric utilities in an exhibit to the order. The exhibit provides the PUC’s perspectives on the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customers’ interests and the state’s public policy goals.
Reliability Standards Working Group. The PUC ordered the Utilities (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:
Distributed Generation Interconnection Plan - the Utilities’ Plan was filed in August 2014.
Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters - the Utilities’ Plan was filed in June 2014.
Action Plan for improving efficiencies in the interconnection requirements studies - the Utilities’ Plan was filed in May 2014.
The Utilities are to file monthly reports providing details about interconnection requirements studies.
Integrated interconnection queue for each distribution circuit for each island grid - the Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.
The PUC also stated it would be opening new dockets to address (1) reliability standards, (2) the technical, economic and policy issues associated with distributed energy resources (see “Distributed Energy Resources (DER) Investigative Proceeding” below) and (3) the Hawaii electricity reliability administrator, which is a third party position which the legislature has authorized the PUC to create by contract to provide support for the PUC in developing and periodically updating local grid reliability standards and procedures and interconnection requirements and overseeing grid access and operation.
Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop an integrated Demand Response (DR) Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. In August 2014,Subsequently, the PUC invited public comment on the Utilities’ Plan. The Utilities submitted status updates in October 2014 and March 2015.an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special advisor to guide, monitor and review the Utility’s Plan design and implementation.


On December 30, 2015, the Utilities filed applications with the PUC (1) for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs 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 Response Management System (DRMS) through the Renewable Energy Infrastructure Program (REIP) Surcharge. In July 2016, the PUC issued an order in the DR Portfolio Tariff proceeding. The 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.
Maui Electric Company 2012 Test Year Rate Case. The PUC acknowledged the extensive analyses provided by Maui Electric in its System Improvement and Curtailment Reduction Plan (SICRP) filed in September 2013. The PUC stated that it is encouraged by the changes in Maui Electric’s operations that have led to a significant reduction in the curtailment of renewables, but stated that Maui Electric has not set forth a clearly defined path that addresses integration and curtailment of additional renewables. The PUC directed Maui Electric to present a PSIP to address present and future system operations so as to not only reduce curtailment, but to optimize the operation of its system for its customers’ benefit. The Maui Electric PSIP was filed in August 2014, and is currently being reviewed by the PUC in a new docket along with the Hawaiian Electric and Hawaii Electric Light PSIPs. Maui Electric filed its second annual SICRP status update in September 2015.
Review of PSIPs. Collectively, the PUC’s April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities’ strategies and plans going forward.
PSIPs for Hawaiian Electric, Maui Electric and Hawaii Electric Light were filed in August 2014. The PSIPs each include a tactical plan to transform how electric utility services will be offered to meet customer needs and produce higher levels of

24


renewable energy. Each plan contains a diversified mix of technologies, including significant distributed and utility‑scale renewable resources, that is expected to result, on a consolidated basis, in over 65% of the Utilities’ energy being produced from renewable resources by 2030. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil to lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generators and lower full service residential customer bills in real dollars.
In November 2015, the PUC issued an order in the proceeding to review the PSIPs filed. The order provided observations and concerns on the PSIPs submitted and requiressubmitted. As required by the order, the Utilities to review and submitsubmitted a Proposed Revision Plan byin November 25, 2015. The PUC ordered the Proposed Revision Plan to include2015, which included a schedule and a work plan to supplement, amend and update the PSIPs in order to address the PUC’s observations and concerns. The Proposed Revision Plan would need to include an Interim PSIP Update filing by February 15, 2016concerns, and submitted updated PSIPs byon April 1, 2016. The parties and participants will filefiled 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 January 15, 2016, after which2045.
The Utilities plan to submit to the PUC, in late September 2016, an update to the April 1, 2016 PSIPs to reflect 2016 fuel price forecasts from the Energy Information Administration, updated cost assumptions, inter-island cable analysis and the termination of the Merger Agreement. The Utilities will continue to evaluate all options to modernize generation using a cleaner fuel to bring price stability and support adding renewable energy for their customers. The PUC is expected to provide further guidance regarding the substance and course of the proceeding.
Distributed Energy Resources (DER) Investigative Proceeding. In March 2015, the PUC issued an order to address DER issues.
On June 29, 2015, the Utilities submitted their final Statement of Position in the DER proceeding, which included:
(1)new pricing provisions for future rooftop photovoltaic (PV) systems,
(2)technical standards for advanced inverters,
(3)new options for customers including battery-equipped rooftop PV systems,
(4)a pilot time-of-use rate,
(5)an improved method of calculating the amount of rooftop PV that can be safely installed, and
(6)a streamlined and standardized PV application process.
On October 12, 2005,2015, the PUC issued a D&O establishing DER reforms that: (1) promote rapid adoption of the next generation of solar PV and other distributed energy technologies; (2) encourage more competitive pricing of distributed energy resource systems; (3) lower overall energy supply costs for all customers; and (4) help to manage DER in terms of each island’s limited grid capacity.


The D&O approved a customer self-supply tariff and a customer grid supply tariff to govern customer generators connected to the Utilities’ systems. These tariffs replace the Net Energy Metering (NEM) program.
The D&O ordered the Utilities, among other things, (a) to collaborate with inverter manufacturers to develop a test plan by December 15, 2015 for the highest priority advanced inverter functions that are 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 will beginbegan in November 2015 and will focusfocused 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 remanded 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.
On June 15, 2016, the PUC issued an order approving the Utilities’ Advanced Inverter Test Plan with, among other conditions, a requirement to supplement the Test Plan to include testing procedures. In addition, the PUC ordered the Utilities to submit the results of the testing described in the Test Plan by December 15, 2016.
Derivative financial instrument. On January 5, 2016, Hawaiian Electric executed a window forward agreement to hedge the foreign currency risk associated with the anticipated purchase of engines from a European manufacturer to be included as part of the Schofield generating station. This window forward agreement has been designated as a cash flow hedge under which a single guaranteed exchange rate agreed upon on a certain date for future currency transactions scheduled to occur on specific dates with a “window” or range of plus/minus 30 days. Unrealized gains are recorded at fair value as assets in “other current assets,” and unrealized losses are recorded at fair value as liabilities in “other current liabilities,” both for the period they are outstanding. For this window forward agreement, the effective portion is reported as a component of accumulated other comprehensive income until reclassified into net income consistent with any gains or losses recognized on the engines. The generating station is expected to be placed in service in the first quarter of 2018.
  June 30, 2016 December 31, 2015
(dollars in thousands) Notional amount Fair value Notional amount Fair value
Window forward contract $20,637
 $466
 $—
 $—
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.

25



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income
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
Consolidating Statement of Comprehensive Income
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
 3,391
 401
 357
 —
 (758) 3,391
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) (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

26



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income
Three months ended SeptemberJune 30, 20142015

(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 $579,777
 111,154
 112,656
 —
 (22) $803,565
 $391,007
 83,732
 83,442
 —
 (18) $558,163
Expenses                        
Fuel oil 229,068
 29,555
 50,809
 —
 —
 309,432
 104,278
 16,241
 25,712
 —
 —
 146,231
Purchased power 142,121
 34,166
 16,595
 —
 —
 192,882
 107,370
 24,555
 17,359
 —
 —
 149,284
Other operation and maintenance 71,584
 19,837
 16,892
 —
 —
 108,313
 66,428
 16,158
 16,278
 —
 —
 98,864
Depreciation 27,302
 8,975
 5,317
 —
 —
 41,594
 29,389
 9,312
 5,540
 —
 —
 44,241
Taxes, other than income taxes 54,412
 10,607
 10,169
 —
 —
 75,188
 37,479
 7,944
 7,959
 —
 —
 53,382
Total expenses 524,487
 103,140
 99,782
 —
 —
 727,409
 344,944
 74,210
 72,848
 —
 —
 492,002
Operating income 55,290
 8,014
 12,874
 —
 (22) 76,156
 46,063
 9,522
 10,594
 —
 (18) 66,161
Allowance for equity funds used during construction 1,668
 142
 127
 —
 —
 1,937
 1,581
 165
 150
 —
 —
 1,896
Equity in earnings of subsidiaries 9,800
 —
 —
 —
 (9,800) —
 9,624
 —
 —
 —
 (9,624) —
Interest expense and other charges, net (11,196) (2,811) (2,429) —
 22
 (16,414) (11,290) (2,592) (2,424) —
 18
 (16,288)
Allowance for borrowed funds used during construction 634
 54
 52
 —
 —
 740
 564
 58
 60
 —
 —
 682
Income before income taxes 56,196
 5,399
 10,624
 —
 (9,800) 62,419
 46,542
 7,153
 8,380
 —
 (9,624) 52,451
Income taxes 17,047
 1,965
 4,030
 —
 —
 23,042
 13,431
 2,536
 3,144
 —
 —
 19,111
Net income 39,149
 3,434
 6,594
 —
 (9,800) 39,377
 33,111
 4,617
 5,236
 —
 (9,624) 33,340
Preferred stock dividends of subsidiaries —
 133
 95
 —
 —
 228
 —
 133
 96
 —
 —
 229
Net income attributable to Hawaiian Electric 39,149
 3,301
 6,499
 —
 (9,800) 39,149
 33,111
 4,484
 5,140
 —
 (9,624) 33,111
Preferred stock dividends of Hawaiian Electric 270
 —
 —
 —
 —
 270
 270
 —
 —
 —
 —
 270
Net income for common stock $38,879
 3,301
 6,499
 —
 (9,800) $38,879
 $32,841
 4,484
 5,140
 —
 (9,624) $32,841

Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Comprehensive Income
Three months ended June 30, 2015
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock
 $32,841
 4,484
 5,140
 —
 (9,624) $32,841
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
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 5,257
 713
 652
 —
 (1,365) 5,257
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (5,272) (716) (655) —
 1,371
 (5,272)
Other comprehensive income (loss), net of taxes (15) (3) (3) —
 6
 (15)
Comprehensive income attributable to common shareholder $32,826
 4,481
 5,137
 —
 (9,618) $32,826


Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income
Six months ended June 30, 2016
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $684,185
 146,835
 146,464
 —
 (37) $977,447
Expenses            
Fuel oil 136,319
 26,122
 43,198
 —
 —
 205,639
Purchased power 194,979
 36,157
 23,781
 —
 —
 254,917
Other operation and maintenance 137,755
 31,557
 34,159
 —
 —
 203,471
Depreciation 63,044
 18,898
 11,599
 —
 —
 93,541
Taxes, other than income taxes 66,098
 13,796
 13,973
 —
 —
 93,867
   Total expenses 598,195
 126,530
 126,710
 —
 —
 851,435
Operating income 85,990
 20,305
 19,754
 —
 (37) 126,012
Allowance for equity funds used during construction 2,965
 333
 438
 —
 —
 3,736
Equity in earnings of subsidiaries 18,812
 —
 —
 —
 (18,812) —
Interest expense and other charges, net (22,210) (5,634) (4,604) —
 37
 (32,411)
Allowance for borrowed funds used during construction 1,116
 128
 178
 —
 —
 1,422
Income before income taxes 86,673
 15,132
 15,766
 —
 (18,812) 98,759
Income taxes 24,909
 5,683
 5,945
 —
 —
 36,537
Net income 61,764
 9,449
 9,821
 —
 (18,812) 62,222
Preferred stock dividends of subsidiaries —
 267
 191
 —
 —
 458
Net income attributable to Hawaiian Electric 61,764
 9,182
 9,630
 —
 (18,812) 61,764
Preferred stock dividends of Hawaiian Electric 540
 —
 —
 —
 —
 540
Net income for common stock $61,224
 9,182
 9,630
 —
 (18,812) $61,224

Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Comprehensive Income
ThreeSix months ended SeptemberJune 30, 20142016
(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
 $38,879
 3,301
 6,499
 —
 (9,800) $38,879
 $61,224
 9,182
 9,630
 —
 (18,812) $61,224
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 257
 —
 —
 —
 —
 257
Retirement benefit plans:  
  
  
  
  
  
  
  
  
  
  
  
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 2,552
 317
 272
 —
 (589) 2,552
Less: 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
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (2,542) (319) (272) —
 591
 (2,542) (6,623) (860) (777) —
 1,637
 (6,623)
Other comprehensive income (loss), net of taxes 10
 (2) —
 —
 2
 10
 261
 (1) (2) —
 3
 261
Comprehensive income attributable to common shareholder $38,889
 3,299
 6,499
 —
 (9,798) $38,889
 $61,485
 9,181
 9,628
 —
 (18,809) $61,485

27



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income
NineSix months ended SeptemberJune 30, 2015

(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
 $790,748
 171,787
 169,116
 —
 (46) $1,131,605
Expenses                        
Fuel oil 364,875
 56,834
 96,961
 —
 —
 518,670
 222,681
 39,626
 60,730
 —
 —
 323,037
Purchased power 329,922
 73,161
 42,726
 —
 —
 445,809
 210,620
 46,448
 28,223
 —
 —
 285,291
Other operation and maintenance 206,133
 51,493
 48,893
 —
 —
 306,519
 136,512
 32,557
 33,797
 —
 —
 202,866
Depreciation 88,167
 27,938
 16,735
 —
 —
 132,840
 58,778
 18,625
 11,081
 —
 —
 88,484
Taxes, other than income taxes 119,603
 24,783
 25,054
 —
 —
 169,440
 75,680
 16,328
 16,122
 —
 —
 108,130
Total expenses 1,108,700
 234,209
 230,369
 —
 —
 1,573,278
 704,271
 153,584
 149,953
 —
 —
 1,007,808
Operating income 145,442
 27,395
 33,688
 —
 (71) 206,454
 86,477
 18,203
 19,163
 —
 (46) 123,797
Allowance for equity funds used during construction 4,418
 458
 490
 —
 —
 5,366
 2,704
 310
 295
 —
 —
 3,309
Equity in earnings of subsidiaries 29,174
 —
 —
 —
 (29,174) —
 17,316
 —
 —
 —
 (17,316) —
Interest expense and other charges, net (33,996) (7,946) (7,299) —
 71
 (49,170) (22,528) (5,272) (4,859) —
 46
 (32,613)
Allowance for borrowed funds used during construction 1,557
 164
 197
 —
 —
 1,918
 952
 111
 118
 —
 —
 1,181
Income before income taxes 146,595
 20,071
 27,076
 —
 (29,174) 164,568
 84,921
 13,352
 14,717
 —
 (17,316) 95,674
Income taxes 43,064
 7,210
 10,077
 —
 —
 60,351
 24,666
 4,813
 5,482
 —
 —
 34,961
Net income 103,531
 12,861
 16,999
 —
 (29,174) 104,217
 60,255
 8,539
 9,235
 —
 (17,316) 60,713
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
 60,255
 8,272
 9,044
 —
 (17,316) 60,255
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
 $59,715
 8,272
 9,044
 —
 (17,316) $59,715

Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Comprehensive Income
NineSix months ended SeptemberJune 30, 2015
(in thousands) 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
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
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
Comprehensive income attributable to common shareholder $102,732
 12,457
 16,709
 —
 (29,166) $102,732

28


Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income
Nine months ended September 30, 2014
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock
 $59,715
 8,272
 9,044
 —
 (17,316) $59,715
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
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 10,190
 1,364
 1,252
 —
 (2,616) 10,190
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (10,183) (1,367) (1,255) —
 2,622
 (10,183)
Other comprehensive income (loss), net of taxes 7
 (3) (3) —
 6
 7
Comprehensive income attributable to common shareholder $59,722
 8,269
 9,041
 —
 (17,310) $59,722

(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other subsidiaries Consolidating adjustments Hawaiian Electric
Consolidated
Revenues $1,623,223
 319,629
 319,265
 —
 (61) $2,262,056
Expenses            
Fuel oil 628,164
 92,234
 145,591
 —
 —
 865,989
Purchased power 406,895
 91,827
 47,399
 —
 —
 546,121
Other operation and maintenance 199,091
 48,701
 47,691
 —
 —
 295,483
Depreciation 81,903
 26,926
 15,961
 —
 —
 124,790
Taxes, other than income taxes 152,545
 30,127
 30,111
 —
 —
 212,783
   Total expenses 1,468,598
 289,815
 286,753
 —
 —
 2,045,166
Operating income 154,625
 29,814
 32,512
 —
 (61) 216,890
Allowance for equity funds used during construction 4,557
 328
 48
 —
 —
 4,933
Equity in earnings of subsidiaries 28,576
 —
 —
 —
 (28,576) —
Interest expense and other charges, net (33,236) (8,411) (7,403) —
 61
 (48,989)
Allowance for borrowed funds used during construction 1,728
 126
 23
 —
 —
 1,877
Income before income taxes 156,250
 21,857
 25,180
 —
 (28,576) 174,711
Income taxes 46,911
 8,149
 9,626
 —
 —
 64,686
Net income 109,339
 13,708
 15,554
 —
 (28,576) 110,025
Preferred stock dividends of subsidiaries —
 400
 286
 —
 —
 686
Net income attributable to Hawaiian Electric 109,339
 13,308
 15,268
 —
 (28,576) 109,339
Preferred stock dividends of Hawaiian Electric 810
 —
 —
 —
 —
 810
Net income for common stock $108,529
 13,308
 15,268
 —
 (28,576) $108,529

Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Comprehensive Income
Nine months ended September 30, 2014
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric 
Other
subsidiaries 
 
Consolidating
adjustments
 Hawaiian Electric
Consolidated
Net income for common stock
 $108,529
 13,308
 15,268
 —
 (28,576) $108,529
Other comprehensive income (loss), net of taxes:  
  
  
  
  
  
Retirement benefit plans:  
  
  
  
  
  
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits 7,659
 953
 817
 —
 (1,770) 7,659
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes (7,627) (955) (817) —
 1,772
 (7,627)
Other comprehensive income (loss), net of taxes 32
 (2) —
 —
 2
 32
Comprehensive income attributable to common shareholder $108,561
 13,306
 15,268
 —
 (28,574) $108,561

29


Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet
SeptemberJune 30, 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 $43,536
 5,731
 3,016
 —
 —
 $52,283
 $43,945
 6,214
 3,016
 —
 —
 $53,175
Plant and equipment 3,941,406
 1,202,463
 1,072,245
 —
 —
 6,216,114
 4,098,246
 1,218,424
 1,094,874
 —
 —
 6,411,544
Less accumulated depreciation (1,293,046) (491,606) (461,962) —
 —
 (2,246,614) (1,344,064) (497,241) (473,438) —
 —
 (2,314,743)
Construction in progress 166,027
 14,111
 16,543
 —
 —
 196,681
 188,057
 23,420
 18,666
 —
 —
 230,143
Utility property, plant and equipment, net 2,857,923
 730,699
 629,842
 —
 —
 4,218,464
 2,986,184
 750,817
 643,118
 —
 —
 4,380,119
Nonutility property, plant and equipment, less accumulated depreciation 4,948
 82
 1,532
 —
 —
 6,562
 5,761
 82
 1,532
 —
 —
 7,375
Total property, plant and equipment, net 2,862,871
 730,781
 631,374
 —
 —
 4,225,026
 2,991,945
 750,899
 644,650
 —
 —
 4,387,494
Investment in wholly owned subsidiaries, at equity 548,907
 —
 —
 —
 (548,907) —
 562,199
 —
 —
 —
 (562,199) —
Current assets  
  
  
  
  
  
  
  
  
  
  
  
Cash and cash equivalents 7,665
 2,399
 539
 101
 —
 10,704
 19,842
 5,264
 2,372
 101
 —
 27,579
Advances to affiliates 12,000
 —
 2,500
 —
 (14,500) —
 —
 18,500
 18,500
 —
 (37,000) —
Customer accounts receivable, net 113,130
 26,105
 23,233
 —
 —
 162,468
 79,632
 18,376
 18,257
 —
 —
 116,265
Accrued unbilled revenues, net 96,789
 12,230
 14,559
 —
 —
 123,578
 63,021
 11,897
 12,806
 —
 —
 87,724
Other accounts receivable, net 12,538
 1,168
 1,770
 —
 (10,713) 4,763
 10,897
 1,400
 1,442
 —
 (9,193) 4,546
Fuel oil stock, at average cost 49,496
 8,442
 12,166
 —
 —
 70,104
 43,440
 7,386
 10,746
 —
 —
 61,572
Materials and supplies, at average cost 33,913
 8,279
 16,781
 —
 —
 58,973
 32,669
 7,573
 16,669
 —
 —
 56,911
Prepayments and other 34,555
 3,957
 8,630
 —
 (251) 46,891
 15,495
 5,456
 1,693
 —
 (765) 21,879
Regulatory assets 67,673
 6,719
 5,558
 —
 —
 79,950
 83,235
 4,891
 2,345
 —
 —
 90,471
Total current assets 427,759
 69,299
 85,736
 101
 (25,464) 557,431
 348,231
 80,743
 84,830
 101
 (46,958) 466,947
Other long-term assets  
  
  
  
  
  
  
  
  
  
  
  
Regulatory assets 612,347
 106,581
 99,070
 —
 —
 817,998
 583,486
 111,731
 99,426
 —
 —
 794,643
Unamortized debt expense 5,171
 1,312
 1,103
 —
 —
 7,586
 249
 46
 49
 —
 —
 344
Other 48,268
 13,885
 13,798
 —
 —
 75,951
 46,537
 13,423
 12,465
 —
 —
 72,425
Total other long-term assets 665,786
 121,778
 113,971
 —
 —
 901,535
 630,272
 125,200
 111,940
 —
 —
 867,412
Total assets $4,505,323
 921,858
 831,081
 101
 (574,371) $5,683,992
 $4,532,647
 956,842
 841,420
 101
 (609,157) $5,721,853
Capitalization and liabilities  
  
  
  
  
  
  
  
  
  
  
  
Capitalization  
  
  
  
  
  
  
  
  
  
  
  
Common stock equity $1,717,064
 286,788
 262,018
 101
 (548,907) $1,717,064
 $1,743,006
 295,275
 266,823
 101
 (562,199) $1,743,006
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 830,546
 190,000
 186,000
 —
 —
 1,206,546
 875,443
 213,640
 190,040
 —
 —
 1,279,123
Total capitalization 2,569,903
 483,788
 453,018
 101
 (548,907) 2,957,903
 2,640,742
 515,915
 461,863
 101
 (562,199) 3,056,422
Current liabilities  
  
  
  
  
  
  
  
  
  
  
  
Short-term borrowings from non-affiliates 94,995
 —
 —
 —
 —
 94,995
 36,995
 —
 —
 —
 —
 36,995
Short-term borrowings from affiliate 2,500
 12,000
 —
 —
 (14,500) —
 37,000
 —
 —
 —
 (37,000) —
Accounts payable 93,654
 16,128
 14,997
 —
 —
 124,779
 77,858
 12,786
 15,877
 —
 —
 106,521
Interest and preferred dividends payable 17,370
 3,553
 4,161
 —
 (6) 25,078
 14,441
 4,115
 2,764
 —
 (11) 21,309
Taxes accrued 134,076
 30,252
 29,498
 —
 (251) 193,575
 95,703
 24,227
 21,983
 —
 (765) 141,148
Regulatory liabilities —
 —
 347
 —
 —
 347
 —
 2,658
 710
 —
 —
 3,368
Other 58,392
 11,063
 16,702
 —
 (10,707) 75,450
 40,066
 9,639
 12,824
 —
 (9,182) 53,347
Total current liabilities 400,987
 72,996
 65,705
 —
 (25,464) 514,224
 302,063
 53,425
 54,158
 —
 (46,958) 362,688
Deferred credits and other liabilities  
  
  
  
  
  
  
  
  
  
  
  
Deferred income taxes 444,261
 91,571
 89,276
 —
 314
 625,422
 492,156
 103,430
 93,607
 —
 289
 689,482
Regulatory liabilities 248,068
 83,194
 30,642
 —
 —
 361,904
 266,592
 89,774
 31,269
 —
 —
 387,635
Unamortized tax credits 53,491
 15,258
 14,899
 —
 —
 83,648
 56,813
 17,308
 15,055
 —
 —
 89,176
Defined benefit pension and other postretirement benefit plans liability 430,838
 66,632
 72,872
 —
 (314) 570,028
 400,713
 68,241
 72,702
 —
 —
 541,656
Other 47,720
 13,647
 13,829
 —
 —
 75,196
 50,055
 13,509
 14,769
 —
 (289) 78,044
Total deferred credits and other liabilities 1,224,378
 270,302
 221,518
 —
 —
 1,716,198
 1,266,329
 292,262
 227,402
 —
 —
 1,785,993
Contributions in aid of construction 310,055
 94,772
 90,840
 —
 —
 495,667
 323,513
 95,240
 97,997
 —
 —
 516,750
Total capitalization and liabilities $4,505,323
 921,858
 831,081
 101
 (574,371) $5,683,992
 $4,532,647
 956,842
 841,420
 101
 (609,157) $5,721,853

30



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet
December 31, 20142015
(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 $43,819
 5,464
 3,016
 —
 —
 $52,299
 $43,557
 6,219
 3,016
 —
 —
 $52,792
Plant and equipment 3,782,438
 1,179,032
 1,048,012
 —
 —
 6,009,482
 4,026,079
 1,212,195
 1,077,424
 —
 —
 6,315,698
Less accumulated depreciation (1,253,866) (473,933) (447,711) —
 —
 (2,175,510) (1,316,467) (486,028) (463,509) —
 —
 (2,266,004)
Construction in progress 134,376
 12,421
 11,819
 —
 —
 158,616
 147,979
 11,455
 15,875
 —
 —
 175,309
Utility property, plant and equipment, net 2,706,767
 722,984
 615,136
 —
 —
 4,044,887
 2,901,148
 743,841
 632,806
 —
 —
 4,277,795
Nonutility property, plant and equipment, less accumulated depreciation 4,950
 82
 1,531
 —
 —
 6,563
 5,659
 82
 1,531
 —
 —
 7,272
Total property, plant and equipment, net 2,711,717
 723,066
 616,667
 —
 —
 4,051,450
 2,906,807
 743,923
 634,337
 —
 —
 4,285,067
Investment in wholly owned subsidiaries, at equity
 538,639
 —
 —
 —
 (538,639) —
 556,528
 —
 —
 —
 (556,528) —
Current assets  
  
