[May 08, 2013] HAWAIIAN ELECTRIC CO INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations Tweet (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 Form 10-K for 2012, as well as the quarterly (as of and for the three months ended March 31, 2013) financial statements and notes thereto included in this Form 10-Q. HEI Consolidated RESULTS OF OPERATIONS Three months ended (in thousands, except per March 31 % Primary reason(s) for share amounts) 2013 2012 change significant change* Revenues $ 784,064 $ 814,860 (4 ) Decrease for the electric utility and bank segments Operating income 70,657 75,816 (7 ) Decrease for the electric utility and bank segments, partly offset by a reduced operating loss for the "other" segment Net income for common 33,679 38,316 (12 ) 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 $ 0.34 $ 0.40 (15 ) Lower net income and higher share weighted average shares outstanding Weighted-average number 98,135 96,167 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 first quarters of 2013 and 2012 were 35%. HEI's consolidated ROACE was 8.5% for the twelve months ended March 31, 2013 and 9.7% for the twelve months ended March 31, 2012. Dividends. The payout ratios for the first quarter of 2013 and full year 2012 were 90% 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; 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 continued to grow into 2013, although at a slower pace. State visitor arrivals grew by 7.1% in the first three months of 2013 over 2012. State visitor expenditures also continued to grow, increasing by 7.6% in the first three months of 2013 over 2012. Hotel occupancies and room rates also continued to rise. The outlook for the visitor industry remains positive, albeit with a potential for more moderate growth, with the Hawaii Tourism Authority expecting a 10.0% increase in scheduled nonstop seats to Hawaii for April - June 2013 over the same period in 2012. Hawaii's unemployment rate was 5.1% in March 2013, lower than the state's 6.2% rate in March 2012 and the March 2013 national unemployment rate of 7.6%. Hawaii real estate activity as indicated by the home resale market has been mixed in the first quarter of 2013. The median sales price for single family residential homes on Oahu decreased by 2.7%, but closed sales increased 49 -------------------------------------------------------------------------------- Table of Contents 6.9% in the first three months of 2013 as compared to the same period in 2012. Oahu condominiums showed strong momentum with median prices rising 9.7% and closed sales (including 174 presale units for the new Holomua project) increasing 37.1% for first quarter of 2013 as compared to the same period in 2012. 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 has 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. The Federal Open Market Committee (FOMC) maintained a highly accommodative stance of monetary policy in their continuing efforts to stimulate the U.S. economy. At its meeting on March 19-20, 2013, the FOMC held the federal funds rate target at 0% to 0.25% and expected to maintain the record low rates for at least as long as the unemployment rate is above 6.5% and the inflation outlook remained under control. 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. Overall, Hawaii's economy is expected to see strengthening growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and finally signs of recovery in the construction industry. U.S. budget cuts, continued uncertainty in global economies, heightened tensions with North Korea and avian influenza pose possible risks to local economic growth. Despite economic improvement, the electric utilities' kilowatt-hour sales declined in 2012. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities' 2013 and 2014 kilowatt-hour 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, primarily 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. The Internal Revenue Service (IRS) issued 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 quarter of 2013, the Company's defined benefit pension and other postretirement benefit plans' assets generated a gain, after investment management fees, of 6.5%. The market value of these assets 50 -------------------------------------------------------------------------------- Table of Contents as of March 31, 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 $86 million ($84 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum required contribution, 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 ended March 31 % (in thousands) 2013 2012 change Primary reason(s) for significant change Revenues $ 35 $ (2 ) NM Operating loss (4,047 ) (4,350 ) NM Lower administrative and general expenses Net loss (4,905 ) (4,861 ) NM Lower operating loss more than offset by slightly higher interest expense and lower income tax benefits NM Not meaningful. 