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HAWAIIAN ELECTRIC INDUSTRIES INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations
[August 08, 2013]

HAWAIIAN ELECTRIC INDUSTRIES INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion updates "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in HEI's and HECO's Form 10-K for 2012 and should be read in conjunction with the 2012 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI's and HECO's 2012 Form 10-K, as well as the quarterly (as of and for the three and six months ended June 30, 2013) financial statements and notes thereto included in this Form 10-Q.

HEI Consolidated RESULTS OF OPERATIONS Three months ended (in thousands, except per June 30 % Primary reason(s) for share amounts) 2013 2012 change significant change* Revenues $ 796,730 $ 854,268 (7 ) Decrease for the electric utility segment, partly offset by increase in bank segment Operating income 82,370 79,406 4 Increase for the electric utility and bank segments and a reduced operating loss for the "other" segment Net income for common 40,588 38,800 5 Higher operating income and stock lower "interest expense-other than on deposit liabilities and other bank borrowings" partly offset by lower AFUDC Basic earnings per common $ 0.41 $ 0.40 2 Higher net income, partly share offset by higher weighted average shares outstanding Weighted-average number 98,660 96,693 2 Issuances of shares under of common shares the HEI Dividend outstanding Reinvestment and Stock Purchase Plan and other plans Six months ended (in thousands, except per June 30 % Primary reason(s) for share amounts) 2013 2012 change significant change* Revenues $ 1,580,794 $ 1,669,128 (5 ) Decrease for the electric utility segment, partly offset by increase in bank segment Operating income 153,027 155,222 (1 ) Decrease for the electric utility segment, partly offset by an increase in the bank segment and a reduced operating loss for the "other" segment Net income for common 74,267 77,116 (4 ) Lower operating income, stock higher "interest expense-other than on deposit liabilities and other bank borrowings" and lower AFUDC, partly offset by lower income taxes Basic earnings per common $ 0.75 $ 0.80 (6 ) Lower net income and higher share weighted average shares outstanding Weighted-average number 98,399 96,430 2 Issuances of shares under of common shares the HEI Dividend outstanding Reinvestment and Stock Purchase Plan and other plans -------------------------------------------------------------------------------- * Also, see segment discussions which follow.

Notes: The Company's effective tax rates (combined federal and state) for the second quarters of 2013 and 2012 were 37%. The Company's effective tax rates (combined federal and state) for the first six months of 2013 and 2012 were 36%.

HEI's consolidated ROACE was 8.5% for the twelve months ended June 30, 2013 and 10.4% for the twelve months ended June 30, 2012.

54 -------------------------------------------------------------------------------- Table of Contents Dividends. The payout ratios for the first six months of 2013 and full year 2012 were 82% and 87%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company's results of operations, the long-term prospects for the Company, and current and expected future economic conditions.

Economic conditions.

Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).

Hawaii's tourism industry, a significant driver of Hawaii's economy, set new records in 2012 and continues to grow in 2013, although at a slower pace. State visitor arrivals grew by 5.6% in the first half of 2013 over 2012. State visitor expenditures also grew, increasing by 6.9% in the first half of 2013 over 2012.

Average daily hotel room rates also continued to rise, but hotel occupancies were weaker. The outlook for the visitor industry remains positive, but is expected to expand at a slower pace. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the third quarter of 2013 to increase by 1.4% over the third quarter of 2012.

Hawaii's unemployment rate continues to decline, falling to 4.6% in June 2013, lower than the state's 6.0% rate in June 2012 and the June 2013 national unemployment rate of 7.6%.

Hawaii real estate activity, as indicated by the home resale market, strengthened in the first half of 2013. The median sales price for single family residential homes on Oahu increased by 0.8% and closed sales increased 11.6% in the first half of 2013 as compared to the same period in 2012. Oahu condominiums maintained strong momentum with median sales prices rising 6.8% and closed sales increasing 18.8% for the first half of 2013 as compared to the first half of 2012. The announcements of several new planned condominium projects in Honolulu were met with immediate interest, and several projects generated strong pre-sale demand.

Hawaii's petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan's nuclear production following the tragic earthquake and tsunami in March 2011 increased regional demand for energy supplies, including petroleum, and the prices of the utilities' fuels have accordingly remained at the elevated 2011 level through 2012 and into 2013.

At its meeting on June 18-19, 2013, the Federal Open Market Committee (FOMC) announced that it expects to continue to hold the federal funds rate target at 0% to 0.25% for as long as the unemployment rate is above 6.5% and the inflation outlook remains no more than 0.5 percentage point above a longer-run 2% goal.

The FOMC stated it will continue purchases of Treasury and agency mortgage-backed securities and employ other policy tools as appropriate to support progress toward the FOMC's statutory mandate of maximum employment and price stability. In June 2013, however, Chairman Ben Bernanke indicated that if the economy continues improving, the Fed may slow its bond-buying program later this year and possibly end it in mid-2014, thereby putting upward pressure on interest rates.

Overall, Hawaii's economy is expected to see increased growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and recovery in the construction industry. U.S. budget cuts, continued uncertainty in global economies, heightened tensions in Asia and potential pandemics pose possible risks to local economic growth.

Despite economic improvement, the electric utilities' KWH sales declined in 2012 and continued to decline in 2013. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities' 2013 and 2014 KWH sales are expected to further decline below 2012 levels.

Recent tax developments. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $116 million for 2012 over depreciation to which the Company would otherwise be entitled without the bonus provisions. The additional depreciation is attributable to the utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which is estimated to increase the Company's federal tax depreciation for 2013 by $120 million, primarily attributable to the utilities.

55 -------------------------------------------------------------------------------- Table of Contents The Internal Revenue Service (IRS) issued proposed and temporary regulations that provide a general framework for determining whether expenditures are deductible as repairs, effective January 1, 2014. The IRS plans to issue final regulations related to repairs deductions in 2013. In the interim, the IRS has directed its examination teams to discontinue the current examination of these repairs issues and withdraw any proposed adjustments previously made in the examination of tax years prior to 2012. Once final regulations are issued, the Company will review the regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for the current and future years.

The IRS recently 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. The utilities have begun to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when the election should be made.

Health care reform. On June 28, 2012, the US Supreme Court upheld the Patient Protection and Affordable Care Act, the 2010 health care reform law. Currently, Hawaii's Prepaid Health Care Act generally provides greater benefits to employees and dependents because of cost sharing limitations. The Company will continue to comply with its obligations under these laws and to monitor the interaction of the state and federal laws.