  
  
  
  
  
  
  
  
  
  
Cash and cash equivalents 12,416
 612
 633
 101
 —
 13,762
 16,281
 2,682
 5,385
 101
 —
 24,449
Advances to affiliates 16,100
 —
 —
 —
 (16,100) —
 —
 15,500
 7,500
 —
 (23,000) —
Customer accounts receivable, net 111,462
 24,222
 22,800
 —
 —
 158,484
 93,515
 20,508
 18,755
 —
 —
 132,778
Accrued unbilled revenues, net 103,072
 15,926
 18,376
 —
 —
 137,374
 60,080
 12,531
 11,898
 —
 —
 84,509
Other accounts receivable, net 9,980
 981
 2,246
 —
 (8,924) 4,283
 16,421
 1,275
 1,674
 —
 (8,962) 10,408
Fuel oil stock, at average cost 74,515
 13,800
 17,731
 —
 —
 106,046
 49,455
 8,310
 13,451
 —
 —
 71,216
Materials and supplies, at average cost 33,154
 6,664
 17,432
 —
 —
 57,250
 30,921
 6,865
 16,643
 —
 —
 54,429
Prepayments and other 44,680
 8,611
 13,567
 —
 (475) 66,383
 25,505
 9,091
 2,295
 —
 (251) 36,640
Regulatory assets 58,550
 6,745
 6,126
 —
 —
 71,421
 63,615
 4,501
 4,115
 —
 —
 72,231
Total current assets 463,929
 77,561
 98,911
 101
 (25,499) 615,003
 355,793
 81,263
 81,716
 101
 (32,213) 486,660
Other long-term assets  
  
  
  
  
  
  
  
  
  
  
  
Regulatory assets 623,784
 107,454
 102,788
 —
 (183) 833,843
 608,957
 114,562
 100,981
 —
 —
 824,500
Unamortized debt expense 5,640
 1,438
 1,245
 —
 —
 8,323
 359
 74
 64
 —
 —
 497
Other 53,106
 15,366
 13,366
 —
 —
 81,838
 47,731
 14,693
 13,062
 —
 —
 75,486
Total other long-term assets 682,530
 124,258
 117,399
 —
 (183) 924,004
 657,047
 129,329
 114,107
 —
 —
 900,483
Total assets $4,396,815
 924,885
 832,977
 101
 (564,321) $5,590,457
 $4,476,175
 954,515
 830,160
 101
 (588,741) $5,672,210
Capitalization and liabilities  
  
  
  
  
  
  
  
  
  
  
  
Capitalization  
  
  
  
  
  
  
  
  
  
  
  
Common stock equity $1,682,144
 281,846
 256,692
 101
 (538,639) $1,682,144
 $1,728,325
 292,702
 263,725
 101
 (556,528) $1,728,325
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 830,546
 190,000
 186,000
 —
 —
 1,206,546
 875,163
 213,580
 189,959
 —
 —
 1,278,702
Total capitalization 2,534,983
 478,846
 447,692
 101
 (538,639) 2,922,983
 2,625,781
 513,282
 458,684
 101
 (556,528) 3,041,320
Current liabilities  
  
  
  
  
    
  
  
  
  
  
Short-term borrowings from affiliate —
 10,500
 5,600
 —
 (16,100) —
 23,000
 —
 —
 —
 (23,000) —
Accounts payable 122,433
 23,728
 17,773
 —
 —
 163,934
 84,631
 17,702
 12,513
 —
 —
 114,846
Interest and preferred dividends payable 15,407
 3,989
 2,931
 —
 (11) 22,316
 15,747
 4,255
 3,113
 —
 (4) 23,111
Taxes accrued 176,339
 37,548
 36,807
 —
 (292) 250,402
 131,668
 30,342
 29,325
 —
 (251) 191,084
Regulatory liabilities 191
 —
 441
 —
 —
 632
 —
 1,030
 1,174
 —
 —
 2,204
Other 48,282
 9,866
 16,094
 —
 (9,096) 65,146
 41,083
 8,760
 13,194
 —
 (8,958) 54,079
Total current liabilities 362,652
 85,631
 79,646
 —
 (25,499) 502,430
 296,129
 62,089
 59,319
 —
 (32,213) 385,324
Deferred credits and other liabilities  
  
  
  
  
    
  
  
  
  
  
Deferred income taxes 429,515
 90,119
 83,238
 —
 —
 602,872
 466,133
 100,681
 87,706
 —
 286
 654,806
Regulatory liabilities 236,727
 77,707
 29,966
 —
 (183) 344,217
 254,033
 84,623
 30,683
 —
 —
 369,339
Unamortized tax credits 49,865
 14,902
 14,725
 —
 —
 79,492
 54,078
 15,406
 14,730
 —
 —
 84,214
Defined benefit pension and other postretirement benefit plans liability 446,888
 72,547
 75,960
 —
 —
 595,395
 409,021
 69,893
 74,060
 —
 —
 552,974
Other 52,446
 10,658
 13,532
 —
 —
 76,636
 51,273
 13,243
 13,916
 —
 (286) 78,146
Total deferred credits and other liabilities 1,215,441
 265,933
 217,421
 —
 (183) 1,698,612
 1,234,538
 283,846
 221,095
 —
 —
 1,739,479
Contributions in aid of construction 283,739
 94,475
 88,218
 —
 —
 466,432
 319,727
 95,298
 91,062
 —
 —
 506,087
Total capitalization and liabilities $4,396,815
 924,885
 832,977
 101
 (564,321) $5,590,457
 $4,476,175
 954,515
 830,160
 101
 (588,741) $5,672,210

31



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Changes in Common Stock Equity
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
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
Consolidating Statement of Changes in Common Stock Equity
NineSix months ended SeptemberJune 30, 20142015
 
(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, 2013 $1,593,564
 274,802
 248,771
 101
 (523,674) $1,593,564
Balance, December 31, 2014 $1,682,144
 281,846
 256,692
 101
 (538,639) $1,682,144
Net income for common stock 108,529
 13,308
 15,268
 —
 (28,576) 108,529
 59,715
 8,272
 9,044
 —
 (17,316) 59,715
Other comprehensive income (loss), net of taxes 32
 (2) —
 —
 2
 32
 7
 (3) (3) —
 6
 7
Common stock dividends (66,369) (8,720) (10,762) —
 19,482
 (66,369) (45,203) (5,010) (7,587) —
 12,597
 (45,203)
Common stock issuance expenses (5) —
 —
 —
 —
 (5) (5) (1) —
 —
 1
 (5)
Balance, September 30, 2014 $1,635,751
 279,388
 253,277
 101
 (532,766) $1,635,751
Balance, June 30, 2015 $1,696,658
 285,104
 258,146
 101
 (543,351) $1,696,658

32



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows
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 5,409
 2,055
 2,363
 —
 —
 9,827
 1,919
 911
 963
 —
 —
 3,793
Increase in deferred income taxes 46,493
 907
 10,497
 —
 314
 58,211
Deferred income taxes 23,954
 2,538
 5,623
 —
 3
 32,118
Change in tax credits, net 3,680
 372
 195
 —
 —
 4,247
 2,772
 1,913
 319
 —
 —
 5,004
Allowance for equity funds used during construction (4,418) (458) (490) —
 —
 (5,366) (2,965) (333) (438) —
 —
 (3,736)
Other (1,389) (302) (331) —
 —
 (2,022)
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)
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 and utility revenue taxes (52,505) (2,276) (6,540) —
 (314) (61,635) (21,371) (192) (6,626) —
 (3) (28,192)
Increase in defined benefit pension and other postretirement benefit plans liability —
 —
 331
 —
 —
 331
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability 299
 27
 (89) —
 —
 237
Change in other assets and liabilities (16,626) 436
 (2,824) —
 (1,790) (20,804) (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

33



Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows
NineSix months ended SeptemberJune 30, 2014
2015
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other
subsidiaries		 Consolidating
adjustments		 Hawaiian Electric
Consolidated
Cash flows from operating activities  
  
  
  
  
  
Net income $109,339
 13,708
 15,554
 —
 (28,576) $110,025
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
  
  
Equity in earnings of subsidiaries (28,651) —
 —
 —
 28,576
 (75)
Common stock dividends received from subsidiaries 19,557
 —
 —
 —
 (19,482) 75
Depreciation of property, plant and equipment 81,903
 26,926
 15,961
 —
 —
 124,790
Other amortization (1) 765
 1,950
 1,574
 —
 —
 4,289
Increase in deferred income taxes 52,274
 5,146
 9,972
 —
 —
 67,392
Change in tax credits, net 4,725
 687
 404
 —
 —
 5,816
Allowance for equity funds used during construction (4,557) (328) (48) —
 —
 (4,933)
Change in cash overdraft —
 —
 (1,038) —
 —
 (1,038)
Changes in assets and liabilities:            
Increase in accounts receivable (17,540) (4,714) (442) —
 2,965
 (19,731)
Decrease (increase) in accrued unbilled revenues (554) 626
 899
 —
 —
 971
Decrease in fuel oil stock 11,328
 219
 4,237
 —
 —
 15,784
Decrease (increase) in materials and supplies 875
 (987) (1,483) —
 —
 (1,595)
Decrease (increase) in regulatory assets (15,159) (2,594) 222
 —
 —
 (17,531)
Decrease in accounts payable (2) (52,684) (454) (142) —
 —
 (53,280)
Change in prepaid and accrued income and utility revenue taxes (18,131) (1,310) 1,366
 —
 —
 (18,075)
Decrease in defined benefit pension and other postretirement benefit plans liability (422) —
 (326) —
 —
 (748)
Change in other assets and liabilities (3) (32,291) (4,040) (2,673) —
 (2,965) (41,969)
Net cash provided by operating activities 110,777
 34,835
 44,037
 —
 (19,482) 170,167
Cash flows from investing activities  
  
  
  
  
  
Capital expenditures (4) (181,565) (34,565) (37,588) —
 —
 (253,718)
Contributions in aid of construction 12,352
 6,229
 3,159
 —
 —
 21,740
Other (5) 537
 154
 22
 —
 —
 713
Advances from (to) affiliates (4,961) 1,000
 —
 —
 3,961
 —
Net cash used in investing activities (173,637) (27,182) (34,407) —
 3,961
 (231,265)
Cash flows from financing activities  
  
  
  
  
  
Common stock dividends (66,369) (8,720) (10,762) —
 19,482
 (66,369)
Preferred stock dividends of Hawaiian Electric and subsidiaries (810) (400) (286) —
 —
 (1,496)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 83,987
 1,000
 3,961
 —
 (3,961) 84,987
Other (337) (50) (75) —
 —
 (462)
Net cash provided by (used in) financing activities 16,471
 (8,170) (7,162) —
 15,521
 16,660
Net increase (decrease) in cash and cash equivalents (46,389) (517) 2,468
 —
 —
 (44,438)
Cash and cash equivalents, beginning of period 61,245
 1,326
 153
 101
 —
 62,825
Cash and cash equivalents, end of period $14,856
 809
 2,621
 101
 —
 $18,387
(1) Prior to revision, other amortization for Maui Electric and Hawaiian Electric Consolidated were $1,947 and $4,662, respectively.
(2) Prior to revision, decrease in accounts payable for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(70,916), $(1,807), $(5,170) and $(77,893), respectively.
(3) Prior to revision, changes in other assets and liabilities for Hawaiian Electric, Hawaii Electric Light, Maui Electric, Consolidating adjustments and Hawaiian Electric Consolidated were $(31,754), $(3,886), $(3,024), $(2,965) and $(41,629), respectively.
(4) Prior to revision, capital expenditures for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(163,333), $(33,212), $(32,560) and $(229,105), respectively.
(5) Prior to revision, cash flows from investing activities-other for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were nil.
(in thousands) Hawaiian Electric Hawaii Electric Light Maui Electric Other
subsidiaries		 Consolidating
adjustments		 Hawaiian Electric
Consolidated
Cash flows from operating activities  
  
  
  
  
  
Net income $60,255
 8,539
 9,235
 —
 (17,316) $60,713
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
  
  
Equity in earnings of subsidiaries (17,366) —
 —
 —
 17,316
 (50)
Common stock dividends received from subsidiaries 12,647
 —
 —
 —
 (12,597) 50
Depreciation of property, plant and equipment 58,778
 18,625
 11,081
 —
 —
 88,484
Other amortization 1,177
 870
 1,173
 —
 —
 3,220
Deferred income taxes 26,423
 1,376
 5,521
 —
 —
 33,320
Change in tax credits, net 3,803
 399
 259
 —
 —
 4,461
Allowance for equity funds used during construction (2,704) (310) (295) —
 —
 (3,309)
Change in cash overdraft —
 —
 193
 —
 —
 193
Other 1,405
 351
 21
 —
 —
 1,777
Changes in assets and liabilities:            
Decrease (increase) in accounts receivable 13,651
 (787) 2,377
 —
 1,714
 16,955
Decrease in accrued unbilled revenues 22,907
 2,154
 2,869
 —
 —
 27,930
Decrease (increase) in fuel oil stock (11,195) 5,450
 3,383
 —
 —
 (2,362)
Decrease (increase) in materials and supplies 297
 (508) 106
 —
 —
 (105)
Increase in regulatory assets (15,984) (2,987) (1,005) —
 —
 (19,976)
Increase (decrease) in accounts payable (5,098) (1,411) 2,138
 —
 —
 (4,371)
Change in prepaid and accrued income and utility revenue taxes (53,350) (3,079) (7,184) —
 —
 (63,613)
Increase in defined benefit pension and other postretirement benefit plans liability —
 —
 221
 —
 —
 221
Change in other assets and liabilities (7,838) (2,199) (4,111) —
 (1,714) (15,862)
Net cash provided by operating activities 87,808
 26,483
 25,982
 —
 (12,597) 127,676
Cash flows from investing activities  
  
  
  
  
  
Capital expenditures (154,727) (25,106) (19,310) —
 —
 (199,143)
Contributions in aid of construction 16,628
 1,465
 996
 —
 —
 19,089
Other 334
 124
 53
 —
 —
 511
Advances from affiliates (2,100) —
 —
 —
 2,100
 —
Net cash used in investing activities (139,865) (23,517) (18,261) —
 2,100
 (179,543)
Cash flows from financing activities  
  
  
  
  
  
Common stock dividends (45,203) (5,010) (7,587) —
 12,597
 (45,203)
Preferred stock dividends of Hawaiian Electric and subsidiaries (540) (267) (191) —
 —
 (998)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less 88,993
 2,500
 (400) —
 (2,100) 88,993
Other (216) —
 (1) —
 —
 (217)
Net cash provided by (used in) financing activities 43,034
 (2,777) (8,179) —
 10,497
 42,575
Net increase (decrease) in cash and cash equivalents (9,023) 189
 (458) —
 —
 (9,292)
Cash and cash equivalents, beginning of period 12,416
 612
 633
 101
 —
 13,762
Cash and cash equivalents, end of period $3,393
 801
 175
 101
 —
 $4,470



34



5 · Bank segment

Selected financial information
American Savings Bank, F.S.B.
Statements of Income Data
 Three months ended 
 September 30		 Nine months ended 
 September 30		 Three months ended June 30 Six months ended June 30
(in thousands) 2015 2014 2015 2014 2016 2015 2016 2015
Interest and dividend income  
  
  
  
  
  
  
  
Interest and fees on loans $46,413
 $45,532
 $137,646
 $133,065
 $49,690
 $46,035
 $98,127
 $91,233
Interest and dividends on investment securities 4,213
 2,773
 10,570
 8,758
 4,443
 3,306
 9,460
 6,357
Total interest and dividend income 50,626
 48,305
 148,216
 141,823
 54,133
 49,341
 107,587
 97,590
Interest expense  
  
  
  
  
  
  
  
Interest on deposit liabilities 1,355
 1,312
 3,881
 3,774
 1,691
 1,266
 3,283
 2,526
Interest on other borrowings 1,515
 1,438
 4,468
 4,263
 1,467
 1,487
 2,952
 2,953
Total interest expense 2,870
 2,750
 8,349
 8,037
 3,158
 2,753
 6,235
 5,479
Net interest income 47,756
 45,555
 139,867
 133,786
 50,975
 46,588
 101,352
 92,111
Provision for loan losses 2,997
 1,550
 5,436
 3,566
 4,753
 1,825
 9,519
 2,439
Net interest income after provision for loan losses 44,759
 44,005
 134,431
 130,220
 46,222
 44,763
 91,833
 89,672
Noninterest income  
  
  
  
  
  
  
  
Fees from other financial services 5,639
 5,642
 16,544
 15,987
 5,701
 5,550
 11,200
 10,905
Fee income on deposit liabilities 5,883
 5,109
 16,622
 14,175
 5,262
 5,424
 10,418
 10,739
Fee income on other financial products 2,096
 1,971
 6,088
 6,325
 2,207
 2,103
 4,412
 3,992
Bank-owned life insurance 1,021
 1,000
 3,062
 2,945
 1,006
 1,058
 2,004
 2,041
Mortgage banking income 1,437
 875
 5,327
 1,749
 1,554
 2,068
 2,749
 3,890
Gains on sale of investment securities —
 —
 —
 2,847
Gains on sale of investment securities, net 598
 —
 598
 —
Other income, net 2,389
 634
 3,363
 1,920
 288
 239
 621
 974
Total noninterest income 18,465
 15,231
 51,006
 45,948
 16,616
 16,442
 32,002
 32,541
Noninterest expense  
  
  
  
  
  
  
  
Compensation and employee benefits 22,728
 19,892
 66,813
 60,050
 21,919
 22,319
 44,353
 44,085
Occupancy 4,128
 4,517
 12,250
 12,959
 4,115
 4,009
 8,253
 8,122
Data processing 3,032
 2,684
 9,101
 8,715
 3,277
 2,953
 6,449
 6,069
Services 2,556
 2,580
 7,730
 7,708
 2,755
 2,833
 5,666
 5,174
Equipment 1,608
 1,672
 4,999
 4,926
 1,771
 1,690
 3,434
 3,391
Office supplies, printing and postage 1,511
 1,415
 4,297
 4,487
 1,583
 1,303
 2,948
 2,786
Marketing 934
 948
 2,619
 2,690
 899
 844
 1,760
 1,685
FDIC insurance 809
 840
 2,393
 2,441
 913
 773
 1,797
 1,584
Other expense 5,116
 4,182
 14,076
 11,198
 5,382
 4,755
 9,357
 8,960
Total noninterest expense 42,422
 38,730
 124,278
 115,174
 42,614
 41,479
 84,017
 81,856
Income before income taxes 20,802
 20,506
 61,159
 60,994
 20,224
 19,726
 39,818
 40,357
Income taxes 7,351
 7,253
 21,382
 21,806
 6,939
 6,875
 13,860
 14,031
Net income $13,451
 $13,253
 $39,777
 $39,188
 $13,285
 $12,851
 $25,958
 $26,326

35



American Savings Bank, F.S.B.
Statements of Comprehensive Income Data
 Three months ended 
 September 30		 Nine months ended 
 September 30		 Three months ended June 30 Six months ended June 30
(in thousands) 2015 2014 2015 2014 2016 2015 2016 2015
Net income $13,451
 $13,253
 $39,777
 $39,188
 $13,285
 $12,851
 $25,958
 $26,326
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 $(2,543), $1,094, $(2,382) and $(2,249) for the respective periods 3,851
 (1,657) 3,608
 3,406
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, nil and $1,132 for the respective periods —
 —
 —
 (1,715)
Net unrealized gains (losses) on available-for-sale investment securities arising during the period, net of (taxes) benefits of ($1,925), $2,439, ($6,830) and $161 for the respective periods 2,915
 (3,694) 10,344
 (243)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $238, nil, $238 and nil for the respective periods (360) —
 (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 $249, $138, $763 and $424 for the respective periods 376
 208
 1,155
 642
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $140, $255, $277 and $514 for the respective periods 211
 387
 419
 779
Other comprehensive income (loss), net of taxes 4,227
 (1,449) 4,763
 2,333
 2,766
 (3,307) 10,403
 536
Comprehensive income $17,678
 $11,804
 $44,540
 $41,521
 $16,051
 $9,544
 $36,361
 $26,862


36



American Savings Bank, F.S.B.
Balance Sheets Data
(in thousands) September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015
Assets  
  
  
  
  
  
  
  
Cash and due from banks  
 $103,934
  
 $107,233
  
 $111,738
  
 $127,201
Interest-bearing deposits   73,041
   54,230
   62,850
   93,680
Available-for-sale investment securities, at fair value  
 785,837
  
 550,394
  
 894,021
  
 820,648
Stock in Federal Home Loan Bank, at cost  
 10,678
  
 69,302
  
 11,218
  
 10,678
Loans receivable held for investment  
 4,535,404
  
 4,434,651
  
 4,754,954
  
 4,615,819
Allowance for loan losses  
 (48,274)  
 (45,618)  
 (55,331)  
 (50,038)
Net loans  
 4,487,130
  
 4,389,033
  
 4,699,623
  
 4,565,781
Loans held for sale, at lower of cost or fair value  
 5,598
  
 8,424
  
 6,217
  
 4,631
Other  
 307,089
  
 305,416
  
 320,233
  
 309,946
Goodwill  
 82,190
  
 82,190
  
 82,190
  
 82,190
Total assets  
 $5,855,497
  
 $5,566,222
  
 $6,188,090
  
 $6,014,755
                
Liabilities and shareholder’s equity  
  
  
  
  
  
  
  
Deposit liabilities—noninterest-bearing  
 $1,422,843
  
 $1,342,794
  
 $1,583,420
  
 $1,520,374
Deposit liabilities—interest-bearing  
 3,403,111
  
 3,280,621
  
 3,648,783
  
 3,504,880
Other borrowings  
 368,593
  
 290,656
  
 272,887
  
 328,582
Other  
 103,553
  
 118,363
  
 103,396
  
 101,029
Total liabilities  
 5,298,100
  
 5,032,434
  
 5,608,486
  
 5,454,865
Commitments and contingencies  
 

  
 

  
 

  
 

Common stock  
 1
  
 1
  
 1
  
 1
Additional paid in capital   339,980
   338,411
   341,849
   340,496
Retained earnings  
 229,211
  
 211,934
  
 244,622
  
 236,664
Accumulated other comprehensive loss, net of tax benefits  
  
  
  
  
  
  
  
Net unrealized gains on securities $4,070
  
 $462
  
Net unrealized gains (losses) on securities $8,111
  
 $(1,872)  
Retirement benefit plans (15,865) (11,795) (17,020) (16,558) (14,979) (6,868) (15,399) (17,271)
Total shareholder’s equity  
 557,397
  
 533,788
  
 579,604
  
 559,890
Total liabilities and shareholder’s equity  
 $5,855,497
  
 $5,566,222
  
 $6,188,090
  
 $6,014,755
                
Other assets  
  
  
  
  
  
  
  
Bank-owned life insurance  
 $136,969
  
 $134,115
  
 $140,176
  
 $138,139
Premises and equipment, net  
 87,432
  
 92,407
  
 91,256
  
 88,077
Prepaid expenses  
 3,879
  
 3,196
  
 4,715
  
 3,550
Accrued interest receivable  
 14,577
  
 13,632
  
 15,749
  
 15,192
Mortgage-servicing rights  
 12,258
  
 11,540
  
 9,016
  
 8,884
Low-income housing equity investments   34,323
   33,438
   41,080
   37,793
Real estate acquired in settlement of loans, net  
 247
  
 891
  
 446
  
 1,030
Other  
 17,404
  
 16,197
  
 17,795
  
 17,281
  
 $307,089
  
 $305,416
  
 $320,233
  
 $309,946
Other liabilities  
  
  
  
  
  
  
  
Accrued expenses  
 $28,952
  
 $37,880
  
 $30,569
  
 $30,705
Federal and state income taxes payable  
 21,565
  
 28,642
  
 16,761
  
 13,448
Cashier’s checks  
 25,852
  
 20,509
  
 21,497
  
 21,768
Advance payments by borrowers  
 5,389
  
 9,652
  
 10,851
  
 10,311
Other  
 21,795
  
 21,680
  
 23,718
  
 24,797
  
 $103,553
  
 $118,363
  
 $103,396
  
 $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.