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. 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) March 31, 2013 December 31, 2012 Short-term borrowings-other than bank $ 134 4 % $ 84 3 % Long-term debt, net-other than bank 1,423 45 1,423 45 Preferred stock of subsidiaries 34 1 34 1 Common stock equity 1,607 50 1,594 51 $ 3,198 100 % $ 3,135 100 % HEI's short-term borrowings and HEI's line of credit facility were as follows: Three months ended March 31, 2013 Balance (in millions) Average balance March 31, 2013 December 31, 2012 Short-term borrowings(1) Commercial paper $ 84 $ 91 $ 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 51 -------------------------------------------------------------------------------- Table of Contents borrowings during the first quarter of 2013 was $96 million. At April 29, 2013, HEI had $89 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 19% as of March 31, 2013, as calculated under the agreement) and "Consolidated Net Worth" of at least $975 million (Net Worth of $1.7 billion as of March 31, 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 $11 million through the issuance of approximately 0.4 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first quarter 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 March 31, 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 $180 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. 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 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 quarter of 2013, net cash provided by operating activities of consolidated HEI was $48 million. Net cash used by investing activities for the same period was $113 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 and HECO's contributions in aid of construction. Net cash provided by financing activities during this period was $107 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 quarter of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $20 million and $10 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." 52 -------------------------------------------------------------------------------- Table of Contents 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. 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 quarter of 2013, the utilities continued to make significant progress in implementing their renewable energy strategies and the PUC issued several important regulatory decisions, all of which are key steps to support Hawaii's efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions (see table in "Most recent rate proceedings" below). Additional PUC decisions are needed that will allow the utilities to recover their increasing expenditures for renewable energy and reliability on a more timely basis. 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 "Major projects" in Note 5 to 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. Future earnings growth is also dependent on rate base growth. 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- 53 -------------------------------------------------------------------------------- Table of Contents 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. Actual and PUC-allowed (as of March 31, 2013) returns were as follows: % Return on rate base (RORB)* ROACE** Rate-making ROACE*** Twelve months ended March 31, 2013 HECO HELCO MECO HECO HELCO MECO HECO HELCO MECO Utility returns 7.78 6.44 7.06 6.97 5.07 7.41 9.53 6.83 8.65 PUC-allowed returns 8.11 8.31 7.91 10.00 10.00 10.00 10.00 10.00 10.00 Difference (0.33 ) (1.87 ) (0.85 ) (3.03 ) (4.93 ) (2.59 ) (0.47 ) (3.17 ) (1.35 ) -------------------------------------------------------------------------------- * 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 will help 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 settlement agreement approved by the PUC on March 19, 2013. For 2013, the 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 10.56%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2 million for their portion of the earnings sharing. HECO's 2012 rate-making ROACE of 10.56% included various adjustments to HECO's actual ROACE of 7.6% 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. 