Retirement benefits. For the first six month of 2013, the Company's defined benefit pension and other postretirement benefit plans' assets generated a gain, after investment management fees, of 7.1%. The market value of these assets as of June 30, 2013 was $1.2 billion (including $1.1 billion for the utilities) compared to $1.1 billion at December 31, 2012 (including $1.0 billion for the utilities).

The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2013 will be $83 million ($81 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum contribution requirements, including requirements of the utilities' pension and other postretirement benefits tracking mechanisms and the plans' funding policies.

Commitments and contingencies. See Note 4, "Bank subsidiary," of HEI's "Notes to Consolidated Financial Statements" and Note 5, "Commitments and contingencies," of HECO's "Notes to Consolidated Financial Statements." Recent accounting pronouncements. See Note 11, "Recent accounting pronouncements," of HEI's "Notes to Consolidated Financial Statements." "Other" segment.

Three months Six months ended ended June 30 June 30 Primary reason(s) for (in thousands) 2013 2012 2013 2012 significant change Revenues $ 15 $ (5 ) $ 50 $ (7 ) Operating loss Lower administrative and (3,473 ) (3,964 ) (7,520 ) (8,314 ) general expenses Net loss Lower operating loss and (4,024 ) (4,765 ) (8,929 ) (9,626 ) interest expense The "other" business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.

56 -------------------------------------------------------------------------------- Table of Contents 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) June 30, 2013 December 31, 2012 Short-term borrowings-other than bank $ 126 4 % $ 84 3 % Long-term debt, net-other than bank 1,423 44 1,423 45 Preferred stock of subsidiaries 34 1 34 1 Common stock equity 1,625 51 1,594 51 $ 3,208 100 % $ 3,135 100 % HEI's short-term borrowings and HEI's line of credit facility were as follows: Six months ended June 30, 2013 Balance (in millions) Average balance June 30, 2013 December 31, 2012 Short-term borrowings(1) Commercial paper $ 81 $ 72 $ 84 Line of credit draws - - - Undrawn capacity under HEI's line of credit facility (expiring December 5, 2016) 125 125 -------------------------------------------------------------------------------- (1) This table does not include HECO'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 six months of 2013 was $96 million. At July 31, 2013, HEI had $70 million in outstanding commercial paper and its line of credit facility was undrawn.

HEI has a line of credit facility of $125 million (see Note 12 of HEI's "Notes to Consolidated Financial Statements"). There are customary conditions which must be met in order to draw on it, including compliance with its 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). In addition to customary defaults, HEI's failure to maintain its financial ratios, as defined in the credit agreement, or meet other requirements may result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated "Capitalization Ratio" (funded debt) of 50% or less (ratio of 18% as of June 30, 2013, as calculated under the agreement) and "Consolidated Net Worth" of at least $975 million (Net Worth of $1.7 billion as of June 30, 2013, as calculated under the agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI's long-term credit ratings.

The Company raised $25 million through the issuance of approximately 0.9 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first six months of 2013.

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. At June 30, 2013, the equity forward transactions could have been settled with physical delivery by HEI of 7 million newly-issued shares to the forward counterparty in exchange for cash of $178 million. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled. HEI anticipates physical settlement of the equity forward transactions before March 25, 2015, but the transactions may also be cash settled or net share settled.

On March 6, 2013, HEI issued $50 million of 3.99% Senior Notes due March 6, 2023 via a private placement. HEI used the net proceeds from the issuance of the Senior Notes to refinance $50 million of its 5.25% medium-term notes that matured on March 7, 2013. The Senior Notes contain customary representation and warranties, affirmative 57 -------------------------------------------------------------------------------- Table of Contents 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) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI's revolving noncollateralized credit agreement. For example, see discussion of "Capitalization Ratio" and "Consolidated Net Worth" above.

For the first six months of 2013, net cash provided by operating activities of consolidated HEI was $131 million. Net cash used by investing activities for the same period was $240 million, due to HECO's consolidated capital expenditures, a net increase in ASB's loans held for investment and purchases of investment and mortgage-related securities, partly offset by repayments of investment and mortgage-related securities, proceeds from sale of investment securities and HECO's contributions in aid of construction. Net cash provided by financing activities during this period was $44 million as a result of several factors, including net increases in deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO'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 six months of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $41 million and $20 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 48 to 49, 64 to 67, and 78 to 80 of HEI's MD&A included in Part II, Item 7 of HEI's 2012 Form 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 49 to 50, 67 to 68, and 80 to 81 of HEI's MD&A included in Part II, Item 7 of HEI's 2012 Form 10-K.

58 -------------------------------------------------------------------------------- Table of Contents Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.

Electric utility RESULTS OF OPERATIONS Utility strategic progress. In 2012 and the first six months of 2013, the utilities continued 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 during the period, including a number of interim and final rate case decisions (see table in "Most recent rate proceedings" below).

The utilities are committed to achieving or exceeding the State's Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see "Renewable energy strategy" below). In addition, while it will not take precedence over the utilities' work to increase their use of renewable energy, the utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation.

Regulatory. In January 2013, the utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See "Utility projects" in Note 5 of HECO's "Notes to Consolidated Financial Statements" and the discussion under "Most recent rate proceedings" below.

With PUC approval, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO 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 revenue adjustments for certain O&M expenses and rate base changes. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a RAM and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in the utilities' under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities' returns have been well below PUC-allowed returns.

Under decoupling, the most significant drivers for improving earnings are: 1. completing major capital projects within PUC approved amounts and on schedule; 2. managing O&M expenses relative to authorized O&M adjustments; and 3. regulatory outcomes that cover O&M requirements and rate base items not included in the RAMs.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for HECO, the PUC opened an investigative docket to review whether the decoupling mechanism is functioning as intended. 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.

HECO, HELCO, MECO and the Consumer Advocate are named as parties to this proceeding and filed a joint statement of position that any material changes to the current decoupling mechanism should be made prospectively after 2016 unless the utilities and the Consumer Advocate mutually agree to the change in this proceeding. Several parties have filed motions to intervene.

The utilities' five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded near-term annual rate base growth rate in the range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 35% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and (4) infrastructure investments to integrate more energy from renewables into the system. Estimates for these initiatives could change over time, based on external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation.