37



Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of $269173 million and $100 million, respectively, as of SeptemberJune 30, 20152016 and $191$229 million and $100 million, respectively, as of December 31, 20142015.
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
(dollar in thousands) Number of issues 
Fair 
value
 Amount Number of issues 
Fair 
value
 Amount
September 30, 2015  
  
  
  
    
  
    
  
(dollars in thousands) Amortized cost Gross unrealized gains Gross unrealized losses 
Estimated fair
value
 Number of issues 
Fair 
value
 Amount Number of issues 
Fair 
value
 Amount
June 30, 2016    
  
    
  
Available-for-sale                                
U.S. Treasury and federal agency obligations $209,025
 $2,435
 $(342) $211,118
 4
 $24,676
 $(46) 3
 $18,218
 $(296) $194,048
 $4,131
 $(20) $198,159
 —
 $—
 $—
 1
 $3,842
 $(20)
Mortgage-related securities- FNMA, FHLMC and GNMA 570,055
 6,884
 (2,220) 574,719
 8
 57,263
 (278) 25
 132,874
 (1,942) 686,506
 10,022
 (666) 695,862
 3
 20,608
 (65) 14
 63,466
 (601)
 $779,080
 $9,319
 $(2,562) $785,837
 12
 $81,939
 $(324) 28
 $151,092
 $(2,238) $880,554
 $14,153
 $(686) $894,021
 3
 $20,608
 $(65) 15
 $67,308
 $(621)
December 31, 2014                    
December 31, 2015                    
Available-for-sale                                        
U.S. Treasury and federal agency obligations $119,507
 $1,092
 $(1,039) $119,560
 6
 $41,970
 $(361) 5
 $29,168
 $(678) $213,234
 $1,025
 $(1,300) $212,959
 13
 $83,053
 $(866) 3
 $17,378
 $(434)
Mortgage-related securities- FNMA, FHLMC and GNMA 430,120
 5,653
 (4,939) 430,834
 6
 47,029
 (164) 29
 172,623
 (4,775) 610,522
 3,564
 (6,397) 607,689
 38
 305,785
 (2,866) 25
 125,817
 (3,531)
 $549,627
 $6,745
 $(5,978) $550,394
 12
 $88,999
 $(525) 34
 $201,791
 $(5,453) $823,756
 $4,589
 $(7,697) $820,648
 51
 $388,838
 $(3,732) 28
 $143,195
 $(3,965)
TheASB does not believe that the investment securities that were in an unrealized loss position at June 30, 2016, represent an other-than-temporary impairment. Total gross unrealized losses on ASB’s investments in mortgage-relatedwere primarily attributable to rising interest rates relative to when the investment securities were purchased and obligations issuednot due to the credit quality of the investment securities. The contractual cash flows of the investment securities are backed by federal agencies were caused by interest rate movements. Becausethe full faith and credit guaranty of the United States government or an agency of the government. ASB does not intend to sell the securities and has determined it is more likely than not that it will not be required to sellbefore the investments before recovery of theirits amortized cost basis which may be at maturity,and there have been no adverse changes in the timing of the contractual cash flows for the securities. ASB did not consider these investments to be other-than-temporarily impaired at Septemberrecognize OTTI for the quarters ended June 30, 2016 and 2015.
The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.
U.S. Treasury and federal agency obligations 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.Themortgages.
The contractual maturities of available-for-sale investment securities were as follows:
September 30, 2015 Amortized cost Fair value
June 30, 2016 Amortized cost Fair value
(in thousands)        
Due in one year or less $—
 $—
 $9,991
 $10,001
Due after one year through five years 75,332
 76,786
 81,303
 83,162
Due after five years through ten years 71,667
 72,198
 81,439
 83,406
Due after ten years 62,026
 62,134
 21,315
 21,590
 209,025
 211,118
 194,048
 198,159
Mortgage-related securities-FNMA,FHLMC and GNMA 570,055
 574,719
 686,506
 695,862
Total available-for-sale securities $779,080
 $785,837
 $880,554
 $894,021



38



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 Unallocated 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, 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
Three months ended
September 30, 2014		  
  
  
  
  
  
  
  
  
  
Three months ended June 30, 2015  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $5,667
 $7,230
 $7,081
 $1,837
 $3,390
 $26
 $15,144
 $1,997
 $—
 $42,372
 $4,921
 $11,228
 $6,523
 $2,286
 $2,837
 $21
 $14,580
 $3,399
 $—
 $45,795
Charge-offs (632) —
 (46) (28) —
 —
 (886) (592) —
 (2,184) (58) —
 (17) —
 —
 —
 (756) (983) —
 (1,814)
Recoveries 160
 —
 299
 90
 —
 —
 952
 222
 —
 1,723
 55
 —
 8
 136
 —
 —
 106
 254
 —
 559
Provision 670
 3
 (119) (92) 1,724
 3
 (1,130) 491
 —
 1,550
 (627) (808) 99
 (319) (262) (3) 3,539
 206
 —
 1,825
Ending balance $5,865
 $7,233
 $7,215
 $1,807
 $5,114
 $29
 $14,080
 $2,118
 $—
 $43,461
 $4,291
 $10,420
 $6,613
 $2,103
 $2,575
 $18
 $17,469
 $2,876
 $—
 $46,365
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
June 30, 2016                    
Ending balance: individually evaluated for impairment $1,388
 $—
 $469
 $919
 $—
 $—
 $3,084
 $7
   $5,867
 $1,709
 $172
 $826
 $819
 $—
 $—
 $2,647
 $7
   $6,180
Ending balance: collectively evaluated for impairment $3,095
 $11,407
 $6,438
 $1,145
 $3,519
 $13
 $13,618
 $3,172
 $—
 $42,407
 $2,675
 $13,389
 $7,010
 $870
 $6,993
 $12
 $14,438
 $3,764
 $—
 $49,151
Financing Receivables:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Ending balance $2,062,458
 $618,113
 $832,267
 $17,369
 $80,230
 $14,318
 $798,428
 $118,450
   $4,541,633
 $2,064,343
 $740,322
 $860,522
 $18,447
 $134,642
 $16,004
 $772,565
 $153,212
   $4,760,057
Ending balance: individually evaluated for impairment $22,560
 $—
 $2,909
 $5,710
 $—
 $—
 $22,853
 $14
   $54,046
 $22,279
 $3,630
 $4,646
 $4,453
 $—
 $—
 $24,153
 $12
   $59,173
Ending balance: collectively evaluated for impairment $2,039,898
 $618,113
 $829,358
 $11,659
 $80,230
 $14,318
 $775,575
 $118,436
   $4,487,587
 $2,042,064
 $736,692
 $855,876
 $13,994
 $134,642
 $16,004
 $748,412
 $153,200
   $4,700,884
Nine months ended
September 30, 2014		  
  
  
  
  
  
  
  
  
  
Six months ended June 30, 2015  
  
  
  
  
  
  
  
  
  
Allowance for loan losses:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Beginning balance $5,534
 $5,059
 $5,229
 $1,817
 $2,397
 $19
 $15,803
 $2,367
 $1,891
 $40,116
 $4,662
 $8,954
 $6,982
 $1,875
 $5,471
 $28
 $14,017
 $3,629
 $—
 $45,618
Charge-offs (992) —
 (182) (81) —
 —
 (1,256) (1,614) —
 (4,125) (214) —
 (20) —
 —
 —
 (802) (1,925) —
 (2,961)
Recoveries 1,056
 —
 624
 253
 —
 —
 1,277
 694
 —
 3,904
 67
 —
 39
 185
 —
 —
 447
 531
 —
 1,269
Provision 267
 2,174
 1,544
 (182) 2,717
 10
 (1,744) 671
 (1,891) 3,566
 (224) 1,466
 (388) 43
 (2,896) (10) 3,807
 641
 —
 2,439
Ending balance $5,865
 $7,233
 $7,215
 $1,807
 $5,114
 $29
 $14,080
 $2,118
 $—
 $43,461
 $4,291
 $10,420
 $6,613
 $2,103
 $2,575
 $18
 $17,469
 $2,876
 $—
 $46,365
December 31, 2015                    
Ending balance: individually evaluated for impairment $917
 $4
 $8
 $1,171
 $—
 $—
 $810
 $5
   $2,915
 $1,453
 $—
 $442
 $891
 $—
 $—
 $3,527
 $7
   $6,320
Ending balance: collectively evaluated for impairment $4,948
 $7,229
 $7,207
 $636
 $5,114
 $29
 $13,270
 $2,113
 $—
 $40,546
 $2,733
 $11,342
 $6,818
 $780
 $4,461
 $13
 $13,681
 $3,890
 $—
 $43,718
Financing Receivables:  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Ending balance $2,030,337
 $502,356
 $808,991
 $16,935
 $87,461
 $18,699
 $770,079
 $107,531
   $4,342,389
 $2,069,665
 $690,561
 $846,294
 $18,229
 $100,796
 $14,089
 $758,659
 $123,775
   $4,622,068
Ending balance: individually evaluated for impairment $20,015
 $754
 $392
 $8,872
 $—
 $—
 $15,058
 $16
   $45,107
 $22,457
 $1,188
 $3,225
 $5,683
 $—
 $—
 $21,119
 $13
   $53,685
Ending balance: collectively evaluated for impairment $2,010,322
 $501,602
 $808,599
 $8,063
 $87,461
 $18,699
 $755,021
 $107,515
   $4,297,282
 $2,047,208
 $689,373
 $843,069
 $12,546
 $100,796
 $14,089
 $737,540
 $123,762
   $4,568,383

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.

39



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 PD Model rating, the loss given default and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens and major changes in business and economic conditions. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt.  Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that the Bank may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable.
The credit risk profile by internally assigned grade for loans was as follows:
 September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015
(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 $563,734
 $70,950
 $745,624
 $493,105
 $79,312
 $743,334
 $664,731
 $107,552
 $712,020
 $642,410
 $86,991
 $703,208
Special mention 9,460
 9,280
 10,316
 5,209
 —
 16,095
 43,607
 —
 12,607
 7,710
 13,805
 7,029
Substandard 44,919
 —
 40,662
 33,603
 17,126
 31,665
 31,984
 27,090
 47,698
 40,441
 —
 47,975
Doubtful —
 —
 1,826
 —
 —
 663
 —
 —
 240
 —
 —
 447
Loss —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Total $618,113
 $80,230
 $798,428
 $531,917
 $96,438
 $791,757
 $740,322
 $134,642
 $772,565
 $690,561
 $100,796
 $758,659

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, 2015  
  
  
  
  
  
  
June 30, 2016  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $6,354
 $1,722
 $11,852
 $19,928
 $2,042,530
 $2,062,458
 $—
 $5,421
 $1,860
 $10,526
 $17,807
 $2,046,536
 $2,064,343
 $—
Commercial real estate —
 —
 —
 —
 618,113
 618,113
 —
 —
 —
 —
 —
 740,322
 740,322
 —
Home equity line of credit 1,192
 81
 436
 1,709
 830,558
 832,267
 —
 878
 445
 602
 1,925
 858,597
 860,522
 —
Residential land 120
 —
 415
 535
 16,834
 17,369
 —
 —
 —
 148
 148
 18,299
 18,447
 —
Commercial construction —
 —
 —
 —
 80,230
 80,230
 —
 —
 —
 —
 —
 134,642
 134,642
 —
Residential construction —
 —
 —
 —
 14,318
 14,318
 —
 —
 —
 —
 —
 16,004
 16,004
 —
Commercial 546
 312
 1,005
 1,863
 796,565
 798,428
 —
 438
 111
 308
 857
 771,708
 772,565
 —
Consumer 1,357
 491
 377
 2,225
 116,225
 118,450
 —
 1,354
 692
 476
 2,522
 150,690
 153,212
 —
Total loans $9,569
 $2,606
 $14,085
 $26,260
 $4,515,373
 $4,541,633
 $—
 $8,091
 $3,108
 $12,060
 $23,259
 $4,736,798
 $4,760,057
 $—
December 31, 2014  
  
  
  
  
  
  
December 31, 2015  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $6,124
 $1,732
 $12,632
 $20,488
 $2,023,717
 $2,044,205
 $—
 $4,967
 $3,289
 $11,503
 $19,759
 $2,049,906
 $2,069,665
 $—
Commercial real estate —
 —
 —
 —
 531,917
 531,917
 —
 —
 —
 —
 —
 690,561
 690,561
 —
Home equity line of credit 1,341
 501
 194
 2,036
 816,779
 818,815
 —
 896
 706
 477
 2,079
 844,215
 846,294
 —
Residential land —
 —
 —
 —
 16,240
 16,240
 —
 —
 —
 415
 415
 17,814
 18,229
 —
Commercial construction —
 —
 —
 —
 96,438
 96,438
 —
 —
 —
 —
 —
 100,796
 100,796
 —
Residential construction —
 —
 —
 —
 18,961
 18,961
 —
 —
 —
 —
 —
 14,089
 14,089
 —
Commercial 699
 145
 569
 1,413
 790,344
 791,757
 —
 125
 223
 878
 1,226
 757,433
 758,659
 —
Consumer 829
 333
 403
 1,565
 121,091
 122,656
 —
 1,383
 593
 644
 2,620
 121,155
 123,775
 —
Total loans $8,993
 $2,711
 $13,798
 $25,502
 $4,415,487
 $4,440,989
 $—
 $7,371
 $4,811
 $13,917
 $26,099
 $4,595,969
 $4,622,068
 $—


40



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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
Real estate:  
  
  
  
Residential 1-4 family $19,987
 $19,253
 $21,056
 $20,554
Commercial real estate —
 5,112
 3,630
 1,188
Home equity line of credit 1,982
 1,087
 3,331
 2,254
Residential land 975
 720
 693
 970
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial 21,767
 10,053
 18,827
 20,174
Consumer 645
 661
 807
 895
Total nonaccrual loans $45,356
 $36,886
 $48,344
 $46,035
Real estate:        
Residential 1-4 family $—
 $—
 $—
 $—
Commercial real estate —
 —
 —
 —
Home equity line of credit —
 —
 —
 —
Residential land —
 —
 —
 —
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial —
 —
 —
 —
Consumer —
 —
 —
 —
Total accruing loans 90 days or more past due $—
 $—
 $—
 $—
Real estate:        
Residential 1-4 family $14,182
 $13,525
 $13,450
 $13,962
Commercial real estate —
 —
 —
 —
Home equity line of credit 2,297
 480
 3,400
 2,467
Residential land 4,735
 7,130
 3,760
 4,713
Commercial construction —
 —
 —
 —
Residential construction —
 —
 —
 —
Commercial 1,212
 2,972
 5,420
 1,104
Consumer —
 —
 —
 —
Total troubled debt restructured loans not included above $22,426
 $24,107
 $26,030
 $22,246


41



The total carrying amount and the total unpaid principal balance of impaired loans were as follows:
 September 30, 2015 Three months ended 
 September 30, 2015		 Nine months ended 
 September 30, 2015		 June 30, 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*
 
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 $11,125
 $12,476
 $—
 $11,159
 $119
 $11,301
 $274
 $10,262
 $11,381
 $—
 $10,672
 $152
 $10,532
 $203
Commercial real estate —
 —
 —
 —
 74
 362
 74
 1,144
 1,422
 —
 1,152
 —
 1,163
 —
Home equity line of credit 507
 744
 —
 498
 1
 444
 3
 1,020
 1,288
 —
 1,038
 9
 943
 9
Residential land 1,652
 2,421
 —
 2,280
 29
 2,647
 125
 1,482
 2,178
 —
 1,484
 15
 1,537
 31
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 3,152
 4,765
 —
 4,250
 3
 5,659
 144
 15,430
 16,776
 —
 8,369
 7
 5,818
 13
Consumer —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 $16,436
 $20,406
 $—
 $18,187
 $226
 $20,413
 $620
 $29,338
 $33,045
 $—
 $22,715
 $183
 $19,993
 $256
With an allowance recorded  
  
  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $11,435
 $11,488
 $1,388
 $11,451
 $174
 $11,585
 $430
 $12,017
 $12,220
 $1,709
 $11,982
 $115
 $12,000
 $237
Commercial real estate —
 —
 —
 —
 —
 1,985
 —
 2,486
 2,526
 172
 2,519
 —
 1,686
 —
Home equity line of credit 2,402
 2,464
 469
 2,048
 13
 1,295
 27
 3,626
 3,699
 826
 3,299
 28
 3,122
 55
Residential land 4,058
 4,136
 919
 3,971
 74
 4,435
 241
 2,971
 2,971
 819
 2,977
 54
 3,177
 121
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 19,701
 21,976
 3,084
 18,487
 106
 10,942
 192
 8,723
 8,904
 2,647
 16,821
 180
 16,896
 210
Consumer 14
 14
 7
 14
 —
 15
 —
 12
 12
 7
 12
 —
 12
 —
 $37,610
 $40,078
 $5,867
 $35,971
 $367
 $30,257
 $890
 $29,835
 $30,332
 $6,180
 $37,610
 $377
 $36,893
 $623
Total  
  
  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $22,560
 $23,964
 $1,388
 $22,610
 $293
 $22,886
 $704
 $22,279
 $23,601
 $1,709
 $22,654
 $267
 $22,532
 $440
Commercial real estate —
 —
 —
 —
 74
 2,347
 74
 3,630
 3,948
 172
 3,671
 —
 2,849
 —
Home equity line of credit 2,909
 3,208
 469
 2,546
 14
 1,739
 30
 4,646
 4,987
 826
 4,337
 37
 4,065
 64
Residential land 5,710
 6,557
 919
 6,251
 103
 7,082
 366
 4,453
 5,149
 819
 4,461
 69
 4,714
 152
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 22,853
 26,741
 3,084
 22,737
 109
 16,601
 336
 24,153
 25,680
 2,647
 25,190
 187
 22,714
 223
Consumer 14
 14
 7
 14
 —
 15
 —
 12
 12
 7
 12
 —
 12
 —
 $54,046
 $60,484
 $5,867
 $54,158
 $593
 $50,670
 $1,510
 $59,173
 $63,377
 $6,180
 $60,325
 $560
 $56,886
 $879


42



 December 31, 2014 Year ended December 31, 2014 December 31, 2015 Three months ended June 30, 2015 Six months ended June 30, 2015
(in thousands) 
Recorded
investment
 
Unpaid
principal
balance
 
Related
allowance
 
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 $11,654
 $12,987
 $—
 $9,056
 $227
 $10,596
 $11,805
 $—
 $11,193
 $66
 $11,373
 $155
Commercial real estate 571
 626
 —
 194
 —
 1,188
 1,436
 —
 530
 —
 543
 —
Home equity line of credit 363
 606
 —
 402
 5
 707
 948
 —
 433
 1
 417
 2
Residential land 2,344
 3,200
 —
 2,728
 172
 1,644
 2,412
 —
 3,026
 44
 2,831
 96
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 8,235
 11,471
 —
 5,204
 38
 5,671
 6,333
 —
 5,432
 139
 6,363
 141
Consumer —
 —
 —
 8
 —
 —
 —
 —
 —
 —
 —
 —
 $23,167
 $28,890
 $—
 $17,592
 $442
 $19,806
 $22,934
 $—
 $20,614
 $250
 $21,527
 $394
With an allowance recorded  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $11,327
 $11,347
 $951
 $8,822
 $419
 $11,861
 $11,914
 $1,453
 $11,794
 $130
 $11,651
 $256
Commercial real estate 4,541
 4,541
 1,845
 3,415
 478
 —
 —
 —
 1,474
 —
 2,978
 —
Home equity line of credit 416
 420
 46
 132
 6
 2,518
 2,579
 442
 1,212
 8
 919
 14
Residential land 5,506
 5,584
 1,057
 6,415
 484
 4,039
 4,117
 891
 4,142
 84
 4,666
 167
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 4,873
 5,211
 760
 12,089
 438
 15,448
 16,073
 3,527
 9,358
 36
 7,170
 86
Consumer 16
 16
 6
 9
 —
 13
 13
 7
 15
 —
 15
 —
 $26,679
 $27,119
 $4,665
 $30,882
 $1,825
 $33,879
 $34,696
 $6,320
 $27,995
 $258
 $27,399
 $523
Total  
  
  
  
  
  
  
  
  
  
  
  
Real estate:  
  
  
  
  
  
  
  
  
  
  
  
Residential 1-4 family $22,981
 $24,334
 $951
 $17,878
 $646
 $22,457
 $23,719
 $1,453
 $22,987
 $196
 $23,024
 $411
Commercial real estate 5,112
 5,167
 1,845
 3,609
 478
 1,188
 1,436
 —
 2,004
 —
 3,521
 —
Home equity line of credit 779
 1,026
��46
 534
 11
 3,225
 3,527
 442
 1,645
 9
 1,336
 16
Residential land 7,850
 8,784
 1,057
 9,143
 656
 5,683
 6,529
 891
 7,168
 128
 7,497
 263
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 13,108
 16,682
 760
 17,293
 476
 21,119
 22,406
 3,527
 14,790
 175
 13,533
 227
Consumer 16
 16
 6
 17
 —
 13
 13
 7
 15
 —
 15
 —
 $49,846
 $56,009
 $4,665
 $48,474
 $2,267
 $53,685
 $57,630
 $6,320
 $48,609
 $508
 $48,926
 $917
 
*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 collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.
ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period and temporary deferral ofor

43



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 and the impact on the allowance for loan losses were as follows:
 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



 Three months ended September 30, 2014 Nine months ended September 30, 2014 Three months ended June 30, 2015 Six months ended June 30, 2015
 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 6
 $1,800
 $1,825
 $43
 18
 $4,915
 $4,972
 $294
 2
 $318
 $318
 $—
 7
 $1,195
 $1,213
 $47
Commercial real estate —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Home equity line of credit 1
 91
 91
 —
 1
 91
 91
 —
 13
 690
 690
 105
 22
 1,119
 1,119
 160
Residential land 2
 256
 256
 —
 18
 4,304
 4,304
 400
 —
 —
 —
 —
 —
 —
 —
 —
Commercial construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Residential construction —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Commercial 2
 2,600
 2,600
 —
 7
 3,827
 3,827
 14
 3
 161
 161
 78
 4
 253
 253
 78
Consumer —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 11
 $4,747
 $4,772
 $43
 44
 $13,137
 $13,194
 $708
 18
 $1,169
 $1,169
 $183
 33
 $2,567
 $2,585
 $285
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.

44


Loans modified in TDRs that experienced a payment default of 90 days or more in for the indicated periods, and for which the payment of default occurred within one year of the modification, were as follows:
 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 loans:    
    
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 loans — —
 — —
Consumer loans — —
 — —
Commercial 1 26
 1 26
Consumer — —
 — —
 1 $7
 1 $7
 1 $26
 2 $514
 
Three months ended September 30, 2014
Nine months ended September 30, 2014
(dollars in thousands)
Number of contracts
Recorded investment
Number of contracts
Recorded investment
Troubled debt restructurings that
 subsequently defaulted
 
 
 
 
Real estate loans:
 
 

 
 
Residential 1-4 family
—
$—

1
$390
Commercial real estate
—
—

—
—
Home equity line of credit
—
—

—
—
Residential land
—
—

—
—
Commercial construction
—
—

—
—
Residential construction
—
—

—
—
Commercial loans
—
—

—
—
Consumer loans
—
—

—
—
 
—
$—

1
$390
There were no loans modified in TDRs that experienced a payment default of 90 days or more in the second quarter of 2015 and six months ended June 30, 2015, and for which the payment of default occurred within one year of the modification.
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 impaired or modified in TDRsa TDR totaled $0.1$2.7 million at SeptemberJune 30, 20152016.
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 sales, but may retainloans other than the servicing rights of thecertain loans sold.


ASB received proceeds from the sale of residential mortgages of $58.1 million and $95.0 million for the three months ended June 30, 2016 and 2015 and $98.5 million and $173.3 million for the six months ended June 30, 2016 and 2015, respectively, and recognized gains on such sales of $1.5 million and $2.1 million for the three months ended June 30, 2016 and 2015 and $2.7 million and $3.9 million for the six months ended June 30, 2016 and 2015 respectively.
There were no repurchased mortgage loans for the three months ended June 30, 2016 and 2015 and six months ended June 30, 2016 and 2015. The repurchase reserve was $0.1 million and nil for the period ended June 30, 2016 and 2015, respectively.
Mortgage servicing fees, a component of other income, net, were $0.7 million and $0.9 million for the three months ended SeptemberJune 30, 2016 and 2015 and 2014 and $2.7$1.4 million and $2.6$1.8 million for the ninesix months ended SeptemberJune 30, 20152016 and 2014,2015, respectively.
TheChanges in the carrying valuesvalue of mortgage servicing assetsrights were as follows:
(in thousands) Gross
carrying amount		 Accumulated amortization Valuation allowance Net
carrying amount
September 30, 2015 $29,818
 $(17,560) $—
 $12,258
September 30, 2014 26,685
 (15,003) (158) 11,524
(in thousands) 
Gross
carrying amount1
 
Accumulated amortization1
 Valuation allowance Net
carrying amount
June 30, 2016 $15,652
 $(6,636) $—
 $9,016
December 31, 2015 14,531
 (5,647) —
 8,884

451 Reflects the impact of loans paid in full.


Changes related to mortgage servicing rights were as follows:
(in thousands)2015
 2014
2016
 2015
Mortgage servicing rights      
Balance, January 1$11,749
 $11,938
$8,884
 $11,749
Amount capitalized2,636
 1,098
1,120
 2,001
Amortization(2,123) (1,297)(988) (1,444)
Other-than-temporary impairment(4) (57)—
 (4)
Carrying amount before valuation allowance, September 3012,258
 11,682
Carrying amount before valuation allowance, June 309,016
 12,302
Valuation allowance for mortgage servicing rights      
Balance, January 1209
 251
—
 209
Provision (recovery)(205) (36)—
 (168)
Other-than-temporary impairment(4) (57)—
 (4)
Balance, September 30—
 158
Balance, June 30—
 37
Net carrying value of mortgage servicing rights$12,258
 $11,524
$9,016
 $12,265
ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale with servicing rights retained. On a monthly basis, ASB compares the net carrying value of the mortgage servicing rights to its fair value to determine if there are any changes to the valuation allowance and/or other-than-temporary impairment for the mortgage servicing rights. ASB’s MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15 and 30 year mortgages and note rate in bands of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others, which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing rights and increase the amortization of the mortgage servicing rights. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others.
ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in other income, net in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.