54 -------------------------------------------------------------------------------- Table of Contents Annual decoupling filings. On March 28, 2013, HECO, HELCO and MECO submitted their annual decoupling filings for tariffed rates for each respective utility that will be effective from June 1, 2013 through May 31, 2014 unless the filing is modified or suspended by the PUC. Incremental annual changes included in the tariffed rates include: (1) the incremental RAM adjusted revenues (the components of which are shown below), (2) the accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected: (in millions) HECO HELCO MECO Annual incremental RAM adjusted revenues O&M $ 3.9 $ 0.9 $ 1.0 Invested capital 27.7 1.2 3.2 Total annual incremental RAM adjusted revenues $ 31.6 $ 2.1 $ 4.2 Accrued earnings sharing credits to be refunded $ (2.1 ) $ - $ - Accrued RBA balance (and associated revenue taxes) to be collected $ 55.4 $ 4.9 $ 5.8 Under the 2011 decoupling tariff order, HECO, HELCO and MECO will accrue and collect 7/12ths of the annual incremental RAM adjusted revenues in one year and the remaining 5/12ths in the following year, provided the RAM rate adjustment remains in effect. The RAM rate adjustment terminates on the effective date of the D&O in a general rate case. However, based on the 2013 Agreement and 2013 D&O, HECO will be allowed to record incremental RAM revenues starting on January 1 of 2014, 2015 and 2016. See "Major projects" in Note 5 of HECO's "Notes to Consolidated Financial Statements." See "Economic conditions" in the "HEI Consolidated" section above. Results. Three months ended March 31 Increase 2013 2012 (decrease) (in millions) $ 719 $ 750 $ (31 ) Revenues. Decrease largely due to: $ (37 ) Lower fuel prices and purchased power, partly offset by: 3 Interim rate increase granted to MECO in its 2012 test year rate case 1 Interim and final rate increases granted to HECO in its 2011 test year rate case 305 328 (23 ) Fuel oil expense. Decrease largely due to lower fuel prices and lower KWHs generated 153 165 (12 ) Purchased power expense. Decrease due to lower KWH purchased and lower purchase capacity/non-fuel charges 101 92 9 Other operation and maintenance expenses. Increase largely due to: 5 Higher customer service expenses 2 Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012 2 Higher employee benefit costs (3 ) Partly offset by a 2012 increase in general liability reserve for an environmental matter 107 108 (1 ) 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 53 57 (4 ) Operating income. Decrease from prior year largely due to higher O&M and depreciation expenses, partly offset by interim and final rate increases 24 27 (3 ) Net income for common stock. Decrease largely due to lower operating income 2,123 2,251 (128 ) Kilowatthour sales (millions) 66.0 67.2 (1.2 ) Wet-bulb temperature (Oahu average; degrees Fahrenheit) 789 861 (72 ) Cooling degree days (Oahu) $ 130.83 $ 134.37 $ (3.54 ) Average fuel oil cost per barrel 449,512 447,407 2,105 Customer accounts (end of period) 55 -------------------------------------------------------------------------------- Table of Contents Note: The electric utilities had effective tax rates for the first quarters of 2013 and 2012 of 37% and 39%, respectively. The 2% decrease in the effective tax rate from the first quarter of 2012 was due to the receipt of nontaxable executive life insurance proceeds and the recognition of research and development credits which became available in 2013 under the American Taxpayer Relief Act of 2012. HECO's consolidated ROACE was 6.7% for the twelve months ended March 31, 2013 and 7.9% for the twelve months ended March 31, 2012. Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to 1% higher than 2012, as the electric utilities expect to manage expenses to near-2012 levels. Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility may initiate a PUC proceeding every third year (on a staggered basis) to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC's final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O. The 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 ROACE Test year (applied/ rates in ROACE RORB equity Consumer reflects(dollars in millions) implemented) Amount effect (%) (%) Rate base % Advocate decoupling HECO 2009 Request (1) 7/3/08 $ 97.0 5.2 11.25 8.81 $ 1,408 54.30 Yes No Interim increase 8/3/09 61.1 4.7 10.50 8.45 1,169 55.81 No Interim increase (adjusted) 2/20/10 73.8 5.7 10.50 8.45 1,251 55.81 No Final increase (2) 3/1/11 66.4 5.1 10.00 8.16 1,250 55.81 Yes 2011 (3) Request 7/30/10 $ 113.5 6.6 10.75 8.54 $ 1,569 56.29 Yes Yes Interim increase 7/26/11 53.2 3.1 10.00 8.11 1,354 56.29 Yes Interim increase (adjusted) 4/2/12 58.2 3.4 10.00 8.11 1,385 56.29 Yes Interim increase (adjusted) 5/21/12 58.8 3.4 10.00 8.11 1,386 56.29 Yes Final increase 9/1/12 58.1 3.4 10.00 8.11 1,386 56.29 Yes HELCO 2010 (4) Request 12/9/09 $ 20.9 6.0 10.75 8.73 $ 487 55.91 Yes Yes Interim increase 1/14/11 6.0 1.7 10.50 8.59 465 55.91 No Interim increase (adjusted) 1/1/12 5.2 1.5 10.50 8.59 465 55.91 No Final increase 4/9/12 4.5 1.3 10.00 8.31 465 55.91 Yes 2013 (5) Request 8/16/12 $ 19.8 4.2 10.25 8.30 $ 455 57.05 Yes Closed 3/27/13 MECO 2010 (6) Request 9/30/09 $ 28.2 9.7 10.75 8.57 $ 390 56.86 Yes Yes Interim increase 8/1/10 10.3 3.3 10.50 8.43 387 56.86 No Interim increase (adjusted) 1/12/11 8.5 2.7 10.50 8.43 387 56.86 No Final increase 5/4/12 4.7 1.5 10.00 8.15 387 56.86 Yes 2012 Request (7) 7/22/11 $ 27.5 6.7 11.00 8.72 $ 393 56.85 Yes Yes Interim increase 6/1/12 13.1 3.2 10.00 7.91 393 56.86 Yes -------------------------------------------------------------------------------- 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. 