ITEM 1B.
UNRESOLVED STAFF COMMENTS
HEI: None.
Hawaiian Electric: Not applicable.
HEI and Hawaiian Electric: See the “Properties” sections under “HEI,” “Electric utility” and “Bank” in Item 1. Business above.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
HEI and Hawaiian Electric: HEI subsidiaries (including Hawaiian Electric and its subsidiaries and ASB) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigation incidental to their respective businesses. See the descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” in HEI’s MD&A and in the Notes 3 and 4 of the Consolidated Financial Statements. Management believes that, other than these proceedings, the likelihood that HEI or its subsidiaries would incur material losses or write-offs in excess of insurance coverage and loss reserves recorded on HEI’s consolidated balance sheet from lawsuits or other proceedings currently pending or threatened is remote. Nevertheless, the outcomes of litigation and administrative proceedings are necessarily uncertain and there is a risk that the outcome of such matters could have a material
adverse effect on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular period in the future.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
HEI and Hawaiian Electric: Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)
The executive officers of HEI are listed below. Messrs. Rosenblum and Wacker are officers of HEI subsidiaries rather than of HEI, but are deemed to be executive officers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive officers serve from the date of their initial appointment until the annual meeting of the HEI Board (or applicable HEI subsidiary board of directors) at which officers are appointed, and thereafter are appointed for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or removal. HEI executive officers may also hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.
Family relationships; executive arrangements
There are no family relationships between any HEI executive officer and any other HEI executive officer or any HEI director or director nominee. There are no arrangements or understandings between any HEI executive officer and any other person pursuant to which such executive officer was selected.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
HEI:
Certain of the information required by this item is incorporated herein by reference to Note 14, “Regulatory restrictions on net assets” and Note 17, “Quarterly information (unaudited)” of the Consolidated Financial Statements and "Item 6.
ITEM 6.
SELECTED FINANCIAL DATA
HEI:
*
At December 31.
**
Calculated using December 31 market price per common share divided by basic earnings per common share. The principal trading market for HEI’s common stock is the New York Stock Exchange (NYSE).
***
At December 31. Represents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 7, 2014, HEI had 8,388 registered shareholders (i.e., holders of record of HEI common stock), 26,791 DRIP participants and total shareholders of 30,585.
See “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations.
For 2013, 2012, 2011, 2010 and 2009, under the two-class method of computing basic earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.39, $0.19, $0.21, $(0.02) and $(0.33) per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2013, 2012, 2011, 2010 and 2009, under the two-class method of computing diluted earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.38, $0.18, $0.20, $(0.03) and $(0.33) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.
Hawaiian Electric:
Selected Financial Data
Hawaiian Electric Company, Inc. and Subsidiaries
*
At December 31.
HEI owns all of Hawaiian Electric’s common stock. Therefore, per share data is not meaningful.
See "Forward-Looking Statements" above, the “electric utility” sections and all information related to, or including, Hawaiian Electric and its subsidiaries in HEI’s MD&A in the Form 10-K and “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries):
The following discussion should be read in conjunction with the Consolidated Financial Statements. The general discussion of HEI’s consolidated results should be read in conjunction with the electric utility and bank segment discussions that follow.
HEI Consolidated
Executive overview and strategy. HEI is a holding company that operates subsidiaries (collectively, the Company), principally in Hawaii’s electric utility and banking sectors. HEI’s strategy is to build fundamental earnings and profitability of its electric utilities and bank in a controlled risk manner to support its current dividend and improve operating and capital efficiency in order to build shareholder value.
HEI, through its electric utility subsidiaries (Hawaiian Electric and its subsidiaries, Hawaii Electric Light and Maui Electric), provides the only electric public utility service to approximately 95% of Hawaii’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, ASB, one of Hawaii’s largest financial institutions based on total assets. Together, HEI’s unique combination of electric utilities and a bank continues to provide the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries while providing an attractive dividend for investors.
In 2013, net income for HEI common stock was $162 million, up $23 million from $139 million in 2012 primarily due to the Utilities’ writedown in 2012 of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits. ASB had slightly lower net income in 2013 compared to 2012 and the “other” segment had slightly lower losses. Basic earnings per share were $1.63 per share in 2013, up 14% from $1.43 per share in 2012 due to the effects of the impact of the Utilities $24 million (net of taxes) writedown in 2012.
The Utilities’ strategic focus has been to meet Hawaii’s energy needs by modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy generation and taking the necessary steps to secure regulatory support for their plans. Electric utility net income for common stock in 2013 of $123 million increased 24% from the prior year due primarily to the 2012 writedown of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits. Key to results for 2014 will be the impacts of actions taken under the Hawaii Clean Energy Initiative (HCEI) and Energy Agreement, including the steps taken toward the integration of new generation from a variety of renewable energy sources into the utility systems, and managing operation and maintenance expenses to the levels included in rates.
ASB continues to develop and introduce new products and services in order to meet the needs of both consumer and commercial customers. Additionally, ASB is making the investments in people and technology necessary to adapt to a constantly changing banking industry and remain competitive. ASB’s earnings in 2013 of $57.5 million decreased $1.1 million compared to prior year net income due primarily to lower net interest and noninterest income and higher noninterest expenses, partly offset by a lower provision for loan losses. In 2013, ASB earnings were also impacted by lower debit card interchange fees as a result of being non-exempt from the Durbin Amendment from July 1, 2013 and the sale of its credit card portfolio. ASB’s future financial results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio.
HEI’s “other” segment had a net loss in 2013 of $18.9 million, comparable to the net loss of $19.3 million in 2012.
Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, Hawaiian Electric, have paid dividends continuously since 1901. The dividend has been stable at $1.24 per share annually since 1998. The indicated dividend yield as of December 31, 2013 was 4.8%. The dividend payout ratios based on net income for common stock for 2013, 2012 and 2011 were 76%, 87% and 86%, respectively. The HEI Board of Directors considers many factors in determining the dividend quarterly, 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.
HEI’s subsidiaries from time to time consider various strategies designed to enhance their competitive positions and to maximize shareholder value. These strategies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to time be engaged in preliminary discussions, either internally or with third parties,
regarding potential transactions. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented.
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, 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 a new record in 2013 with visitor arrivals growing by 2.6% over 2012 to 8.2 million arrivals. Visitor expenditures also grew 2.0% in 2013 compared to 2012 to over $14.5 billion. The good news was tempered, however, as strong growth in state visitor arrivals and expenditures in the first half of 2013 was partially offset by lower than 2012 arrivals and expenditures in the second half of the year. Hotel occupancies and average daily hotel room rates remained strong. The outlook for the visitor industry remains positive, but is expected to expand at a slower pace in 2014. The HTA expects scheduled nonstop seats to Hawaii for the first quarter of 2014 to increase by 2.4% over the first quarter of 2013, based on the expectation that airlift capacity declines in U.S. markets will be offset by increases in international flights.
For the first time since November 2008, the U.S. unemployment rate fell below 7% in December 2013. Hawaii’s unemployment rate was relatively stable at 4.5% in December 2013, lower than the state’s 5.1% rate in December 2012 and the December 2013 national unemployment rate of 6.7%.
Hawaii real estate activity, as indicated by the home resale market, was strong in 2013 as the median sales price for single family residential homes on Oahu increased 4.8% and the number of closed sales increased 4.6% over 2012. Oahu condominiums also maintained strong momentum as the median sales price rose 4.6% and closed sales increased 11.8% in 2013 over 2012. Strengthening interest in new housing was reflected in increased development activity. The announcements of several new planned condominium developments in Honolulu, at various price points from workforce housing to luxury projects, were met with immediate interest and generated strong pre-sale demand. In November 2013, Castle & Cooke’s Koa Ridge master plan for 3,500 single- and multi-family homes received Honolulu City Council and the Mayor’s approval for a zoning change from agricultural land after more than ten years of public debate.
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 2013.
At its January 28-29, 2014 meeting, the Federal Open Market Committee (FOMC) saw quickening economic activity in recent quarters and improvement in labor market conditions as consistent with a strengthening in the broader economy. In light of the cumulative progress toward improved labor market conditions, the FOMC decided to continue to take measured steps to modestly reduce the pace of purchases of Treasury and agency mortgage-backed securities beyond the steps the FOMC had taken after its meeting in December 2013. The FOMC also indicated that if economic data continues to support the outlook of ongoing improvement, the pace of asset purchases would likely be further reduced. The FOMC emphasized that asset purchases are not on a preset course and are still contingent on FOMC evaluation.
On October 1, 2013, the U.S. government began a new fiscal year with no spending legislation enacted and as a result, a partial federal shutdown took effect. On October 16, 2013, the government shutdown ended when Congress passed legislation on a budget through January 15, 2014 and raised the government debt ceiling to provide the U.S. Treasury with borrowing authority through February 7, 2014. A final $1.1 trillion U.S. budget was approved with relative ease in January 2014.
Overall, Hawaii’s economy is expected to see continuing growth in 2014 and 2015. Local economic growth is expected to be supported by continued recovery in the construction industry and steady, but slower growth in the visitor industry. U.S. fiscal problems, continued uncertainty in global economies, heightened tensions in Asia and potential pandemics pose possible risks to local economic growth.
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 $131 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 increased the Company’s federal tax depreciation for 2013 by an estimated
$131 million, primarily attributable to the Utilities. Congress has not extended the bonus depreciation provision and therefore no significant bonus depreciation will be taken on 2014 plant additions.
Also, see Note 12 of the Consolidated Financial Statements.
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.
Results of operations.
NM
Not meaningful.
See “Executive overview and strategy” above and the “Other segment,” “Electric utility” and “Bank” sections below for discussions of results of operations.
Retirement benefits. The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, plus earnings and realized and unrealized gains and losses on plan assets, and changes made to the provisions of the plans. During 2011, for example, the qualified retirement plan for employees of HEI and Hawaiian Electric was changed for employees hired on or after May 1, 2011. Those employees will receive lower benefit accruals, different early retirement reduction factors and no automatic cost of living increases. The change is expected to decrease ongoing costs through a reduction in service cost. (See Note 10 of the Consolidated Financial Statements.) Costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on plan assets and the discount rate. The Company’s accounting for retirement benefits under the plans in which the employees of the Utilities participate is also adjusted to account for the impact of decisions by the Public Utilities Commission of the State of Hawaii (PUC). Changes in obligations associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.
The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefits costs on a prospective basis.
For 2013, the Company’s retirement benefit plans’ assets generated a gain of 20%, net of investment management and trustee fees, resulting in net earnings and unrealized gains of $223 million, compared to net earnings and unrealized gains of $134 million for 2012 and net losses and unrealized losses of $12 million for 2011. The market value of the retirement benefit plans’ assets for December 31, 2013 and 2012 were $1.4 billion and $1.1 billion, respectively.
The Company intends to make contributions to the qualified pension plan for HEI and Hawaiian Electric equal to the calculated net periodic pension cost for the year. However, if the minimum required contribution determined under the Employee Retirement Income Security Act of 1974 (ERISA), as amended by the Pension Protection Act of 2006, for the year is greater than the net periodic pension cost, then the Company will contribute the minimum required contribution and the
Utilities’ difference between the minimum required contribution and the net periodic pension cost will increase their regulatory asset. In the next rate case, the regulatory asset will be amortized over five years and used to reduce the cash funding requirement based on net periodic pension cost. The regulatory asset may not be applied against the ERISA minimum required contribution.
The net periodic pension cost is expected to be higher than the ERISA minimum required contribution for 2014. Therefore, to satisfy the requirements of the electric utilities’ pension tracking mechanism, net periodic pension cost will be the basis of the cash funding for 2014. Based on plan assets as of December 31, 2013 and various assumptions in Note 10 of the Consolidated Financial Statements, the Company estimates that the cash contributions to the plans for 2014 will be $59 million ($1 million for HEI and $58 million for the Utilities).
Based on various assumptions in Note 10 of the Consolidated Financial Statements and assuming no further changes in retirement benefit plan provisions, information regarding consolidated HEI’s and consolidated Hawaiian Electric’s retirement benefits was, or is estimated to be, as follows, and constitutes “forward-looking statements:”
Based on various assumptions in Note 10 of the Consolidated Financial Statements, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2013, associated with a change in certain actuarial assumptions, were as follows and constitute “forward-looking statements.”