Key assumptions used in estimating the fair value of the bank’sASB’s mortgage servicing rights used in the impairment analysis were as follows:
(dollars in thousands) September 30, 2015
 December 31, 2014
 June 30, 2016
 December 31, 2015
Unpaid principal balance $1,503,369
 $1,391,030
 $1,137,226
 $1,097,314
Weighted average note rate 4.01% 4.07% 4.03% 4.05%
Weighted average discount rate 9.5% 9.6% 9.4% 9.6%
Weighted average prepayment speed 9.9% 9.5% 11.4% 9.3%
The sensitivity analysis of fair value of MSR to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions iswas as follows:
(dollars in thousands) September 30, 2015
 December 31, 2014
 June 30, 2016
 December 31, 2015
Prepayment rate:        
25 basis points adverse rate change $(832) $(757) $(567) $(561)
50 basis points adverse rate change (1,643) (1,524) (1,037) (1,104)
Discount rate:        
25 basis points adverse rate change (148) (140) (97) (111)
50 basis points adverse rate change (293) (278) (192) (220)

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

In October 2015, ASB entered into an agreement to sell certain MSRs for approximately 1,500 underlying fully amortizing, conventional residential mortgage loans with an unpaid principal balance of $419 million, subject to FNMA approval.
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 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

46


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, 2015 $269 $— $269
December 31, 2014 191 — 191
June 30, 2016 $173 $— $173
December 31, 2015 229 — 229
 Gross amount not offset in the Balance Sheet Gross amount not offset in the Balance Sheet
(in millions) 
Net amount of 
liabilities presented
in the Balance Sheet
 
Financial
instruments
 
Cash
collateral
pledged
 Net amount 
 
Liabilities presented
in the Balance Sheet
 
Financial
instruments
 
Cash
collateral
pledged
September 30, 2015  
  
  
  
June 30, 2016  
  
  
Financial institution $50
 $50
 $—
 $—
 $50
 $57
 $—
Government entities 66
 66
 —
 —
 27
 42
 —
Commercial account holders 153
 153
 —
 —
 96
 117
 —
Total $269
 $269
 $—
 $—
 $173
 $216
 $—
        
December 31, 2014  
  
  
  
December 31, 2015  
  
  
Financial institution $50
 $50
 $—
 $—
 $50
 $56
 $—
Government entities 56
 56
 —
 —
 56
 61
 —
Commercial account holders 85
 85
 —
 —
 123
 144
 —
Total $191
 $191
 $—
 $—
 $229
 $261
 $—
The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts or into segregated tri-party custodial accounts at the FHLB. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as


liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.
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 risk 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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
(in thousands) Notional amount Fair value Notional amount Fair value Notional amount Fair value Notional amount Fair value
Interest rate lock commitments $27,587
 $585
 $29,330
 $390
 $34,277
 $795
 $22,241
 $384
Forward commitments 24,706
 (124) 32,833
 (106) 31,228
 (266) 23,644
 (29)

47


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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
(in thousands)  Asset derivatives 
 Liability
derivatives
  Asset derivatives  Liability
derivatives		  Asset derivatives 
 Liability
derivatives
  Asset derivatives  Liability
derivatives
Interest rate lock commitments $585
 $—
 $393
 $3
 $795
 $—
 $384
 $—
Forward commitments 1
 125
 5
 111
 4
 270
 1
 30
 $586
 $125
 $398
 $114
 $799
 $270
 $385
 $30
1 Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.
The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in the statements of income:
Derivative Financial Instruments Not 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) 2015 2014 2015 2014 2016 2015 2016 2015
Interest rate lock commitmentsMortgage banking income $139
 $215
 $195
 $(249)Mortgage banking income $140
 $(389) $411
 $56
Forward commitmentsMortgage banking income (117) (25) (18) (164)Mortgage banking income (74) 258
 (237) 99
 $22
 $190
 $177
 $(413) $66
 $(131) $174
 $155
Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $9.2$10.0 million and $14.8$10.1 million at SeptemberJune 30, 20152016 and December 31, 2014,2015, 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, 2015,2016, 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.  In March 2011, a purported class action lawsuit was filedASB is subject in the First Circuit Courtnormal course of business to pending and threatened legal proceedings. Management does not anticipate that the stateaggregate ultimate liability arising out of Hawaii bythese 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 customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. ASB filed a motion to dismiss the lawsuitmaterial adverse effect on the basis that ASB’s overdraft practices are governed by federal regulations established for federal savings banks which preempt the customer’s state law claims. In July 2011, the Circuit Court denied ASB's motion without prejudice and ASB appealed that decision. ASB's appeal is pending before the Hawaii Supreme Court. However, in December 2014, through a voluntary mediation process, ASB reached a tentative settlementresults of the claims. The tentative settlement, which received final court approval on May 21, 2015, providedoperations or liquidity for a payment of $2.0 million into a class settlement fund,particular reporting period in the proceeds of which would be used to refund class members and pay attorneys’ fees and administrative and other costs, in exchange for a complete release of all claims asserted against ASB. The $2.0 million settlement amount was fully reserved by ASB in December 2014 and paid into the settlement fund in January 2015.future.
6 · Retirement benefits
Defined benefit pension and other postretirement benefit plans information.  For the first ninesix months of 20152016, the Company contributed $6633 million ($6532 million by the Utilities) to its pension and other postretirement benefit plans, compared to $4544 million ($4443 million by the Utilities) in the first ninesix months of 2014.2015. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 20152016 is $88$65 million ($8664 million by the Utilities, $2$1 million by HEI and nil by ASB), compared to $6088 million ($5986 million by the Utilities, $12 million by HEI and nil by ASB) in 20142015. In addition, the Company expects to pay directly $2 million ($1 million by the Utilities) of benefits in 20152016, compared to $21 million ($10.4 million by the Utilities) paid in 20142015.
The Pension Protection Act of 2006 (Pension Protection Act) signed into law on August 17, 2006, amended the Employee Retirement Income Security Act of 1974 (ERISA).  Among other things, the Pension Protection Act changed the funding rules for qualified pension plans. On August 8, 2014, President Obama signed the latest change to the Pension Protection Act, the Highway and Transportation Funding Act of 2014 (HATFA). HATFA resulted in an increase of the Adjusted Funding Target Attainment Percentage (AFTAP) for benefit distribution purposes and eased funding requirements effective with the 2014 plan year (a plan sponsor could have elected to apply the provisions of HATFA to 2013, but the Company did not so elect). As a result, the minimum funding requirements for the HEI Retirement Plan under ERISA are less than the net periodic cost for 2014 and 2015. To satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities contributed the net periodic cost in 2014 and expect to contribute the net periodic cost in 2015.
The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan. The HEI Retirement Plan met the threshold

48


requirements in each of 2013, 2014 and 2015 so that the more conservative assumptions did not apply for either 2014 or 2015 and will not apply for 2016. Other factors could cause changes to the required contribution levels.
The components of net periodic benefit cost 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) 2015 2014 2015 2014 2015 2014 2015 2014 2016 2015 2016 2015 2016 2015 2016 2015
HEI consolidated                                
Service cost $16,577
 $12,306
 $982
 $870
 $49,683
 $36,958
 $2,945
 $2,619
 $14,913
 $16,640
 $832
 $1,094
 $30,304
 $33,106
 $1,668
 $1,963
Interest cost 19,229
 18,044
 2,254
 2,137
 57,731
 54,158
 6,757
 6,414
 20,481
 19,363
 2,363
 2,268
 40,758
 38,502
 4,837
 4,503
Expected return on plan assets (22,126) (20,337) (2,912) (2,724) (66,426) (61,018) (8,753) (8,180) (24,616) (22,149) (3,091) (2,934) (49,280) (44,300) (6,143) (5,841)
Amortization of net prior service loss (gain) 1
 22
 (448) (448) 3
 66
 (1,345) (1,345) (14) 1
 (448) (449) (28) 2
 (896) (897)
Amortization of net actuarial loss (gain) 9,191
 5,064
 450
 (2) 27,608
 15,240
 1,346
 (8)
Net periodic benefit cost (credit) 22,872
 15,099
 326
 (167) 68,599
 45,404
 950
 (500)
Amortization of net actuarial loss 6,408
 9,455
 116
 466
 12,377
 18,417
 403
 896
Net periodic benefit cost 17,172
 23,310
 (228) 445
 34,131
 45,727
 (131) 624
Impact of PUC D&Os (10,017) (3,331) (60) 494
 (29,994) (9,993) (180) 1,482
 (4,765) (10,464) 483
 (218) (8,811) (19,977) 672
 (120)
Net periodic benefit cost (adjusted for impact of PUC D&Os) $12,855
 $11,768
 $266
 $327
 $38,605
 $35,411
 $770
 $982
 $12,407
 $12,846
 $255
 $227
 $25,320
 $25,750
 $541
 $504
Hawaiian Electric consolidated                                
Service cost $16,066
 $11,900
 $967
 $848
 $48,197
 $35,698
 $2,902
 $2,544
 $14,465
 $16,148
 $820
 $1,080
 $29,398
 $32,131
 $1,642
 $1,935
Interest cost 17,632
 16,495
 2,175
 2,058
 52,897
 49,484
 6,525
 6,175
 18,801
 17,749
 2,280
 2,191
 37,404
 35,265
 4,669
 4,350
Expected return on plan assets (20,635) (18,167) (2,873) (2,684) (61,906) (54,496) (8,621) (8,054) (22,885) (20,639) (3,046) (2,889) (45,817) (41,271) (6,049) (5,748)
Amortization of net prior service loss (gain) 10
 15
 (450) (451) 30
 46
 (1,352) (1,353) 3
 10
 (451) (451) 7
 20
 (902) (902)
Amortization of net actuarial loss 8,342
 4,616
 438
 —
 25,028
 13,845
 1,315
 —
 5,885
 8,592
 113
 455
 11,346
 16,686
 397
 877
Net periodic benefit cost (credit) 21,415
 14,859
 257
 (229) 64,246
 44,577
 769
 (688)
Net periodic benefit cost 16,269
 21,860
 (284) 386
 32,338
 42,831
 (243) 512
Impact of PUC D&Os (10,017) (3,331) (60) 494
 (29,994) (9,993) (180) 1,482
 (4,765) (10,464) 483
 (218) (8,811) (19,977) 672
 (120)
Net periodic benefit cost (adjusted for impact of PUC D&Os) $11,398
 $11,528
 $197
 $265
 $34,252
 $34,584
 $589
 $794
 $11,504
 $11,396
 $199
 $168
 $23,527
 $22,854
 $429
 $392
HEI consolidated recorded retirement benefits expense of $2718 million ($2216 million by the Utilities) and $2418 million ($2315 million by the Utilities) in the first ninesix months of 20152016 and 2014,2015, 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 20152016 and 2014,2015, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan


was $4.02.8 million and $3.42.7 million, respectively, and cash contributions were $4.33.7 million and $4.23.4 million, respectively. For the first ninesix months of 20152016 and 2014,2015, the Utilities’ expense for its defined contribution pension plan under the HEIRSP was $1.1$0.8 million and $0.7 million, respectively, and cash contributions were $1.1$0.8 million and $0.7 million, respectively.

49


7 · 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, 20152016, approximately 3.53.4 million shares remained available for future issuance under the terms of the EIP, (assumingassuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards),awards, including an estimated 0.70.4 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, 20152016, there were 141,044 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) 2015 2014 2015 2014 2016 2015 2016 2015
HEI consolidated                
Share-based compensation expense 1
 $1.0
 $2.0
 $4.8
 $7.2
 $1.0
 $2.0
 $2.0
 $3.8
Income tax benefit 0.3
 0.7
 1.7
 2.6
 0.4
 0.7
 0.7
 1.4
Hawaiian Electric consolidated                
Share-based compensation expense 1
 0.1
 0.6
 1.3
 2.2
 0.3
 0.7
 0.6
 1.2
Income tax benefit —
 0.2
 0.5
 0.9
 0.1
 0.3
 0.2
 0.5
1 
$0.03For the three and six months ended June 30, 2016, the Company has not capitalized any share-based compensation. $0.05 million and $0.04$0.09 million of this share-based compensation expense was capitalized in the third quarter of 2015three and 2014, respectively. $0.12 million and $0.12 million of this share-based compensation expense was capitalized in the ninesix months ended SeptemberJune 30, 2015 and 2014, respectively.2015.

Stock awards. No nonemployee director stock grants were awarded from January 1 to August 4, 2016. Nonemployee director awards totaling $0.2 million were paid in cash in July 2016. In 2015, HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:
Nine months ended September 30 Six months ended June 30
($ in millions)2015 2014 2016 2015
Shares granted28,246
 33,170
 —
 28,246
Fair value$0.8
 $0.8
 $—
 $0.8
Income tax benefit0.3
 0.3
 —
 0.3
The number of shares issued to each nonemployee director of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI Common Stock on the grant date.


Stock appreciation rights.  As of June 30, 2016 and December 31, 2014, the shares underlying SARs outstanding totaled 80,000, with a weighted-average exercise price of $26.18. As of September 30, 2015, there were no remaining SARs outstanding.
SARs activity and statistics were as follows:
Three months ended September 30 Nine months ended September 30Three months ended June 30 Six months ended June 30
(dollars in thousands, except prices)2015 2014 2015 20142015 2015
Shares underlying SARs exercised—
 —
 80,000
 —
—
 80,000
Weighted-average price of shares exercised$—
 $—
 $26.18
 $—
$—
 $26.18
Intrinsic value of shares exercised 1
—
 —
 502
 —
—
 502
Tax benefit realized for the deduction of exercises—
 —
 82
 —
—
 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.

50



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
2015 2014 2015 20142016 2015 2016 2015
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period252,302
 $28.35
 264,326
 $25.74
 261,235
 $25.77
 288,151
 $25.17
226,537
 $29.59
 261,691
 $28.33
 210,634
 $28.82
 261,235
 $25.77
Granted690

30.91
 2,750
 24.48
 85,772

33.69
 117,786

25.17
—

—
 788
 31.25
 94,282

29.90
 85,082

33.72
Vested(19,840) 25.35
 (3,500) 23.50
 (99,891) 25.69
 (142,361) 24.07
(785) 27.88
 (832) 26.60
 (79,164) 27.91
 (80,051) 25.77
Forfeited(14,316) 25.82
 —
 —
 (28,280) 26.66
 —
 —
—
 —
 (9,345) 28.36
 —
 —
 (13,964) 27.52
Outstanding, end of period218,836
 $28.79
 263,576
 $25.76
 218,836
 $28.79
 263,576
 $25.76
225,752
 $29.59
 252,302
 $28.35
 225,752
 $29.59
 252,302
 $28.35
Total weighted-average grant-date fair value of shares granted ($ millions)$—
   $0.1
   $2.9
   $3.0
  $—
   $—
   $2.8
   $2.9
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
As of SeptemberJune 30, 20152016, there was $4.75.5 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 2.62.8 years.
For the first ninesix months of 20152016 and 2014,2015, total restricted stock units that vested and related dividends had a fair value of $3.72.6 million and $4.13.0 million, respectively, and the related tax benefits were $1.10.9 million and $1.30.8 million, respectively.
Long-term incentive plan payable in stock.  The 2013-20152014-2016 long-term incentive plan (LTIP) and 2014-2016 LTIP provideprovides for performance awards under the original EIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods includeperiod includes awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2013-2015 LTIP and 2014-2016 LTIP havehas performance goals related to levels of HEI consolidated net income, HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated net income, Hawaiian Electric consolidated ROACE and ASB net income — all based on the applicable three-year averages, and ASB return on assets relative to performance peers. The 2015-2017 and the 2016-2018 LTIP providesprovide for performance awards payable in cash, and thus, isare not included in the tables below.
LTIP linked to TRS.  Information about HEI’s LTIP grants linked to TRS was as follows:
Three months ended September 30 Nine months ended September 30Three months ended June 30 Six months ended June 30
2015 2014 2015 20142016 2015 2016 2015
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period163,423
 $27.63
 257,956
 $28.45
 257,956
 $28.45
 232,127
 $32.88
83,947
 $22.95
 168,777
 $27.63
 162,500
 $27.66
 257,956
 $28.45
Granted (target level)—
 —
 —
 —
 —
 —
 97,524

22.95
—
 —
 —
 —
 —
 —
 —

—
Vested (issued or unissued and cancelled)—
 —
 —
 —
 (75,915) 30.71
 (70,189) 35.46
—
 —
 —
 —
 (78,553) 32.69
 (75,915) 30.71
Forfeited—
 —
 —
 —
 (18,618) 26.41
 (1,506) 28.32
—
 —
 (5,354) 27.42
 —
 —
 (18,618) 26.41
Outstanding, end of period163,423
 $27.63
 257,956
 $28.45
 163,423
 $27.63
 257,956
 $28.45
83,947
 $22.95
 163,423
 $27.63
 83,947
 $22.95
 163,423
 $27.63
Total weighted-average grant-date fair value of shares granted ($ millions)$—
   $—
   $—
   $2.2
  
(1)Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period.

51


The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:
 2014
Risk-free interest rate0.66%
Expected life in years3
Expected volatility17.8%
Range of expected volatility for Peer Group12.4% to 23.3%
Grant date fair value (per share)$22.95
 For the ninesix months ended SeptemberJune 30, 20152016 and 2014,2015, there were no vested LTIP awards linked to TRS. For the ninesix months ended SeptemberJune 30, 20152016, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 2012-20142013-2015 LTIP lapsed.
As of SeptemberJune 30, 20152016, there was $0.90.3 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 0.80.5 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
2015 2014 2015 20142016 2015 2016 2015
Shares (1) Shares (1) Shares (1) Shares (1)Shares (1) Shares (1) Shares (1) Shares (1)
Outstanding, beginning of period220,158
 $26.00
 359,782
 $26.01
 364,731
 $26.01
 296,843
 $26.14
113,550
 $25.18
 230,219
 $26.00
 222,647
 $26.02
 364,731
 $26.01
Granted (target level)—
 —
 —

—
 —
 —
 129,603

25.18
—
 —
 —

—
 —
 —
 —

—
Vested (issued)—
 —
 —
 —
 (121,249) 26.05
 (65,089) 24.95
—
 —
 —
 —
 (109,097) 26.89
 (121,249) 26.05
Cancelled(14,050) 26.89
 —
 —
 (14,050) 26.89
 —
 —
Forfeited—
 —
 —
 —
 (23,324) 25.85
 (1,575) 26.07
—
 —
 (10,061) 26.02
 —
 —
 (23,324) 25.85
Outstanding, end of period206,108
 $25.94
 359,782
 $26.01
 206,108
 $25.94
 359,782
 $26.01
113,550
 $25.18
 220,158
 $26.00
 113,550
 $25.18
 220,158
 $26.00
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)$—
   $—
   $—
   $3.3
  
(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For the ninesix months ended SeptemberJune 30, 20152016 and 2014,2015, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $4.73.6 million and $1.9$4.7 million and the related tax benefits were $1.81.4 million and $0.8$1.8 million, respectively.
As of SeptemberJune 30, 20152016, there was $1.40.5 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 0.80.5 years.
8 · Earnings per share and shareholders’Shareholders’ equity
Earnings per share. Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both participating securities (i.e., restricted shares that became fully vested in the fourth quarter of 2014) and unrestricted common stock:
 Three months ended September 30, 2014 Nine months ended September 30, 2014
 Basic Diluted Basic Diluted
Distributed earnings$0.31
 $0.31
 $0.93
 $0.93
Undistributed earnings0.16
 0.15
 0.40
 0.39
 $0.47
 $0.46
 $1.33
 $1.32
As of September 30, 2015, there were no remaining share awards that could have been potentially antidilutive. As of September 30, 2014, there were no shares that were antidilutive.

52


Shareholders’ equity.
Equity forward transaction.  On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering on that date of 6.1 million shares of HEI common stock at $26.75 per share. On March 19, 2013, HEI common stock closed at $27.01 per share. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with the resulting additional 0.9 million shares of HEI common stock.
The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans. Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of the equity forward transactions, HEI was required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward was subject to certain adjustments in accordance with the terms of the equity forward transactions.
The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in 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.  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 losses on derivatives  Retirement benefit plans AOCI  AOCI -retirement benefit plans
Balance, December 31, 2014$462
 $(289) $(27,551) $(27,378) $45
Current period other comprehensive income (loss)3,608
 177
 1,576
 5,361
 11
Balance, September 30, 2015$4,070
 $(112) $(25,975) $(22,017) $56
          
Balance, December 31, 2013$(3,663) $(525) $(12,562) $(16,750) $608
Current period other comprehensive income1,691
 177
 888
 2,756
 32
Balance, September 30, 2014$(1,972) $(348) $(11,674) $(13,994) $640
 HEI Consolidated Hawaiian Electric Consolidated
 (in thousands) Net unrealized gains (losses) on securities  Unrealized gains (losses) on derivatives  Retirement benefit plans AOCI  Unrealized gains on derivatives Retirement benefit plans AOCI
Balance, December 31, 2015$(1,872) $(54) $(24,336) $(26,262) $—
 $925
 $925
Current period other comprehensive income9,984
 311
 613
 10,908
 257
 4
 261
Balance, June 30, 2016$8,112
 $257
 $(23,723) $(15,354) $257
 $939
 $1,186
Balance, December 31, 2014$462
 $(289) $(27,551) $(27,378) $—
 $45
 $45
Current period other comprehensive income(243) 118
 1,056
 931
 —
 7
 7
Balance, June 30, 2015$219
 $(171) $(26,495) $(26,447) $—
 $52
 $52

53


Reclassifications out of AOCI were as follows:
 Amount reclassified from AOCI   Amount reclassified from AOCI  
 Three months ended 
 September 30		 Nine months  
 ended September 30		   Three months ended June 30 Six months ended June 30 Affected line item in the
(in thousands) 2015 2014 2015 2014 Affected line item in the Statement of Income 2016 2015 2016 2015  Statement of Income
HEI consolidated                  
Net realized gains on securities $—
 $—
 $—
 $(1,715) Revenues-bank (net gains on sales of securities) $(360) $—
 $(360) $—
 Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges  
  
  
  
    
  
  
  
  
Interest rate contracts (settled in 2011) 59
 59
 177
 177
 Interest expense —
 59
 54
 118
 Interest expense
Retirement benefit plan items  
  
  
  
    
  
  
  
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost 5,611
 2,829
 16,850
 8,515
 See Note 6 for additional details 3,698
 5,780
 7,236
 11,239
 See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets (5,091) (2,542) (15,274) (7,627) See Note 6 for additional details (3,401) (5,272) (6,623) (10,183) See Note 6 for additional details
Total reclassifications $579
 $346
 $1,753
 $(650)   $(63) $567
 $307
 $1,174
  
Hawaiian Electric consolidated                  
Retirement benefit plan items    
    
      
    
  
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost $5,095
 $2,552
 $15,285
 $7,659
 See Note 6 for additional details $3,391
 $5,257
 $6,627
 $10,190
 See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets (5,091) (2,542) (15,274) (7,627) See Note 6 for additional details (3,401) (5,272) (6,623) (10,183) See Note 6 for additional details
Total reclassifications $4
 $10
 $11
 $32
   $(10) $(15) $4
 $7
  

9 · 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

54


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, goodwill and AROs. The fair value of Hawaiian Electric’s ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by Hawaiian Electric’s credit spread (also see Note 4).
Fair value measurement and disclosure valuation methodology. 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 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 Company 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’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.
Loans held for sale. Residential mortgage loans 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.
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 real estate owned. Foreclosed assets are carried at fair value (less estimated costs to sell) and is generally based upon appraisals or independent market prices that are periodically updated subsequent to classification as real estate owned.

55


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) 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 is 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" 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 MSR 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.sources, including broker market transactions and third party pricing services.
Long-term debtdebt—other than bank.  Fair value 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.

56Window forward contract. The estimated fair value was obtained from a third-party financial services provider based on the effective exchange rate offered for the foreign currency denominated transaction. Window forward contracts are classified as Level 2 measurements.




The following table presents the carrying or notional amount, fair value, and placement in the fair value hierarchy of the Company’s financial instruments. For stock in Federal Home Loan Bank, the carrying amount is a reasonable estimate of fair value because it can only be redeemed at par. For bank-owned life insurance, the carrying amount is the cash surrender value of the insurance policies, which is a reasonable estimate of fair value. For financial liabilities such as noninterest-bearing demand, interest-bearing demand, and savings and money market deposits, the carrying amount is a reasonable estimate of fair value as these liabilities have no stated maturity.
   Estimated fair value   Estimated fair value
 Carrying 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, 2015  
  
  
  
  
June 30, 2016  
  
  
  
  
Financial assets  
  
  
  
  
  
  
  
  
  
Money market funds $10
 $—
 $10
 $—
 $10
 $10
 $—
 $10
 $—
 $10
Available-for-sale investment securities 785,837
 —
 785,837
 —
 785,837
 894,021
 —
 894,021
 —
 894,021
Stock in Federal Home Loan Bank 10,678
 —
 10,678
 —
 10,678
 11,218
 —
 11,218
 —
 11,218
Loans receivable, net 4,492,728
 —
 —
 4,700,042
 4,700,042
 4,705,840
 —
 6,242
 4,933,935
 4,940,177
Mortgage servicing rights 9,016
 —
 —
 11,224
 11,224
Bank-owned life insurance 140,176
 —
 140,176
 —
 140,176
Derivative assets 586
 —
 586
 —
 586
 55,879
 —
 1,219
 —
 1,219
The Utilities’ derivative assets (included in amount above) 20,637
 —
 420
 —
 420
Financial liabilities  
  
  
  
    
  
  
  
  
Deposit liabilities 4,825,954
 —
 4,828,402
 —
 4,828,402
 5,232,203
 —
 5,238,391
 —
 5,238,391
Short-term borrowings—other than bank 171,992
 —
 171,992
 —
 171,992
 115,985
 —
 115,985
 —
 115,985
The Utilities’ short-term borrowings (included in amount above) 94,995
 —
 94,995
 —
 94,995
 36,995
 —
 36,995
 —
 36,995
Other bank borrowings 368,593
 —
 375,428
 —
 375,428
 272,887
 —
 276,709
 —
 276,709
Long-term debt, net—other than bank 1,506,546
 —
 1,595,161
 —
 1,595,161
 1,578,842
 —
 1,749,242
 —
 1,749,242
The Utilities’ long-term debt, net (included in amount above) 1,206,546
 —
 1,288,112
 —
 1,288,112
 1,279,123
 —
 1,441,061
 —
 1,441,061
Derivative liabilities 125
 112
 13
 —
 125
 30,263
 211
 59
 —
 270
December 31, 2014  
  
  
  
  
December 31, 2015  
  
  
  
  
Financial assets  
  
  
  
  
  
  
  
  
  
Money market funds $10
 $—
 $10
 $—
 $10
 $10
 $—
 $10
 $—
 $10
Available-for-sale investment securities 550,394
 —
 550,394
 —
 550,394
 820,648
 —
 820,648
 —
 820,648
Stock in Federal Home Loan Bank 69,302
 —
 69,302
 —
 69,302
 10,678
 —
 10,678
 —
 10,678
Loans receivable, net 4,397,457
 —
 —
 4,578,822
 4,578,822
 4,570,412
 —
 4,639
 4,744,886
 4,749,525
Mortgage servicing rights 8,884
 —
 —
 11,790
 11,790
Bank-owned life insurance 138,139
 —
 138,139
 —
 138,139
Derivative assets 398
 —
 398
 —
 398
 22,616
 —
 385
 —
 385
Financial liabilities  
  
  
  
    
  
  
  
  
Deposit liabilities 4,623,415
 —
 4,623,773
 —
 4,623,773
 5,025,254
 —
 5,024,500
 —
 5,024,500
Short-term borrowings—other than bank 118,972
 —
 118,972
 —
 118,972
 103,063
 —
 103,063
 —
 103,063
Other bank borrowings 290,656
 —
 298,837
 —
 298,837
 328,582
 —
 333,392
 —
 333,392
Long-term debt, net—other than bank 1,506,546
 —
 1,622,736
 —
 1,622,736
The Utilities’ long-term debt, net (included in amount above) 1,206,546
 —
 1,313,893
 —
 1,313,893
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
Derivative liabilities 114
 71
 43
 —
 114
 23,269
 15
 15
 —
 30
As of September 30, 2015 and December 31, 2014, loans serviced by ASB* See Note 11 for others had notional amounts of $1.6 billion and $1.4 billion, and the estimated fair valueimpact to prior period financial information of the mortgage servicing rights for such loans was $16.0 million and $14.5 million, respectively. adoption of ASU No. 2015-03.