56 -------------------------------------------------------------------------------- Table of Contents (1) In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 5 of HECO's "Notes to Consolidated Financial Statements"). (2) Because the final increase was $7.4 million less in annual revenues, HECO refunded $2.1 million to customers (including interest) in February 2011. (3) HECO filed a request with the PUC for a general rate increase of $113.5 million, based on a 2011 test year and 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. (4) 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. (5) 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. (6) MECO's interim increase, effective August 1, 2010, was based on a stipulated agreement reached with the Consumer Advocate and temporary approval of new depreciation rates and methodology in a separate depreciation proceeding. The adjustment to this increase, effective January 12, 2011, reflects the final rates from MECO's 2007 test year rate case. On February 13, 2012, the PUC issued an order instructing MECO and the Consumer Advocate to submit a revised stipulated agreement to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation was filed. On March 29, 2012, MECO and the Consumer Advocate filed an updated agreement on all material issues in MECO's 2010 test year rate case proceeding. On May 2, 2012, the PUC issued a final D&O, which approved the updated agreement, and on May 4, 2012, the tariffs implementing the D&O became effective. MECO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. MECO 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 than the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund was required. (7) MECO's request is 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 below on interim decision and subsequent proposed adjustments to the interim increase. HECO 2011 test year rate case. In the HECO 2011 test year rate case, the PUC had granted HECO's request to defer Customer Information System (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 CIP CT-1 and the CIS projects, with the remaining recoverable costs 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 "Major projects" in Note 5 of HECO's Consolidated Financial Statements for additional information on the 2013 Agreement and the 2013 D&O and other effects. MECO 2012 test year rate case. On May 21, 2012, the PUC issued an interim D&O in MECO's 2012 test year rate case, which became effective June 1, 2012. The D&O authorized MECO to reset its target heat rates by fuel type to 2012 test year levels for the purpose of calculating the energy cost adjustment clause (ECAC) adjustment factor, which will help to ensure MECO's continuing recovery of its fuel costs. The interim increase is based on MECO's updated stipulated agreement with the Consumer Advocate filed on May 14, 2012. On July 20, 2012, MECO and the Consumer Advocate filed a stipulated supplement to the stipulated agreement to reduce the test year revenue requirement by $0.1 million in administrative and general expenses and requested that the final D&O for this rate case incorporate the adjustment into the final 2012 test year revenue requirement. 57 -------------------------------------------------------------------------------- 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 MECO's and HECO's plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the initial increments expected to come on line in 2015 and 2017, respectively. Due to a subsequent lowering of MECO's forecasted peaks, the projected capacity need date on the island of Maui has been deferred. Due to a subsequent lowering of HECO's forecasted sales and peaks, the projected capacity need and the timing will be dependent on the possible retirement or deactivation of generating units. The scope of both RFPs will be further defined in the the utilities' IRP, targeted to be filed with the PUC in June 2013. The respective schedules for the HECO and MECO RFPs will be assessed thereafter. † 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 to begin as early as 2015. † 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 expected to be placed in service in the second quarter of 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 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. † 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. 