59 -------------------------------------------------------------------------------- Table of Contents Actual and PUC-allowed (as of June 30, 2013) returns were as follows: % Return on rate base (RORB)* ROACE** Rate-making ROACE*** Twelve months ended June 30, 2013 HECO HELCO MECO HECO HELCO MECO HECO HELCO MECO Utility returns 7.73 6.54 7.01 6.80 5.18 7.39 10.05 7.02 8.60 PUC-allowed returns 8.11 8.31 7.34 10.00 10.00 9.00 10.00 10.00 9.00 Difference (0.38 ) (1.77 ) (0.33 ) (3.20 ) (4.82 ) (1.61 ) 0.05 (2.98 ) (0.40 ) -------------------------------------------------------------------------------- * 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 the write-off of $40 million of CIS project costs, executive bonuses and advertising.

The approval of decoupling by the PUC has helped the utilities to gradually improve their ROACEs, which 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 they actually achieve due to the following: 1) the timing of general rate case decisions, 2) the effective date of the RAMs, 3) the 5-year historical average for baseline plant additions, and 4) the PUC's consistent exclusion of certain expenses from rates.

The structural gap in 2014 to 2016 is expected to be 80 to 110 basis points, an improvement of 40 basis points from management's prior expectations. The improvement is due to the change in the timing of the recognition of the RAM revenues in 2014 to 2016 as defined in the 2013 Agreement. For 2013, the expected structural gap remains unchanged at 120 to 150 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the utilities (primarily investments in software projects, changes in fuel inventory and O&M in excess of indexed escalations). The specific magnitude of the impact will depend on various factors, including the size of software projects, changes in fuel prices and management's ability to manage costs within the current mechanisms.

Management expects the earned ROACE to gradually improve from 2014 to 2016.

As part of decoupling, HECO also tracks its rate-making ROACE as calculated under the earnings sharing mechanism and which includes only items considered in establishing rates. Earnings over and above the ROACE allowed by the PUC are shared between HECO and its ratepayers on a tiered basis. For 2012, HECO's rate-making ROACE was 10.70%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2.6 million for their portion of the earnings sharing. HECO's 2012 rate-making ROACE of 10.70% included various adjustments to HECO's actual ROACE of 7.57% such as the exclusion of the $40 million of CIS project costs pursuant to the 2013 Agreement, and of other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). HELCO's rate-making ROACE was 7.79% and MECO's rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.

60 -------------------------------------------------------------------------------- Table of Contents Annual decoupling filings. On May 31, 2013, the PUC approved the revised annual decoupling filings for tariffed rates for HECO, HELCO and MECO that will be effective from June 1, 2013 through May 31, 2014. The amounts approved as noted below reflect the electric utilities' agreements with the position of the Consumer Advocate. The revised tariffed rates include: (in millions) HECO HELCO MECO Annual incremental RAM adjusted revenues Operations and maintenance $ 3.9 $ 0.9 $ 1.0 Invested capital 27.5 1.2 2.4 Total annual incremental RAM adjusted revenues $ 31.4 $ 2.1 $ 3.4 Accrued earnings sharing credits to be refunded $ (2.6 ) $ - $ - Accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected $ 55.4 $ 4.9 $ 5.8 Results.

Three months ended June 30 Increase 2013 2012 (decrease) (in millions) $ 731 $ 790 $ (59 ) Revenues. Decrease largely due to: $ (56 ) Lower fuel prices and lower KWH sales adjusted for decoupling mechanisms and revenue taxes 2 Interim rate increase granted to MECO in its 2012 test year rate case (8 ) MECO test year 2012 final (refund) 1 Interim and final rate increases granted to HECO in its 2011 test year rate case 289 331 (42 ) Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated 178 188 (10 ) Purchased power expense. Decrease largely due to lower purchased power energy costs, partially offset by higher KWH purchased 94 96 (2 ) Other operation and maintenance expenses.

Decrease largely due to: 4 Higher customer service expenses 2 Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012 (3 ) MECO final decision adjustments for deferral of pension/OPEB and IRP expenses (4 ) Decrease due to timing of overhauls 109 113 (4 ) Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions 61 62 (1 ) Operating income. Slight decrease due to MECO 2012 test year refund, partially offset by lower O&M, MECO interim and HECO rate increases 29 29 - Net income for common stock. Slight decrease largely due to lower operating income 2,247 2,257 (10 ) Kilowatthour sales (millions) 69.3 68.0 1.3 Wet-bulb temperature (Oahu average; degrees Fahrenheit) 1,114 1,150 (36 ) Cooling degree days (Oahu) $ 129.94 $ 145.27 $ (15.33 ) Average fuel oil cost per barrel 61 -------------------------------------------------------------------------------- Table of Contents Six months ended June 30 Increase 2013 2012 (decrease) (in millions) $ 1,450 $ 1,539 $ (89 ) Revenues. Decrease largely due to: $ (93 ) Lower fuel prices and lower KWH sales adjusted for decoupling mechanisms and revenue taxes 5 Interim rate increase granted to MECO in its 2012 test year rate case (8 ) MECO test year 2012 final (refund) 2 Interim and final rate increases granted to HECO in its 2011 test year rate case 594 659 (65 ) Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated 332 353 (21 ) Purchased power expense. Decrease largely due to lower purchased power energy costs, less KWH purchased and lower purchase capacity/non-fuel charges 195 188 7 Other operation and maintenance expenses.

Increase largely due to: 9 Higher customer service expenses 3 Higher employee benefit costs 2 Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012 (3 ) 2012 increase in general liability reserve for an environmental matter (3 ) MECO final decision adjustments for deferral of pension/OPEB and IRP expenses (4 ) Decrease due to timing of overhauls 215 220 (5 ) Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions 114 119 (5 ) Operating income. Decrease largely due to MECO 2012 test year refund, higher O&M, partly offset by MECO interim and HECO rate increases 53 57 (4 ) Net income for common stock. Decrease largely due to lower operating income 4,370 4,508 (138 ) Kilowatthour sales (millions) 67.6 67.6 - Wet-bulb temperature (Oahu average; degrees Fahrenheit) 1,903 2,011 (108 ) Cooling degree days (Oahu) $ 131.49 $ 139.63 $ (8.14 ) Average fuel oil cost per barrel 450,455 448,001 2,472 Customer accounts (end of period) Note: The electric utilities had effective tax rates for the second quarters of 2013 and 2012 of 39% and 38%, respectively, and for the first six months of 2013 and 2012 of 38%.