57



Fair value measurements on a recurring basis.  Assets and liabilities measured at fair value on a recurring basis were as follows:
 September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015
 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) $—
 $10
 $—
 $—
 $10
 $—
 $—
 $10
 $—
 $—
 $10
 $—
Available-for-sale investment securities (bank segment)  
  
  
  
  
  
  
  
  
  
  
  
Mortgage-related securities-FNMA, FHLMC and GNMA $—
 $574,719
 $—
 $—
 $430,834
 $—
 $—
 $695,862
 $—
 $—
 $607,689
 $—
U.S. Treasury and federal agency obligations —
 211,118
 —
 —
 119,560
 —
 —
 198,159
 —
 —
 212,959
 —
 $—
 $785,837
 $—
 $—
 $550,394
 $—
 $—
 $894,021
 $—
 $—
 $820,648
 $—
Derivative assets 1
  
  
  
  
  
  
Interest rate lock commitments $—
 $585
 $—
 $—
 $393
 $—
Forward commitments —
 1
 —
 —
 5
 —
Derivative assets  
  
  
  
  
  
Interest rate lock commitments 1
 $—
 $795
 $—
 $—
 $384
 $—
Forward commitments 1
 —
 4
 —
 —
 1
 —
Window forward contract 2
 —
 420
 —
 —
 —
 —
 $—
 $586
 $—
 $—
 $398
 $—
 $—
 $1,219
 $—
 $—
 $385
 $—
Derivative liabilities 1
                        
Interest rate lock commitments $—
 $—
 $—
 $—
 $3
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Forward commitments 112
 13
 —
 71
 40
 —
 211
 59
 —
 15
 15
 —
 $112
 $13
 $—
 $71
 $43
 $—
 $211
 $59
 $—
 $15
 $15
 $—
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 derivatives are included in other current assets 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 quarter ended SeptemberJune 30, 2015.2016.
 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. AssetsThe 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, 2015        
June 30, 2016        
Loans $951
 $—
 $—
 $951
 $313
 $—
 $—
 $313
Real estate acquired in settlement of loans 70
 —
 —
 70
 446
 —
 —
 446
December 31, 2014        
December 31, 2015        
Loans 2,445
 —
 —
 2,445
 178
 —
 —
 178
Real estate acquired in settlement of loans 288
 —
 —
 288
 1,030
 —
 —
 1,030
 At SeptemberJune 30, 20152016 and 2014,2015, there were no adjustments to fair value for ASB’s loans held for sale.sale which were carried at the lower of cost or fair value.

58



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, 2015   
June 30, 2016   
Residential loans $313
 Fair value of property or collateral Appraised value less 7% selling costs 42-94% 78%
Real estate acquired in settlement of loans $446
 Fair value of property or collateral Appraised value less 7% selling costs 100% 100%
   
December 31, 2015   
Residential loans $823
 Fair value of property or collateral Appraised value less 7% selling costs 31-91% 70% $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 52% 128
 Fair value of property or collateral Appraised value less 7% selling costs N/A (2)
Total loans $951
        $178
       
Real estate acquired in settlement of loans $70
 Fair value of property or collateral Appraised value less 7% selling costs 100% 100% $1,030
 Fair value of property or collateral Appraised value less 7% selling cost 100% 100%
   
December 31, 2014   
Residential loans $2,297
 Fair value of property or collateral Appraised value less 7% selling costs 39-99% 83%
Home equity lines of credit 3
 Fair value of property or collateral Appraised value less 7% selling costs 7%
Commercial loans 145
 Fair value of property or collateral Fair value of business assets 91%
Total loans $2,445
       
Real estate acquired in settlement of loans $288
 Fair value of property or collateral Appraised value less 7% selling cost 100% 100%
1(1) Represent percent of outstanding principal balance.
(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.

10 · Cash flows
Nine months ended September 30 2015 2014
Six months ended June 30 2016 2015
(in millions)        
Supplemental disclosures of cash flow information  
  
  
  
HEI consolidated        
Interest paid to non-affiliates $61
 $64
 $43
 $41
Income taxes paid 62
 31
 14
 35
Income taxes refunded 55
 24
 45
 55
Hawaiian Electric consolidated        
Interest paid to non-affiliates 43
 44
 31
 30
Income taxes paid 13
 6
 —
 9
Income taxes refunded 12
 8
 20
 12
Supplemental disclosures of noncash activities  
  
  
  
HEI consolidated        
Real estate acquired in settlement of loans (investing) —
 2
Common stock dividends reinvested in HEI common stock 1
 11
 —
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing) 5
 —
 —
 5
Obligations to fund low income housing investments (operating) 1
 6
 6
 —
HEI consolidated and Hawaiian Electric consolidated        
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing), as revised for the nine months ended September 30, 2014 (1) 1
 15
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing) (32) (12)
(1) As revised for1The amounts shown represent common stock dividends reinvested in HEI common stock under the nine months ended September 30, 2014 - See Note 1, “BasisHEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions. From January 6, 2016, HEI satisfied the share purchase requirements of presentation - Revisionthe DRIP through new issuances of previously issued financial statements.”its common stock. In 2015, HEI satisfied such requirements with cash through open market purchases of its common stock.



59


11 · Recent accounting pronouncements
Investments in Qualified Affordable Housing Projects. In January 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which permits entities to make an accounting policy election to account for their investments in qualified affordable housing projects using the proportional amortization method if certain conditions are met and investment amortization, net of tax credits, may be recognized in the income statement as a component of income taxes attributable to continuing operations. The amendments also require additional disclosures.
The Company retrospectively adopted ASU No. 2014-01 in the first quarter of 2015. For prior periods, pursuant to ASU No. 2014-01, (a) amortization expense related to ASB’s qualifying investments in low income housing tax credits was reclassified from noninterest expense to income taxes; and (b) additional amortization, net of associated tax benefits was recognized in income taxes as a result of the adoption. The cumulative effect to retained earnings as of January 1, 2014 of adopting this guidance was a reduction of $0.7 million. Amounts in the financial statements as of December 31, 2014 and 2013 and for the three and nine months ended September 30, 2014, have been updated to reflect the retrospective application.
For the quarter ended September 30, 2015, ASB recognized $1.3 million of amortization, $1.3 million of tax credits and $0.6 million of other tax benefits associated with the low income housing tax credits within income taxes. For the nine months ended September 30, 2015, ASB recognized $3.8 million of amortization, $3.9 million of tax credits and $1.6 million of other tax benefits associated with the low income housing tax credits within income taxes.

60


The table below summarizes the impact to prior period financial statements of the adoption of ASU No. 2014-01:
  HEI Consolidated ASB
 (in thousands)
As
previously
 filed
Adjustment from adoption of ASU No. 2014-01
Revision
adjustment
(see Note 1)
As
currently reported
 
As
previously
 filed
Adjustment from adoption of ASU No. 2014-01
As
currently reported
 
 HEI Consolidated Income Statement/ASB Statement of Income Data        
 Three months ended September 30, 2014       
 Bank expenses/Noninterest expense$43,964
$(934) $43,030
 $39,664
$(934)$38,730
 Bank operating income/Income before income taxes19,572
934
 20,506
 19,572
934
20,506
 Income taxes26,323
941
 27,264
 6,312
941
7,253
 Net income for common stock/Net income47,815
(7) 47,808
 13,260
(7)13,253
 Nine months ended September 30, 2014       
��Bank expenses/Noninterest expense129,528
(2,750) 126,778
 117,924
(2,750)115,174
 Bank operating income/Income before income taxes58,243
2,750
 60,993
 58,244
2,750
60,994
 Income taxes73,265
3,037
 76,302
 18,769
3,037
21,806
 Net income for common stock/Net income135,163
(287) 134,876
 39,475
(287)39,188
 HEI Consolidated Balance Sheet/ASB Balance Sheet Data        
 December 31, 2014        
 Other assets541,542
981
 $542,523
 $304,435
$981
$305,416
 Total assets and Total liabilities and shareholders’ equity11,184,161
981
 $11,185,142
 $5,565,241
$981
$5,566,222
 Deferred income taxes/Other liabilities631,734
1,836
 $633,570
 $116,527
$1,836
$118,363
 Total liabilities9,358,440
1,836
 $9,360,276
 $5,030,598
$1,836
$5,032,434
 Retained earnings297,509
(855) $296,654
 $212,789
$(855)$211,934
 Total shareholders’ equity1,791,428
(855) $1,790,573
 $534,643
$(855)$533,788
 HEI Consolidated Statement of Changes in Stockholders’ Equity        
 December 31, 2013        
 Retained earnings255,694
(664) $255,030
    
 Total shareholders’ equity1,727,070
(664) $1,726,406
    
 HEI Consolidated Statement of Cash Flows        
 Nine months ended September 30, 2014       
 Net income136,580
(287) 136,293
    
 Increase in deferred income taxes48,900
370
$1,026
50,296
    
 Change in other assets and liabilities(47,677)(83)(8,566)(56,326)    
Reclassification of loans upon foreclosure. In January 2014, the FASB issued ASU No. 2014-04, “Receivables-Troubled Debt Restructurings by Creditors (Subtopic 310-40): Reclassification of Residential Real Estate Collateralized Consumer Mortgage Loans upon Foreclosure,” which clarifies when an in substance repossession or foreclosure occurs, and a creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan. A creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan upon either: (1) the creditor obtaining legal title to the residential real estate property upon completion of a foreclosure; or (2) the borrower conveying all interest in the residential real estate property to the creditor to satisfy that loan through a deed in lieu of foreclosure or through a similar legal agreement. The amendment also requires additional disclosures.

61


The Company adopted ASU No. 2014-04 in the first quarter of 2015 and the adoption did not have a material impact on the Company’s results of operations, financial condition or liquidity.
Revenues from contracts.  In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers: (Topic 606).” The core principle of the guidance in ASU No. 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should 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.
Repurchase agreements. In June 2014, the FASB issued ASU No. 2014-11, “Transfers and Servicing (Topic 860): Repurchase-to-Maturity Transactions, Repurchase Financings, and Disclosure,” which changes the accounting for repurchase-to-maturity transactions and repurchase financing arrangements. It also requires additional disclosures about repurchase agreements and other similar transactions. The ASU requires a new disclosure for transactions economically similar to repurchase agreements in which the transferor retains substantially all of the exposure to the economic return on the transferred financial assets throughout the term of the transaction. The ASU also requires expanded disclosures about the nature of collateral pledged in repurchase agreements and similar transactions accounted for as secured borrowings.
The Company adopted ASU No. 2014-11 in the first quarter of 2015 and the adoption did not have a material impact on the Company’s results of operations, financial condition or liquidity.
Debt issuance costs. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.
The Company plans to retrospectively adoptadopted ASU No. 2015-03 in the first quarter 2016 and does not expect the adoption todid not have a material impact on the Company’s financial condition and had no impact on the Company’s results of operations financial condition or liquidity.


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. Provisions related to the timing of when excess 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 cost of the asset. The length of time the fair value of an AFS debt security has been below the amortized cost will no longer impact the determination of whether a credit loss exists. The AFS debt security model will also require the use of an allowance to record the estimated losses (and subsequent recoveries). The accounting for the initial recognition of the estimated expected credit losses for purchased financial assets with credit deterioration would be recognized through an allowance for loan losses with an offset to the cost basis of the related financial asset at acquisition (i.e., there is no impact to net income at initial recognition).
The Company plans to adopt ASU 2016-13 in the first quarter of 2020 and has not yet determined the impact of adoption.
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 16% as of SeptemberJune 30, 20152016, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. HEI currently intends to terminate  the HEI Facility if, and when, the proposed Merger closes. 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

62


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 125137.5 basis points and annual fees on undrawn commitments of 17.520 basis points.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 SeptemberJune 30, 2015,2016, 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 56% as of SeptemberJune 30, 2015,2016, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI. Under the proposed Merger Agreement, Hawaiian Electric will become a wholly-owned subsidiary of NEE. The terms of the Hawaiian Electric Facility are such that the proposed Merger would constitute a “Change in Control.” Hawaiian Electric has requested, and the financial institutions providing the Hawaiian Electric Facility have consented and agreed, that the proposed Merger shall not constitute a “Change in Control,” as defined in the credit agreement, provided that (i) the Merger is consummated and (ii) Hawaiian Electric becomes and remains a wholly-owned subsidiary of NEE.
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.
Subsequent events - changesChanges in long-term debt.
HEI.  On May 2, 2014,March 21, 2016, HEI entered into a $75 million term loan agreement with The Bank of Tokyo-Mitsubishi UFJ, Ltd., Royal Bank of Canada and U.S. Bank, National Association (Loan Agreement)America, N.A., which agreementmatures on March 23, 2018 and includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On May 2, 2014,March 23, 2016, HEI drew a $125an initial $75 million Eurodollar term loan at an initial interest rate of 1.18% for a term of two years and at aan initial one month interest period (and with subsequent resetting interest rate ranging from 1.09% to 1.18%rates averaging 1.19% through SeptemberJune 30, 2015.2016). The proceeds from the term loan were used to pay off $100pay-off HEI’s $75 million of 6.51% medium term notes4.41% senior note at maturity on May 5, 2014, pay down maturing commercial paper and for general corporate purposes.March 24, 2016.
On October 8, 2015, (a) the Royal Bank of Canada assigned its loans under the Loan Agreement to The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank, National Association and (b) HEI, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank, National Association entered into Amendment No. 1 to the Loan Agreement. Amendment No. 1, among other things, improved pricing on Eurodollar Borrowings under the Loan Agreement by 15 basis points and extended the maturity date of the Loan Agreement to October 6, 2017. It is currently contemplated that borrowings under the Loan Agreement will be repaid concurrently with the closing of the NEE Merger.
Hawaiian Electric.  On October 15, 2015, Hawaiian Electric, Maui Electric and Hawaii Electric Light issued, through a private placement pursuant to the separate note purchase agreements (the Note Purchase Agreements), $50 million, $5 million and $25 million, respectively, of Series 2015A taxable unsecured 5.23% senior notes due October 1, 2045 (collectively, the Notes). Hawaiian Electric is also a party as guarantor under the Note Purchase Agreements entered into by Maui Electric and Hawaii Electric Light.
All the proceeds of the Notes were used by the Utilities to finance their capital expenditures and for the reimbursement of funds used for the payment of capital expenditures.
The Note Purchase Agreements contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes then outstanding becoming immediately due and payable). The Note Purchase Agreements also include provisions regarding the maintenance of financial ratios that are generally consistent with those in the Hawaiian Electric credit agreement described above.
The Notes may be prepaid in whole or in part at any time at the prepayment price of the principal amount plus a “Make-Whole Amount.” Each of the Note Purchase Agreements also (a) requires the Utilities to offer to prepay the Notes (without a

63


Make-Whole Amount) in the event that there is a “change in control” as defined, and (b) permits the Utilities to offer to prepay Notes (without a Make-Whole Amount) in the event of certain sales of assets. Under the Note Purchase Agreements, the proposed merger of HEI and NEE will not be deemed a “change in control.”
13 · Related party transactions
For general management and administrative services in the second quarters of 2016 and 2015 and six months ended June 30, 2016 and 2015, HEI charged the Utilities $2.3 million, $1.5 million, $4.4 million and $3.2 million, respectively, and HEI charged ASB $0.6 million, $0.6 million, $1.4 million and $1.2 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.
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 30Three months ended June 30 Six months ended June 30
(in millions)2015 2014 2015 20142016 2015 2016 2015
HEI consolidated              
HMSA costs$8
 $6
 $22
 $18
$7
 $8
 $14
 $15
HMSA expense*6
 4
 16
 13
5
 5
 10
 11
HDS costs1
 1
 1
 2
HDS expense*1
 1
 1
 1
Hawaiian Electric consolidated              
HMSA costs6
 5
 17
 15
6
 6
 11
 11
HMSA expense*4
 3
 11
 9
3
 4
 7
 7
HDS costs1
 1
 1
 1
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).
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 20142015 Form 10-K as amended by Amendment No. 1 on Form 10-K/A, and should be read in conjunction with such discussion and the 20142015 annual consolidated financial statements of HEI and Hawaiian Electric and notes thereto included in HEI’s and Hawaiian Electric’s 20142015 Form 10-K, as amended by Amendment No. 1 on Form 10-K/A, as well as the quarterly (as of and for the three and ninesix months ended SeptemberJune 30, 2015)2016) financial statements and notes thereto included in this Form 10-Q.
HEI consolidated
RESULTS OF OPERATIONS
(in thousands, except per Three months ended June 30 %  
share amounts) 2016 2015 change Primary reason(s)*
Revenues $566,244
 $623,912
 (9) Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income 85,455
 72,730
 17
 Increases for the electric utility and bank segments, and lower loss for the “other” segment
Net income for common stock 44,128
 35,018
 26
 Higher net income for the electric utility and bank segments and lower net loss for the “other” segment
Basic earnings per common share $0.41
 $0.33
 24
 Higher net income, partly offset by the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding 107,962
 107,418
 1
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans




(in thousands, except per Three months ended 
 September 30		 %  Six months ended June 30 % 
share amounts) 2015 2014 change Primary reason(s)* 2016 2015 change Primary reason(s)*
Revenues $717,176
 $867,096
 (17) Decrease for the electric utility segment, partly offset by increase for the bank segment $1,117,204
 $1,261,774
 (11) Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income 97,095
 92,036
 5
 Increase for the electric utility and bank segments, partly offset by higher loss for the “other” segment 154,306
 142,236
 8
 Increases for the electric utility segment and lower loss for the “other” segment, partly offset by decreases for bank segment
Net income for common stock 50,673
 47,808
 6
 Higher net income for the electric utility and bank segments, partly offset by higher net loss for the “other” segment 76,480
 66,884
 14
 Higher net income for the electric utility segment and lower net loss for the “other” segment, partly offset by lower net income for the bank segment
Basic earnings per common share $0.47
 $0.47
 —
 Higher net income, offset by the impact of higher weighted average shares outstanding $0.71
 $0.63
 13
 Higher net income, partly offset by the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding 107,457
 102,416
 5
 Issuances of shares under the 2013 equity forward transaction and HEI stock compensation plans 107,791
 105,361
 2
 Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans


64


(in thousands, except per Nine months ended September 30 %  
share amounts) 2015 2014 change Primary reason(s)*
Revenues $1,978,950
 $2,449,502
 (19) Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income 239,331
 264,433
 (9) Decrease for the electric utility segment and higher loss for the “other” segment, partly offset by increase for the bank segment
Net income for common stock 117,557
 134,876
 (13) Lower net income for the electric utility segment and higher net loss for the “other” segment, partly offset by higher net income for the bank segment
Basic earnings per common share $1.11
 $1.33
 (17) Lower net income and the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding 106,067
 101,768
 4
 Issuances of shares under the 2013 equity forward transaction, HEI Dividend Reinvestment and Stock Purchase Plan and other plans
*                 Also, see segment discussions which follow.
* Also, see segment discussions which follow.
 
Notes:  The Company’s effective tax rates (combined federal and state income tax rates) for the third quarters of 2015 and 2014 were 37% and 36%, respectively, and for the first nine months of 2015 and 2014 were 37% and 36%, respectively. The effective tax rate was higher for the quarter and nine months ended September 30, 2015 compared to the same periods in 2014 due primarily to nondeductible merger- and spin-off-related expenses.
HEI’s consolidated ROACE was 8.8% for the twelve months ended June 30, 2016 and 8.1% for the twelve months ended SeptemberJune 30, 2015 and 10.1% for the twelve months ended September 30, 2014.2015.
Dividends.  The payout ratios for the first ninesix months of 20152016 and full year 20142015 were 84%87% and 75%82%, 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. See Note 2 of the Consolidated Financial Statements for a discussion of a special HEI dividend of $0.50 per share contemplated in the Merger Agreement.
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; U.S. Bureau of Labor 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 20152016 with higher visitor arrivalsexpenditures and expendituresarrivals as compared to the same period a year ago. Visitor arrivals increased 4.1%3.3% and expenditures increased 2.6%1.6% compared to the first nine monthshalf of 2014.2015. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the fourththird quarter of 20152016 to increase by 3.8%1.1% over the fourththird quarter of 20142015 driven by an expected 5.1%2.3% increase in domestic seats and 1.1%from the U.S West, an 11.3% increase in international seats.seats from Asian countries other than Japan, and a 6.5% increase in international seats from Oceania (Australia and New Zealand).
Hawaii’s unemployment rate improved to 3.4%3.3% in September 2015,June 2016, lower than the state’s 4.2%3.6% rate in September 2014June 2015 and the September 2015June 2016 national unemployment rate of 5.1%4.9%.
Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices and closed sales in the first nine monthshalf of 2015.2016. Median sales prices for single family residential homes and condominiums on Oahu increased 4.0%6.1% and 1.4%7.4% respectively, over the first nine monthshalf of 2014.2015. Closed sales for single family residential homes and condominiums increased by 4.9%7.8% and 5.1%10.7% respectively, compared to the first nine monthshalf of 2014.2015.
Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. In 2014,the second quarter of 2016, prices of all petroleum fuels held steady during the first half of the year before falling steeplyhave slightly rebounded to prices last seen in the second half. Fuel prices remained lower in the first nine months of 2015 over the same period in 2014.2015.
Information received since the June 2016 Federal Open Market Committee (FOMC) met in September 2015meeting indicates that the labor market strengthened and economic activity has been expanding at a moderate pace.rate. The FOMC reaffirmed its view that the current 0% to 0.25% percent target range for the federal funds rate remains appropriatetarget of 0.25% to 0.5% and stated that it will continue to assess progress towards its objectives of an improved labor market and a movement back to 2% inflation.

65Overall, Hawaii is expected to see a continuation of the moderate expansion experienced in the first six months of 2016. Tourism gains are expected to be marginal, with domestic gains expected to be offset by economic weakening in Canada and Japan. Brexit may broadly impact the European economy and specifically, tourism from Europe to Hawaii. Construction



Overall, the Hawaii economyremains high, as activity is expected to continue growing for the rest of 2015in 2016 as planned and 2016 driven by the tourism industry, particularly on the neighbor islands, the continuation of the construction upturnpermitted building continues and moderate expansion of jobs and income. Hawaii’s economy depends on conditions in the U.S. economy and key international economies such as Japan.new recently approved projects begin.
Recent tax developments. SThe Tax Increase Prevention Act of 2014 provided an extension of 50% bonus depreciation through December 31, 2014, increasing the Company's 2014 federal tax depreciation by an estimated $162 million, primarily attributable to the Utilities. Previously, the American Taxpayer Relief Act of 2012 provided 50% bonus depreciation through December 31, 2013, resulting in an increase in 2013 federal tax depreciation of $160 million, primarily attributable to the Utilities. Under current tax law, there is no provision for bonus depreciation in 2015 and future years. However, several proposed bills extending bonus depreciation are currently being considered by Congress.
Also, seeee “Recent tax developments” in Note 4 and Hawaiian Electric’s consolidated income taxes paid and refunded in Note 10 of the Consolidated Financial Statements.
Retirement benefits.  For the first ninesix months of 2015,2016, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a loss, includingreturn, net of investment management fees, of -4.2%6.4%. Included in this return is the return on ASB’s plan assets, which are managed with a liability driven investment strategy. For the first six months of 2016, ASB’s defined benefit pension plan assets generated a return, net of investment management fees, of 13.3%, due primarily to the lower interest rate environment since the investments were purchased. The market value of thesethe Company’s defined benefit pension and other postretirement benefit plans’ assets as of SeptemberJune 30, 20152016 and December 31, 20142015 was $1.4$1.5 billion (including $1.3$1.4 billion for the Utilities) and $1.4 billion (including $1.3 billion for the Utilities), respectively.
The net periodic pension cost is expected to be 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 20152016 will be $88$65 million ($8664 million by the Utilities, $2$1 million by HEI and nil by ASB), whichcompared 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 following table reflects the sensitivity of the qualified defined benefit pension projected benefit obligation (PBO) as of December 31, 2015 associated with a changedecline in the pension benefits2016 contribution from 2015 is largely due to the increase in the discount rate actuarial assumption byand a downward revision to the indicated basis points and constitutes “forward-looking statements.”
Change in 4.22%Impact on HEIImpact on the
Actuarial Assumptionassumption in basis pointsconsolidated PBOUtilities PBO
Pension benefits discount rate- 100/+100$347 million/$(269) million$325 million/$(251) million
In October 2015, the Society of Actuaries (SOA) released MP-2015 (mortality improvement scale), an update from MP-2014, to reflect two additional years of U.S. population mortality experience data from the Social Security Administration,Mortality Improvement Scale, which occurred at rates generally lower than assumedresulted in MP-2014. Application of MP-2015, as published, will resulta decline in lower futurenet periodic pension and OPEB plan obligations, costs and required contribution amounts. The Company is currently evaluating whether to adopt the use of MP-2015 in its measurement of its pension and OPEB plan obligations at December 31, 2015. The Company used the SOA published RP-2014 (mortality tables) and MP-2014 to measure its pension and OPEB plan obligations at December 31, 2014 and costs in 2015. 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, 2017. As of December 31, 2014, the Company is using different mortality assumptions for ERISA funding versus financial reporting and accounting.cost.
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.