58 -------------------------------------------------------------------------------- Table of Contents † In December 2012, the 5 MW Kalaeloa Solar Two, LLC PV facility was placed into commercial operation, selling power to HECO under a 20-year contract. † In February 2013, HELCO issued the Final Geothermal RFP for up to 50 MW of dispatchable firm power on the island of Hawaii. Bids were received in April 2013 and are being evaluated. † HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of March 31, 2013, there were 9 MW, 1 MW and 1 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively. † As of March 31, 2013, there were 105 MW, 24 MW and 27 MW of installed net energy metering capacity from renewable energy technologies (mainly PV) at HECO, HELCO and MECO, respectively. Net energy metering is proceeding at a record pace. The amount of net energy metering capacity installed in the first quarter of 2013 was more than twice the amount installed in the same quarter 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 kilowatt-hour. HECO will consider requesting a waiver from the PUC Competitive Bidding Framework for projects that meet these goals. Proposals were received in March 2013 and are being evaluated. 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) March 31, 2013 December 31, 2012 Short-term borrowings $ 43 2 % $ - - % Long-term debt, net 1,148 42 1,148 43 Preferred stock 34 1 34 1 Common stock equity 1,477 55 1,472 56 $ 2,702 100 % $ 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 Three months ended March 31, December 31, (in millions) March 31, 2013 2013 2012 Short-term borrowings(1) Commercial paper $ 36 $ 43 $ - 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 quarter of 2013 was $71 million. At March 31, 2013, HECO had $17 million of short-term borrowings from HELCO, and MECO had $13 million of short-term borrowings from HECO. At April 29, 2013, HECO had $40 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $14 million of short-term borrowings from HELCO. Also, at April 29, 2013, MECO had $19 million of short-term borrowings from HECO. Intercompany borrowings are eliminated in consolidation. HECO has a line of credit facility of $175 million (see Note 9 of 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 59 -------------------------------------------------------------------------------- Table of Contents 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 43% for MECO as of March 31, 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 March 31, 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 source of their repayment is 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 SPRBs 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; 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. Operating activities provided $54 million in net cash during the first quarter of 2013. Investing activities for the same period used net cash of $56 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $22 million, primarily due to the increase in short-term borrowings, partly offset by payment of $21 million of common and preferred dividends. 60 -------------------------------------------------------------------------------- Table of Contents Bank RESULTS OF OPERATIONS Three months ended March 31 Increase (in millions) 2013 2012 (decrease) Primary reason(s) for significant change Interest income $ 46 $ 49 $ (3 ) The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB's average loan portfolio balance for the first quarter of 2013 was $108 million higher than for the first quarter of 2012 as the average home equity lines of credit, commercial real estate and consumer loan balances increased by $89 million, $36 million and $28 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. The average residential loan portfolio decreased by $27 million due to higher repayments and loan sales during 2012. The loan portfolio yield was impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield. The average investment and mortgage-related securities portfolio balance increased by $54 million as ASB used its excess liquidity to purchase securities. Noninterest 19 16 3 Higher gain on sale of loans as more income residential loans were sold in order to manage interest rate risk. Revenues 65 65 - Interest expense 2 3 (1 ) Lower funding costs as a result of the low interest rate environment. Average deposit balances for the first quarter of 2013 increased by $137 million compared to first quarter of 2012 due to an increase in core deposits of $209 million, partly offset by a decrease in term certificates of $72 million. The other borrowings average balance decreased by $40 million due to lower retail repurchase agreements. Provision for 2 4 (2 ) The provision for loan losses benefited loan losses from lower net charge-offs and improved credit quality associated with the continued improvement in Hawaii's economy. However, the provision was impacted by a single commercial real estate loan that was put on nonaccrual status. Noninterest 39 35 4 Higher compensation and benefits expense expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities. Expenses 43 42 1 Operating income 22 23 (1 ) Lower net interest income and higher noninterest expenses, partially offset by higher noninterest income. Net income 14 16 (2 ) Lower operating income. 