The impact on 2014 net income for common stock for changes in actuarial assumptions should be immaterial based on the adoption by the electric utilities of pension and postretirement benefits other than pensions (OPEB) tracking mechanisms approved by the PUC. See Note 10 of the Consolidated Financial Statements for further retirement benefits information.
Other segment.
Including writedowns of and net gains and losses from investments.
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 (venture capital investments with a carrying value of $0.5 million as of December 31, 2013); The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; and Pacific Energy Conservation Services, Inc., a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm was dismantled in the fourth quarter of 2010 and dissolved in the second quarter of 2011; as well as eliminations of intercompany transactions.
HEI corporate-level operating, general and administrative expenses were $16 million in 2013 compared to $16 million in 2012 and $15 million in 2011. In 2013, HEI had higher administrative and general expenses, including retirement benefits, partly offset by lower executive compensation. In 2012, HEI had higher executive compensation and employee benefits expenses, including retirement benefits.
The “other” segment’s interest expenses were $16 million in 2013, $16 million in 2012 and $22 million in 2011. In 2013, $50 million of long-term debt was refinanced at a lower interest rate. In 2012, HEI had lower average borrowings and interest rates. The “other” segment’s income tax benefits were $14 million in 2013, $15 million in 2012 and $17 million in 2011.
Effects of inflation. U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 1.5% in 2013, 2.1% in 2012 and 3.2% in 2011. Hawaii inflation, as measured by the Honolulu CPI, was 2.4% in 2012, 3.7% in 2011 and 2.1% in 2010. DBEDT estimates average Honolulu CPI to have been 1.7% in 2013 and forecasts it to be 2.1% for 2014.
Inflation continues to have an impact on HEI’s operations. Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, replace assets at much higher costs and must request and obtain rate increases to maintain adequate earnings. In the past, the PUC has granted rate increases in part to cover increases in construction costs and operating expenses due to inflation.
Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.
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 in the foreseeable future.
The Company’s total assets were $10.3 billion as of December 31, 2013 and $10.1 billion as of December 31, 2012.
The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:
HEI’s short-term borrowings and HEI’s line of credit facility were as follows:
This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities, which are disclosed below under “Electric utility-Financial Condition-Liquidity and capital resources. At February 7, 2014, HEI’s outstanding commercial paper balance was $96 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2013 was $105 million.
HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements. HEI also periodically makes short-term loans to Hawaiian Electric to meet Hawaiian Electric’s cash requirements, including the funding of loans by Hawaiian Electric to Hawaii Electric Light and Maui Electric, but no such short-term loans to Hawaiian Electric were outstanding as of December 31, 2013. HEI periodically utilizes long-term debt, historically consisting of medium-term notes and other unsecured
indebtedness, to fund investments in and loans to its subsidiaries to support their capital improvement or other requirements, to repay long-term and short-term indebtedness and for other corporate purposes.
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. On December 19, 2013, HEI settled 1.3 million shares under the equity forward for proceeds of $32.1 million (net of the underwriting discount of $1.3 million), which funds were ultimately used to purchase common stock of Hawaiian Electric.
In November 2011, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities. Under Securities and Exchange Commission (SEC) regulations, this registration statement expires on November 4, 2014.
HEI has a line of credit facility of $125 million. See Note 7 of the Consolidated Financial Statements. The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Issuer Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 2.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts.
In addition to their impact on pricing under HEI’s credit agreement, the rating of HEI’s commercial paper and debt securities could significantly impact the ability of HEI to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities.
On January 21, 2014, Fitch Ratings (Fitch) assigned initial ratings to HEI as noted in the table below. The key ratings drivers cited were (1) ownership of two investment grade subsidiaries, (2) subordination of cash flows and (3) moderate degree of parent level debt leverage.
As a result of updating it ratings methodology, Moody’s placed the ratings of most U.S. regulated utilities and utility holding companies on review for upgrade. HEI was included in the list of companies on review for upgrade. Subsequently, on January 30, 2014, Moody’s confirmed HEI’s ratings as noted in the table below and indicated that despite their view that Hawaiian Electric, like many other regulated utilities in the U.S., received more credit supportive regulatory treatment over the years, HEI's and Hawaiian Electric’s cash flow to debt ratios are too weak to support an upgrade. HEI's ratings reflect the relatively stable earnings and cash flow historically provided by both the vertically integrated utility businesses at Hawaiian Electric and the stable banking operations at ASB. The ratings also recognize the challenges at Hawaiian Electric, which have some of the highest retail electric rates in the country and the heavy pressure from regulators and stakeholders to reduce rates and dependence on fuel oil. Moody’s indicated the rating could be downgraded or placed on negative outlook if Maui Electric’s poor rate case outcome spills over to Hawaiian Electric and Hawaii Electric Light.
On February 10, 2014, S&P maintained its corporate credit ratings for HEI, as noted in the table below. S&P indicated that the "BBB-" issuer credit rating on HEI is derived from S&P's anchor of "bbb", based on a “strong” business risk and “significant” financial risk profile assessments for the company. The negative comparable rating analysis modifier resulted in a -1 notch adjustment to the anchor. S&P indicated that unfavorable comparable ratings analysis reflects the Utilities’ ongoing challenges to earn closer to the allowed returns and the need to continuously effectively manage regulatory risk; past challenges to complete major projects on budget and on schedule; and the potential threat from increasing roof-top solar penetration, relative to peers. The stable outlook reflects S&P’s understanding that “the decoupling mechanisms will remain largely unchanged and the company will successfully manage expenses, HECO will reach a constructive outcome in its next rate case filing, and HEI will maintain a balanced funding approach that continues to support the current credit profile.”
As of February 10, 2014, the Fitch, Moody's and S&P ratings of HEI were as follows:
The above ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
Management believes that, if HEI’s commercial paper ratings were to be downgraded, or if credit markets for commercial paper with HEI’s ratings or in general were to tighten, it could be more difficult and/or expensive for HEI to sell commercial paper or HEI might not be able to sell commercial paper in the future. Such limitations could cause HEI to draw on its syndicated credit facility instead, and the costs of such borrowings could increase under the terms of the credit agreement as a result of any such ratings downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it could be more difficult and/or expensive for HEI to issue long-term debt. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of HEI and its subsidiaries.
Issuances of common stock through the Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan (DRIP), Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan provided new capital of $48 million (approximately 1.8 million shares) in 2013, $47 million (approximately 1.8 million shares) in 2012 and $24 million (approximately 1.0 million shares) in 2011. From August 18, 2011 to January 8, 2012, HEI satisfied the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than new issuances.
Operating activities provided net cash of $327 million in 2013, $235 million in 2012 and $250 million in 2011. Investing activities used net cash of $564 million in 2013, $427 million in 2012 and $327 million in 2011. In 2013, net cash used in investing activities was primarily due to a net increase in loans held for investment, Hawaiian Electric’s consolidated capital expenditures (net of contributions in aid of construction) and purchases of investment and mortgage-related securities, partly offset by the repayments of investment and mortgage-related securities and the proceeds from sales of investment securities and real estate acquired in settlement of loans of ASB. Financing activities provided net cash of $237 million in 2013, $142 million in 2012 and $16 million in 2011. In 2013, net cash provided by financing activities included net increases in deposits, other bank borrowings, long-term debt and short-term borrowings and proceeds from the issuance of common stock, offset by the payment of common and preferred stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition-Liquidity and capital resources” sections below.) During 2013, Hawaiian Electric and ASB (via ASHI) paid cash dividends to HEI of $82 million and $40 million, respectively.
A portion of the net assets of Hawaiian Electric and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. One of the conditions to the PUC’s approval of the merger and corporate restructuring of Hawaiian Electric and HEI requires that Hawaiian Electric maintain a consolidated common equity to total capitalization ratio of not less than 35% (actual ratio of 56% at December 31, 2013), and restricts Hawaiian Electric from making distributions to HEI to the extent it would result in that ratio being less than 35%. In the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its ability to meet its debt or other cash obligations. See Note 14 of the Consolidated Financial Statements.
Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2014 through 2016 consists primarily of the net capital expenditures of the Utilities. In addition to the funds required for the Utilities’ construction programs (see “Electric utility-Liquidity and capital resources”), approximately $175 million will be required during 2014 through 2016 to repay maturing HEI medium-term notes, which are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, other medium- or long-term debt, common stock and/or dividends from subsidiaries. Medium-term notes of $100 million maturing in May 2014 are expected to be replaced with new debt. In addition, Hawaiian Electric special purpose revenue bonds (SPRBs) totaling $11 million will be maturing during 2014 through 2016 and are expected to be repaid with proceeds from issuances of debt and/or equity financing. Additional debt and/or equity financing may be utilized to invest in the Utilities and bank, pay down commercial paper or other short-term borrowings or may be required to fund unanticipated expenditures not included in the 2014 through 2016 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the Utilities, unanticipated utility capital expenditures that may be required by the HCEI or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if certain tax positions taken by the Company do not prevail or if taxes are increased by federal or state legislation. In addition, existing debt may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both).
As further explained in “Retirement benefits” above and Notes 1 and 10 of the Consolidated Financial Statements, the Company maintains pension and OPEB plans. The Company’s contributions to the retirement benefit plans totaled $83 million in 2013 ($81 million by the Utilities, $2 million by HEI and nil by ASB), $78 million in 2012 ($63 million by the Utilities, $2 million by HEI and $13 million by ASB) and $75 million in 2011 ($73 million by the Utilities, $2 million by HEI and nil by ASB) and are expected to total $59 million in 2014 ($58 million by the Utilities, $1 million by HEI and nil by ASB). These
contributions satisfied the minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006, and the requirements of the electric utilities’ pension and OPEB tracking mechanisms. In addition, the Company paid directly $2 million of benefits in 2013, $1 million in 2012 and $2 million in 2011 and expects to pay $2 million of benefits in 2014. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate cash flow or access to capital resources to support any necessary funding requirements.
Selected contractual obligations and commitments. Information about payments under the specified contractual obligations and commercial commitments of HEI and its subsidiaries was as follows:
Deposits that have no maturity are included in the “Less than 1 year” column, however, they may have a duration longer than one year.
Includes contractual obligations and commitments for capital expenditures and expense amounts.
The tables above do not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, obligations that may arise under indemnities provided to purchasers of discontinued operations and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2013, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables above; however, see “Retirement benefits” above for estimated minimum required contributions for 2014.
See Note 3 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments.
Off-balance sheet arrangements. Although the Company has off-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors, including the following types of off-balance sheet arrangements:
1.
obligations under guarantee contracts,
2.
retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serve as credit, liquidity or market risk support to that entity for such assets,
3.
obligations under derivative instruments, and
4.
obligations under a material variable interest held by the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.
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 its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors. Also see “Forward-Looking Statements” and “Risk Factors” above and “Certain factors that may affect future results and financial condition” in each of the electric utility and bank segment discussions below.
Economic conditions, U.S. capital markets and credit and interest rate environment. Because the core businesses of HEI’s subsidiaries are providing local electric public utility services and banking services in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates, particularly on the construction and real estate industries, and by the impact of world conditions on federal government spending in Hawaii. The two largest components of Hawaii’s economy are tourism and the federal government (including the military).
Declines in the Hawaii, U.S. and Asian economies in recent years led to declines in KWH sales, delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses.
If Fitch, Moody's or S&P were to downgrade HEI’s or Hawaiian Electric’s debt ratings, or if future events were to adversely affect the availability of capital to the Company, HEI’s and Hawaiian Electric’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase.
Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust, and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obligations. The Utilities’ pension tracking mechanisms help moderate pension expense; however, a decline in the value of the Company’s defined benefit pension plan assets may increase the unfunded status of the Company’s pension plans and result in increases in future funding requirements.
Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. Changes in interest rates and credit spreads also affect the fair value of ASB’s investment and mortgage-related securities. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return and overall economic activity. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.
Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. The Utilities’ transmission and distribution systems (excluding substation buildings and contents) have a replacement value roughly estimated at $6 billion and are uninsured. Similarly, the Utilities have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the Utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers also have exclusions or limitations of coverage for claims related to certain perils including, but not limited to, mold and terrorism. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to an insurance deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur uninsured losses in amounts that would have a material adverse effect on the Company’s results of operations, financial condition and liquidity.