HECO's consolidated ROACE was 6.6% for the twelve months ended June 30, 2013 and 8.7% for the twelve months ended June 30, 2012.

Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to approximately 1% over prior year, as the electric utilities expect to manage expenses to near-2012 levels.

See "Economic conditions" in the "HEI Consolidated" section above.

Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility shall initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and 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.

62 -------------------------------------------------------------------------------- Table of Contents 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, the details of any granted interim and final PUC D&O increases, and whether an interim or final PUC D&O remains pending.

Stipulated agreement Date % over Common reached with Test year (applied/ rates in ROACE RORB equity Consumer (dollars in millions) implemented) Amount effect (%) (%) Rate base % Advocate HECO 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 HELCO 2010 (2) 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 (3) Request 8/16/12 $ 19.8 4.2 10.25 8.30 $ 455 57.05 Closed 3/27/13 MECO 2012 (4) 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 -------------------------------------------------------------------------------- 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) HECO filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. HECO'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) HELCO'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, HELCO 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. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO 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.

(3) HELCO's request was required 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 D&O (described below), the rate case was withdrawn and the docket has been closed.

(4) MECO's request was required 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 5 of HECO's "Notes to Consolidated Financial Statements." HECO 2011 test year rate case. In the HECO 2011 test year rate case, the PUC had granted HECO's request to defer CIS project operation and maintenance (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 HECO to accrue AFUDC on these deferred costs until the completion of the regulatory audit.

On January 28, 2013, HECO, HELCO, MECO 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 63 -------------------------------------------------------------------------------- Table of Contents 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 HELCO 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 HECO 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, HECO will be allowed to record RAM revenues starting on January 1 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See "Utility projects" in Note 5 of HECO's "Notes to Consolidated Financial Statements" for additional information on the 2013 Agreement and the 2013 D&O and their effects.

MECO 2012 test year rate case. See "MECO 2012 test year rate case" in Note 5 of HECO's "Notes to Consolidated Financial Statements" for information on the PUC's final D&O.

Integrated Resource Planning. In June 2013, HECO, HELCO and MECO filed their 2013 integrated resource planning (IRP) report and five-year action plans detailing plans to meet future electricity needs for the islands of Oahu, Maui, Molokai, Lanai and Hawaii. IRP aims to develop long-range 20-year resource plans for meeting energy needs under various scenarios and then to develop near-term actions for implementation over the next five years. The 2013 IRP process was the first IRP to employ scenario planning, as well as an independent entity that facilitated and provided oversight of the process, since the PUC revised the IRP Framework in March 2012. The IRP process included input from a community advisory group established by the PUC of almost 70 business, community, and government, environmental and other leaders. The utilities also held two rounds of public meetings on the islands of Oahu, Maui, Molokai, Lanai and Hawaii to seek comments from the general public, in addition to 17 meetings with the advisory group.

The overarching goals of the action plans filed are lowering costs to customers, replacing expensive oil with cleaner sources of energy, modernizing the electric grid, and looking out for the interests of all customers. Significant action plan items include: † Lowering costs to customers by accelerating the development of low-cost, fast-track, utility-scale renewable energy projects, including solar and wind facilities.

† Deactivating (i.e., removing from service with the possibility of reactivating in the future in a major emergency for example) older, less efficient oil-fired power plant units, to help lower costs and increase the use of renewable energy generation. This includes Honolulu Power Plant and two of four generating units at Maui's Kahului Power Plant by 2014, as well as two generators at Oahu's Waiau Power Plant by 2016. In addition, all units at Kahului Power Plant would be fully retired by 2019. Hawaii Island's Shipman Plant is already deactivated and will be retired in 2014.

† Converting or replacing power plants that are not deactivated to use cost-effective, cleaner fuels, including renewable biomass or biofuel and liquefied natural gas.

† Supporting the state's efforts to procure cheaper, cleaner, liquefied natural gas to replace the use of oil in making electricity.

† Increasing the capability of utility grids to accept additional customer-sited renewable generation, especially roof-top photovoltaic systems, while protecting safety, reliability and fairness of electric service for all customers.

† Developing "smart" grids for all three companies to improve customer service, integrate more renewable energy, and enable customers to better control their electric bills. Major components of the smart grid include installing smart meters for all customers (with opt-out provisions) in the 2017-2018 timeframe, automating the grid, and developing utility energy storage systems.

In July 2013, the Independent Entity, the person selected by the PUC to provide unbiased oversight of the IRP, filed a report to the PUC documenting his evaluation of the IRP process. The evaluation recognizes that the IRP report and action plans are compliant with many IRP Framework requirements and provides substantial analysis addressing the Principal Issues, which were issues and questions identified by the PUC to be addressed in the IRP process. However, the Independent Entity did not certify that the IRP process was conducted consistent with all provisions of the IRP Framework or that it fully addressed the Principal Issues. Under the IRP Framework, the PUC should issue a decision (with approval, partial approval, rejection, modifications and/or other directives) on the action plans within six months after the utilities' IRP filing, unless the PUC determines that an evidentiary hearing is warranted.

64 -------------------------------------------------------------------------------- Table of Contents Renewable energy strategy. The utilities' policy is to support efforts to increase 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, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO 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). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2012, HECO achieved an RPS without DSM energy savings of 13.9%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the 2015 RPS.

Recent developments in the utilities' renewable energy strategy include the following (also see the projects discussed under "Renewable Energy Projects" in Note 5 of HECO's "Notes to Consolidated Financial Statements"): † In February 2011, the PUC opened dockets related to HECO's and MECO's plans to proceed with competitive bidding processes to acquire up to approximately 300 MW and 50 MW, respectively, of new, renewable firm dispatchable capacity generation resources. In July 2013, the PUC closed the HECO and MECO RFPs, stating that the RFPs and related proceedings appear to be premature. The PUC will consider future requests by HECO or MECO to open another proceeding to conduct an RFP for generation upon demonstration of need and a plan focused on customer needs.

† In July 2011, the PUC directed HECO 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, HECO filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP (see Note 5 of HECO's "Notes to Consolidated Financial Statements" for additional information).

† In August 2011, HECO signed a 20-year contract, subject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of PUC approval. In 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.

† In September 2011, the PUC denied the utilities' requested approval of HELCO's contract with Aina Koa Pono-Ka'u LLC (AKP) citing the higher cost of the biofuel over the cost of petroleum diesel. In August 2012, HELCO signed a new 20-year contract with AKP, subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption expected to begin in 2017 or later. HELCO filed an application for approval of this contract in August 2012.