61 -------------------------------------------------------------------------------- Table of Contents Details of ASB's other noninterest income and other noninterest expense were as follows: Three months ended March 31 2013 2012 (in thousands) Bank-owned life insurance $ 967 $ 979 Other 625 381 Total other income, net $ 1,592 $ 1,360 FDIC insurance premium $ 840 $ 853 Marketing 538 550Office supplies, printing and postage 873 990 Communication 471 436 Reversal of interest expense-tax - (552 ) Other 4,873 4,430 Total other expense $ 7,595 $ 6,707 See Note 4 of HEI's "Notes to Consolidated Financial Statements" and "Economic conditions" in the "HEI Consolidated" section above. Despite the revenue pressures across the banking industry, management expects ASB's low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers. For the quarter ended March 31, 2013, ASB reported a 1.12% annualized return on assets, net interest margin of 3.78% and a 61% efficiency ratio. For the year ended December 31, 2012, ASB reported a 1.18% return on assets, net interest margin of 3.93% and a 59% efficiency ratio. 62 -------------------------------------------------------------------------------- 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: Three months ended March 31 2013 2012 Average Yield/ Average Yield/ (dollars in thousands) balance Interest rate (%) balance Interest rate (%) Assets: Other investments (1) $ 198,202 $ 64 0.13 $ 251,615 $ 97 0.15 Available-for-sale investment and mortgage-related securities 648,693 3,619 2.23 595,072 3,879 2.61 Loans(2) Residential 1-4 family 1,882,185 23,356 4.96 1,909,675 25,610 5.36 Commercial real estate 421,492 4,633 4.42 385,916 4,586 4.76 Home equity line of credit 640,151 4,462 2.83 550,790 3,770 2.75 Residential land 25,009 256 4.09 41,868 555 5.30 Commercial loans 711,707 7,469 4.24 712,599 7,959 4.49 Consumer loans 123,648 2,427 7.94 95,220 2,408 10.17 Total loans (3) 3,804,192 42,603 4.50 3,696,068 44,888 4.87 Total interest-earning assets (4) 4,651,087 46,286 4.00 4,542,755 48,864 4.31 Allowance for loan losses (42,608 ) (38,187 ) Non-interest-earning assets 434,117 432,600 Total assets $ 5,042,596 $ 4,937,168 Liabilities and shareholder's equity: Savings $ 1,775,477 254 0.06 $ 1,698,849 310 0.07 Interest-bearing checking 640,190 24 0.02 605,526 30 0.02 Money market 195,563 63 0.13 249,685 121 0.19 Time certificates 469,798 971 0.84 541,330 1,318 0.98 Total interest-bearing deposits 3,081,028 1,312 0.17 3,095,390 1,779 0.23 Advances from Federal Home Loan Bank 50,000 535 4.28 50,000 541 4.28 Securities sold under agreements to repurchase 147,296 629 1.71 187,326 720 1.52 Total interest-bearing liabilities 3,278,324 2,476 0.30 3,332,716 3,040 0.36 Non-interest bearing liabilities: Deposits 1,151,572 1,000,099 Other 110,850 110,913 Total liabilities 4,540,746 4,443,728 Shareholder's equity 501,850 493,440 Total liabilities and shareholder's equity $ 5,042,596 $ 4,937,168 Net interest income $ 43,810 $ 45,824 Net interest margin (%) (5) 3.78 4.04 -------------------------------------------------------------------------------- (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 $1.5 million and $1.1 million for the three months ended March 31, 2013 and 2012, respectively, 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 and $0.2 million for the three months ended March 31, 2013 and 2012, respectively. (5) Defined as net interest income as a percentage of average earning assets. 63 -------------------------------------------------------------------------------- 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 by market 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: March 31, 2013 December 31, 2012 (dollars in thousands) Balance % of total Balance % of total Real estate loans: Residential 1-4 family $ 1,915,207 49.7 $ 1,866,450 49.2 Commercial real estate 391,679 10.2 375,677 9.9 Home equity line of credit 648,904 16.8 630,175 16.6 Residential land 23,894 0.6 25,815 0.7 Commercial construction 40,698 1.1 43,988 1.2 Residential construction 8,275 0.2 6,171 0.2 Total real estate loans, net 3,028,657 78.6 2,948,276 77.8 Commercial loans 699,918 18.1 721,349 19.0 Consumer loans 127,260 3.3 121,231 3.2 3,855,835 100.0 3,790,856 100.0 Less: Deferred fees and discounts (10,103 ) (11,638 ) Allowance for loan losses (42,730 ) (41,985 ) Total loans, net $ 3,803,002 $ 3,737,233 The increase in the total loan portfolio during the first quarter of 2013 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 target of mid-single digit growth for the year. 