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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;

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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), 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, unrest, ongoing conflicts in North Africa and the Middle East, terrorist acts, 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);

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the PUC’s potential delay in considering (and potential disapproval of actual or proposed) Hawaii Clean Energy Initiative (HCEI)-related costs; reliance by the Utilities on outside parties such as the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding solar power, wind power, proposed undersea cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

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the ability of the Utilities to develop, implement and recover the costs of implementing the Utilities’ action plans and business model changes that are being developed in response to the four orders that the Public Utilities Commission of the State of Hawaii (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 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;

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•	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 HEI 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;

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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));

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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).

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•	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.

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•	Distributed Generation Interconnection Plan to be filed within 120 days. 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 to be filed within 60 days. The plan shall achieve full implementation of the distribution circuit monitoring program within 180 days. The Utilities’ Plan was filed in June 2014.

•	Action Plan for improving efficiencies in the interconnection requirements studies to be filed within 30 days. The Utilities’ Plan was filed in May 2014.

•	The Utilities are to file monthly reports providing details about interconnection requirements studies.

•	Proposal to implement an integrated interconnection queue for each distribution circuit for each island grid to be filed within 120 days. The Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.

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(1)	Allowed intervention to ten parties in the proceeding,

(2)	Consolidated portions of two other proceedings related to rules on interconnection of distributed generating facilities with the Utilities system,

(3)	Declined to rule on distributed generation interconnection plan filed in August 2014 as a result of the Reliability Standards Working Group order,

(4)	Declined to rule on Utilities’ TDG motion, filed on January 20, 2015, and instead, directed the parties to collaborate on a “Transition Plan” from existing DER programs, including NEM, to a longer-term DER market structure;

(5)	Ordered the parties to collaborate on issues through a series of bi-weekly technical sessions;

(6)	Issued a Statement of Issues and a Procedural Schedule for the docket that directs the parties to file stipulations on areas of agreement, or separate statements of positions on issues where agreement cannot be reached, by June 29, 2015; and

(7)	Ordered the Utilities to submit weekly reports documenting progress on clearing interconnection applications, and monthly reports on the status of key technical developments to enable DER market growth.

(1)	new pricing provisions for future rooftop PV systems,

(2)	technical standards for advanced inverters,

(3)	new options for customers including battery-equipped rooftop PV systems,

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(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.

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*	Since loan was classified as impaired.

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1	$0.05 million and $0.03 million of this share-based compensation expense was capitalized in the second quarter of 2015 and 2014, respectively. $0.09 million and $0.07 million of this share-based compensation expense was capitalized in the six months ended June 30, 2015 and 2014, respectively.

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

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

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

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•	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,

•	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

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(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

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(5)	See “Hawaii Electric Light 2016 test year rate case” below.

(7)	See “Maui Electric 2015 test year rate case” below.

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In July 2011, the PUC directed Hawaiian Electric to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200-MW RFP, ordering that Hawaiian Electric shall amend its current draft of the Oahu 200-MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order.

•	In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii. The Hu Honua Bioenergy, LLC plant is currently scheduled to be in service in 2016.

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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. Bids were received in January 2015, and in February 2015, Ormat Technologies, Inc. was selected to provide 25 MW of additional geothermal energy, subject to successful contract negotiations and PUC approval of the final agreement.

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In August 2012, the battery facility at a 30-MW Kahuku wind farm experienced a fire. After the interconnection infrastructure was rebuilt and voltage regulation equipment was installed, the facility came up to full output in January 2014 to perform control system acceptance testing, and energy is being purchased at a base rate until PUC approval of an amendment to the PPA. An application for PUC approval of an amendment to the PPA was filed in April 2014.

•	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

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In February 2013, Hawaiian Electric issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding,” which seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per KWH. Proposals were received and Hawaiian Electric obtained waivers from the PUC Competitive Bidding Framework for certain projects, subject to certain conditions. In July 2015, the PUC issued orders approving (with conditions) four PPAs for a combined 137 MW of solar projects. Hawaiian Electric is reviewing these orders. Three additional waiver projects are still awaiting decision by the PUC.

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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, but continue to negotiate.

•	In October 2013, 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.

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In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s 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, LLC for the proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA.

•	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 June 2015, the PUC denied the request to waive Lanikuhana from competitive bidding requirements and Hawaiian Electric is seeking reconsideration of that decision.

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In March 2015, Hawaiian Electric requested PUC approval of a 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 when existing contracts are set to expire. Renewable Energy Group supplies 3 million to 7 million gallons per year to CIP CT-1 under its existing contract with Hawaiian Electric which was approved by the PUC in May 2012.

•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of June 30, 2015, there were 13 MW, 1 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 June 30, 2015, there were approximately 232 MW, 52 MW and 55 MW of installed net energy metering capacity from renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

•	In July 2015, Maui Electric signed two PPAs, each for a 2.87-MW solar facility, which are subject to PUC approval.

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2	Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank.

3	Includes loans held for sale, at lower of cost or fair value.

4	Includes loan fees of $0.7 million and $0.7 million for the three months ended June 30, 2015 and 2014, respectively, and $1.3 million and $1.8 million for the six months ended June 30, 2015 and 2014, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

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

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