† In May 2012, the PUC approved HECO's 3-year biodiesel supply contract with Renewable Energy Group for continued biodiesel supply to CT-1 of 3 million to 7 million gallons per year.

† In May 2012, MECO began purchasing wind energy from the 21 MW Kaheawa Wind Power II, LLC facility, which went into commercial operation in July 2012.

† In May 2012, HECO signed a contract, which was approved by the PUC, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility, which was placed in service in April 2013.

† In May 2012, HELCO signed a power purchase agreement, subject to PUC approval, 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.

† 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. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.

† In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire and HECO has not purchased wind energy from the wind farm since then.

† In August 2012, the PUC approved a waiver from the competitive bidding process to allow HECO 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.

65 -------------------------------------------------------------------------------- Table of Contents † In September 2012, HECO began purchasing test wind energy from the 69 MW Kawailoa Wind, LLC facility. The wind farm was placed into full commercial operation in November 2012.

† In December 2012, the PUC approved a 3-year biodiesel supply contract with Pacific Biodiesel to supply 250,000 to 1 million gallons of biodiesel at the Honolulu International Airport Emergency Power Facility beginning in 2013.

† In December 2012, the 21 MW Auwahi Wind Energy LLC facility was placed into commercial operation, selling power to MECO under a 20-year contract.

† In December 2012, the 5 MW Kalaeloa Solar Two, LLC photovoltaic facility was placed into commercial operation, selling power to HECO under a 20-year contract.

† HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of June 30, 2013, there were 9 MW, 1 MW and 2 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

† As of June 30, 2013, there were approximately 127 MW, 26 MW and 30 MW of installed net energy metering capacity from renewable energy technologies (mainly photovoltaic) at HECO, HELCO and MECO, respectively. Net energy metering continues to proceed at a record pace. The amount of net energy metering capacity installed in the first half of 2013 was more than twice the amount installed during the first half of 2012.

† In February 2013, HECO issued an "Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding." The invitation for waiver projects 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, in June 2013, HECO filed a waiver request from the PUC Competitive Bidding Framework for five projects that meet these goals.

Commitments and contingencies. See Note 5 of HECO's "Notes to Consolidated Financial Statements." Recent accounting pronouncements. See Note 8, "Recent accounting pronouncements," of HECO's "Notes to Consolidated Financial Statements." FINANCIAL CONDITION Liquidity and capital resources. Management believes that HECO's ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and 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.

HECO's consolidated capital structure was as follows: (dollars in millions) June 30, 2013 December 31, 2012 Short-term borrowings $ 54 2 % $ - - % Long-term debt, net 1,148 42 1,148 43 Preferred stock 34 1 34 1 Common stock equity 1,485 55 1,472 56 $ 2,721 100 % $ 2,654 100 % Information about HECO's short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows: Average balance Balance Six months ended June 30, December 31, (in millions) June 30, 2013 2013 2012 Short-term borrowings(1) Commercial paper $ 37 $ 54 $ - Line of credit draws - - - Borrowings from HEI - - - Undrawn capacity under line of credit facility (expiring December 5, 2016) 175 175 -------------------------------------------------------------------------------- (1) The maximum amount of HECO's external short-term borrowings during the first six months of 2013 was $71.0 million. At June 30, 2013, HECO had $9.6 million of short-term borrowings from HELCO, and MECO had $18 million of short-term borrowings from HECO. At July 31, 2013, HECO had $37 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $10 million of short-term borrowings from HELCO. Also, at July 31, 2013, MECO had $22 million of short-term borrowings from HECO.

Intercompany borrowings are eliminated in consolidation.

66 -------------------------------------------------------------------------------- Table of Contents HECO has a line of credit facility of $175 million (see Note 9of HECO's "Notes to Consolidated Financial Statements"). There are customary conditions that 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, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary's "Consolidated Subsidiary Funded Debt to Capitalization Ratio" to exceed 65% (ratio of 42% for HELCO and 44% for MECO as of June 30, 2013, as calculated under the agreement)). In addition to customary defaults, HECO'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 HECO fails to maintain a "Consolidated Capitalization Ratio" (equity) of at least 35% (ratio of 55% as of June 30, 2013, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of HECO and its subsidiaries, but the sources of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO's guarantees of its subsidiaries' obligations. The payment of principal and interest due on Special Purpose Revenue Bonds currently outstanding and issued prior to 2009 are insured by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012 (with a plan of rehabilitation approved on June 11, 2013); MBIA Insurance Corporation (which bonds have been reinsured by National Public Finance Guarantee Corp.); or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The Standard & Poor's (S&P's) and Moody's Investor Service's ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities or have been withdrawn.

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 HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions. New long-term debt authorizations of $150 million (HECO $100 million, HELCO $25 million and MECO $25 million) can be requested under the expedited approval procedure through 2015.

In January 2013, HECO, HELCO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $90 million, $56 million and $20 million, respectively, of unsecured obligations bearing taxable interest to refinance select series of outstanding revenue bonds. In February 2013, HECO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $50 million and $20 million, respectively, of unsecured obligations bearing taxable interest. The proceeds are expected to be used to fund capital expenditures, including repaying short-term indebtedness incurred to fund capital expenditures. By orders issued on June 28 and July 24, 2013, the PUC approved both requests.

Operating activities provided $112 million in net cash during the first six months of 2013. Investing activities for the same period used net cash of $132 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $12 million, primarily due to the increase in short-term borrowings, partly offset by payment of $42 million of common and preferred dividends.

67 -------------------------------------------------------------------------------- Table of Contents Bank RESULTS OF OPERATIONS Three months ended June 30 Increase (in millions) 2013 2012 (decrease) Primary reason(s) for significant change Interest $ 47 $ 48 $ (1 ) The impact of higher average earning asset income balances was more than offset by lower yields on earning assets. ASB's average loanportfolio balance for the second quarter of 2013 was $180 million higher than for the second quarter of 2012 as the average home equity lines of credit, residential, commercial real estate and consumer loan balances increased by $89 million, $81 million, $25 million and $24 million, respectively. The growth in these loan portfolios was consistent with ASB's portfolio mix target and loan growth strategy. The loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield.

Noninterest 19 17 2 Higher gain on sale of securities as ASB income sold $70 million of agency obligations during the second quarter of 2013.