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: March 31, 2013 December 31,2012 (dollars in thousands) Balance % of total Balance % of total Federal agency obligations $ 167,960 26 % $ 171,491 26 % Mortgage-related securities - FNMA, FHLMC and GNMA 409,339 62 417,383 62 Municipal bonds 82,101 12 82,484 12 $ 659,400 100 % $ 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. 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 March 31, 2013. As of March 31, 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 quarter of 2013 was 0.12%, compared to 0.17% for the first quarter 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 64 -------------------------------------------------------------------------------- Table of Contents 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 March 31, 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 $10 million and $11 million, respectively. See "Item 3. Quantitative and qualitative disclosures about market risk." During the first quarter of 2013, ASB recorded a provision for loan losses of $1.9 million primarily due to charge-offs during the quarter for 1-4 family, residential land, commercial and consumer loans. During the first quarter of 2012, ASB recorded a provision for loan losses of $3.5 million primarily due to charge-offs during the quarter 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. Three months ended Year ended March 31 December 31 (in thousands) 2013 2012 2012 Allowance for loan losses, January 1 $ 41,985 $ 37,906 $ 37,906 Provision for loan losses 1,858 3,546 12,883 Less: net charge-offs 1,113 2,618 8,804 Allowance for loan losses, end of period $ 42,730 $ 38,834 $ 41,985 Ratio of allowance for loan losses, end of period, to end of period loans outstanding 1.11 % 1.05 % 1.11 % Ratio of net charge-offs during the period to average loans outstanding (annualized) 0.12 % 0.28 % 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 a 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. HEI will be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. The Dodd-Frank Act requires regulators, at a minimum, to apply to bank and thrift holding companies leverage and risk-based capital standards that are at least as strict as those in effect at the insured depository institution level on the date the Act became effective, although there will be a phase-in period for meeting these standards. 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 December 21, 2012, the Bureau issued the Remittance Rule (an amendment to Regulation E) which closed for comment on January 30, 2013. 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 65 -------------------------------------------------------------------------------- Table of Contents 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 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. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer's ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower. ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and allows federal law to preempt a state consumer financial law on a "case by case" basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (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. As specified in the Dodd-Frank Act, these regulations will exempt banks like ASB, that, along with their affiliates, have less than $10 billion in assets. For the first quarter of 2013, ASB had earned an average of 49 cents per transaction. However, market pressures could cause all banks to observe the limitation. Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective. Proposed Capital Rules. The FRB, OCC and FDIC issued three notices of proposed rulemaking (NPR) that would revise and replace the current capital rules. The proposed rules are intended to help ensure banks maintain strong capital positions, which would enable them to continue lending to creditworthy households and businesses even after unforeseen losses and during severe economic downturns. The first NPR, titled Regulatory Capital Rules: Regulatory Capital, Implementation of Basel III, Minimum Regulatory Capital Ratios, Capital Adequacy, and Transition Provisions (Basel III NPR), applies to all depository institutions, bank holding companies with total consolidated assets of $500 million or more, and savings and loan holding companies and revises the risk-based and leverage capital requirements consistent with agreements reached by the Basel Committee on Banking Supervision (Basel III). The Basel III NPR would increase the quantity and quality of