Environmental matters. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, may require that certain environmental permits be obtained and maintained as a condition to constructing or operating certain facilities. Obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance.
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.
Material estimates that are particularly susceptible to significant change include the amounts reported for investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses. Management considers an accounting estimate to be material if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of operations or financial condition.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified accounting policies it believes to be the most critical to the Company’s financial statements-that is, management believes that the policies discussed below 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. The policies affecting both of the Company’s two principal segments are discussed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and critical accounting policies.” Management has reviewed the material estimates and critical accounting policies with the HEI Audit Committee and, as applicable, the Hawaiian Electric Audit Committee.
For additional discussion of the Company’s accounting policies, see Note 1 of the Consolidated Financial Statements and for additional discussion of material estimates and critical accounting policies, see the electric utility and bank segment discussions below under the same heading.
Pension and other postretirement benefits obligations. For a discussion of material estimates related to pension and other postretirement benefits (collectively, retirement benefits), including costs, major assumptions, plan assets, other factors affecting costs, accumulated other comprehensive income (loss) (AOCI) charges and sensitivity analyses, see “Retirement benefits” in “Consolidated-Results of operations” above and Notes 1 and 10 of the Consolidated Financial Statements.
Contingencies and litigation. The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the likelihood of any adverse judgments in or outcomes of these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.
In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale.
See Notes 3 and 4 of the Consolidated Financial Statements.
Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities using tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from its tax advisors. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.
See Note 12 of the Consolidated Financial Statements.
Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 2 of the Consolidated Financial Statements. The discussion concerning Hawaiian Electric should be read in conjunction with its consolidated financial statements and accompanying notes.
Electric utility
Executive overview and strategy. The Utilities provide electricity for 95% of Hawaii’s residents, operating on five separate grids. The Utilities’ strategic focus is meeting Hawaii’s energy needs in a reliable, economical and environmentally sound way by modernizing the electric grid, maximizing the use of low-cost, clean energy sources, sustaining an effective asset management program and promoting smart use of energy by customers through information and choices. The Utilities are focused on helping Hawaii achieve its statutory goal of 40% of electricity from clean, locally-generated sources by 2030.
Utility strategic progress. In 2012 and 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 3 of the Consolidated Financial Statements and the discussion under “Most recent rate proceedings” below.
In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 or 2012. The decoupling model implemented delinks revenues from sales and includes annual revenue adjustments for certain O&M expenses and rate base changes.
Under decoupling, the most significant drivers for improving earnings are:
•completing major capital projects within PUC approved amounts and on schedule;
•managing O&M expense relative to authorized O&M adjustments; and
•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, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. On February 7, 2014, in the first part of this bifurcated proceeding, the PUC issued a D&O on select issues, which made certain modifications to the decoupling mechanism. Among other things, the D&O requires:
•
An adjustment to the Rate Base RAM Adjustment to include 90% of the amount of the current RAM Period Rate Base RAM Adjustment that exceeds the Rate Base RAM Adjustment from the prior year, to be effective with the Utilities' 2014 decoupling filing.
•
Effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case, instead of the 6% that has been previously approved.
The second part of this proceeding will continue this year with panel hearings scheduled for August 2014. See "Decoupling" in Note 3 of the Consolidated Financial Statements.
Actual and PUC-allowed (as of December 31, 2013) returns were as follows:
* 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 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 actually achieved due to the following:
•the timing of general rate case decisions,
•
the effective date of the RAMs for Hawaii Electric Light and Maui Electric,
•the 5-year historical average for baseline plant additions,
•
the modifications to the rate base RAM and RBA interest rate per the PUC's February 2014 decision on decoupling (as discussed in Note 3 of the Notes to Consolidated Financial Statements), and
•the PUC’s consistent exclusion of certain expenses from rates.
The structural gap in 2014 to 2016 is expected to be 100 to 130 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.
As part of decoupling, the Utilities also track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. Earnings of a utility over and above the ROACE allowed by the PUC are shared between the utility and its ratepayers on a tiered basis. For 2013, Maui Electric’s rate-making ROACE was 9.33%, which was above the PUC allowed 9% ROACE and triggered the earnings sharing mechanism. As a result, Maui Electric will credit its customers $0.3 million for their portion of the earnings sharing. Maui Electric’s 2013 ratemaking ROACE of 9.33% included adjustments to Maui Electric’s actual ROACE of 8.91% such as expenses not considered in establishing electric rates (e.g., executive bonuses). For 2013, Hawaiian Electric’s rate-making ROACE was 8.91% and Hawaii Electric Light’s rate-making ROACE was 7.46%, which did not trigger the earnings sharing mechanism. For 2012, Hawaiian Electric’s rate-making ROACE was 10.70%, which was above the PUC-allowed 10% ROACE. As a result, Hawaiian Electric credited its customers $2.6 million for their portion of the earnings sharing. Hawaiian Electric’s 2012 rate-making ROACE of 10.70% included various adjustments to Hawaiian Electric’s actual ROACE of 7.57% such as the exclusion of the $40 million of CIS project costs pursuant to the 2013 Agreement, and other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). For 2012, Hawaii Electric Light’s rate-making ROACE was 7.79% and Maui Electric’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.
Annual decoupling filings. On May 31, 2013, the PUC approved the revised annual decoupling filings for tariffed rates for the Utilities that will be effective from June 1, 2013 through May 31, 2014. The amounts approved as noted below reflect the Utilities’ agreements with the position of the Consumer Advocate. The revised tariffed rates include:
Results of operations.
•
2013 vs. 2012
2012 vs. 2011
The rate schedules of the electric utilities currently contain energy cost adjustment clauses (ECACs) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.
KWH sales for 2012 were lower than 2011 due largely to cooler, less humid weather, continued conservation efforts and increasing levels of customer-sited renewable generation. KWH sales for 2011 were lower than 2010 due largely to cooler, less humid weather and continued conservation efforts by customers.
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 to allow the utility to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of
capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
The 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.
Note: The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases.
(1) Hawaiian Electric filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by Hawaiian Electric in a separate depreciation proceeding. Hawaiian Electric’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.
The $53.2 million, $58.2 million, and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.
(2) Hawaii Electric Light’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses. On February 8, 2012, the PUC issued a final D&O, which reflected the approval of decoupling and cost-recovery mechanisms, and on February 21, 2012, Hawaii Electric Light filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. Hawaii Electric Light implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. Hawaii Electric Light also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.
(3) Hawaii Electric Light’s request was to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. As a result of the 2013 Agreement and 2013 D&O (described below), the rate case was withdrawn and the docket has been closed.
(4) Maui Electric’s request was to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. See discussion on final D&O, including the refund to customers in September and October 2013 required as a result of the final D&O, in Note 3 of the Consolidated Financial Statements.
Hawaiian Electric 2011 test year rate case. In the Hawaiian Electric 2011 test year rate case, the PUC had granted Hawaiian Electric’s request to defer CIS project O&M expenses (limited to $2,258,000 per year in 2011 and 2012) that were to be subject to a regulatory audit of project costs, and allowed Hawaiian Electric to accrue allowance for funds used during construction (AFUDC) on these deferred costs until the completion of the regulatory audit.
On January 28, 2013, the Utilities and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects, with the remaining recoverable costs for the projects of $52 million to be included in rate base as of December 31, 2012. The parties agreed that Hawaii Electric Light would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and Hawaiian Electric would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that, starting in 2014, Hawaiian Electric will be allowed to record RAM revenues starting on January 1 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 3 of the Consolidated Financial Statements for additional information on the 2013 Agreement and the 2013 D&O and their effects.
Hawaiian Electric 2014 test year rate case. On October 30, 2013 Hawaiian Electric filed with the PUC a Notice of Intent to file an application for a general rate case (on or after January 2, 2014, but before June 30, 2014, using a 2014 test year) and a motion, which was subsequently recommended by the Consumer Advocate, for approval of test period waiver. Hawaiian Electric’s filing of a 2014 rate case would be in accordance with a PUC order which calls for a mandatory triennial rate case cycle.
Maui Electric 2012 test year rate case. See “Maui Electric 2012 test year rate case” in Note 3 of the Consolidated Financial Statements for information on the PUC’s final D&O.
Integrated Resource Planning. In June 2013, the Utilities 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:
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Lowering costs to customers by accelerating the development of low-cost, fast-track, utility-scale renewable energy projects, including solar and wind facilities.
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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, which have shut down operations, as well as two generators at Oahu’s Waiau Power Plant, scheduled to be shutdown by the end of 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.
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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.
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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. The PUC granted several parties' motions to intervene, and ordered that the parties submit simultaneous statements of position to aid the PUC in determining the completeness and compliance of the IRP report and action plans at this point in the review process, and how to move forward most productively in the proceeding. In September and October 2013, the parties submitted their statements of position.
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. The Utilities met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2013, the Utilities achieved an RPS without DSM energy savings of 18%, primarily through a comprehensive portfolio of renewable energy power purchase agreements (PPAs), 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 3 of the Consolidated Financial Statements):
•
In July 2011, the PUC directed Hawaiian Electric to submit a draft request for proposals (RFP) for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP (see Note 3 of the Consolidated Financial Statements for additional information).
•
In May 2012, the PUC approved Hawaiian Electric’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.
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In May 2012, Maui Electric 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, Hawaiian Electric 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, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii.
•
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, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received in April 2013 and Hawaii Electric Light is developing further requests for information from the bidders based on its evaluation of the bids.
•
In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire. After interconnection infrastructure was rebuilt and voltage regulation equipment was installed, the facility came up to full output in January 2014 to perform control system acceptance testing, and energy is being purchased at a base rate until PUC approval of an amendment to the Power Purchase Agreement.
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In August 2012, the PUC approved a waiver from the competitive bidding process to allow Hawaiian Electric to negotiate with the U.S. Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu and expected to be placed in service in 2017.
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In September 2012, Hawaiian Electric 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.
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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.
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In December 2012, the 21 MW Auwahi Wind Energy LLC facility was placed into commercial operation, selling power to Maui Electric under a 20-year contract.
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In December 2012, the 5 MW Kalaeloa Solar Two, LLC photovoltaic facility was placed into commercial operation, selling power to Hawaiian Electric under a 20-year contract.
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In February 2013, Hawaiian Electric issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.” 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 and November 2013, Hawaiian Electric
filed waiver requests from the PUC Competitive Bidding Framework for five projects (two of which have since been withdrawn) and six projects, respectively, which met these goals.
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In May 2013, Maui Electric requested a waiver from the PUC Competitive Bidding Framework to conduct negotiations for a PPA for approximately 4.5 to 6.0 MW of firm power from a proposed Mahinahina Energy Park, LLC project, fueled with biofuel.
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In October 2013, Hawaiian Electric requested approval from the PUC for a waiver from the competitive bidding process and to commit $42.4 million for the purchase and installation of a 15 MW utility scale PV generation system at its Kahe Power generation station property. If approved, the project is expected to be completed in 2015.
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In October 2013, the Utilities signed a 3-year biodiesel supply contract, subject to PUC approval, with Pacific Biodiesel Technologies, LLC to spot purchase as available biodiesel at cost parity to petroleum diesel.
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In October 2013, the PUC approved Hawaiian Electric’s 20-year contract with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of November 25, 2013.
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In November 2013, the 5 MW Kalaeloa Renewable Energy Park, LLC photovoltaic facility was placed into commercial operation selling power to Hawaiian Electric under a 20-year contract.
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In December 2013, the PUC denied approval of Hawaii Electric Light’s contract with Aina Koa Pono-Ka’u LLC (AKP) to supply 16 million gallons of biodiesel per year, citing the higher cost of the biofuel over the cost of petroleum diesel.
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In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s proposed 24 MW wind farm located in the Kahuku area on Oahu from the competitive bidding process and of the Power Purchase Agreement for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and Na Pua Makani Power Partners, LLC for the proposed 24 MW wind farm.
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The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2013, there were 10 MW, 1 MW and 2 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
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As of December 31, 2013, there were approximately 167 MW, 33 MW and 35 MW of installed net energy metering capacity from renewable energy technologies (mainly photovoltaic) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively. The amount of net energy metering capacity installed in 2013 was about 46% higher than the amount installed in 2012.