Revenues 66 65 1 Interest 2 3 (1 ) Lower funding costs as a result of the low expense interest rate environment. Average deposit balances for the second quarter of 2013 increased by $184 million compared to the second quarter of 2012 due to an increase in core deposits of $252 million, partly offset by a decrease in term certificates of $68 million. The other borrowings average balance decreased by $30 million due to lower retail repurchase agreements.

Provision (1 ) 2 (3 ) The credit for loan losses in the second (credit) for quarter of 2013 was due to the $1 million loan losses release of reserves as a result of an agreement to sell ASB's credit card portfolio.No additional provision expense was incurred as increases in the provision for loan losses to cover loan growth and charge-offs were offset by the release of commercial real estate loan portfolio reserves due to paydowns, recoveries of previously charged off consumer loans and the ongoing improvement in the quality of ASB's loan portfolio.

Noninterest 40 38 2 Higher compensation and benefits expenses expense due to targeted staffing increases to support increased business volumes, information technology (IT) and risk management capabilities.

Expenses 41 43 (2 ) Operating 25 22 3 Higher noninterest income and lower income provision for loan losses, partially offset by lower net interest income and higher noninterest expenses.

Net income 16 14 2 Higher operating income.

68 -------------------------------------------------------------------------------- Table of Contents Six months ended June 30 Increase (in millions) 2013 2012 (decrease) Primary reason(s) for significant change Interest $ 93 $ 96 $ (3 ) The impact of higher average earning income asset balances was more than offset by lower yields on earning assets. ASB's average loan portfolio balance for the six monthsended June 30, 2013 was $144 million higher than for the same period in 2012 as the average home equity lines of credit, commercial real estate, residential and consumer loan balances increased by $89 million, $30 million, $27 million and $26 million, respectively. The growth in these loan portfolios was consistent with ASB's portfolio mix target and loan growth strategy. Loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolioyields. The average investment and mortgage-related securities portfolio balance increased by $23 million as ASB used its excess liquidity to purchase securities.

Noninterest 38 34 4 Higher gain on sale of securities due to income the sale of $70 million of agency obligations and higher mortgage banking income due to higher gain on sale of loans.

Revenues 131 130 1 Interest 5 6 (1 ) Lower funding costs as a result of the expense low interest rate environment. Average deposit balances for the six months ended June 30, 2013 increased by $161 millioncompared to the same period in 2012 due to an increase in core deposits of $230 million, partly offset by a decrease in term certificates of $70 million. The other borrowings average balance decreased by $35 million due to lower retail repurchase agreements.

Provision for 1 6 (5 ) The 2013 provision for loan losses loan losses declined due in part to the improved credit quality associated with the continuing improvement in Hawaii's economy, lower net charge-offs in the higher risk land loan portfolios and purchased mortgage portfolio and $1.0 million release of the allowance on credit card loans due to the upcoming portfolio sale.

Noninterest 79 73 6 Higher compensation and benefits expense expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities.

Expenses 85 85 - Operating 46 45 1 Lower provision for loan losses and income higher noninterest income, partially offset by lower net interest income and higher noninterest expenses.

Net income 30 30 - 69 -------------------------------------------------------------------------------- Table of Contents Details of ASB's other noninterest income and othernoninterest expense were as follows: Three months ended June 30 Six months ended June 30 (in thousands) 2013 2012 2013 2012 Bank-owned life insurance $ 985 $ 993 $ 1,952 $ 1,972 Other 746 456 1,371 837 Total other income $ 1,731 $ 1,449 $ 3,323 $ 2,809 FDIC insurance premium $ 848 $ 854 $ 1,688 $ 1,707 Marketing 824 554 1,362 1,104 Office supplies, printing and postage 1,026 919 1,899 1,909 Communication 424 430 895 866 Reversal of interest expense-tax - - - (552 ) Other 5,378 5,349 10,251 9,779 Total other expense $ 8,500 $ 8,106 $ 16,095 $ 14,813 See Note 4 of HEI's "Notes to Consolidated FinancialStatements" 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.