66


“Other” segment.
 Three months ended 
 September 30		 Nine months ended September 30  Three months ended June 30 Six months ended June 30 
(in thousands) 2015 2014 2015 2014 Primary reason(s) 2016 2015 2016 2015 Primary reason(s)
Revenues $(42) $(5) $(4) $(325) Lower writedown of venture capital investments for the nine months $100
 $(34) $168
 $38
 
Operating loss (6,364) (4,626) (28,282) (13,450) Higher administrative and general expenses, due to higher merger- and spin-off-related expenses ($1.8 million of expenses for third quarter 2015 and $15.2 million for first nine months of 2015) (5,455) (13,157) (11,524) (21,918) Lower administrative and general expenses due to lower merger- and spin-off-related expenses
Net loss (5,784) (4,324) (24,941) (12,841) Higher operating loss and lower tax benefits relative to the losses in 2015 (partly due to non-deductibility of certain merger- and spin-off-related expenses), partly offset by lower interest expense (5,014) (10,674) (10,702) (19,157) Lower operating loss and higher tax benefits relative to the losses in second quarter 2016 and six months ended June 30, 2016 (due to non-deductibility of certain merger- and spin-off-related expenses at the time)
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)abandoned prior to its dissolution in December 2015); and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions. Expenses related to the pendingpreviously proposed merger with NEE and spin-off of ASBH of $4.4 million, $9.0$2.0 million and $1.8$3.5 million were included in the results of the stand-alone corporate operations of HEI during the first, second quarter and third quarterssix months ended June 30, 2016, respectively, and $9.0 million and $13.5 million were included in the results of 2015.the stand-alone corporate operations of HEI during the second quarter and six months ended June 30, 2015, respectively. See Note 2, “Termination of proposed merger and other 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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
Short-term borrowings—other than bank $172
 5% $119
 3% $116
 3% $103
 3%
Long-term debt, net—other than bank 1,507
 41
 1,507
 44
 1,579
 43
 1,578
 43
Preferred stock of subsidiaries 34
 1
 34
 1
 34
 1
 34
 1
Common stock equity 1,921
 53
 1,791
 52
 1,966
 53
 1,928
 53
 $3,634
 100% $3,451
 100% $3,695
 100% $3,643
 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, 2015 September 30, 2015 December 31, 2014 Six months ended June 30, 2016 June 30, 2016 December 31, 2015
Short-term borrowings 1
  
  
  
  
  
  
Commercial paper $51
 $77
 $119
 $79
 $79
 $103
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 20152016 was $134$103 million. At October 31, 2015,As of July 29, 2016, HEI had $78 million ofno outstanding commercial paper, and its line of credit facility was undrawn.
HEI has a line of credit facility, as amended and restated on April 2, 2014, of $150 million. See Note 12 of the Consolidated Financial Statements.
The Company raised $3 millionFrom March 6, 2014 through January 5, 2016, HEI satisfied the issuanceshare purchase requirements of approximately 0.1 million shares of common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the HEIRSP and ASB 401(k) Plan from January 1 through March 5,

67


2014. As of March 6, 2014, HEI began satisfying the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances. From January 6 through June 30, 2016, the Company raised $19 million through the issuance of approximately 0.6 million shares of common stock under the DRIP, HEIRSP and ASB 401(k) Plan. Starting on June 2, 2016, HEI satisfied the share purchase requirements of the HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances. Effective August 9, 2016, HEI will satisfy the share purchase requirements of the HEIRSP and ASB 401(k) Plan through new issuances of its common stock rather than through open market purchases.
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, 2014.2014, 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 for a brief description of the loan agreement.Statements.
In December 2014, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities.




As of August 3, 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 21, 2015,3, 2016, Moody’s Investor Service (Moody’s) changeddowngraded HEI’s short-term rating for commercial paper from P-2 to P-3. HEI’s outlook from stableis stable. Moody’s noted, “[t]he downgrade of HEI’s commercial paper rating to negative “dueP-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 concerns about the execution risk inherentface significant challenges in transforming its oil-dominated generation base to renewables.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 2015,2016, net cash provided by operating activities of HEI consolidated was $221$225 million. Net cash used by investing activities for the same period was $503$385 million, primarily due to Hawaiian Electric’s consolidated capital expenditures, purchases of ASB’s investment securities, aand net increaseincreases in ASB’s loans held for investment and stock in FHLB, partly offset by ASB’s repayments and calls of investment securities, and redemption of stockproceeds from the FHLB,sale of commercial loans and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $335$116 million as a result of several factors, including proceeds from the issuance of shares under the equity forward, a net increase in short-term borrowings, and net increases in ASB’s deposit liabilities retail repurchase agreements and other bankshort-term borrowings and proceeds from the issuance of HEI common stock, partly offset by the payment of common stock dividends.dividends and net decreases in other bank borrowings and retail repurchase agreements. 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 2015,2016, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $68$47 million and $23$18 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 74 to 76 of HEI’s MD&A included in Part II, Item 7 of HEI’s 20142015 Form 10-K, as amended by Amendment No. 1 on Form 10-K/A.10-K.
Additional factors that may affect future results and financial condition are described on pages iv and v under “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 76 to 79 of HEI’s MD&A included in Part II, Item 7 of HEI’s 20142015 Form 10-K, as amended by Amendment No. 1 on Form 10-K/A.10-K.

68


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 June 30 Increase  
2016 2015 (decrease) (dollars in millions, except per barrel amounts)
$495
 $558
 $(63)  
Revenues. Net decrease largely due to:
     $(53) lower fuel prices
     (11) lower purchased power expense
     (7) lower KWH generated
     8
 higher rate base and O&M RAM
92
 146
 (54)  
Fuel oil expense. Decrease due to lower fuel cost and lower KWH generated
139
 149
 (10)  
Purchased power expense. Decrease due to lower purchased power energy prices
99
 99
 —
  
Operation and maintenance expenses. Relatively flat due to:
     2
 higher costing overhauls
     1
 higher LNG consultant costs
     (3) 
lower transmission, distribution and generation costs due to:
-lower vegetation management costs,
-less boiler and steam maintenance work and
-less transmission line inspections
94
 98
 (4)  
Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
71
 66
 5
  
Operating income. Increase due to an overall decrease in expenses
36
 33
 3
  
Net income for common stock. Increase due to higher operating income
        
2,156
 2,144
 12
  Kilowatthour sales (millions)
69.9
 69.2
 0.7
  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,257
 1,181
 76
  Cooling degree days (Oahu)
$44.98
 $69.37
 $(24.39)  Average fuel oil cost per barrel



Six months ended June 30 Increase  
2016 2015 (decrease) (dollars in millions, except per barrel amounts)
$977
 $1,132
 $(155)  
Revenues. Net decrease largely due to:
     $(131) lower fuel prices
     (34) lower purchased power expense
     6
 higher rate base and O&M RAM
     3
 higher KWH generated
206
 323
 (117)  
Fuel oil expense. Decrease largely due to lower fuel prices, partly offset by higher KWH generated
255
 285
 (30)  
Purchased power expense. Decrease due to lower purchased power energy prices
203
 203
 —
  
Operation and maintenance expenses. Relatively flat due to:
     4
 higher costing overhauls
     4
 higher PSIP consultant costs
     2
 higher LNG consultant costs
     (6) 
lower transmission, distribution and generation costs due to:
-lower vegetation management costs,
-less boiler and steam maintenance work,
-less transmission line inspections and
-storm repair costs incurred in 2015
     (1) lower Distributed Energy Resources cost
     (1) 2015 costs for damage to combined heat and power generating unit
     (1) lower bad debt reserve for one customer account
187
 197
 (10)  
Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
126
 124
 2
  
Operating income. Increase due to an overall decrease in expenses
61
 60
 1
  
Net income for common stock. Increase due to higher operating income
        
4,241
 4,188
 53
  Kilowatthour sales (millions)
68.6
 67.8
 0.8
  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
2,141
 1,976
 165
  Cooling degree days (Oahu)
$49.05
 $77.85
 $(28.80)  Average fuel oil cost per barrel
458,893
 456,608
 2,285
  Customer accounts (end of period)
Hawaiian Electric’s consolidated ROACE was 8.0% for the twelve months ended June 30, 2016 and 7.7% for the twelve months ended June 30, 2015.
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 2016 KWH sales are expected to be below the 2015 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, down from the previous estimate of 4% lower than 2015, due to expected greater spending on new customer programs to support renewable energy integration.
The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of June 30, 2016 amounted to $4 billion, of which approximately 26% related to production PPE, 65% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 3% 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.
Utility strategic progress.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 PUC issued several important regulatory decisions duringUtilities are committed to assisting the last few years, including a numberState of interim and final rate case decisions (see table in “Most recent rate proceedings” below).
On August 26,

Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy by 2045. Hawaii’s RPS law was revised in the 2015 Legislature and requires electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045, respectively. Energy savings resulting from DSM 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 2015 was 23%, exceeding the 2015 RPS goal, and the Utilities led the nation in 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 plans for Hawaii’s energy futurePower 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). Updated PSIPs were filed in April 2016. Under these plans, the Utilities will support sustainable growth of 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), and the Utilities proposed a switch from high-priced oil to lower cost liquefied natural gas.
On October 1, 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed a proposed community-based renewable energy program and tariff with the PUC that will 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. The program, upon approval by the PUC, will allow customers to buy an interest in electricity generated by community renewable projects in diverse locations 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.
Transition to renewable energy. The Utilities are committedpursuing the transition to assisting the State of Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy in a manner that will help stabilize customer bills as they become less dependent 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, (see “Renewable energy strategy” below). The Utilities are also working with the State of Hawaii and other entities to examine the possibility of using LNG as a cleaner and lower cost fuel as transition fuel for some generation as the Utilities moveseek 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 oilexisting resources is becoming more challenging. As a result, there is a growing risk that energy production from generating resources may need to renewable energy. Since 2014be 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 evaluating delivering LNGprogressively making changes in specialized shipping containers to their generating stations on a transitional basis, an approach that requires minimal on-island infrastructure. In March 2014, Hawaiian Electric issued a RFP for the supply of containerized LNGoperating practices, are making investments in grid modernization technologies, and is currently in negotiations to resolve key contractual provisionsare working with the preferred bidder. The Utilities are workingsolar industry to align their containerized LNG plans withmitigate these risks and continue the State’s directives and plan on finalizing LNG fuel agreements in the first quarterintegration of 2016. The Utilities would seek approval from the PUC for the fuel agreement(s) and the commitment of funds for capital improvements shortly thereafter.
In August 2015, Hawaii State Governor Ige voiced his opposition to LNG as a replacement fuel for power generation citing (a) the high infrastructure costs and (b) permitting requirements as primary obstacles.more renewable energy.
After launching a smart grid customer engagement plan during the second quarter of 2014.2014, 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, customer energy portals were launched and are available for customer use and a PrePay Application was launched. The Initial Phase implementation will bewas completed by the end ofin 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. TheIn March 2016, the Utilities are planning to seeksought PUC approval from the PUC in the fourth quarter of 2015 to commit funds for an expansion of the smart grid project. The smart grid project including atis expected to cost $340 million and be implemented over 5 years (beginning in 2017 for Oahu and 2018 for the Hawaii Electric LightIsland and Maui Electric.County).
Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 and 2012. The decoupling model implemented delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers and are in the public interest. On March 31, 2015, the PUC issued an Order to make certain modifications to the decoupling mechanism. See "Decoupling" in Note 4 of the Consolidated Financial Statements for a discussion onof 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.

69



Actual and PUC-allowed (as of SeptemberJune 30, 2015)2016) returns were as follows:
% Return on rate base (RORB)* ROACE** Rate-making ROACE*** Return on rate base (RORB)* ROACE** Rate-making ROACE***
Twelve months ended September 30, 2015 Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric Hawaiian Electric Hawaii Electric Light Maui Electric
Twelve months ended June 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 7.23
 6.00
 7.74
 7.95
 6.30
 9.21
 8.84
 6.51
 9.74
 7.26
 7.07
 7.43
 7.95
 7.47
 8.67
 8.94
 8.02
 9.04
PUC-allowed returns 8.11
 8.31
 7.34
 10.00
 10.00
 9.00
 10.00
 10.00
 9.00
 8.11
 8.31
 7.34
 10.00
 10.00
 9.00
 10.00
 10.00
 9.00
Difference (0.88) (2.31) 0.40
 (2.05) (3.70) 0.21
 (1.16) (3.49) 0.74
 (0.85) (1.24) 0.09
 (2.05) (2.53) (0.33) (1.06) (1.98) 0.04
*       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 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,
•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 2015 to 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 underthrough the RAM, cap, 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. The earnings share mechanism was not triggered for any of the utilities in 2015. For 2014, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric will credithas been crediting $0.5 million to its customers for their portion of the earnings sharing during the period June 2015 to May 2016. Earnings sharing credits are included in the annual decoupling filing for the following year.
Annual decoupling filings.  See “Decoupling” in Note 4 of the Consolidated Financial Statements for a discussion of the 20152016 annual decoupling filings.

70


Results.
Three months ended 
 September 30		 Increase  
2015 2014 (decrease) (dollars in millions, except per barrel amounts)
$648
 $804
 $(156)  
Revenues. Net decrease largely due to:
     $(131) lower fuel prices
     (42) lower purchased power energy costs
     7
 higher KWH generated
     7
 higher KWH purchased
196
 309
 (113)  
Fuel oil expense. Decrease largely due to lower fuel cost partly offset by higher KWH generated
161
 193
 (32)  
Purchased power expense. Decrease due to lower purchased power energy prices offset by higher KWH purchased
104
 108
 (4)  
Operation and maintenance expenses. Net decrease due to:
     (4) higher consultant costs in 2014 related to 4 PUC D&Os
     (4) higher 2014 storm restoration costs
     (3) higher 2014 smart grid costs
     (2) reversal of previously expensed Interactive Voice Response system project costs, based on PUC decision allowing deferral and amortization of costs
     5
 ERP software costs write off resulting from PUC ERP/EAM decision
     4
 increased generating unit maintenance, including costs to comply with MATS
106
 117
 (11)  
Other expenses. Decrease in revenue taxes due to lower revenue offset by higher depreciation expense for plant investments
83
 76
 7
  
Operating income. Increase due to an overall decrease in expenses
43
 39
 4
  
Net income for common stock. Increase due to higher operating income
        
2,468
 2,384
 84
  Kilowatthour sales (millions)
74.9
 72.2
 2.7
  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,711
 1,631
 80
  Cooling degree days (Oahu)
$81.35
 $133.26
 $(51.91)  Average fuel oil cost per barrel

71


Nine months ended September 30 Increase  
2015 2014 (decrease) (dollars in millions, except per barrel amounts)
$1,780
 $2,262
 $(482)  
Revenues. Decrease largely due to:
     $(373) lower fuel prices
     (101) lower purchased power energy costs
     (8) lower KWH generated
519
 866
 (347)  
Fuel oil expense. Decrease largely due to lower fuel cost and lower KWH generated.
446
 546
 (100)  
Purchased power expense. Decrease due to lower purchased power energy prices and lower KWH purchased
307
 295
 12
  
Operation and maintenance expenses. Net increase due to:
     11
 increased generating unit maintenance, including costs to comply with MATS
     5
 ERP software costs write off resulting from PUC ERP/EAM decision
     4
 higher consulting costs for energy transformation plans
     3
 higher employee benefit costs
     2
 higher bad debt reserves for one customer account
     (5) higher consultant costs in 2014 related to 4 PUC D&Os
     (4) higher 2014 smart grid costs
     (2) higher 2014 storm restoration costs
     (2) reversal of previously expensed Interactive Voice Response system project costs, based on PUC decision allowing deferral and amortization of costs
302
 338
 (36)  
Other expenses. Decrease in revenue taxes due to lower revenue offset by higher depreciation expense for plant investments
206
 217
 (11)  
Operating income. Decrease due to lower revenues
103
 109
 (6)  
Net income for common stock. Decrease due to lower operating income
        
6,656
 6,699
 (43)  Kilowatthour sales (millions)
70.2
 69.5
 0.7
  Wet-bulb temperature (Oahu average; degrees Fahrenheit)
3,687
 3,703
 (16)  Cooling degree days (Oahu)
$79.13
 $132.19
 $(53.06)  Average fuel oil cost per barrel
457,051
 454,156
 2,895
  Customer accounts (end of period)
Note:  The electric utilities had effective tax rates for the third quarters of 2015 and 2014 of 37% and 37%, respectively. The electric utilities had effective tax rates for the first nine months of 2015 and 2014 of 37% and 37%.
Hawaiian Electric’s consolidated ROACE was 7.9% for the twelve months ended September 30, 2015 and 9.0% for the twelve months ended September 30, 2014.
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’ 2015 KWH sales are expected to further decline below 2014 levels.
Other operation and maintenance expenses (excluding expense covered by surcharges or by third parties) for 2015 are projected to be flat as compared to 2014 as the Utilities continue to implement rigorous cost management measures focused on reprioritization of work, staffing levels, and discretionary expenses. The Utilities previously projected a 2% decrease compared to 2014, however higher than anticipated costs have arisen including the unexpected $4.8 million write-off of enterprise resource planning software and other costs.
The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of September 30, 2015 amounted to $4 billion, of which approximately 26% related to production PPE, 65% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 3% 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.

72


Most recent rate proceedings.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
Hawaiian Electric    
  
  
  
  
  
  
2011 (1)
    
  
  
  
  
  
  
Request 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
  
Interim increase (adjusted) 4/2/12 58.2
 3.4
 10.00
 8.11
 1,385
 56.29
  
Interim increase (adjusted) 5/21/12 58.8
 3.4
 10.00
 8.11
 1,386
 56.29
  
Final increase 9/1/12 58.1
 3.4
 10.00
 8.11
 1,386
 56.29
  
2014 (2)
 6/27/14              
Hawaii Electric Light    
  
  
  
  
  
  
2010 (3)
    
  
  
  
  
  
  
Request 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
  
Interim increase (adjusted) 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
  
2013 (4)
    
  
  
  
  
  
  
Request 8/16/12 $19.8
 4.2
 10.25
 8.30
 $455
 57.05
  
Closed 3/27/13  
  
  
  
  
  
  
2016 (5)
 6/17/15              
Maui Electric    
  
  
  
  
  
  
2012 (6)
    
  
  
  
  
  
  
Request 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
  
Final increase 8/1/13 5.3
 1.3
 9.00
 7.34
 393
 56.86
  
2015 (7)
 12/30/14              
 
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)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.

73


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.
(4)   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 the 2013 Agreement and 2013 Order (described below), approved by the PUC in March 2013, the rate case was withdrawn and the docket has been closed.
(5)See “Hawaii Electric Light 2016 test year rate case” below.


(6)   Maui Electric’s request was to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. See discussion on final D&O, including the refund to customers in September and October 2013 required as a result of the final D&O, in Note 4 of the Consolidated Financial Statements.
(7)See “Maui Electric 2015 test year rate case” below.
Hawaiian Electric 2011 test year rate case.  In the Hawaiian Electric 2011 test year rate case, the PUC had granted Hawaiian Electric’s request to defer Customer Information System (CIS) project O&M expenses (limited to $2,258,000 per year in 2011 and 2012) that were to be subject to a regulatory audit of project costs, and allowed Hawaiian Electric to accrue AFUDC on these deferred costs until the completion of the regulatory audit.
On January 28, 2013, the Utilities and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects, with the remaining recoverable costs for the projects of $52 million to be included in rate base as of December 31, 2012. The parties agreed that Hawaii Electric Light would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and Hawaiian Electric would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that, starting in 2014, Hawaiian Electric will be allowed to record RAM revenues starting on January 1 (instead of the prior start date of June 1) for the years 2014, 2015 and 2016. For each of the ninesix months ended SeptemberJune 30, 20152016 and 2014,2015, Hawaiian Electric had additional net RAM revenues of $3.8 million and $12.3 million, respectively.$4 million.
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 foregoforgo 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. The abbreviated filing explained that Hawaiian Electric is aggressively attacking the root causes of high rates, by, among other things, vigorously pursuing the opportunity to switch from oil to liquefied natural gas, acquiring lower-cost renewable energy resources, pursuing opportunities to achieve operational efficiencies, and deactivating older, high-cost generation. Instead of seeking a rate increase, Hawaiian Electric stated that it is focused on developing and executing the new business model, plans and strategies required by the PUC’s April 2014 regulatory orders discussed in Note 4 of the Consolidated Financial Statements, as well as other actions that will reduce rates.
Hawaiian Electric further explained 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. If the PUC determines that additional materials are required, Hawaiian Electric stated it will work with the Consumer Advocate on a schedule to submit additional information as needed. Hawaiian Electric asked for an expedited decision on this filing and stated that if the PUC decides that such a ruling is not in order, Hawaiian Electric reserves the right to supplement the abbreviated filing with additional material to support the increase in revenue requirements forgone by this filing—calculated to be $56 million over revenues at current effective rates. Hawaiian Electric’s revenue at current effective rates includes: (1) the revenue from Hawaiian Electric’s base rates, including the revenue from the energy cost adjustment clause and the purchased power adjustment clause, (2) the revenue that would be included in the decoupling RBA in 2014 based on 2014 test year forecasted sales and (3) the revenue from the 2014 RAM implemented in connection with the decoupling mechanism.
Under Hawaiian Electric’s proposal, the decoupling RBA and RAM would continue, subject to any change to these mechanisms ordered by the PUC in Schedule B of the decoupling proceedings, the DSM surcharge would continue since demand response (DR) program costs would not be rolled into base rates (as required in the April 28, 2014 DR Order) until the next rate case and the pension and OPEB tracking mechanisms would continue. Hawaiian Electric plans to file its next rate case according to the normal rate case cycle using a 2017 test year. If circumstances change, Hawaiian Electric may file its next rate case earlier.
Management cannot predict whether the PUC will accept this abbreviated filing to satisfy Hawaiian Electric’s obligation to file a rate case in 2014, whether additional material will be required or whether Hawaiian Electric will be required to

74


proceed with a traditional rate proceeding.
Maui Electric 2015 test year rate case.  On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby foregoing the opportunity to seek a general rate increase. If Maui Electric were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 RAM revenues. The normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%.


Management cannot predict any actions bywhether the PUC aswill accept this abbreviated filing to satisfy Maui Electric’s obligation to file a result of this filing.rate case in 2015, whether additional material will be required or whether Maui Electric will be required to proceed with a traditional rate proceeding.
Hawaii Electric Light 2016 test year rate case. On June 17, 2015, Hawaii Electric Light filed its notice of intent to file a general rate case application by December 30, 2016, and simultaneously filed a motion which requested a test year waiveran extension to utilize afile its 2016 calendar test year. Notice is contingent uponrate case to no later than December 30, 2016. On November 19, 2015, the PUC’s approval ofPUC issued an order granting Hawaii Electric Light's request to extendLight’s motion, extending the current December 31, 2015 deadline to file theits 2016 rate case usingto December 30, 2016 and imposing a 2016 calendar test year. The rate case filing is requirednumber of conditions, including the removal of all HEI non-incentive executive compensation from the Company’s base rates, a demonstration that it substantially reduced its cost structure, a proposal of a set of economic incentive and cost recovery mechanisms to satisfyfurther encourage reductions in rates and an acceleration of its clean energy transformation, and a proposal to modify the obligationECAC to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O.provide incentives to reduce fuel and purchased power expenses. 
Integrated resource planning and April 2014 regulatory orders. See “April 2014 regulatory orders” in Note 4 to the Consolidated Financial Statements.
Renewableenergy strategy.  The Utilities’ policy is to support efforts to increaseDevelopments in renewable energy in Hawaii. The Utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The Utilities’ renewable energy strategy will also allow them to meet Hawaii’s RPS law as revised in the 2015 Legislature, which requires electric utilities to meet an RPS of 10%, 15%, 30%, 40%, 70% and 100% by December 31, 2010, 2015, 2020, 2030, 2040 and 2045, respectively. The Utilities met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings)efforts.  Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2014, the Utilities achieved an RPS without DSM energy savings of an estimated 21%, primarily through a comprehensive portfolio of renewable energy PPAs, NEM programs and biofuels. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems. The Utilities are on track to exceed their 2015 RPS goal, and lead the nation in terms of the amount of PV systems installed by its customers.
As more generating resources, whether utility scale or distributed generation, 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. Also, 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. 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. 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.
Developments in the Utilities’ efforts to further their renewable energy strategy include 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-MW200 MW RFP, ordering that Hawaiian Electric shall amend its current draft of the Oahu 200-MW200 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 Bioenergy, LLC plant is currentlywas scheduled to be in service in 2016.
In May 2012, However, Hu Honua encountered construction delays, failed to meet its current obligations under 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. Bids were received in January 2015,PPA and in February 2015, Ormat Technologies, Inc. was selectedfailed to provide 25 MWadequate 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 additional geothermal energy, subject to successful contract negotiationsreinstating the PPA under revised terms and PUC approval of the final agreement.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

75


2014 to perform control system acceptance testing, and energy is being purchased at a base rate until PUC approval of an amendment to the PPA. 2014. An application for PUC approval of an amendment to the PPA was filed in April 2014.2014 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 and expected to be placed in service in 2017.Oahu. In May 2014, Hawaiian Electric filed an application with the PUC to allow expenditures of $170 million for execution of the project, which is expected to be placed in service by the end of 2017.
In JulySeptember 2015, the PUC issued orders approving (with conditions) four PPAs for a combined 137 MWapproved Hawaiian Electric's application with conditions and limitations. See "Schofield Generating Station Project" in Note 4 of solar projects. Hawaiian Electric expects to manage curtailment levels of these projects. In August 2015, the PUC issued orders denying Hawaiian Electric’s applications to approve three other solar projects.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 October 2013,April 2016, the PUC approved Hawaiian Electric’s 20-year contract with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of November 25, 2013.PUC’s Hearing Officer issued a recommended D&O that confirms Maui Electric abided by state law.
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 Na Pua Makani Power Partners, LLCNPM for the proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA. Hawaiian Electric and NPM are currently working on an amendment to the PPA to incorporate the results of the interconnection requirements study.