Other regulatory matters. In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Utility projects” in Note 3 of the Consolidated Financial Statements.
Adequacy of supply.
Hawaiian Electric. In March 2013, Hawaiian Electric filed its 2013 Adequacy of Supply (AOS) letter, which indicated that based on its August 2012 sales and peak forecast, Hawaiian Electric’s generation capacity is sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2018. In January 2014 Hawaiian Electric deactivated two fossil fuel generating units from active service at its Honolulu Power Plant, and anticipates deactivating two additional fossil fuel units at its Waiau Power Plant in the 2016 timeframe. Hawaiian Electric is proceeding with future firm capacity additions in coordination with the State of Hawaii Department of Transportation, and also the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, generation security project on federal lands. Hawaiian Electric is continuing negotiations with two firm capacity IPPs on Oahu with Power Purchase Agreements scheduled to expire in 2016 and 2022.
Hawaii Electric Light. In January 2014, Hawaii Electric Light filed its 2014 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2016 is sufficiently large to meet all reasonably expected demands for service and provide for reasonable reserves for emergencies. In February 2013, Hawaii Electric Light filed with the PUC its Final RFP for Renewable Geothermal Dispatchable Energy and Firm Capacity Resources seeking up to 50 MW of firm, dispatchable geothermal capacity. Hawaii Electric Light is continuing the review process to meet the goals of the Geothermal RFP. In December 2013, the PUC approved Hawaii Electric Light's PPA with Hu Honua Bioenergy, LLC to provide firm renewable generating capacity. Should these additional firm renewable facilities come on line as anticipated, Hawaii Electric Light will not have a need for additional firm capacity in the foreseeable future. Included in the PUC’s D&O was a requirement for Hawaii Electric Light to file a Power Supply Improvement Plan (PSIP) within 120 days. The PSIP shall address, at a minimum, the following issues: (1) Fossil Generation Retirement Plan, which shall include an analysis of which existing fossil fuel plants can be retired, when it is feasible to retire each such plant, the effect on system operations of retiring each such plant, and the anticipated ratepayer savings that would result; (2) a Generation Flexibility Plan designed to enable Hawaii Electric Light to accommodate greater quantities of low cost energy resources; (3) a Must-Run Generation Reduction Plan to reduce or eliminate the must-run designation and operation of generating units on Hawaii Electric Light’s power supply system and enable Hawaii Electric light to accept additional lower-cost energy resources; and (4) a Generation Commitment and Economic Dispatch
Review to ensure that existing generation resource allocation policies and practices yield the most fuel-efficient and cost-effective outcome given Hawaii Electric Light’s rapidly changing portfolio of power supply resources.
Maui Electric. In January 2013, Maui Electric filed its 2013 AOS letter, which indicated that Maui Electric’s generation capacity through 2015 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai. Maui Electric expects to have adequate firm capacity on the island of Maui for the period through 2018 and anticipates needing additional firm capacity in the 2019 timeframe. In February 2014, Maui Electric deactivated two fossil fuel generating units at its Kahului Power Plant. Maui Electric anticipates the retirement of all generating units at the Kahului Power Plant in the 2019 timeframe because of their age. Maui Electric will seek to acquire additional firm generating capacity through a competitive bidding process, and make transmission system improvements needed to ensure reliability and voltage support, in this timeframe.
Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the Utilities and their customers. Also see “Hawaii Clean Energy Initiative” and “Environmental regulation” in Note 3 of the Consolidated Financial Statements and “Recent tax developments” above.
Renewable energy. In 2011, a Hawaii law was enacted that gives the PUC the authority to allow those electric utilities (including the Utilities) that aggregate their renewable portfolios in measuring whether they achieve the the renewable portfolio standards under the Hawaii RPS law discussed above under "Renewable energy strategy" to distribute the costs and expenses of renewable energy projects among those utilities. The bill also allows the PUC to establish a surcharge for such costs and expenses without a rate case filing. Also passed in 2011, Act 10 provides for continued inclusion of customer-sited, grid-connected renewable energy generation in the RPS calculations after 2015. This is the current practice in calculating RPS levels, which provides electric utility ratepayers with a clear value from a program such as net energy metering.
Commitments and contingencies. See “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements.
Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.
Liquidity and capital resources. Management believes that Hawaiian Electric’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, 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.
Hawaiian Electric’s consolidated capital structure was as follows:
Information about Hawaiian Electric’s short-term borrowings (other than from Hawaii Electric Light and Maui Electric) and line of credit facility were as follows:
The maximum amount of external short-term borrowings in 2013 was $73 million. At December 31, 2013, Hawaiian Electric had $1 million of short-term borrowings from Hawaii Electric Light and Maui Electric had $7 million of short-term borrowings from
Hawaiian Electric, which borrowings are eliminated in consolidation. At February 7, 2014, Hawaiian Electric had $24 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $8 million from Hawaii Electric Light and a loan of $14 million to Maui Electric.
Hawaiian Electric utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. Hawaiian Electric also borrows short-term from HEI for itself and on behalf of Hawaii Electric Light and Maui Electric, and Hawaiian Electric may borrow from or loan to Hawaii Electric Light and Maui Electric short-term. The intercompany borrowings among the Utilities, but not the borrowings from HEI, are eliminated in the consolidation of Hawaiian Electric’s financial statements. The Utilities periodically utilize long-term debt, historically borrowings of the proceeds of SPRBs issued by the DBF and more recently the issuance of privately placed taxable unsecured senior notes, to finance the Utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by the Utilities.
Hawaiian Electric has a line of credit facility of $175 million. See Note 7 of the Consolidated Financial Statements. The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of Hawaiian Electric’s long-term rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 2.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts.
In addition to their impact on pricing under Hawaiian Electric’s credit agreement, the ratings of Hawaiian Electric’s commercial paper and debt securities could significantly impact the ability of Hawaiian Electric to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (e.g., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of Hawaiian Electric securities.
On January 21, 2014, Fitch assigned initial ratings to Hawaiian Electric as noted in the table below. The key ratings drivers cited were (1) constructive regulatory environment, (2) solid credit profile, (3) elevated capital investment cycle, (4) atypical power/retail electricity market structure and (5) emerging competitive landscape.
As a result of updating it ratings methodology, Moody’s placed the ratings of most U.S. regulated utilities and utility holding companies on review for upgrade. Hawaiian Electric was included in the list of companies on review for upgrade. Subsequently, on January 30, 2014, Moody’s confirmed Hawaiian Electric’s ratings as noted in the table below and indicated that despite their view that Hawaiian Electric, like many other regulated utilities in the U.S., received more credit supportive regulatory treatment over the years, Hawaiian Electric’s cash flow to debt ratios are too weak to support an upgrade. The ratings also recognize the challenges of having some of the highest retail electric rates in the country and the heavy pressure from regulators and stakeholders to reduce rates and dependence on fuel oil. Moody’s indicated the rating could be downgraded or placed on negative outlook if Maui Electric’s poor rate case outcome spills over to Hawaiian Electric and Hawaii Electric Light.
On February 10, 2014, S&P maintained its corporate credit ratings for Hawaiian Electric, as noted in the table below. S&P indicated that the "BBB-" issuer credit rating on Hawaiian Electric is derived from S&P's anchor of "bbb", based on a “strong” business risk and “significant” financial risk profile assessments for the company. The negative comparable rating analysis modifier resulted in a -1 notch adjustment to the anchor. S&P indicated that unfavorable comparable ratings analysis reflects the Utilities' ongoing challenges to earn closer to the allowed returns and the need to continuously effectively manage regulatory risk; past challenges to complete major projects on budget and on schedule; and the potential threat from increasing roof-top solar penetration, relative to peers. The stable outlook reflects S&P’s understanding that “the decoupling mechanisms will remain largely unchanged and the company will successfully manage expenses, HECO will reach a constructive outcome in its next rate case filing, and HEI will maintain a balanced funding approach that continues to support the current credit profile.”
As of February 10, 2014, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:
* Not rated.
The above ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
Management believes that, if Hawaiian Electric’s commercial paper ratings were to be downgraded or if credit markets were to further tighten, it could be more difficult and/or expensive to sell commercial paper or secure other short-term borrowings. Similarly, management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive for DBF and/or the Company to sell SPRBs and other debt securities, respectively, for the benefit of the Utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of the Utilities.
Revenue bonds are issued by the DBF to finance capital improvement projects of the Utilities, but the source of their repayment is the unsecured obligations of the Utilities under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on SPRBs currently outstanding and issued prior to 2009 are insured by Ambac Assurance Corporation or Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013 the plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of these insurers, which at the time the insured obligations were issued were higher than the ratings of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.
On November 15, 2010, the PUC approved the request of Hawaiian Electric, Hawaii Electric Light and Maui Electric for the sale of each utility’s common stock over a five-year period from 2010 through 2014 (Hawaiian Electric’s sale to HEI of up to $210 million and Hawaii Electric Light and Maui Electric’s sales to Hawaiian Electric of up to $43 million and $15 million, respectively), and the purchase of Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric. In December 2010, Hawaii Electric Light and Maui Electric sold $23 million and $3 million, respectively, of their common stock to Hawaiian Electric, and Hawaiian Electric sold $4 million of its common stock to HEI. In December 2011 and December 2012, Hawaiian Electric sold $40 million and $44 million, respectively, of its common stock to HEI. In December 2013, Maui Electric sold $12.5 million of its common stock to Hawaiian Electric and Hawaiian Electric sold $78.5 million of its common stock to HEI.
The PUC has approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by the Utilities, up to specified amounts, during the period 2013 through 2015, subject to certain conditions. On October 3, 2013, after obtaining such expedited approvals, the Utilities issued through a private placement taxable unsecured senior notes with an aggregate principal amount of $236 million. See Note 8 of the Consolidated Financial Statements for a discussion of the use of these proceeds. PUC approval to issue an additional $80 million of long-term debt (Hawaiian Electric $50 million, Hawaii Electric Light $25 million and Maui Electric $5 million) and $47 million to refinance outstanding revenue bonds (Hawaiian Electric $40 million, Hawaii Electric Light $5 million and Maui Electric $2 million) can be requested under the expedited approval procedure through 2015.
Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from) net income. In 2013 and 2012, net cash provided by operating activities increased by $115 million and $16 million, respectively, compared to the prior year. In 2013, noncash depreciation and amortization amounted to $159 million due to an increase in plant and equipment and deferred income taxes increased $65 million. Further, net cash provided by operating
activities included a net decrease of $40 million in accounts receivable and accrued unbilled revenues due to more cash receipts from customers as a result of improved collections, and a $27 million decrease in fuel oil stock due to lower payments to fuel suppliers. In 2012, noncash depreciation and amortization amounted to $151 million due to an increase in plant and equipment and deferred income taxes increased $87 million. Further, net cash provided by operating activities included a $10 million decrease in fuel oil stock due to lower payments to fuel suppliers and lower fuel stock held, offset by a net increase of $43 million in accounts receivable and accrued unbilled revenues due to less cash receipts from customers and large customers' balances still outstanding at year end.
In 2013 and 2012, net cash used in investing activities increased by $46 million and $62 million, respectively, compared to the prior year. The increases resulted primarily from increased capital expenditures due to more capital projects.
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. In 2013 and 2012, cash flows from financing activities increased by $9 million and $88 million, respectively, compared to the prior year. In 2013, cash provided by financing activities consisted primarily of net proceeds received from the issuance of $236 million of taxable unsecured senior notes and $79 million of common stock, partially offset by the redemption of $166 million of special purpose revenue bonds and the payment of $84 million of common and preferred stock dividends. In 2012, cash provided by financing activities consisted of net proceeds received from the issuance of $457 million of taxable unsecured senior notes and $44 million of common stock, partially offset by the repayment of $369 million of long term debt and the payment of $75 million of common and preferred stock dividends. In 2011, no long-term debt was issued or redeemed.
For the three-year period 2014 through 2016, the Utilities forecast $1.1 billion of net capital expenditures, which could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation. Hawaiian Electric’s consolidated cash flows from operating activities (net income for common stock, adjusted for non-cash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are currently not expected to provide sufficient cash to cover the forecasted net capital expenditures. Debt and equity financing are expected to be required to fund this estimated shortfall and to fund any unanticipated expenditures not included in the 2014 through 2016 forecast, such as increases in the costs or acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements.