capital required, revise the definition of capital to improve the ability of regulatory capital instruments to absorb losses, establish limitations on capital distributions and certain discretionary bonus payments if additional specified amounts of common equity tier 1 capital are not met, and introduce a supplementary leverage ratio for internationally active banking organizations. The Basel III NPR would also revise the prompt corrective action framework by incorporating new regulatory capital minimums and updating the definition of tangible common equity. The second NPR, titled Regulatory Capital Rules: Standardized Approach for Risk-weighted Assets; Market Discipline and Disclosure Requirements (Standardized Approach NPR), proposes to revise and harmonize the rules for calculating risk-weighted assets to enhance risk sensitivity and address weaknesses identified over the past several years. The Standardized Approach NPR would incorporate aspects of the Basel II standardized 66 -------------------------------------------------------------------------------- Table of Contents framework such as methods for determining risk-weighted assets for residential mortgages, securitization exposures, and counterparty credit risk. The Standardized Approach NPR would apply to the same set of institutions as the Basel III NPR, but also introduces disclosure requirements for U.S. banking organizations with $50 billion or more in assets. The third NPR, Regulatory Capital Rules: Advanced Approaches Risk-based Capital Rule: Market Risk Capital Rule (Advanced Approaches NPR), would apply to banking organizations that are subject to the banking agencies' advanced approaches rule, or to their market risk rule, and revises the advanced approaches risk-based capital rules to be consistent with Basel III and the Dodd-Frank Act. Generally, the advanced approaches rules would apply to institutions with $250 billion or more in consolidated assets or $10 billion or more in foreign exposure, and the market risk rule would apply to savings and loan holding companies with significant trading activity. Proposed Capital Requirements Proposal effective dates 1/1/13 1/1/14 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 3.50 % 4.00 % 4.50 % 5.125 % 5.75 % 6.375 % 7.00 % Tier 1 capital ratio + conservation buffer 4.50 % 5.50 % 6.00 % 6.625 % 7.25 % 7.875 % 8.50 % Total capital ratio + conservation buffer 8.00 % 8.00 % 8.00 % 8.625 % 9.25 % 9.875 % 10.50 % Countercyclical capital buffer - not applicable to ASB 0.625 % 1.25 % 1.875 % 2.50 % The proposed rules allow for a transition period to meet the proposed capital requirement levels. ASB is reviewing the proposed rules and the impact to its capital ratios. Based on a preliminary assessment, management believes ASB and HEI can satisfy the proposed capital rules that would be applicable to them, if adopted. Commitments and contingencies. See Note 4 of HEI's "Notes to Consolidated Financial Statements." FINANCIAL CONDITION Liquidity and capital resources. March 31, December 31, (dollars in millions) 2013 2012 % change Total assets $ 5,116 $ 5,042 1 Available-for-sale investment and mortgage-related securities 659 671 (2 ) Loans receivable held for investment, net 3,803 3,737 2 Deposit liabilities 4,313 4,230 2 Other bank borrowings 193 196 (1 ) As of March 31, 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 March 31, 2013, ASB's unused FHLB borrowing capacity was approximately $1.0 billion. As of March 31, 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 quarter of 2013, net cash provided by ASB's operating activities was $30 million. Net cash used during the same period by ASB's investing activities was $56 million, primarily due to purchases of investment and mortgage-related securities of $27 million, a net increase in loans receivable of $67 million and additions to premises and equipment of $3 million, partly offset by repayments of investment and mortgage-related securities of $37 million and proceeds from the sale of real estate acquired in settlement of loans of $3 million. Net cash provided in financing activities during this period was $67 million, primarily due to net increases in deposit liabilities of $83 million, partly offset by a net decrease in retail repurchase agreements of $3 million, the payment of $10 million in common stock dividends to HEI (through ASHI) and a net decrease in mortgage escrow deposits of $3 million. 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 March 31, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 11.7% (6.0%) and a total risk-based capital ratio of 12.8% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI). 67 -------------------------------------------------------------------------------- Table of Contents [ Back To TMCnet.com's Homepage ]