In April 2014, Hawaiian Electric requested PUC approval of a PPA for Renewable As-Available Energy with Lanikuhana Solar, LLC for a proposed 20-MW PV facility on Oahu. In JuneJuly 2015, the PUC deniedissued orders approving (with conditions) four PPAs for a combined 137 MW of solar projects. In January 2016, two of the requestfour approved projects (which are SunEdison projects) received notices of default from Hawaiian Electric for failure to waivemeet guaranteed project milestones, and in February 2016 a third project (also a SunEdison project) received a notice of failure to meet a substantial commitment milestone. In January 2016, the Lanikuhana facility from competitive bidding requirements.PUC reopened proceedings for the three SunEdison projects. In February 2016, Hawaiian Electric filed project status reports with the PUC and terminated the three SunEdison PPAs totaling 109.6 MW. SunEdison maintains that the terminations were improper. SunEdison and the Consumer Advocate filed responses with the PUC regarding Hawaiian Electric’s status reports, and a technical conference was held on March 18, 2016. On April 12, 2016, the PUC issued a staff report concerning the termination of the PPAs. The staff report stated that Hawaiian Electric acted too hastily and without an in-depth analysis, however, the staff report acknowledged that it is within Hawaiian Electric’s management discretion to determine whether or not to terminate the PPAs. The PUC has not yet closed the dockets for these projects. On April 21, 2016, SunEdison filed for Chapter 11 bankruptcy protection.
The fourth project approved by the PUC in July 2015 is the 27.6 MW Waianae Solar project that is being developed by Eurus Energy America. It is expected to be in service at the end of 2016, at which time it will be 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 3, LLC), each for a 2.87-MW solar facility. In February 2016, the PUC approved both PPAs, subject to certain conditions and modifications.   
In September 2015, the PUC approved Hawaiian Electric’s 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC to supply 2 million to 3 million gallons of biodiesel at CIP CT-1 and the Honolulu International Airport Emergency Power Facility beginning in November 2015. Renewable Energy Group has supplied 3 million to 7 million gallons per year to CIP CT-1 under its contract with Hawaiian Electric originally set to expire November 2015. The contract has been extended from November 2015 to November 2016 as a contingency supply contract with no volume purchase requirements.
In October 2015, the Utilities filed with the PUC a proposal for a Community-Based Renewable Energy program and tariff that would allow customers who cannot, or chose not to, take advantage of 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 and other participating parties filed comments on the draft program.
On May 5, 2016, Maui Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Maui Electric Dispatchable Firm Generation Request for Proposals. The solicitation intends to seek approximately 20 MW of new renewable generation capacity and approximately 20 MW of fuel flexible firm generation resources on the island of Maui by 2022, as proposed in the PSIP Update Report.
On June 6, 2016, Hawaiian Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Hawaiian Electric Renewable Energy Request for Proposals. The solicitation intends to seek new renewable energy generation on the island of Oahu to be placed into service by the end of 2020, consistent with the Five-Year Action Plan proposed in the PSIP Update Report.
In July 2016, Hawaiian Electric announced plans to build, own and operate a 20-MW solar facility in conjunction with the Department of the Navy at a Navy/Air Force joint base for an  estimated cost of $70 million, subject to PUC approval. The renewable energy generated by the solar facility will feed into Oahu’s electric grid. 
The Utilities began accepting energy from feed-in tariff projects in 2011. As of SeptemberJune 30, 2015,2016, there were 1315 MW, 36 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, 2015,2016, there were approximately 244282 MW, 5667 MW and 6074 MW of installed NEM capacity fromdistributed renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
In July 2015, Maui Electric signed two PPAs, eachrespectively, for a 2.87-MW solar facility, which are subject to PUC approval.

tariff-based customer generation programs, namely NEM, Customer Grid Supply (CGS) and Customer Self Supply (CSS).
Other regulatory matters.  In addition to the items below, also see Note 4 of the Consolidated Financial Statements.
PUC Commissioner. On June 29, 2016, the Governor appointed Thomas Gorak on an interim basis 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 term as a PUC Commissioner began on July 1, 2016 and is subject to Senate confirmation.

Adequacy of supply.
Hawaiian Electric. In January 2015,2016, Hawaiian Electric filed its 20152016 Adequacy of Supply (AOS) letter, which indicated that based on its February 2014May 2015 sales and peak forecast for the 20152016 to 2017 time period, Hawaiian Electric’s generation capacity


will be sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2016, notwithstanding a generation shortfall event in January 2015, due to unexpected concurrent outages of a utility generating unit and several IPPs.2017.
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 20162022 timeframe. Hawaiian Electric is proceeding with future firm capacity additions in coordination with the State of Hawaii Department of Transportation in 2015,2016, and 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 first quarter of 2018. Hawaiian Electric is continuing negotiations with two firm capacity IPPs on Oahu under PPAsOahu. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution. The PPA with AES Hawaii, Inc. is scheduled to expire in 2016 and 2022.

76


Hawaii Electric Light. In January 2015,2016, Hawaii Electric Light filed its 20152016 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 20172018 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 2020-2025 timeframe.
Maui Electric. In January 2015,2016, Maui Electric filed its 20152016 AOS letter, which indicated that Maui Electric’s generation capacity through 2018 is sufficient to meet the forecasted demands onfor the islands of Maui, Lanai and Molokai.Molokai for the next three years is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. The 2016 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 2019 timeframe.2022 timeframe after the planned retirement of Kahului Power Plant. In February 2014, Maui Electric deactivated two fossil fuel generating units, with a combined rating of 9.5 MW,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 2015.2015 and 2016. In consideration of the time needed to acquire replacement firm generating capacity, Maui Electric now anticipates the retirement of all generating units at the Kahului Power Plant, which have a combined rating of 32.3 MW, in the 2022 timeframe. A capacity planning analysis is in progress to better define needs and timing. Maui Electric plans to issue one or more RFPs for energy storage, demand response and firm generating capacity, and to make system improvements needed to ensure reliability and voltage support in this timeframe. In May 2016, Maui Electric requested that the PUC open a new docket for Maui Electric’s competitive bidding process for additional firm capacity resources.
April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively provide certain key policy, resource planning, and operational directives to the Utilities. See “April 2014 regulatory orders” in Note 4 of the Consolidated Financial Statements.
Commitments and contingencies.  See Note 4 of the Consolidated Financial Statements.
Recent accounting pronouncements.  See Note 11, “Recent accounting pronouncements,” of the Consolidated Financial Statements.


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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
Short-term borrowings $95
 3% $—
 —% $37
 1% $—
 —%
Long-term debt, net 1,207
 40
 1,207
 41
 1,279
 41
 1,279
 42
Preferred stock 34
 1
 34
 1
 34
 1
 34
 1
Common stock equity 1,717
 56
 1,682
 58
 1,743
 57
 1,728
 57
 $3,053
 100% $2,923
 100% $3,093
 100% $3,041
 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, 2015 September 30, 2015 December 31, 2014 Six months ended June 30, 2016 June 30, 2016 December 31, 2015
Short-term borrowings 1
  
  
  
  
  
  
Commercial paper $57
 $95
 $—
 $19
 $37
 $—
Line of credit draws —
 —
 —
 —
 —
 —
Borrowings from HEI —
 —
 —
 —
 —
 —
Undrawn capacity under line of credit facility   200
 200
   200
 200
 
1   The maximum amount of Hawaiian Electric’s external short-term borrowings during the first ninesix months of 20152016 was $126$61 million. At SeptemberAs of June 30, 2015,2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $3$18.5 million and Hawaii Electric Light had short-term borrowings from Hawaiian Electric$18.5 million, respectively. As of $12 million. At October 31, 2015,July 29, 2016, Hawaiian Electric had no$27 million of outstanding commercial paper, no draws under its line of credit facility and no borrowings from HEI. Also, at October 31, 2015,as of July 29, 2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $16$18.5 million and none from Maui Electric.$15.5 million, respectively. Intercompany borrowings are eliminated in consolidation.

77


Hawaiian Electric has a line of credit facility, as amended and restated on April 2, 2014, of $200 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. See Note 12 of the 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 SPRBs currently outstandingthe Series 2007A and issued prior to 2009Refunding 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.
The PUC has approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by the Utilities, up to specified amounts, during the period 2013 through 2015, subject to certain conditions. On October 3, 2013, after obtaining such expedited approvals, the Utilities issued through a private placement taxable non-collateralized senior notes with an aggregate principal amount of $236 million.
In September 2014, the Utilities filed a request with the PUC under the expedited approval procedure for approval to issue unsecured obligations bearing taxable interest through December 31, 2015 of up to $80 million (Hawaiian Electric $50 million, Hawaii Electric Light $25 million and Maui Electric $5 million). In May 2015, the PUC approved the Utilities’ request. On October 15, 2015, the Utilities issued through a private placement taxable unsecured senior notes totaling $80 million. See Note 12 of “Notes to Consolidated Financial Statements.”
In June 2015, the Utilities refiled with the PUC a letter request to refinance outstanding revenue bonds with refunding revenue bonds totaling $47 million. On August 10, 2015, the PUC approved the Utilities’ request.
In May 2015, up to $80 million of Special Purpose Revenue Bonds (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’ capital improvement programs.
In June 2015, 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 the owner at the time of each such saleHEI of up to $330 million and Hawaii Electric Light’s and Maui Electric’s sales to Hawaiian Electric of up to $15 million and $45 million, respectively), and the purchase of the Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric in 2016. In June 2016, the PUC issued a D&O approving the issue and sale of each utility’s common stock in 2016 up to the amounts requested in the application.


In February 2016, Hawaiian Electric and Maui Electric filed an application with the PUC for approval to issue in 2016 unsecured obligations bearing taxable interest (Hawaiian Electric up to $70 million and Maui Electric up to $20 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.
As of August 3, 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 21, 2015,3, 2016, Moody’s changeddowngraded Hawaiian Electric’s senior unsecured debt rating from Baa1 to Baa2 and downgraded other ratings. Hawaiian Electric’s outlook from stableis 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 negative “due to concerns about the execution risk inherentface significant challenges in transforming its oil-dominated generation base to renewables.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.”   Moody’s stated that they could reevaluate Hawaiian Electric’s rating and outlook upon the closing of the pending merger with NEE.
Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from) net income. For the first nine months of 2015,In 2016, net cash provided by operating activities increased by $31 million, compared to the prior year.$66 million. For the first ninesix months of 2015,2016, noncash depreciation and amortization amounted to $143$97 million due to an increase in plant and equipment.equipment and deferred income taxes increased $32 million. Further, for the first nine months of 2015, the changes in assets and liabilitiesnet cash provided by operating activities included a net decrease of $9$13 million in accounts receivable and accrued unbilled revenues due largely to the timingdecrease in customer bills as a result of customer payments, a decrease of $36 million inlower fuel oil stock,prices included in rates, and a $40$23 million decreaseincrease in accounts payable due to the decrease in the fuel oil prices and timing of vendor payments.
For the first ninesix months of 2015,2016, net cash used in investing activities decreased byincreased $1 million compared to the prior year. Cash usedFurther in investing activities consisted primarily of2016, capital expenditures partlyamounted to $197 million, offset by contributions in aid of construction.construction of $17 million.
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. For the first ninesix months of 2015,in 2016, cash flows from financing activities increasedchanged by $9a negative $53 million compared to the prior year. For the first ninesix months of 2015,2016, cash provided byflows from financing activities consisted primarily of net proceeds received from short-term borrowings of $95 million, offset by $69$48 million of common and preferred stock dividend payments duringoffset by the first nine monthsproceeds received from short-term borrowings of 2015.

78


Due to the change in the RAM, the number of other high priority issues before the PUC and the continuing refinement of transformation plans, the Utilities forecast 2015 net capital expenditures to approximate $310 million (which was reduced from $420 million). As a result, Hawaiian Electric will not need an equity infusion from HEI in 2015. In October 2015, Hawaiian Electric issued $80 million of long-term debt. See Note 12 of “Notes to Consolidated Financial Statements.”$37 million.



Bank
  Three months ended June 30 Increase  
(in millions) 2016 2015 (decrease) Primary reason(s)
Interest income $54
 $49
 $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, 2016 increased by $256 million compared to the same period in 2015 as average commercial real estate, home equity lines of credit, consumer and residential balances increased by $225 million, $34 million, $24 million and $21 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The yield on earning assets increased by 9 basis points as the adjustable rate loans repriced upward with the increase in the prime rate at end of 2015, which resulted in an increase in loan portfolio yields of 9 basis points. The average investment securities portfolio balance increased by $257 million due to the purchase of investments with excess liquidity. The average FHLB stock balance decreased by $28 million as FHLB stock in excess of the required holdings was repurchased by the FHLB.
Noninterest income 17
 17
 —
 Noninterest income was flat for the three months ended June 30, 2016 compared to noninterest income for the three months ended June 30, 2015. A decrease in mortgage banking income of $0.5 million as result of a decrease in residential mortgage loan sales volume in second quarter of 2016 compared to the same period in 2015 was offset by gains on the sale of investment securities of $0.6 million.
Revenues 71
 66
 5
  
Interest expense 3
 3
 —
 Interest expense was relatively 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 June 30, 2016 increased by $414 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $333 million and $81 million, respectively. Other borrowings decreased by $29 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 2 basis points.
Provision for loan losses 5
 2
 3
 The provision for loan losses increased by $2.9 million primarily due to increased reserves for growth in the loan portfolio and additional loan loss reserves for commercial loans due to downgrades of specific commercial credits. The provision for loan losses for the quarter ended June 30, 2015 included the reversal of the Pahoa lava loss reserves. Credit quality and trends continued to be stable and good, reflecting prudent credit risk management and a strong Hawaii economy. Delinquency rates have decreased from 0.55% at June 30, 2015 to 0.49% at June 30, 2016. The net charge-off ratio for the three months ended June 30, 2016 was 0.15% compared to a net charge-off ratio of 0.11% 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 a loan charge-off related to one commercial borrower.
Noninterest expense 43
 41
 2
 The increase in noninterest expense for the three months ended June 30, 2016 compared to the same period in 2015 was primarily due to the costs related to the replacement and upgrade of the electronic banking platform.
Expenses 51
 46
 5
  
Operating income 20
 20
 —
 Higher net interest income and noninterest income was offset by higher provision loan losses and higher noninterest expense.
Net income 13
 13
 —
  



  Three months ended 
 September 30		 Increase  
(in millions) 2015 2014 (decrease) Primary reason(s)
Interest income $51
 $49
 $2
 The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for the third quarter of 2015 increased by $187 million compared to the same period in 2014 as average commercial real estate, commercial, residential and home equity lines of credit loan balances increased by $89 million, $38 million, $28 million, and $24 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. Yields on earning assets decreased by 10 basis points. Loan portfolio yields were impacted by the low interest rate environment as new loan production yields were generally lower than the average loan portfolio yields. The average investment and mortgage-related securities portfolio balance increased by $221 million due to the purchase of investments with excess liquidity. The average FHLB stock balance decreased by $69 million as FHLB stock in excess of the required holdings was repurchased by the FHLB.
Noninterest income 18
 15
 3
 Higher noninterest income primarily due to the $2.0 million gain on sale of real estate, $0.8 million higher deposit fee income and $0.6 million higher mortgage banking income.
Revenues 69
 64
 5
  
Interest expense 3
 3
 —
 Interest expense was flat as higher interest-bearing liability balances were offset by lower rates on interest-bearing liabilities. Average deposit balances for the third quarter of 2015 increased by $304 million compared to the same period in 2014 due to an increase in core deposits of $290 million. Average term certificate balances increased by $14 million. Other borrowings increased by $85 million primarily due to an increase in repurchase agreements. The interest-bearing liability rate decreased by 1 basis point.
Provision for loan losses 3
 2
 1
 The provision for loan losses increased by $1.4 million primarily due to growth in the loan portfolio and net charge-offs during the quarter. Credit quality and trends continue to be strong, reflecting prudent credit risk management and a strong Hawaii economy. ASB had a net charge-off ratio for the third quarter of 2015 of 0.10% compared to a net charge-off ratio of 0.04% in the third quarter of 2014. The increase in net charge-offs were due to ASB’s strategic expansion of its unsecured consumer loan product with risk-based pricing and lower recoveries.
Noninterest expense 42
 38
 4
 The increase in noninterest expense for the third quarter of 2015 compared to the same period in 2014 was primarily due to $1.8 million higher employee benefit costs and $0.4 million reserve for unfunded loan commitments.
Expenses 48
 43
 5
  
Operating income 21
 21
 —
 Higher net interest income and noninterest income were offset by higher noninterest expenses and higher provision for loan losses.
Net income 13
 13
 —
  


79


 Nine months  
 ended September 30		 Increase   Six months ended June 30 Increase  
(in millions) 2015 2014 (decrease) Primary reason(s) 2016 2015 (decrease) Primary reason(s)
Interest income $148
 $142
 $6
 The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for the nine months ended September 30, 2015 increased by $230 million compared to the same period in 2014 as average commercial real estate, home equity lines of credit and residential balances increased by $109 million, $44 million, and $44 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The yield on earning assets decreased by 9 basis points. Loan portfolio yields were impacted by the low interest rate environment as new loan production yields were generally lower than the average loan portfolio yields. The average investment and mortgage-related securities portfolio balance increased by $113 million due to the purchase of investments with excess liquidity. The average FHLB stock balance decreased by $47 million as FHLB stock in excess of the required holdings was repurchased by the FHLB. $108
 $98
 $10
 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, 2016 increased by $222 million compared to the same period in 2015 as average commercial real estate, home equity lines of credit, residential and consumer balances increased by $200 million, $31 million, $19 million and $16 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The yield on earning assets increased by 9 basis points as the adjustable rate loans repriced upward with the increase in the prime rate at end of 2015, which resulted in an increase in loan portfolio yields of 9 basis points. The average investment securities portfolio balance increased by $281 million due to the purchase of investments with excess liquidity. The average FHLB stock balance decreased by $43 million as FHLB stock in excess of the required holdings was repurchased by the FHLB.
Noninterest income 51
 46
 5
 Higher noninterest income was primarily due to a $3.6 million increase in gain on sale of loans a result of higher refinancing activity, $2.4 million higher deposit fee income and $2.0 million gain on sale of real estate, partly offset by $2.8 million lower gain on sale of securities in 2015 compared to 2014 as a result of the gain from the sale of ASB’s municipal bond portfolio in 2014. 32
 32
 —
 Noninterest income was flat for the six months ended June 30, 2016 compared to noninterest income for the six months ended June 30, 2015 primarily due to lower mortgage banking income of $1.1 million as result of a decrease in residential mortgage loan sales volume for the first half of 2016 compared to the same period in 2015 was offset by gains on sale of investment securities of $0.6 million and higher fee income on financial products in 2016.
Revenues 199
 188
 11
  140
 130
 10
 
Interest expense 8
 8
 —
 Interest expense was flat as higher interest-bearing liability balances were offset by lower rates on interest-bearing liabilities. Average deposit balances for the nine months ended September 30, 2015 increased by $285 million compared to the same period in 2014 due to an increase in core deposits of $278 million. Average term certificate balances increased by $7 million. Other borrowings increased by $67 million primarily due to an increase in repurchase agreements. The interest-bearing liability rate decreased by 1 basis point. 6
 5
 1
 Interest expense increased slightly due to growth in the deposit liabilities. Average deposit balances for the six months ended June 30, 2016 increased by $388 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $315 million and $73 million, respectively. Other borrowings decreased by $9 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 2 basis points.
Provision for loan losses 6
 4
 2
 The provision for loan losses increased by $1.9 million due to loan growth and net charge-offs, partly offset by the reversal of the Pahoa lava reserves and commercial loan payoffs. Credit quality and trends continue to be strong, reflecting prudent credit risk management and a strong Hawaii economy. The net charge-off ratio for the nine months ended September 30, 2015 was 0.08% compared to a net charge-off ratio for the nine months ended September 30, 2014 of 0.01%. The increase in net charge-offs were due to ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing and lower recoveries from previously charged off loans. 10
 3
 7
 The provision for loan losses increased by $7.1 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 six months ended June 30, 2015 included the reversal of the Pahoa lava reserves. Credit quality and trends continued to be stable and good, reflecting prudent credit risk management and a strong Hawaii economy. Delinquency rates have decreased from 0.55% at June 30, 2015 to 0.49% at June 30, 2016. The net charge-off ratio for the six months ended June 30, 2016 was 0.18% 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 two commercial borrowers.
Noninterest expense 124
 115
 9
 Noninterest expense for the nine months ended Sepember 30, 2015 was $9.1 million higher than the noninterest expense for the same period in 2014 primarily due to higher employee benefit costs, an increase in retail delivery compensation costs, reversal of debit card expenses in 2014 with no similar reversal in 2015 and reserves for unfunded loan commitments. 84
 82
 2
 The increase in noninterest expense for the six months ended June 30, 2016 was primarily due to the costs related to the replacement and upgrade of the electronic banking platform.
Expenses 138
 127
 11
  100
 90
 10
 
Operating income 61
 61
 —
 Higher net interest income and noninterest income were offset by higher noninterest expenses and higher provision for loan losses. 40
 40
 —
 Higher net interest income was offset by higher provision loan losses, lower noninterest income and higher noninterest expense.
Net income 40
 39
 1
  26
 26
 —
 

                       See Note 5 of the Consolidated Financial Statements and “Economic conditions” in the “HEI Consolidated” section above.
                       Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers.

80



                       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) 2015 2014 2015 2014 2016 2015 2016 2015
Return on average assets 0.92
 0.98
 0.92
 0.97
 0.86
 0.89
 0.85
 0.93
Return on average equity 9.73
 9.88
 9.69
 9.83
 9.22
 9.38
 9.06
 9.67
Net interest margin 3.53
 3.62
 3.52
 3.60
 3.58
 3.52
 3.60
 3.52
Average balance sheet and net interest margin.  The following tables set forthprovides a summary of average balances together withincluding major categories of interest, earnedearning assets and accrued, and resulting yields and costs:interest-bearing liabilities:
Three months ended September 30 2015 2014
Three months ended June 30 2016 2015
(dollars in thousands) Average
balance		 
Interest1
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1 income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest income/
expense
 Yield/
rate (%)
Assets:  
  
  
  
  
  
  
  
  
  
  
  
Other investments 2
 $122,322
 $86
 0.27
 $152,476
 $68
 0.17
Securities purchased under resale agreements —
 —
 —
 —
 —
 —
Interest-earning deposits $64,821
 $81
 0.49
 $158,368
 $100
 0.25
FHLB Stock 11,284
 44
 1.58
 39,379
 27
 0.27
Available-for-sale investment securities 762,572
 4,127
 2.17
 541,262
 2,705
 2.00
 894,684
 4,318
 1.93
 637,893
 3,179
 1.99
Loans                        
Residential 1-4 family 2,065,421
 22,493
 4.36
 2,037,715
 22,725
 4.46
 2,075,255
 22,201
 4.28
 2,053,803
 22,560
 4.39
Commercial real estate 663,805
 6,690
 4.00
 574,779
 6,407
 4.43
 867,266
 8,716
 4.01
 641,927
 6,499
 4.05
Home equity line of credit 828,096
 6,684
 3.20
 804,504
 6,576
 3.24
 856,960
 6,989
 3.28
 822,862
 6,523
 3.18
Residential land 17,876
 268
 5.97
 16,888
 257
 6.09
 18,758
 285
 6.08
 17,767
 288
 6.50
Commercial 813,475
 7,376
 3.58
 775,503
 7,368
 3.76
 762,247
 7,595
 3.99
 812,929
 7,403
 3.64
Consumer 117,699
 2,902
 9.79
 110,471
 2,199
 7.90
 142,955
 3,904
 10.98
 118,652
 2,762
 9.34
Total loans 3,4
 4,506,372
 46,413
 4.10
 4,319,860
 45,532
 4.20
Total interest-earning assets 3
 5,391,266
 50,626
 3.74
 5,013,598
 48,305
 3.84
Total loans 1,2
 4,723,441
 49,690
 4.21
 4,467,940
 46,035
 4.12
Total interest-earning assets 1
 5,694,230
 54,133
 3.81
 5,303,580
 49,341
 3.72
Allowance for loan losses (46,726)  
  
 (42,812)  
  
 (52,749)  
  
 (46,221)  
  
Non-interest-earning assets 486,995
  
  
 461,925
  
  
 503,617
  
  
 490,081
  
  
Total assets $5,831,535
  
  
 $5,432,711
  
  
 $6,145,098
  
  
 $5,747,440
  
  
Liabilities and shareholder’s equity:  
  
  
  
  
  
  
  
  
  
  
  
Savings $1,990,016
 $319
 0.06
 $1,888,932
 $289
 0.06
 $2,099,422
 $343
 0.07
 $1,968,345
 $309
 0.06
Interest-bearing checking 784,265
 35
 0.02
 742,018
 32
 0.02
 834,821
 42
 0.02
 778,653
 34
 0.02
Money market 164,200
 52
 0.13
 166,295
 51
 0.12
 165,433
 52
 0.13
 163,036
 50
 0.12
Time certificates 453,460
 949
 0.83
 439,563
 940
 0.85
 520,151
 1,254
 0.97
 439,248
 873
 0.80
Total interest-bearing deposits 3,391,941
 1,355
 0.16
 3,236,808
 1,312
 0.16
 3,619,827
 1,691
 0.19
 3,349,282
 1,266
 0.15
Advances from Federal Home Loan Bank 101,739
 794
 3.05
 101,543
 794
 3.06
 101,648
 785
 3.06
 100,000
 784
 3.10
Securities sold under agreements to repurchase 238,822
 721
 1.18
 153,909
 644
 1.64
 179,559
 682
 1.51
 209,998
 703
 1.33
Total interest-bearing liabilities 3,732,502
 2,870
 0.30
 3,492,260
 2,750
 0.31
 3,901,034
 3,158
 0.32
 3,659,280
 2,753
 0.30
Non-interest bearing liabilities:  
  