Proceeds from the issuance of equity, cash flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the forecasted $360 million needed for the net capital expenditures in 2014. For 2014, net capital expenditures include approximately $220 million for transmission and distribution projects, approximately $80 million for generation projects and approximately $60 million for general plant and other projects.
Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generation units, the availability of generating sites and transmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, commitments under the Energy Agreement, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.
For a discussion of funding for the electric utilities’ retirement benefits plans, see Note 1 and Note 10 of the Consolidated Financial Statements and “Retirement benefits” above. The electric utilities were required to make contributions of $61 million for 2013, $53 million for 2012 and $71 million for 2011 to the qualified pension plans to meet minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006. The electric utilities made additional voluntary contributions in 2013, 2012 and 2011. Contributions by the electric utilities to the retirement benefit plans for 2013, 2012 and 2011 totaled $81 million, $63 million and $73 million, respectively, and are expected to total $58 million in 2014. In addition, the electric utilities paid directly $1 million of benefits in 2013, $1 million of benefits in 2012 and $1 million of benefits in 2011 and expect to pay $1 million of benefits in 2014. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The electric utilities believe they will have adequate cash flow or access to capital resources to support any necessary funding requirements.
Selected contractual obligations and commitments. The following table presents aggregated information about total payments due from the Utilities during the indicated periods under the specified contractual obligations and commitments:
¹ Includes contractual obligations and commitments for capital expenditures and expense amounts.
The table above does not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2013, the fair value of the assets held in trusts to satisfy the obligations of the Utilities’ retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above, but retirement benefit plan obligations, including estimated minimum required contributions for 2014 are discussed in the section “Retirement benefits” in Hawaiian Electric’s MD&A and Note 10 of the Consolidated Financial Statements.
See Note 3 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments.
Certain factors that may affect future results and financial condition. Also see “Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.
HCEI Energy Agreement. Hawaiian Electric, for itself and its subsidiaries, entered into the Energy Agreement on October 20, 2008. See “Hawaii Clean Energy Initiative” in Note 3 of the Consolidated Financial Statements.
The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, presents risks to the Company. Among such risks are: (1) the dependence on third-party suppliers of renewable purchased energy, which if the Utilities are unsuccessful in negotiating purchased power agreements with such independent power producers (IPPs) or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the Utilities’ achievement of their commitments under the Energy Agreement and/or the Utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the Utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the Utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the Utilities depending on their design and implementation. These initiatives include, but are not limited to, removing the system-wide caps on net energy metering (but studying DG interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of the implementation of these or other HCEI programs on the results of operations, financial condition and liquidity of the Utilities.
Regulation of electric utility rates. The rates the electric utilities are allowed to charge for their services, and the timeliness of permitted rate increases, are among the most important items influencing their results of operations, financial condition and liquidity. The PUC has broad discretion over the rates the electric utilities charge and other matters. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts permitted to be included in rate base, the authorized returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on the Company’s and Hawaiian Electric’s consolidated results of operations, financial condition and liquidity. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O and interim rate increases are subject to refund with interest if the interim increase is greater than the increase approved in the final D&O.
Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and IPPs to deliver fuel oil and power, respectively. See “Fuel contracts” and “Power purchase agreements” in Note 3 of the Consolidated Financial Statements. The Company estimates that 66% of the net energy generated and purchased by the Utilities in 2014 will be generated from the burning of fossil fuel oil. Purchased KWHs provided approximately 40% of the total net energy generated and purchased in 2013, 2012 and 2011.
Failure or delay by the electric utilities’ oil suppliers and shippers to provide fuel pursuant to existing supply contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could interrupt the ability of the electric utilities to deliver electricity, thereby materially adversely affecting the Company’s results of operations and financial condition. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an inventory level equivalent to one month’s supply of both medium sulfur fuel oil and diesel fuel. Some, but not all, of the Utilities’ PPAs require that the IPPs maintain minimum fuel inventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties for failure to produce the firm capacity anticipated by those agreements.
Other operation and maintenance expenses. O&M expenses increased by 1% in 2013 and 4% in 2012 and decreased by 1% in 2011 when compared to the prior year. The change in O&M expenses (excluding expenses covered by surcharges or by third parties) was 1%, 4% and de minimis for 2013, 2012 and 2011, respectively, when compared to the prior year. O&M expenses (excluding expenses covered by surcharges or by third parties) for 2014 are projected to be relatively flat when compared to 2013 as the electric utilities expect to manage expenses to near-2013 levels.
Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. For example, two major capital improvement utility projects, the Keahole project (consisting of CT-4, CT-5 and ST-7) and the East Oahu Transmission Project, encountered opposition and were seriously delayed before being placed in service, with a writedown being required for both the Keahole and EOTP projects in 2007 and 2011, respectively. More recently, the Utilities and the Consumer Advocate signed a settlement agreement, subject to approval by the PUC, to write off $40 million of costs in 2012 in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects. See Note 3 of the Consolidated Financial Statements for a discussion of additional regulatory contingencies.
Competition. Although competition in the generation sector in Hawaii is moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, the PUC has promoted a more competitive electric industry environment through its decisions concerning competitive bidding and distributed generation (DG). An increasing amount of generation is provided by IPPs and customer distributed generation.
Competitive bidding. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.
The Kalaeloa Solar Two photovoltaic energy PPA and the Kawailoa Wind windfarm PPA are two renewable projects that resulted from Hawaiian Electric’s Renewable Energy RFP under the Competitive Bidding Framework.
The Utilities received PUC approval for exemptions from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources, including the City & County of Honolulu’s HPower facility expansion and the Puna Geothermal Venture geothermal facility expansion. Also, certain renewable energy projects were “grandfathered” from the competitive bidding process, including the Kahuku Wind Power, Auwahi Wind Energy LLC, and Kaheawa Wind Power II wind farms. The PUC can also grant waivers to renewable energy projects that are not exempt from the Competitive Bidding Framework such as for the Hu Honua biomass facility.
Distributed generation. In January 2006, the PUC issued a D&O indicating that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system. The D&O affirmed the
ability of the Utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. The D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.
Environmental matters. The Utilities generating stations operate under air pollution control permits issued by the Hawaii Department of Health (DOH) and, in a limited number of cases, by the federal Environmental Protection Agency (EPA). Hawaii law requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. Meeting this requirement results in increased project costs.
The 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter resulted in substantial changes for the electric utility industry such as the installation of additional emissions controls, retirements of older generating units and switches to lower emissions fuels. Further significant impacts may occur under newly adopted rules (e.g., one-hour NAAQS for sulfur dioxide and nitrogen dioxide, control of GHGs under the GHG PSD and Title V Tailoring Rule), under rules deemed applicable to the Utilities’ facilities (e.g., Regional Haze Rule), if currently proposed legislation, rules and standards are adopted (e.g., GHG emission reduction rules), or if new legislation, rules or standards are adopted in the future. Similarly, soon-to-be issued rules governing cooling water intake may significantly impact Hawaiian Electric’s steam generating facilities on Oahu.
Additional environmental compliance costs are expected to be incurred as a result of the initiatives called for in the Energy Agreement, including permitting and siting costs for new facilities and testing and permitting costs related to changing to the use of biofuels. Management believes that the recovery through rates of most, if not all, of any costs incurred by the Utilities in complying with environmental requirements would be allowed by the PUC, but no assurance can be given that this will in fact be the case. In addition, there can be no assurance that a significant environmental liability will not be incurred by the Utilities or that the related costs will be recoverable through rates. See “Environmental regulation” in Note 3 of the Consolidated Financial Statements.
Technological developments. New technological developments (e.g., the commercial development of energy storage, fuel cells, DG and generation from renewable sources) may impact the Utilities’ future competitive position, results of operations, financial condition and liquidity.
Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.
Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.
The Utilities evaluate the impact of applying lease accounting standards to their new PPAs, PPA amendments and other arrangements they enter into. A possible outcome of the evaluation is that an arrangement results in its classification as a capital lease, which could have a material effect on Hawaiian Electric’s consolidated balance sheet if a significant amount of capital assets of the IPP and lease obligations needed to be recorded.
Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion under “Utility projects” in Note 3 of the Consolidated Financial Statements concerning costs of major projects that have not yet been approved for inclusion in the applicable utility’s rate base.
Regulatory assets and liabilities. The Utilities are regulated by the PUC. In accordance with accounting standards for regulatory operations, the Company’s financial statements reflect assets, liabilities, revenues and costs of the Utilities based on current cost-based rate-making regulations. The actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities.
Regulatory liabilities represent amounts collected from customers for costs that are expected to be incurred in the future. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rates is probable.
As of December 31, 2013, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $349 million and $576 million, respectively, compared to $324 million and $865 million as of December 31, 2012, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 of the Consolidated Financial Statements. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the Utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 2013 is probable. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.
Management believes that the operations of the Utilities currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company's results of operations, financial condition and liquidity.
Revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period, but not yet billed to customers, and RBA revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales. As of December 31, 2013, revenues applicable to energy consumed, but not yet billed to customers, amounted to $145 million and the RBA revenues recognized in 2013 amounted to $67 million.
Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. The rate schedules of the Utilities include ECACs under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules of the Utilities also include PPACs under which electric rates are more closely aligned with purchase power costs incurred. Management believes that a material adverse effect on the Company’s results of operations, financial condition and liquidity may result if the ECACs, PPACs or RBAs were lost.
Consolidation of variable interest entities. A business enterprise must evaluate whether it should consolidate a variable interest entity (VIE). The Company evaluates the impact of applying accounting standards for consolidation to its relationships with IPPs with whom the Utilities execute new PPAs or execute amendments of existing PPAs. A possible outcome of the analysis is that Hawaiian Electric or its subsidiaries may be found to meet the definition of a primary beneficiary of a VIE which finding may result in the consolidation of the IPP in the Consolidated Financial Statements. The consolidation of IPPs could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. The Utilities do not know how the consolidation of IPPs would be treated for regulatory or credit ratings purposes. See Notes 1 and 5 of the Consolidated Financial Statements.
Bank
Executive overview and strategy. When ASB was acquired by HEI in 1988, it was a traditional thrift with assets of $1 billion and net income of about $13 million. ASB has grown by both acquisition and internal growth, but has been optimizing its balance sheet in recent years as a result of its multi-year performance improvement project, which has resulted in a reduction in asset size and a concomitant improvement in profitability and capital efficiency. ASB ended 2013 with assets of $5.2 billion and net income of $58 million, compared to assets of $5.0 billion as of December 31, 2012 and net income of $59 million in 2012.
ASB is a full-service community bank serving both consumer and commercial customers. In order to remain competitive and continue building core franchise value, ASB continues to develop and introduce new products and services in order to meet the needs of those markets such as mobile banking. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive. ASB’s ongoing challenge is to continue to increase revenues and control expenses.
The interest rate environment and the quality of ASB’s assets will continue to impact its financial results.
ASB continues to face a challenging interest rate environment. The persistent, low level of interest rates and excess liquidity in the financial system have impacted new loan production rates and made it challenging to find investments with adequate risk-adjusted returns, which resulted in a negative impact on ASB’s asset yields and net interest margin. The potential for compression of ASB’s margin when interest rates rise is an ongoing concern.
As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Quantitative and Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies include:
1.
attracting and retaining low-cost, core deposits, particularly those in non-interest bearing transaction accounts;
2.
reducing the overall exposure to fixed-rate residential mortgage loans and diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable-rate loans such as commercial, commercial real estate and consumer loans;
3.
managing costing liabilities to optimize cost of funds and manage interest rate sensitivity; and
4.
focusing new investments on shorter duration or variable rate securities.
ASB’s loan quality improved in 2013 as a result of stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the state of Hawaii. The slowdown in the economy, both nationally and locally, had resulted in ASB experiencing historically higher levels of loan delinquencies and losses in 2010 and 2011, which were concentrated in the residential land portfolio and on the neighbor islands. The residential land portfolio has declined, which enabled ASB to release some loan loss reserves on that portfolio. ASB’s provision for loan losses decreased in 2013 compared to 2012 due to continued improvement in credit quality, recoveries from previously charged off loans and the release of reserves related to the sale of the credit card portfolio.