ASB's return on average assets, net interest margin andefficiency ratio were as follows: Three months ended Six months ended June 30 June 30 (percent) 2013 2012 2013 2012 Return on average assets 1.25 1.15 1.19 1.22 Net interest margin 3.79 3.97 3.79 4.01 Efficiency ratio 62 60 62 58 70 -------------------------------------------------------------------------------- Table of Contents Average balance sheet and net interest margin. The following tables set forth average balances, together with interest earned and accrued, and resulting yields and costs: 2013 2012 Three months ended June 30 Average Yield/ Average Yield/ (dollars in thousands) balance Interest rate (%) balance Interest rate (%) Assets: Other investments (1) $ 164,374 $ 44 0.11 $ 201,812 $ 66 0.13 Securities purchased under resale agreements 26,154 25 0.38 - - - Available-for-sale investment and mortgage-related securities 617,942 3,386 2.19 624,581 3,435 2.20 Loans (2) Residential 1-4 family 1,964,140 23,503 4.79 1,882,701 24,802 5.27 Commercial real estate 429,409 4,973 4.64 404,542 4,649 4.60 Home equity line of credit 665,879 4,840 2.92 576,655 3,914 2.73 Residential land 22,607 335 5.93 37,453 598 6.39 Commercial loans 699,023 7,347 4.21 723,995 7,916 4.40 Consumer loans 123,601 2,626 8.52 99,261 2,594 10.51 Total loans (2), (3) 3,904,659 43,624 4.47 3,724,607 44,473 4.79 Total interest-earning assets (4) 4,713,129 47,079 4.00 4,551,000 47,974 4.22Allowance for loan losses (43,372 ) (39,295 ) Non-interest-earning assets 429,924 429,258 Total assets $ 5,099,681 $ 4,940,963 Liabilities and shareholder's equity: Savings $ 1,811,157 263 0.06 $ 1,725,034 304 0.07 Interest-bearing checking 659,790 25 0.02 613,370 30 0.02 Money market 176,812 56 0.13 187,455 73 0.16 Time certificates 462,762 952 0.83 530,896 1,289 0.97 Total interest-bearing deposits 3,110,521 1,296 0.17 3,056,755 1,696 0.22 Advances from Federal Home Loan Bank 51,264 542 4.18 50,000 541 4.28 Securities sold under agreements to repurchase 144,496 636 1.74 175,745 673 1.52 Total interest-bearing liabilities 3,306,281 2,474 0.30 3,282,500 2,910 0.35 Non-interest bearing liabilities: Deposits 1,182,244 1,052,275 Other 104,372 106,125 Total liabilities 4,592,897 4,440,900 Shareholder's equity 506,784 500,063 Total liabilities and shareholder's equity $ 5,099,681 $ 4,940,963 Net interest income $ 44,605 $ 45,064 Net interest margin (%) (5) 3.79 3.97 71 -------------------------------------------------------------------------------- Table of Contents 2013 2012 Six months ended June 30 Average Yield/ Average Yield/ (dollars in thousands) balance Interest rate (%) balance Interest rate (%) Assets: Other investments (1) $ 181,195 $ 108 0.12 $ 226,714 $ 162 0.14Securities purchased under resale agreements 13,149 25 0.38 - - - Available-for-sale investment and mortgage-related securities 633,232 7,005 2.21 609,826 7,315 2.40 Loans (2) Residential 1-4 family 1,923,389 46,859 4.87 1,896,188 50,412 5.32 Commercial real estate 425,473 9,606 4.53 395,229 9,235 4.68 Home equity line of credit 653,086 9,302 2.87 563,723 7,684 2.74 Residential land 23,801 591 4.97 39,661 1,153 5.81 Commercial loans 705,330 14,816 4.23 718,297 15,875 4.44 Consumer loans 123,624 5,053 8.23 97,240 5,002 10.34 Total loans (2), (3) 3,854,703 86,227 4.49 3,710,338 89,361 4.83 Total interest-earning assets (4) 4,682,279 93,365 4.00 4,546,878 96,838 4.27Allowance for loan losses (42,992 ) (38,741 ) Non-interest-earning assets 432,009 430,929 Total assets $ 5,071,296 $ 4,939,066 Liabilities and shareholder's equity: Savings $ 1,793,415 517 0.06 $ 1,711,941 614 0.07 Interest-bearing checking 650,044 49 0.02 609,448 60 0.02 Money market 186,136 119 0.13 218,571 194 0.18 Time certificates 466,261 1,923 0.83 536,113 2,607 0.98 Total interest-bearing deposits 3,095,856 2,608 0.17 3,076,073 3,475 0.23 Advances from Federal Home Loan Bank 50,635 1,077 4.23 50,000 1,082 4.28 Securities sold under agreements to repurchase 145,888 1,265 1.73 181,535 1,393 1.52 Total interest-bearing liabilities 3,292,379 4,950 0.30 3,307,608 5,950 0.36 Non-interest bearing liabilities: Deposits 1,166,993 1,026,187 Other 107,594 108,519 Total liabilities 4,566,966 4,442,314 Shareholder's equity 504,330 496,752 Total liabilities and shareholder's equity $ 5,071,296 $ 4,939,066 Net interest income $ 88,415 $ 90,888 Net interest margin (%) (5) 3.79 4.01 -------------------------------------------------------------------------------- (1) Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.

(2) Includes loans held for sale.

(3) Includes loan fees of $1.4 million and $1.3 million for the three months ended June 30, 2013 and 2012, respectively, and $2.9 million and $2.5 million for the six months ended June 30, 2013 and 2012, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.

(4) Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million for the three months ended June 30, 2013 and 2012, and $0.4 million for the six months ended June 30, 2013 and 2012.

(5) Defined as net interest income as a percentage of average earning assets.

72 -------------------------------------------------------------------------------- Table of Contents Earning assets, costing 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 costing liabilities. The interest rate environment has been impacted by disruptions in the financial markets and these conditions have continued to have a negative impact on ASB's net interest margin.

Loan originations and mortgage-related securities are ASB's primary sources of earning assets.

Loan portfolio. ASB's loan volumes and yields are affected bymarket interest rates, competition, demand for financing, availability of funds and management's responses to these factors. The composition of ASB's loan portfolio was as follows: June 30, 2013 December 31, 2012 (dollars in thousands) Balance % of total Balance % of total Real estate loans: Residential 1-4 family $ 2,001,035 50.5 $ 1,866,450 49.2 Commercial real estate 382,735 9.7 375,677 9.9 Home equity line of credit 673,727 17.0 630,175 16.6 Residential land 21,836 0.5 25,815 0.7 Commercial construction 50,114 1.3 43,988 1.2 Residential construction 9,664 0.2 6,171 0.2 Total real estate loans, net 3,139,111 79.2 2,948,276 77.8 Commercial loans 719,519 18.2 721,349 19.0 Consumer loans 104,759 2.6 121,231 3.2 3,963,389 100.0 3,790,856 100.0 Less: Deferred fees and discounts (9,755 ) (11,638 ) Allowance for loan losses (41,004 ) (41,985 ) Total loans, net $ 3,912,630 $ 3,737,233 The increase in the total loan portfolio during the first six months of 2013 compared to the same period in 2012 was primarily due to an increase in originated ASB's residential 1-4 family, home equity lines of credit and commercial real estate loan portfolios and is in line with ASB's portfolio mix target and loan growth strategy.

In May 2013, ASB entered into an agreement with First Bankcard, a division of First National Bank of Omaha, to sell ASB's credit card portfolio to First Bankcard. As part of the agreement, through First Bankcard, ASB will be able to offer ASB customers a greater variety of business and consumer credit card products, an enhanced rewards program, and regular marketing support. First Bankcard supports more than 500 partners with 5,700 retail branches, owning over 4 million credit card accounts. ASB transferred the $25 million credit card portfolio to held for sale and carried it at lower of cost or market. On August 1, 2013, ASB completed the sale of its credit card portfolio to First Bankcard.

Home equity - key credit statistics.

June 30, 2013 December 31, 2012 Outstanding balance (in thousands) $ 673,727 $ 630,175 Percent of portfolio in first lien position 35.0 % 29.9 % Net charge-off ratio 0.14 % 0.10 % Delinquency ratio 0.30 % 0.40 % End of draw period - interest only Current June 30, 2013 Total Interest only 2013-2014 2015-2017 Thereafter amortizing Outstanding balance (in thousands) $ 673,727 $ 524,775 $ 132 $ 12,153 $ 512,490 $ 148,952 % of total 100 % 78 % - % 2 % 76 % 22 % The home equity line of credit (HELOC) portfolio makes up 17% 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 89% 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 73 -------------------------------------------------------------------------------- Table of Contents principal and interest payments. As of June 30, 2013, approximately 11% of the portfolio balances are 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 11% of the portfolio and are included in the amortizing balances identified in the table above.