    
  
    
  
    
  
  
Deposits 1,440,136
  
   1,291,463
  
   1,568,725
  
   1,424,883
  
  
Other 105,804
  
   112,532
  
   98,678
  
   115,448
  
  
Shareholder’s equity 553,093
  
   536,456
  
   576,661
  
   547,829
  
  
Total liabilities and shareholder’s equity $5,831,535
  
   $5,432,711
  
   $6,145,098
  
   $5,747,440
  
  
Net interest income   $47,756
     $45,555
    
 $50,975
    
 $46,588
  
Net interest margin (%) 5
  
   3.53
  
   3.62
Net interest margin (%) 3
  
  
 3.58
  
  
 3.52

81




Nine months ended September 30 2015 2014
Six months ended June 30 2016 2015
(dollars in thousands) Average
balance		 
Interest1
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest1 income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest
income/
expense
 Yield/
rate (%)		 Average
balance		 
Interest income/
expense
 Yield/
rate (%)
Assets:  
  
  
  
  
  
  
  
  
  
  
  
Other investments 2
 $172,715
 $312
 0.24
 $172,051
 $230
 0.18
Securities purchased under resale agreements —
 —
 —
 6,813
 20
 0.38
Interest-earning deposits $72,070
 $180
 0.49
 $144,408
 $181
 0.25
FHLB Stock 11,031
 88
 1.61
 53,922
 45
 0.17
Available-for-sale investment securities 650,645
 10,258
 2.10
 537,904
 8,658
 2.15
 874,542
 9,192
 2.10
 593,754
 6,131
 2.07
Loans                        
Residential 1-4 family 2,059,921
 67,714
 4.38
 2,016,331
 67,869
 4.49
 2,075,890
 44,521
 4.29
 2,057,125
 45,221
 4.40
Commercial real estate 646,769
 19,251
 3.97
 537,694
 17,284
 4.29
 837,837
 16,880
 4.02
 638,110
 12,561
 3.95
Home equity line of credit 824,510
 19,683
 3.19
 780,760
 19,088
 3.27
 854,145
 13,854
 3.26
 822,687
 12,999
 3.19
Residential land 17,347
 830
 6.38
 16,353
 751
 6.12
 18,482
 561
 6.07
 17,078
 562
 6.59
Commercial 805,333
 21,847
 3.61
 782,371
 21,767
 3.71
 755,510
 14,967
 3.96
 801,194
 14,471
 3.63
Consumer 118,974
 8,321
 9.35
 109,748
 6,306
 7.68
 135,572
 7,344
 10.89
 119,622
 5,419
 9.13
Total loans 3,4
 4,472,854
 137,646
 4.10
 4,243,257
 133,065
 4.18
Total interest-earning assets 3
 5,296,214
 148,216
 3.73
 4,960,025
 141,973
 3.82
Total loans 1,2
 4,677,436
 98,127
 4.20
 4,455,816
 91,233
 4.11
Total interest-earning assets 1
 5,635,079
 107,587
 3.82
 5,247,900
 97,590
 3.73
Allowance for loan losses (46,295)  
  
 (41,701)  
  
 (51,599)  
  
 (46,076)  
  
Non-interest-earning assets 488,103
  
  
 454,127
  
  
 500,412
  
  
 488,666
  
  
Total assets $5,738,022
  
  
 $5,372,451
  
  
 $6,083,892
  
  
 $5,690,490
  
  
Liabilities and shareholder’s equity:  
  
  
  
  
  
  
  
  
  
  
  
Savings $1,967,446
 $928
 0.06
 $1,866,482
 $835
 0.06
 $2,073,790
 $676
 0.07
 $1,955,974
 $609
 0.06
Interest-bearing checking 776,100
 102
 0.02
 732,270
 93
 0.02
 828,345
 84
 0.02
 771,950
 67
 0.02
Money market 163,659
 152
 0.12
 174,648
 163
 0.13
 166,338
 105
 0.13
 163,384
 100
 0.12
Time certificates 442,224
 2,699
 0.82
 434,553
 2,683
 0.83
 509,884
 2,418
 0.95
 436,513
 1,750
 0.81
Total interest-bearing deposits 3,349,429
 3,881
 0.15
 3,207,953
 3,774
 0.16
 3,578,357
 3,283
 0.18
 3,327,821
 2,526
 0.15
Advances from Federal Home Loan Bank 100,586
 2,353
 3.09
 100,520
 2,353
 3.09
 101,854
 1,571
 3.05
 100,000
 1,559
 3.10
Securities sold under agreements to repurchase 216,066
 2,115
 1.29
 149,340
 1,910
 1.69
 193,296
 1,381
 1.42
 204,499
 1,394
 1.36
Total interest-bearing liabilities 3,666,081
 8,349
 0.30
 3,457,813
 8,037
 0.31
 3,873,507
 6,235
 0.32
 3,632,320
 5,479
 0.30
Non-interest bearing liabilities:  
  
  
  
  
  
  
  
  
  
  
  
Deposits 1,413,351
  
  
 1,269,355
  
  
 1,537,660
  
  
 1,399,737
  
  
Other 111,175
  
  
 113,895
  
  
 99,427
  
  
 113,905
  
  
Shareholder’s equity 547,415
  
  
 531,388
  
  
 573,298
  
  
 544,528
  
  
Total liabilities and shareholder’s equity $5,738,022
  
  
 $5,372,451
  
  
 $6,083,892
  
  
 $5,690,490
  
  
Net interest income  
 $139,867
  
  
 $133,936
  
  
 $101,352
  
  
 $92,111
  
Net interest margin (%) 5
  
  
 3.52
  
  
 3.60
Net interest margin (%) 3
  
  
 3.60
  
  
 3.52
1       Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of nil and nil for the three months ended September 30, 2015 and 2014, respectively, and nil and $0.2 million for the nine months ended September 30, 2015 and 2014, respectively.
2
Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank.
31    
Includes loans held for sale, at lower of cost or fair value.
42    
Includes loan fees of $0.6$0.7 million and $0.8$0.7 million for the three months ended SeptemberJune 30, 20152016 and 2014,2015, respectively, and $1.9$1.5 million and $2.6$1.3 million for the ninesix months ended SeptemberJune 30, 20152016 and 2014,2015, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.
53   
Defined as net interest income on a fully taxable equivalent basis, as a percentage of average total interest-earning assets.
Earning assets, costinginterest-bearing 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 costinginterest-bearing liabilities. The interest rate environment has been impacted by disruptions in the financial markets over a period of several years and these conditions have continued to havehad a negative impact on ASB’s net interest margin.margin during that period. With the recent interest increase by the Feds, ASB’s net interest margin has increased.
                       Loan originationsThe loan portfolio and mortgage-related securities are ASB’s primary earning assets.

82



                       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, 2015 December 31, 2014 June 30, 2016 December 31, 2015
(dollars in thousands) Balance % of total Balance % of total Balance % of total Balance % of total
Real estate:  
  
  
  
  
  
  
  
Residential 1-4 family $2,062,458
 45.4
 $2,044,205
 46.0
 $2,064,343
 43.4
 $2,069,665
 44.8
Commercial real estate 618,113
 13.6
 531,917
 12.0
 740,322
 15.6
 690,561
 14.9
Home equity line of credit 832,267
 18.3
 818,815
 18.4
 860,522
 18.1
 846,294
 18.3
Residential land 17,369
 0.4
 16,240
 0.4
 18,447
 0.4
 18,229
 0.4
Commercial construction 80,230
 1.8
 96,438
 2.2
 134,642
 2.8
 100,796
 2.2
Residential construction 14,318
 0.3
 18,961
 0.4
 16,004
 0.3
 14,089
 0.3
Total real estate, net 3,624,755
 79.8
 3,526,576
 79.4
 3,834,280
 80.6
 3,739,634
 80.9
Commercial 798,428
 17.6
 791,757
 17.8
 772,565
 16.2
 758,659
 16.4
Consumer 118,450
 2.6
 122,656
 2.8
 153,212
 3.2
 123,775
 2.7
 4,541,633
 100.0
 4,440,989
 100.0
 4,760,057
 100.0
 4,622,068
 100.0
Less: Deferred fees and discounts (6,229)  
 (6,338)  
 (5,103)  
 (6,249)  
Allowance for loan losses (48,274)  
 (45,618)  
 (55,331)  
 (50,038)  
Total loans, net $4,487,130
  
 $4,389,033
  
 $4,699,623
  
 $4,565,781
  
       Home equity — key credit statistics.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 3% of the portfolio and are included in the amortizing balances identified in the table above.
.
September 30, 2015 December 31, 2014June 30, 2016 December 31, 2015
Outstanding balance (in thousands)$832,267
 $818,815
$860,522
 $846,294
Percent of portfolio in first lien position42.5% 40.9 %43.7 % 42.9%
Net charge-off (recovery) ratio0.02% (0.07)%(0.01)% 0.02%
Delinquency ratio0.21% 0.25 %0.22 % 0.25%
     End of draw period – interest only Current     End of draw period – interest only Current
September 30, 2015 Total Interest only 2015-2016 2017-2019 Thereafter amortizing
June 30, 2016 Total Interest only 2016-2017 2018-2020 Thereafter amortizing
Outstanding balance (in thousands) $832,267
 $632,835
 $549
 $131,001
 $501,285
 $199,432
 $860,522
 $660,359
 $10,048
 $138,790
 $511,521
 $200,163
% of total 100% 76% —% 16% 60% 24% 100% 77% 1% 16% 60% 23%
 
The home equity line               ��       As of credit (HELOC)June 30, 2016, the HELOC portfolio makes upcomprised 18% 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%97% of the total HELOC portfolio and is the current product offering. Within this product type, borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed rate loan with level principal and interest payments. As of SeptemberJune 30, 20152016, approximately 20% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older vintage equity lines represent 4% of the portfolio and are included in the amortizing balances identified in the table above.
Loan portfolio risk elements.  See Note 5 of the Consolidated Financial Statements.


Available-for-sale investment securities.  ASB’s investment portfolio was comprised as follows:
 September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015
(dollars in thousands) Balance % of total Balance % of total Balance % of total Balance % of total
U.S. Treasury and federal agency obligations $211,118
 27% $119,560
 22% $198,159
 22% $212,959
 26%
Mortgage-related securities — FNMA, FHLMC and GNMA 574,719
 73
 430,834
 78
 695,862
 78
 607,689
 74
Total available-for-sale investment securities $785,837
 100% $550,394
 100% $894,021
 100% $820,648
 100%

83


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, 20152016, ASB’s costinginterest-bearing liabilities consisted of 93%95% deposits and 7%5% other borrowings compared to costing liabilities of 94% deposits and 6% other borrowings as of December 31, 2014.2015. The weighted average cost of deposits for the first ninesix months of 2016 and 2015 was 0.13% and 2014 was 0.11%., respectively.
Federal Home Loan Bank Merger. In the second quarter of 2015, 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. 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 those instruments,the investment securities, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.the investment securities.
As of SeptemberJune 30, 20152016 and December 31, 2014,, ASB had an unrealized gain, net of taxes, on available-for-sale investmentsinvestment securities (including securities pledged for repurchase agreements) in AOCI of $4.1$8.1 million and $0.5compared to an unrealized loss, net of taxes, of $1.9 million respectively.at December 31, 2015. See “Item 3. Quantitative and qualitative disclosures about market risk.”risk” for a discussion of ASB’s interest rate risk sensitivity.
During the first six months of 2016, ASB recorded a provision for loan losses of $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 ninesix months of 2015, ASB recorded a provision for loan losses of $5.4$2.4 million primarily due to growth inloan loss reserves for the commercial real estate and commercial loan portfolio and net charge-offs including lower recoveriesportfolios due to downgrades of previously charged off loans,specific credits, partly offset by the reversal of the Pahoa lava reserves and commercial loan payoffs. During the first nine months of 2014, ASB recorded a provision for loan losses of $3.6 million primarily due to growth in the loan portfolio and net charge-offs during the year for consumer loans. 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) 2015 2014 2014 2016 2015 2015
Allowance for loan losses, January 1 $45,618
 $40,116
 $40,116
 $50,038
 $45,618
 $45,618
Provision for loan losses 5,436
 3,566
 6,126
 9,519
 2,439
 6,275
Less: net charge-offs 2,780
 221
 624
 4,226
 1,692
 1,855
Allowance for loan losses, end of period $48,274
 $43,461
 $45,618
 $55,331
 $46,365
 $50,038
Ratio of net charge-offs during the period to average loans outstanding (annualized) 0.08% 0.01% 0.01% 0.18% 0.08% 0.04%
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 unfunded reserve is adjusted by recording an expense or recovery in other noninterest expense. As of June 30, 2016 and December 31, 2015, the reserve for unfunded loan commitments was $1.8 million and $1.7 million, respectively.
Legislation and regulation.  ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (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 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, 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. If the Spin-Off of ASB Hawaii occurs as contemplated by the Merger Agreement, HEI (or its successor) will no longer be required to serve as a source of strength to ASB. The Dodd-Frank Act also imposes 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

84


potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.”
The Dodd-Frank Act established the Bureau. It has authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower.
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;state, (2) the state law prevents or significantly interferes with a bank’s exercise of its power;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 iswas 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. ASB’sThe 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, noror 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 tierTier 1 capital ratio of 4.5%, a tierTier 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

85


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, 20152016, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.2%11.9%, a Tier-1 capital ratio of 12.2%11.9%, a Total capital ratio of 13.4%13.2% and a Tier-1 leverage ratio of 8.8%8.7%.
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 Spin-Off of ASB Hawaii occurs as contemplated by the Merger Agreement, HEI (or its successor) will no longer be subject to the final capital rules as applied to SLHCs. 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.
Commitments and contingencies.  See Note 5 of the Consolidated Financial Statements.
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. ASB hashad 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 hashad receded, the lava flow remainsremained 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.


FINANCIAL CONDITION
Liquidity and capital resources.
(dollars in millions) September 30, 2015 December 31, 2014 % change June 30, 2016 December 31, 2015 % change
Total assets $5,855
 $5,566
 5 $6,188
 $6,015
 3
Available-for-sale investment securities 786
 550
 43 894
 821
 9
Loans receivable held for investment, net 4,487
 4,389
 2 4,700
 4,566
 3
Deposit liabilities 4,826
 4,623
 4 5,232
 5,025
 4
Other bank borrowings 369
 291
 27 273
 329
 (17)
As of SeptemberJune 30, 20152016, ASB was one of Hawaii’s largest financial institutions based on assets of $5.9$6.2 billion and deposits of $4.8$5.2 billion.
As of SeptemberJune 30, 20152016, ASB’s unused FHLB borrowing capacity was approximately $1.7 billion. As of SeptemberJune 30, 20152016, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.8$1.9 billion. Commitments to lend to borrowers whose loan terms have been impaired or modified in troubled debt restructurings totaled $0.1$2.7 million at SeptemberJune 30, 2015.2016. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

86


For the ninesix months ended SeptemberJune 30, 2015,2016, net cash provided by ASB’s operating activities was $35$25 million. Net cash used during the same period by ASB’s investing activities was $273$205 million, primarily due to purchases of investment securities of $327$177 million, a net increase in loans receivable of $102$156 million and additions to premises and equipment of $10$6 million, partly offset by repayments and calls of investment securities of $96 million, net redemption of stock from the FHLB of $59$103 million, proceeds from the sale of real estate held-for-saleinvestments securities of $7$16 million and proceeds from the sale of premises and equipmentloans of $4commercial loans of $14 million. Net cash provided by financing activities during this period was $254$134 million, primarily due to increases in deposit liabilities of $203$207 million, partly offset by a net increasedecrease in retail repurchase agreements of $68$27 million, and proceeds frommaturities of securities sold under agreements to repurchase of $10$29 million partly offset by the payment of $23and $18 million in common stock dividends to HEI (through ASB Hawaii) and a net decrease in mortgage escrow deposits of $4 million..
ASB believes that maintaining a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of SeptemberJune 30, 20152016, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a Common equity tier-1Tier-1 ratio of 12.2%11.9% (6.5%), a Tier-1 capital ratio of 12.2%11.9% (8.0%), a Total capital ratio of 13.4%13.2% (10.0%) and a Tier-1 leverage ratio of 8.8%8.7% (5.0%). As of December 31, 2015, ASB was well-capitalized with a Common equity Tier-1 ratio of 12.1%, Tier-1 capital ratio of 12.1%, a Total capital ratio of 13.3% and a Tier-1 leverage ratio of 8.8%. FRB approval is required before ASB can 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 pages 79 to 81, HEI’s and Hawaiian Electric’s Quantitative and Qualitative Disclosures About Market Risk in Part II, Item 7A of HEI’s 20142015 Form 10-K.10-K (pages 80 to 82).
ASB’s interest-rate risk sensitivity measures as of SeptemberJune 30, 20152016 and December 31, 20142015 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, 2015 December 31, 2014 September 30, 2015 December 31, 2014 June 30, 2016 December 31, 2015 June 30, 2016 December 31, 2015
+300 1.0% 1.9% (9.7)% (6.1)% 2.1% 1.6% (6.6)% (9.3)%
+200 0.1
 0.7
 (5.5) (2.9) 0.8
 0.6
 (2.6) (5.3)
+100 (0.2) 0.1
 (2.0) (0.7) —
 (0.1) 0.1
 (1.9)
-100 (0.5) (0.5) (1.3) (2.5) (0.2) (0.5) (5.1) (1.2)
Management believes that ASB’s interest rate risk position as of SeptemberJune 30, 20152016 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was slightly lessmore asset sensitive for all rate increases as of SeptemberJune 30, 20152016 compared to December 31, 2014. Savings 2015. The repricing assumption of certain core deposits was updated and resulted in slower repricing of those


deposit balances grew by $75 million within the mix shiftingtwelve-month simulation period. This shift to higherless rate sensitive products. In addition, retail repurchase agreements, which have short-term repricing horizons,deposits increased by $68 million. These shifts to more rate sensitive liabilities lessened ASB’s asset sensitivity.
ASB’s base EVE increaseddecreased to $949$948 million as of SeptemberJune 30, 20152016 compared to $947$974 million as of December 31, 20142015 due to growththe decrease in capital.the yield curve which increased the market value of core deposits.
The change in EVE to rising rates became moreless sensitive as of SeptemberJune 30, 20152016 compared to December 31, 2014. The $235 million growth and shift in mix of the investment portfolio into longer duration securities and callable step-up debentures, which have the potential to extend in average life2015 as rates rise, lengthened 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 durations of the fixed rate mortgage and investment portfolio and increased EVE sensitivity.portfolios. On the liability side of the balance sheet, core deposit balancesdeposits grew $172by $126 million with the mix shifting to shorterlonger duration products and thereby increasing EVE sensitivity.products. Additionally, the repricing assumption of certain core deposits was updated, resulting in longer duration deposit liabilities.
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

87


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 PrincipalChief Executive Officer and PrincipalChief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
As of SeptemberJune 30, 2015,2016, an evaluation was performed under the supervision and with the participation of the Company’s management, including the PrincipalChief Executive Officer and PrincipalChief 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 Securities Exchange Act of 1934, as amended.Act. Management, including the Company’s PrincipalChief Executive Officer and PrincipalChief Financial Officer, concluded that the Company’s disclosure controls and procedures were not effective, as of SeptemberJune 30, 2015 due to2016, at the material weakness in the Company’s internal control over financial reporting described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. As discussed in the Company’s 2014 Annual Report on Form 10-K/A, the Company did not maintain effective controls over the preparation and review of its Consolidated Statement of Cash Flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the statement of cash flows, and management’s review process was not effective. Accordingly, management concluded that its internal control over financial reporting was not effective as of December 31, 2014.

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 20152016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Remediation. In order to address this material weakness, the Company’s management, with oversight from its Audit Committee of the Board of Directors of HEI, has taken steps and plans to take additional measures to remediate the underlying causes of the material weakness. The Company’s remediation plans related to the review of the Consolidated Statements of Cash Flows include a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statements of Cash Flows, and enhancing templates to facilitate the preparation and review of cash flows. New controls will be implemented and will be tested for operational effectiveness. Managementis committed to maintaining a strong internal control environment and believes this remediation effort will represent an improvement in controls. Management anticipates that the new controls, as or when implemented and when tested for a sufficient period of time, will remediate the material weakness.
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 Securities Exchange Act of 1934, as amended, 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 PrincipalChief Executive Officer and PrincipalChief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
As of SeptemberJune 30, 2015,2016, an evaluation was performed under the supervision and with the participation of Hawaiian Electric’s management, including the PrincipalChief Executive Officer and PrincipalChief 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 Securities


Exchange Act of 1934, as amended.Act. Management, including Hawaiian Electric’s PrincipalChief Executive Officer and PrincipalChief Financial Officer, concluded that Hawaiian Electric’s disclosure controls and procedures were not effective as of

88


September 30, 2015 due to the material weakness in Hawaiian Electric’s internal control over financial reporting described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. As discussed in Hawaiian Electric’s 2014 Annual Report on Form 10-K/A, Hawaiian Electric did not maintain effective controls over the preparation and review of Hawaiian Electric’s Consolidated Statement of Cash Flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the statement of cash flows, and management’s review process was not effective. Accordingly, management concluded that its internal control over financial reporting was not effective, as of December 31, 2014.June 30, 2016, 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 20152016 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.
Remediation. In order to address this material weakness, Hawaiian Electric’s management, with oversight from its Audit Committee of the Board of Directors of Hawaiian Electric, has taken steps and plans to take additional measures to remediate the underlying causes of the material weakness. Hawaiian Electric’s remediation plans related to the review of the Consolidated Statements of Cash Flows include a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statements of Cash Flows, and enhancing templates to facilitate the preparation and review of cash flows. New controls will be implemented, and will be tested for operational effectiveness. Management is committed to maintaining a strong internal control environment and believes this remediation effort will represent an improvement in controls. Management anticipates that the new controls, as or when implemented and when tested for a sufficient period of time, will remediate the material weakness.
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 20142015 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, 4 and 5 of the 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 2625 to 35 of HEI’s and Hawaiian Electric’s 20142015 Form 10-K as amended by Amendment No. 1 on Form 10-K/A, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and the Consolidated Financial Statements herein. Also, see “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.

89


Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of HEI common shares were made in the open market during the thirdsecond quarter to satisfy the requirements of certain plans as follows:
ISSUER PURCHASES OF EQUITY SECURITIES
Period*
(a)
Total Number of Shares Purchased **
 (b)
Average
Price Paid
per Share **
 (c)
 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 (d)
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 to 31, 201522,666
$30.25—
NA
August 1 to 31, 201515,466
$29.12—
NA
September 1 to 30, 2015265,231
$27.67—
NA
Period*
(a)
Total Number of Shares Purchased **
 (b)
Average
Price Paid
per Share **
 (c)
 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 (d)
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 to 30, 2016—NA— NA
May 1 to 31, 2016—NA— NA
June 1 to 30, 201622,50033.43— 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 shares listed in column (a), 19,79619,400 of the 22,666 shares, 13,366 of the 15,466 shares and 232,931 of the 265,23122,500 shares were purchased for the DRIP; 28,100HEIRSP and 3,100 of the 265,231 shares were purchased for the HEIRSP; and 2,870 of the 22,666 shares, 2,100 of the 15,466 shares and 4,200 of the 265,23122,500 shares were purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.


Item 5. Other Information
A.           Ratio of earnings to fixed charges.
Nine months  
 ended September 30		 Years ended December 31Six months ended June 30 Years ended December 31
2015 2014 2014 2013 2012 2011 20102016 2015 2015 2014 2013 2012 2011
HEI and Subsidiaries 
  
  
  
  
  
  
 
  
  
  
  
  
  
Excluding interest on ASB deposits3.68
 3.93
 3.80
 3.55
 3.30
 3.24
 2.90
3.64
 3.31
 3.68
 3.80
 3.55
 3.30
 3.24
Including interest on ASB deposits3.54
 3.78
 3.65
 3.42
 3.15
 3.04
 2.65
3.46
 3.19
 3.54
 3.65
 3.42
 3.15
 3.04
Hawaiian Electric and Subsidiaries4.03
 4.19
 4.04
 3.72
 3.37
 3.52
 2.88
3.76
 3.65
 3.97
 4.04
 3.72
 3.37
 3.52
 
Prior period ratios reflect the retrospective application of ASU No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which was adopted as of January 1, 2015 and did not have a material impact on the Company’s financial condition or results of operations. See “Investments in qualified affordable housing projects” in Note 11 of the Consolidated Financial Statements.
See HEI Exhibit 12.1 and Hawaiian Electric Exhibit 12.2.

B. On August 2, 2016, Chester A. Richardson (68), Executive Vice President, General Counsel, Secretary and Chief Administrative Officer of HEI, notified the company of his retirement from his position effective as of October 17, 2016.
90


Item 6. Exhibits
 
HEI Exhibit 12.1 
Hawaiian Electric Industries, Inc. and Subsidiaries
Computation of ratio of earnings to fixed charges, ninesix months ended SeptemberJune 30, 20152016 and 20142015 and years ended December 31, 2015, 2014, 2013, 2012 2011 and 20102011
   
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. Ajello (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 12.2 
Hawaiian Electric Company, Inc. and Subsidiaries
Computation of ratio of earnings to fixed charges, ninesix months ended SeptemberJune 30, 20152016 and 20142015 and years ended December 31, 2015, 2014, 2013, 2012 2011 and 20102011
   
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


91

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. Ajello By/s/ Tayne S. Y. Sekimura
 James A. Ajello  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 16, 2015August 4, 2016 Date: November 16, 2015August 4, 2016


9291