Results of operations.
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2013 vs. 2012
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2012 vs. 2011
Calculated using the average daily balances.
See Note 4 of the Consolidated Financial Statements for a discussion of guarantees and further information about ASB.
Average balance sheet and net interest margin. The following tables set forth average balances, together with interest and dividend income earned and accrued, and resulting yields and costs for 2013, 2012 and 2011.
Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank of Seattle ($95 million, $97 million and $98 million as of December 31, 2013, 2012 and 2011 respectively).
Includes loans held for sale.
Includes loan fees of $5.2 million, $4.9 million and $3.9 million for 2013, 2012 and 2011, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.
Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.9 million, $0.8 million and $0.5 million for 2013, 2012 and 2011, respectively.
Defined as net interest income as a percentage of average earning assets.
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 over a period of several years 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 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. See Note 4 of the Consolidated Financial Statements for the composition of ASB’s loans receivable.
The increase in the total loan portfolio from $3.7 billion at the end of 2012 to $4.1 billion at the end of 2013 was primarily due to growth in the residential 1-4, commercial real estate, home equity line of credit and commercial loan portfolios, which was consistent with ASB’s portfolio mix targets and loan growth strategy.
Home equity - key credit statistics.
The home equity line of credit (HELOC) portfolio makes up 18% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable rate term loan with a 20-year amortization period. This product type comprises 91% of the total HELOC portfolio and is the current product offering. Within this product type, borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed rate loan with level principal and interest payments. As of December 31, 2013, approximately 18% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older vintage equity lines represent 9% of the portfolio and are included in the amortizing balances identified in the table above.
Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property securing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold.
See “Allowance for loan losses” in Note 4 of the Consolidated Financial Statements for information with respect to nonperforming assets. The level of nonperforming loans has continued to decrease with the improving Hawaii economy.
Allowance for loan losses. See “Allowance for loan losses” in Note 4 of the Consolidated Financial Statements for the tables which sets forth the allocation of ASB’s allowance for loan losses. For 2013, the allowance for loan losses decreased by $1.9 million, due to improved overall credit quality and higher recoveries in the residential 1-4 family and residential land loan portfolios.
Investment and mortgage-related securities. ASB’s investment portfolio was comprised as follows:
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
primarily 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.
The unrealized losses on ASB’s investment in federal agency mortgage-backed securities were primarily caused by higher interest rates. The higher interest rate environment coupled with tighter spreads on all mortgage collateralized securities caused the market value of the securities held to decrease below the carrying book value. All contractual cash flows of those investments are guaranteed by an agency of the U.S. government. See “Investment and mortgage-related securities” in Note 1 for a discussion of securities impairment assessment.
As of December 31, 2013, 2012 and 2011, ASB did not have any private-issue mortgage-related securities.
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. As of December 31, 2013, ASB’s costing liabilities consisted of 95% deposits and 5% other borrowings. As of December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. See Note 4 of the Consolidated Financial Statements for the composition of ASB’s deposit liabilities and other borrowings.
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 December 31, 2013 and 2012, ASB had an unrealized loss, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $4 million compared to an unrealized gain, net of taxes, of $11 million as of December 31, 2012. See “Quantitative and qualitative disclosures about market risk.”
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.” Also see “Federal Deposit Insurance Corporation restoration plan” and “Deposit insurance coverage” in Note 4 of the Consolidated Financial Statements.
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 (OTS) 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). It became effective on October 28, 2013. For consumer 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 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. This rule has not had a significant impact on ASB's results of operations.
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, on July 1, 2013, ASB became non-exempt as the consolidated assets of HEI exceeded $10 billion. For the second half of 2013, ASB earned an average of 23 cents per electronic debit transaction, compared to an average of 49 cents per electronic debit transaction in the first half. ASB estimates debit card interchange fees to be lower, as a result of the application of this Amendment, by approximately $6 million after tax 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 Rules. On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies. 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 initially be subject to the following minimum regulatory capital requirements: a common equity tier 1 capital ratio of 4.5%, a tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a leverage ratio of 4%, and these requirements would increase in subsequent years. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum 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. The phased-in effective dates of the capital requirements under the final rule are:
Minimum Capital Requirements
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. If the fully phased-in capital requirements were currently applicable to HEI and ASB, management believes HEI and ASB would satisfy the capital requirements, including the fully phased-in capital conservation buffer.
FHLB of Seattle stock. As of December 31, 2013, ASB’s investment in stock of the FHLB of Seattle of $92.5 million was carried at cost because it can only be redeemed at par. There is a minimum required investment in such stock based on measurements of ASB’s capital, assets and/or borrowing levels, and ASB’s investment is substantially in excess of that requirement. In 2013, the FHLB of Seattle paid ASB cash dividends of $47,000. FHLB of Seattle did not pay any cash dividends in 2011 or 2012.
In September 2012, the Federal Housing Finance Agency (Finance Agency) classified the FHLB of Seattle as “adequately capitalized” and after receiving approval from the Finance Agency, began repurchasing excess stock. The FHLB of Seattle repurchased a total of $3.5 million and $1.7 million of excess stock from ASB in 2013 and 2012, respectively.
Commitments and contingencies. See Note 4 of the Consolidated Financial Statements.
Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.
Liquidity and capital resources.
As of December 31, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.2 billion and deposits of $4.4 billion.
ASB’s principal sources of liquidity are customer deposits, borrowings and the maturity and repayment of portfolio loans and securities. ASB’s deposits as of December 31, 2013 were $143 million higher than December 31, 2012. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. As of December 31, 2013, FHLB borrowings totaled $100 million, representing 1.9% of assets. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. As of December 31, 2013, ASB’s unused FHLB borrowing capacity was approximately $1.1 billion. As of December 31, 2013, securities sold under agreements to repurchase totaled $145 million, representing 2.8% of assets. ASB utilizes deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and purchase investment and mortgage-related securities. As of December 31, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion, including commitments to lend $0.3 million to borrowers whose loan terms have been impaired or modified in troubled debt restructurings. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
As of December 31, 2013 and 2012, ASB had $48.5 million and $64.9 million of loans on nonaccrual status, respectively, or 1.2% and 1.7% of net loans outstanding, respectively. As of December 31, 2013 and 2012, ASB had $1.2 million and $6.1 million, respectively, of real estate acquired in settlement of loans.
In 2013, operating activities provided cash of $74 million. Net cash of $253 million was used by investing activities primarily due to purchases of investment and mortgage-related securities, a net increase in loans held for investment and capital expenditures, partly offset by repayments of investment and mortgage-related securities and proceeds from the sales of investment securities and real estate acquired in settlement of loans. Financing activities provided net cash of $151 million due to a net increase in deposits and a net increase in other borrowings, partly offset by the payment of common stock dividends.
ASB believes that maintaining a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2013, ASB was well-capitalized (see “Regulation-Capital requirements” below for ASB’s capital ratios).
For a discussion of ASB dividends, see “Common stock equity” in Note 4 of the Consolidated Financial Statements.
Certain factors that may affect future results and financial condition. Also see “Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.
Competition. The banking industry in Hawaii is highly competitive. ASB is one of Hawaii’s largest financial institutions, based on total assets, and is in direct competition for deposits and loans, not only with larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small- and medium-sized businesses, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securities brokerage firms. These competitors offer a variety of lending, deposit and investment products to retail and business customers.
The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation and perceptions of the institution’s financial soundness and safety. To meet competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns.
The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.
ASB is a full-service community bank serving both consumer and commercial customers and has been diversifying its loan portfolio from single-family home mortgages to higher-spread, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its consumer, commercial and commercial real estate loans.
U.S. capital markets and credit and interest rate environment. Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of December 31, 2013, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.5 billion.
Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. Persistent low levels of interest rates have made it challenging to find investments with adequate risk-adjusted returns and had a negative impact on ASB’s asset yields and net interest margin. If the current interest rate environment persists, the potential for compression of ASB’s net interest margin will continue. ASB also manages the credit risk associated with its lending and securities portfolios, but a deep and prolonged recession led by a material decline in housing prices could materially impair the value of its portfolios. See “Quantitative and Qualitative Disclosures about Market Risk” below.
Technological developments. New technological developments (e.g., significant advances in internet banking) may impact ASB’s future competitive position, results of operations and financial condition.
Environmental matters. Prior to extending a loan collateralized by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.
Regulation. ASB is subject to examination and comprehensive regulation by the Department of Treasury, OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OCC.
Capital requirements. The OCC, which is ASB’s principal regulator, administers two sets of capital standards-minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2013, ASB was in compliance with OCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of OCC prompt corrective action regulations and FDIC capital regulations, as follows:
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ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2013 with a tangible capital ratio of 9.1% (1.5%), a core capital ratio of 9.1% (4.0%) and a total risk-based capital ratio of 12.1% (8.0%).
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ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2013 with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 11.2% (6.0%) and a total risk-based capital ratio of 12.1% (10.0%).
The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (typically acquired by foreclosure). The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to HEI (through ASHI) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI currently could be required to contribute to ASB up to an additional $28.3 million of capital, if necessary, to maintain ASB’s capital position.
Examinations. ASB is subject to periodic “safety and soundness” examinations and other examinations by the OCC. In conducting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OCC’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as an officer, director, employee, attorney or auditor, except as provided by regulation. The OCC also regularly examines ASB’s information technology practices and its performance under Community Reinvestment Act measurement criteria.
The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2013, ASB was “well-capitalized” and thus not subject to these restrictions.
Qualified Thrift Lender status. ASB is a “qualified thrift lender” (QTL) under its federal thrift charter and, in order to maintain this status, ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s
case, the activities of HEI, ASHI and HEI’s other subsidiaries would also be subject to restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2013, ASB was a qualified thrift lender.
Unitary savings and loan holding company. The Gramm-Leach-Bliley Act of 1999 (Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, ASHI and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the authorized financial holding companies permitted under the Gramm Act. There have been legislative proposals in the past which would operate to eliminate the thrift charter or the grandfathered status of HEI as a unitary thrift holding company and effectively require the divestiture of ASB.
Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.
Investment and mortgage-related securities. ASB owns federal agency obligations and mortgage-related securities issued by the FNMA, GNMA and FHLMC and municipal bonds, all of which are classified as available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported in AOCI.
ASB views the determination of whether an investment security is temporarily or other-than-temporarily impaired as a critical accounting policy since the estimate is susceptible to significant change from period to period because it requires management to make significant judgments, assumptions and estimates in the preparation of its consolidated financial statements.
See “Investment and mortgage-related securities” in Note 1 of the Consolidated Financial Statements for a discussion of securities impairment assessment and other-than-temporary impaired securities.
Prices for investments and mortgage-related securities are provided by an independent third party pricing service and are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The price of these securities is generally based on observable inputs, which include market liquidity, credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns and overall market psychology. To validate the accuracy and completeness of security pricing, a separate third party pricing service is used on a quarterly basis to compare prices that were received from the initial third party pricing service. If the pricing differential between the two pricing sources exceeds an established threshold, the security price will be re-evaluated by sending a re-pricing request to both independent third party pricing services, to another third party vendor or to an independent broker to determine the most accurate price based on all observable inputs found in the market place. The third party price selected will be based on the value that best reflects the data and observable characteristics of the security. As of December 31, 2013, ASB had investment and mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $0.5 billion.
Allowance for loan losses. See Note 1 of the Consolidated Financial Statements and the discussion above under “Earning assets, costing liabilities and other factors.” As of December 31, 2013, ASB’s allowance for loan losses was $40.1 million and ASB had $48.5 million of loans on nonaccrual status, compared to $42.0 million and $64.9 million at December 31, 2012, respectively. In 2013, ASB recorded a provision for loan losses of $1.5 million, compared to a provision of $12.9 million in 2012.