Loan portfolio risk elements. See Note 4 of HEI's "Notes to Consolidated Financial Statements." Investment and mortgage-related securities. ASB's investment portfolio was comprised as follows: June 30, 2013 December 31, 2012 (dollars in thousands) Balance % of total Balance % of total Federal agency obligations $ 99,064 18 % $ 171,491 26 % Mortgage-related securities - FNMA, FHLMC and GNMA 382,044 68 417,383 62 Municipal bonds 79,064 14 82,484 12 $ 560,172 100 % $ 671,358 100 % Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. The decrease in federal agency obligations was due to the sale of $70 million of agency obligations in the second quarter of 2013. The decrease in mortgage-related securities was due to paydowns in the portfolio.

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 Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. Advances from the FHLB of Seattle have remained at $50 million from December 31, 2012 to June 30, 2013. As of June 30, 2013 and December 31, 2012, ASB's costing liabilities consisted of 96% deposits and 4% other borrowings. The weighted average cost of deposits for the first six months of 2013 was 0.12%, compared to 0.17% for the first six months of 2012.

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, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.

As of June 30, 2013 and December 31, 2012, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $1 million and $11 million, respectively. The decrease in AOCI was due to the impact of rising interest rates on the fair value of ASB's investment and mortgage-related securities. See "Item 3. Quantitative and qualitative disclosures about market risk." 74 -------------------------------------------------------------------------------- Table of Contents During the first six months of 2013, ASB recorded a provision for loan losses of $0.9 million primarily due to net charge-offs during the year for consumer, commercial and HELOC loans, and growth in the loan portfolio, partly offset by the release of reserves for the credit card and commercial real estate loan portfolios. During the first six months of 2012, ASB recorded a provision for loan losses of $5.9 million primarily due to charge-offs during the year for 1-4 family, residential land, commercial and consumer loans. Continued financial stress on ASB's customers may result in higher levels of delinquencies and losses.

Six months ended Year ended June 30 December 31 (in thousands) 2013 2012 2012 Allowance for loan losses, January 1 $ 41,985 $ 37,906 $ 37,906 Provision for loan losses 899 5,924 12,883 Less: net charge-offs 1,880 4,367 8,804 Allowance for loan losses, end of period $ 41,004 $ 39,463 $ 41,985 Ratio of allowance for loan losses, end of period, to end of period loans outstanding 1.04 % 1.06 % 1.11 % Ratio of net charge-offs during the period to average loans outstanding (annualized) 0.10 % 0.24 % 0.24 % Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (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, ASHI 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, ASHI 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 Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau).

Supervision and regulation of HEI and ASHI, 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. 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 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.

On May 22, 2012, the Bureau issued the Final Remittance Rule (an amendment to Regulation E). For international wires, the rule now provides flexibility regarding the disclosure of foreign taxes, as well as fees imposed by a designated recipient's institution for receiving a remittance transfer in an account. Second, the rule limits a remittance transfer provider's obligation to disclose foreign taxes to those imposed by a country's central government. And third, the rule revises the error resolution provisions that apply when a remittance transfer is not 75 -------------------------------------------------------------------------------- Table of Contents delivered to a designated recipient because the sender provided incorrect or insufficient information, and, in particular, when a sender provides an incorrect account number and that incorrect account number results in the funds being deposited in the wrong account.

ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and allows federal law to preempt a state consumer financial law on a "case by case" basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank's exercise of its power; or (3) the state law is preempted by another federal law.

The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms.

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, as of July 1, 2013, ASB is not exempt. For the second quarter of 2013, ASB had earned an average of 49 cents per electronic debit transaction. ASB estimates debit card interchange fees to be lower by approximately $3 million after tax for the remainder of 2013 and approximately $6 million after tax if it continues to be non-exempt in 2014.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective.

Final Capital Rule. 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. The FRB anticipates that it will release a proposal on intermediate holding companies in the near term 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.

Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would be subject to the following minimum regulatory capital requirements: a common equity tier 1 capital ratio of 4.5%, a tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a leverage ratio of 4%. 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 risk-based capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization's total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies' calculation of risk-weighted assets and address shortcomings in risk-based capital requirements identified by the agencies.

76 -------------------------------------------------------------------------------- Table of Contents Minimum Capital Requirements Effective dates 1/1/15 1/1/16 1/1/17 1/1/18 1/1/19 Capital conservation buffer 0.625 % 1.25 % 1.875 % 2.50 % Common equity 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 is effective January 1, 2015 for ASB. 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 be effective for HEI or ASHI on January 1, 2015 as well. HEI and ASB have reviewed the final rule and the impact to capital ratios. If the final rules were currently applicable to HEI and ASB, management believes HEI and ASB would satisfy the new capital requirements, including the fully phased-in capital conservation buffer.

Commitments and contingencies. See Note 4 of HEI's "Notes to Consolidated Financial Statements." FINANCIAL CONDITION Liquidity and capital resources.

June 30, December 31, (dollars in millions) 2013 2012 % change Total assets $ 5,069 $ 5,042 1 Available-for-sale investment and mortgage-related securities 560 671 (17 ) Loans receivable held for investment, net 3,913 3,737 5 Deposit liabilities 4,276 4,230 1 Other bank borrowings 188 196 (4 ) As of June 30, 2013, ASB was one of Hawaii's largest financial institutions based on assets of $5.1 billion and deposits of $4.3 billion.

As of June 30, 2013, ASB's unused FHLB borrowing capacity was approximately $0.9 billion. As of June 30, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion. Management believes ASB's current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first six months of 2013, net cash provided by ASB's operating activities was $48 million. Net cash used during the same period by ASB's investing activities was $108 million, primarily due to purchases of investment and mortgage-related securities of $40 million, a net increase in loans receivable of $201 million and additions to premises and equipment of $8 million, partly offset by proceeds from the sale of investment securities of $71 million, repayments of investment and mortgage-related securities of $63 million, proceeds from the sale of real estate acquired in settlement of loans of $6 million and redemption of stock from FHLB of Seattle of $2 million.

Net cash provided in financing activities during this period was $19 million, primarily due to net increases in deposit liabilities of $46 million and a net increase in mortgage escrow deposits of $1 million, partly offset by a net decrease in retail repurchase agreements of $8 million and the payment of $20 million in common stock dividends to HEI (through ASHI).

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 June 30, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.3% (5.0%), a Tier-1 risk-based capital ratio of 11.5% (6.0%) and a total risk-based capital ratio of 12.5% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

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