The determination of the allowance for loan losses is sensitive to the credit risk ratings assigned to ASB’s loan portfolio and loss ratios inherent in the ASB loan portfolio at any given point in time. A sensitivity analysis provides insight regarding the impact that adverse changes in credit risk ratings may have on ASB’s allowance for loan losses. At December 31, 2013, in the event that 1% of the homogenous loans move down one delinquency classification (e.g., 1% of the loans in the 0-29 days delinquent category move to the 30-59 days delinquent category, 1% of the loans in the 30-59 days delinquent category move to the 60-89 days delinquent category and 1% of the loans in the 60-89 days delinquent category move to the 90+ days delinquent category) and 1% of non-homogenous loans were downgraded one credit risk rating category for each category (e.g., 1% of the loans in the “pass” category moved to the “special mention” category, 1% of the loans in the “special mention” category moved to the “substandard” category, 1% of the loans in the “substandard” category moved to the “doubtful” category and 1% of the loans in the “doubtful” category moved to the “loss” category), the allowance for loan losses would have
increased by approximately $0.4 million. The sensitivity analyses do not imply any expectation of future deterioration in ASB loans’ risk ratings and they do not necessarily reflect the nature and extent of future changes in the allowance for loan losses due to the numerous quantitative and qualitative factors considered in determining ASB’s allowance for loan losses. The example above is only one of a number of possible scenarios.
Although management believes ASB’s allowance for loan losses is adequate, the actual loan losses, provision for loan losses and allowance for loan losses may be materially different if conditions change (e.g., if there is a significant change in the Hawaii economy or real estate market), and material increases in those amounts could have a material adverse effect on the Company’s results of operations, financial condition and liquidity.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries is applicable):
The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility and the “other” segment’s exposures to these two risks are not material as of December 31, 2013.
Credit risk for ASB is the risk that borrowers or issuers of securities will not be able to repay their obligations to the bank. Credit risk associated with ASB’s lending portfolios is controlled through its underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated through investment portfolio limits, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss sensitivity analysis. See “Allowance for loan losses” above and in Note 4 of the Consolidated Financial Statements.
Liquidity risk for ASB is the risk that the bank will not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liability management process, on-going analytical analysis, monitoring and reporting information such as weekly cash-flow analyses and maintenance of liquidity contingency plans.
The Utilities are exposed to some commodity price risk primarily related to their fuel supply and IPP contracts. The Utilities' commodity price risk is substantially mitigated so long as they have their current ECACs in their rate schedules. The Utilities currently have no hedges against its commodity price risk.
The Company currently has no direct exposure to market risk from trading activities nor foreign currency exchange rate risk.
The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity, especially as it relates to ASB, but also as it may affect the discount rate used to determine retirement benefit liabilities, the market value of retirement benefit plans’ assets and the Utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.
Bank interest rate risk
The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk (IRR). ASB’s interest-rate risk profile is strongly influenced by its primary business of making fixed-rate residential mortgage loans and taking in retail deposits. Large mismatches in the amounts or timing between the maturity or repricing of interest sensitive assets or liabilities could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates. Many other factors also affect ASB’s exposure to changes in interest rates, such as general economic and financial conditions, customer preferences, and competition for loans or deposits.
ASB’s Asset/Liability Management Committee (ALCO), whose voting members are officers and employees of ASB, is responsible for managing interest rate risk and carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies under which management monitors and coordinates ASB’s assets and liabilities.
See Note 4 of the Consolidated Financial Statements for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.
Management of ASB measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income (NII) and the market value of interest-sensitive assets and liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanced with a mortgage prepayment model and a collateralized mortgage obligation database. The simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions for mortgage loans and mortgage-related securities.
NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in the alternate interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming “rate ramps” or gradual interest changes and accomplished by moving the yield curve in a parallel fashion, over the next twelve month period, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-related assets, future pricing spreads for new assets and liabilities, and the speed and magnitude with which deposit rates change in response to changes in the overall level of interest rates. Other NII sensitivity analysis may include scenarios such as yield curve twists or non-static balance sheet changes (such as changes to key balance sheet drivers).
Consistent with OCC guidelines, the market value or economic capitalization of ASB is measured as economic value of equity (EVE). EVE represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. Key assumptions used in the calculation of ASB’s EVE include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alternate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. EVE is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points (bp) up to + 300 bp. The change in EVE is measured as the change in EVE in a given rate scenario from the base case and expressed as a percentage. To gain further insight into the IRR profile, additional analysis is periodically performed in alternate scenarios including rate shifts of greater magnitude, yield curve twists and changes in key balance sheet drivers.
ASB’s interest-rate risk sensitivity measures as of December 31, 2013 and 2012 constitute “forward-looking statements” and were as follows:
Management believes that ASB’s interest rate risk position as of December 31, 2013 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was less asset sensitive for all rate increases as of December 31, 2013 compared to December 31, 2012 due to changes in the mix of assets and steepening of the yield curve which resulted in less cash flows maturing or repricing within the 12 month horizon.
ASB’s base EVE increased to $906 million as of December 31, 2013 compared to $767 million as of December 31, 2012 due to growth in capital, steepening of the yield curve and changes in assumptions about the behavior of core deposits.
The change in EVE was more sensitive in the rising scenarios as of December 31, 2013 compared to December 31, 2012 due to steepening of the yield curve which extended the duration of fixed-rate mortgage-related assets, the shift in the investment portfolio towards a longer duration mix, and changes in the mix of retail loans and core deposits.
The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and
other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.
Other than bank interest rate risk
The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (currently fixed-rate debt) and preferred securities. As of December 31, 2013, management believes the Company is exposed to “other than bank” interest rate risk because of its periodic borrowing requirements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see “Retirement benefits” in HEI’s MD&A and Note 10 of the Consolidated Financial Statements) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Electric utility-Certain factors that may affect future results and financial condition-Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. The Company’s longer-term debt, in the form of borrowings of proceeds of revenue bonds, registered Medium-Term Notes and privately-placed Senior Notes, is at fixed rates (see Note 16 of the Consolidated Financial Statements for the fair value of long-term debt, net-other than bank).
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
HEI and Hawaiian Electric:
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of
Hawaiian Electric Industries, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and its subsidiaries (the “Company”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the Annual Report of Management on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 21, 2014
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Hawaiian Electric Company, Inc.:
In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, comprehensive income, changes in common stock equity and cash flows present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and its subsidiaries (the "Company") at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 21, 2014
Consolidated Statements of Income
Hawaiian Electric Industries, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income
Hawaiian Electric Industries, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
Hawaiian Electric Industries, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Changes in Shareholders’ Equity
Hawaiian Electric Industries, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Cash Flows
Hawaiian Electric Industries, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Income
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Capitalization
Hawaiian Electric Company, Inc. and Subsidiaries
(continued)
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Capitalization (continued)
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Changes in Common Stock Equity
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Cash Flows
Hawaiian Electric Company, Inc. and Subsidiaries
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
1 · Summary of significant accounting policies
General
Hawaiian Electric Industries, Inc. (HEI) is a holding company with direct and indirect subsidiaries principally engaged in electric utility and banking businesses, primarily in the State of Hawaii. HEI is the parent holding company of Hawaiian Electric Company, Inc. (Hawaiian Electric) and indirect parent holding company of American Savings Bank, F. S. B. (ASB). HEI’s common stock is traded on the New York Stock Exchange.
Hawaiian Electric and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (Hawaii Electric Light) and Maui Electric Company, Limited (Maui Electric), are regulated public electric utilities (collectively, the Utilities) in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai. Hawaiian Electric also owns Renewable Hawaii, Inc. (RHI), Uluwehiokama Biofuels Corp. (UBC) and HECO Capital Trust III. See Note 2.
ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii.
HEI and Hawaiian Electric have combined their financial statements. Also, Hawaiian Electric changed its consolidated statements of income from a utility presentation to a commercial company presentation, resulting in more consistency between HEI’s and Hawaiian Electric’s consolidated financial statements. The combined notes to the consolidated financial statements apply to both HEI and Hawaiian Electric unless otherwise described.
Basis of presentation. In preparing the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), 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.
Material estimates that are particularly susceptible to significant change for the Company include the amounts reported for investment and mortgage-related securities (ASB only); property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities (Utilities only); electric utility revenues (Utilities only); and allowance for loan losses (ASB only).
Consolidation. The HEI consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, the Company). The Hawaiian Electric consolidated financial statements include the accounts of Hawaiian Electric and its subsidiaries. The consolidated financial statements exclude subsidiaries which are variable interest entities (VIEs) when the Company or the Utilities are not the primary beneficiaries. Investments in companies over which the Company or the Utilities have the ability to exercise significant influence, but not control, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated in consolidation. See Note 5 for information regarding unconsolidated VIEs.
Cash and cash equivalents. The Utilities consider cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and liquid investments (with original maturities of three months or less) to be cash and cash equivalents. The Company considers the same items to be cash and cash equivalents as well as ASB’s deposits with the Federal Home Loan Bank (FHLB) of Seattle, federal funds sold (excess funds that ASB loans to other banks overnight at the federal funds rate) and securities purchased under resale agreements.
Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses and other-than-temporary impairment (OTTI) not related to credit losses excluded from earnings and reported on a net basis in accumulated other comprehensive income (loss) (AOCI).
For securities that are not trading securities, individual securities are assessed for impairment at least on a quarterly basis, and more frequently when economic or market conditions warrant. An investment is impaired if the fair value of the security is
less than its carrying value at the financial statement date. When a security is impaired, the Company determines whether this impairment is temporary or other-than-temporary. If the Company does not expect to recover the entire amortized cost basis of the security, an OTTI exists. If the Company intends to sell the security, or will more likely than not be required to sell the security before recovery of its amortized cost, the OTTI must be recognized in earnings. If the Company does not intend to sell the security and it is not more likely than not that the Company will be required to sell the security before recovery of its amortized cost, the OTTI must be separated into the amount representing the credit loss and the amount related to all other factors. The amount of OTTI related to the credit loss is recognized in earnings while the remaining OTTI is recognized in other comprehensive income. Once an OTTI has been recognized on a security, the Company accounts for the security as if the security had been purchased on the measurement date of the OTTI at an amortized cost basis equal to the previous amortized cost basis less the OTTI recognized in earnings. The difference between the new amortized cost basis and the cash flows expected to be collected is accreted in accordance with existing applicable guidance as interest income. Any discount or reduced premium recorded for the security will be amortized over the remaining life of the security in a prospective manner based on the amount and timing of future estimated cash flows. If upon subsequent evaluation, there is a significant increase in cash flows expected to be collected or if actual cash flows are significantly greater than cash flows previously expected, such changes shall be accounted for as a prospective adjustment to the accretable yield.
The specific identification method is used in determining realized gains and losses on the sales of securities. Discounts and premiums on investment securities are accreted or amortized over the remaining lives of the securities, adjusted for actual portfolio prepayments, using the interest method. Discounts and premiums on mortgage-related securities are accreted or amortized over the remaining lives of the securities, adjusted based on changes in anticipated prepayments, using the interest method.
Equity method. Investments in up to 50%-owned affiliates over which the Company or the Utilities have the ability to exercise significant influence over the operating and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in operating revenues. Equity method investments are also evaluated for OTTI. Also see Note 5 below.
Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make utility plant more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.
Depreciation. Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Electric utility plant additions in the current year are depreciated beginning January 1 of the following year in accordance with rate-making. Electric utility plant has lives ranging from 20 to 88 years for production plant, from 25 to 65 years for transmission and distribution plant and from 5 to 65 years for general plant. The Utilities’ composite annual depreciation rate, which includes a component for cost of removal, was 3.1% in 2013, 3.1% in 2012 and 3.2% in 2011.
Leases. HEI, the Utilities and ASB have entered into lease agreements for the use of equipment and office space. The provisions of some of the lease agreements contain renewal options.
The Company's operating lease expense was $19 million, $19 million and $14 million in 2013, 2012 and 2011, respectively, and future minimum lease payments are $18 million, $16 million, $13 million, $10 million, $7 million and $29 million for 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. The Utilities' operating lease expense was $8 million, $8 million and $6 million in 2013, 2012 and 2011, respectively, and future minimum lease payments are $9 million, $8 million, $6 million, $5 million, $3 million and $18 million for 2014, 2015, 2016, 2017, 2018 and thereafter, respectively.
Retirement benefits. Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant (in the case of the Utilities). Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), including changes promulgated by the Pension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost during the year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the Public Utilities Commission of the State of
Hawaii (PUC), the Utilities generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost.
Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Utilities must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC. Future decisions in rate cases could further impact funding amounts.
The Company and the Utilities recognize on their respective balance sheets the funded status of their defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.
Environmental expenditures. The Company and the Utilities are subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.
Financing costs. Financing costs related to the registration and sale of HEI common stock are recorded in shareholders’ equity.
HEI uses the straight-line method, which approximates the effective interest method, to amortize the long-term debt financing costs of the holding company over the term of the related debt.
The Utilities use the straight-line method, which approximates the effective interest method, to amortize long-term debt financing costs and premiums or discounts over the term of the related debt. Unamortized financing costs and premiums or discounts on the Utilities' long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.
HEI and the Utilities use the straight-line method to amortize the fees and related costs paid to secure a firm commitment under their line-of-credit arrangements.
Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s and the Utilities' assets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.
The Company recognizes investment tax credits as a reduction of income tax expense in the period the assets giving rise to such credits are placed in service, except for the Utilities' investment tax credits, which are deferred and amortized over the estimated useful lives of the properties to which the credits relate, in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”
The Utilities are included in the consolidated income tax returns of HEI. However, income tax expense has been computed for financial statement purposes as if the Utilities filed separate consolidated Hawaiian Electric income tax returns.
Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and written down or an unanticipated tax liability might be incurred.
The Company and the Utilities use a “more-likely-than-not” recognition threshold and measurement standard for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.
Earnings per share (HEI only). Basic earnings per share (EPS) is computed by dividing net income for common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that dilutive common shares for stock compensation and the equity forward transactions are added to the denominator. HEI uses the two-
class method of computing EPS as restricted stock grants include non-forfeitable rights to dividends and are participating securities.
Under the two-class method, HEI's EPS was comprised as follows for both participating securities and unrestricted common stock:
As of December 31, 2013 and 2012, the antidilutive effect of stock appreciation rights (SARs) on 102,000 shares of HEI common stock (for which the exercise prices were greater than the closing market prices of HEI’s common stock on such dates), was not included in the computation of diluted EPS. As of December 31, 2011, there were no shares that were antidilutive.
Share-based compensation. The Company and the Utilities apply the fair value based method of accounting to account for its stock compensation, including the use of a forfeiture assumption. See Note 11.
Impairment of long-lived assets and long-lived assets to be disposed of. The Company and the Utilities review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.
Recent accounting pronouncements and interpretations.
Obligations resulting from joint and several liability. In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information.
The Company and the Utilities retrospectively adopted ASU No. 2013-04 in the first quarter of 2014 and it did not have a material impact on the Company’s or the Utilities' results of operations, financial condition or liquidity.
Unrecognized tax benefits (UTBs). In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which requires the netting of UTBs against a deferred tax asset for a loss or other carryforward that would apply in settlement of the uncertain tax positions. UTBs should be netted against all available same-jurisdiction loss or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the UTBs.
The Company and the Utilities plan to prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not believe that such adoption will have a material impact on the Company’s or the Utilities' results of operations, financial condition or liquidity.
Reclassification of loans upon foreclosure. In January 2014, the FASB issued ASU No. 2014-04, "Receivables-Troubled Debt Restructurings by Creditors (Subtopic 310-40): Reclassification of Residential Real Estate Collateralized Consumer Mortgage Loans upon Foreclosure,” which clarifies when an in substance repossession or foreclosure occurs, and a creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan. A creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan upon either: (1) the creditor obtaining legal title to the residential real estate property upon completion of a foreclosure; or (2) the borrower conveying all interest in the residential real estate property to the creditor to satisfy that loan through a deed in lieu of foreclosure or through a similar legal agreement. The amendment also requires additional disclosures.
The Company plans to prospectively adopt ASU No. 2014-04 in the first quarter of 2015 and does not believe that such adoption will have a material impact on the Company’s results of operations, financial condition or liquidity.
Reclassifications. In the fourth quarter of 2013, Hawaiian Electric changed its consolidated statements of income for 2013 and prior comparative periods from a utility presentation to a commercial company presentation, under which all operating revenues and expenses (including non-regulated revenues and expenses) are included in the determination of operating income. Additionally, income tax expense, which was previously included partially in operating expenses and partially in other income (deductions), is now entirely presented directly above net income in income taxes and includes income taxes related to non-regulated revenues and expenses. These and other reclassifications made to prior years’ financial statements to conform to the 2013 presentation did not affect previously reported results of operations.
Electric utility
Regulation by the Public Utilities Commission of the State of Hawaii (PUC). The Utilities are regulated by the PUC and account for the effects of regulation under FASB ASC Topic 980, “Regulated Operations.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance.
Accounts receivable. Accounts receivable are recorded at the invoiced amount. The Utilities generally assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Utilities’ best estimate of the amount of probable credit losses in the Utilities existing accounts receivable. On a monthly basis, the Utilities adjust their allowance, with a corresponding charge (credit) on the statement of income, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote. At both December 31, 2013 and 2012, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $2 million.
Contributions in aid of construction. The Utilities receive contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 to 55 years as an offset against depreciation expense.
Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC. Prior to the implementation of decoupling, revenues related to the sale of energy were generally recorded when service was rendered or energy was delivered to customers and included revenues applicable to energy consumed in the accounting period but not yet billed to the customers.
The rate schedules of the Utilities include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules also include purchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECACs and PPACs are required to be reconciled quarterly.
Upon the implementation of decoupling (Hawaiian Electric on March 1, 2011, Hawaii Electric Light on April 9, 2012 and Maui Electric on May 4, 2012), the Utilities: (1) recognize monthly revenue balancing account (RBA) revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales, (2) recognize a revenue escalation component via a revenue adjustment mechanism (RAM) for certain operation and maintenance (O&M) expenses and rate base changes and (3) recognize (when applicable) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility’s ratemaking return on average common equity (ROACE) exceeds the ROACE allowed in its most recent rate case.
The Utilities’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, the Utilities’ revenue tax payments to the taxing authorities in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For 2013, 2012 and 2011, the Utilities included approximately $266 million, $280 million and $264 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.
Power purchase agreements. If a power purchase agreement (PPA) falls within the scope of ASC Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the Utilities would recognize a capital asset and a lease obligation. Currently, none of the PPAs are required to be recorded as a capital lease.
The Utilities evaluate PPAs to determine if the PPAs are VIEs, if the Utilities are primary beneficiaries and if consolidation is required. See Note 5.
Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.
Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.
The weighted-average AFUDC rate was 7.6% in 2013, 7.6% in 2012 and 8.0% in 2011, and reflected quarterly compounding.
Bank (HEI only)
Loans receivable. ASB states loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method.
Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over the life of the loan using the interest method or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.
Loans held for sale, gain on sale of loans, and mortgage servicing assets and liabilities. Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Generally, the determination of fair value is based on the fair value of the loans. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.
ASB capitalizes mortgage servicing assets or liabilities when the related loans are sold with servicing rights retained. Accounting for the servicing of financial assets requires that mortgage servicing assets or liabilities resulting from the sale or securitization of loans be initially measured at fair value at the date of transfer, and permits a class-by-class election between fair value and the lower of amortized cost or fair value for subsequent measurements of mortgage servicing asset classes. Mortgage servicing assets or liabilities are included as a component of gain on sale of loans. Under ASC Topic 860, “Transfers and Servicing,” ASB elected to continue to amortize all mortgage servicing assets in proportion to and over the period of estimated net servicing income and assess servicing assets for impairment based on fair value at each reporting date. Such amortization is reflected as a component of revenues on the consolidated statements of income. The fair value of mortgage servicing assets, for the purposes of impairment, is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. ASB measures impairment of mortgage servicing assets on a disaggregated basis based on certain risk characteristics including loan type and note rate. Impairment losses are recognized through a valuation allowance for each impaired stratum, with any associated provision recorded as a component of loan servicing fees included in ASB’s noninterest income.
Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.
Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a ten-point risk rating system for evaluating the credit quality of the loans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. Ratings are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). ASB’s credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans are categorized into the regulatory asset quality classifications - Pass (Risk Rating 1 to 6), Special Mention (Risk Rating 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) based on credit quality. The allowance for loan loss allocations for
these loans are based on internal migration analyses with actual net losses. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans that are not considered collateral dependent, generally the discounted cash flow method is used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured loans, the present value of the expected future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured terms. Impairment shortfalls are charged to the provision for loan losses and included in the allowance for loan losses. However, impairment shortfalls that are deemed to be confirmed losses (uncollectible) are charged off, with the loan written down by the amount of the confirmed loss.
Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products with common risk characteristics and the allowance for loan loss allocations for these loan types uses historical loss ratio analyses based on actual net charge-offs. For residential loans, the loan portfolio is segmented by loan categories and geographic location within the State of Hawaii. The consumer loan portfolio is segmented into various secured and unsecured loan product types. The credit scored business loan portfolio is segmented by loans under lines of credit or term loans, and corporate credit cards. The look-back period of actual loss experience is reviewed annually and may vary depending on the credit environment.
In addition to actual loss experience, ASB considers the following qualitative factors for all loans in estimating the allowance for loan losses:
•
changes in lending policies and procedures;
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changes in economic and business conditions and developments that affect the collectability of the portfolio;
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changes in the nature, volume and terms of the loan portfolio;
•
changes in lending management and other relevant staff;
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changes in loan quality (past due, non-accrual, classified loans);
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changes in the quality of the loan review system;
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changes in the value of underlying collateral;
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effect of, and changes in the level of, any concentrations of credit; and
•
effect of other external and internal factors.
For all loan segments, ASB generally ceases the accrual of interest on loans when they become contractually 90 days past due or when there is reasonable doubt as to collectability. Subsequent recognition of interest income for such loans is on the cash or cost recovery method. When, in management’s judgment, supported by underwriting, the borrower’s ability to make principal and interest payments has resumed and collectability is reasonably assured, a loan not accruing interest (nonaccrual loan) is returned to accrual status. ASB uses either the cash or cost-recovery method to record cash receipts on impaired loans that are not accruing interest. While the majority of consumer loans are subject to ASB’s policies regarding nonaccrual loans, all past due unsecured consumer loans may be charged off upon reaching a predetermined delinquency status varying from 120 to 180 days.
Management believes its allowance for loan losses adequately estimates actual loan losses that will ultimately be incurred. However, such estimates are based on currently available information and historical experience, and future adjustments may be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.
Loans modified in a troubled debt restructuring. Loans are considered to have been modified in a troubled debt restructuring (TDR) when, due to a borrower’s financial difficulties, ASB makes concessions to the borrower that it would not otherwise consider for a non-troubled borrower. Modifications may include interest rate reductions, interest only payments for an extended period of time, protracted terms such as amortization and maturity beyond the customary length of time found in the normal market place, and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual loan that has been modified in a TDR remains on nonaccrual status until the borrower has demonstrated sustained repayment performance for a period of six consecutive months. However, performance
prior to the modification, or significant events that coincide with the modification, are included in assessing whether the borrower can meet the new terms and may result in the loan being returned to accrual status at the time of loan modification or after a shorter performance period. If the borrower’s ability to meet the revised payment schedule is uncertain, or there is reasonable doubt over the full collectability of principal and interest, the loan remains on nonaccrual status.
Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at fair value, less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. Costs related to holding real estate are charged to operations as incurred.
Goodwill and other intangibles. Goodwill is tested for impairment at least annually. Intangible assets with definite useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with ASC 350, “Intangibles-Goodwill and other” (ASC 350).
Goodwill. At December 31, 2013 and 2012, the amount of goodwill was $82.2 million. The goodwill is with respect to ASB and is the Company’s only intangible asset with an indefinite useful life and is tested for impairment annually in the fourth quarter using data as of September 30.
To determine if there was any impairment to the book value of goodwill pertaining to ASB, the fair value of ASB was estimated using a valuation method based on a market approach and discounted cash flow method with each method having an equal weighting in determining the fair value of ASB. The market approach considers publicly traded financial institutions with assets of $3.5 billion to $8 billion and measures the institutions’ market values as a multiple to (1) net income and (2) book equity. ASB used the median market value multiples for net income and book equity from its selection criteria and applied the multiples to its net income and book equity to calculate ASB’s fair value using the market approach. In order to reflect a premium that a buyer would pay for a controlling interest in ASB, a control premium of 18.3% was included in determining the market approach fair value. The control premium was based on control premiums paid in 18 acquisitions completed within the last two years where 100% interest was purchased and control premium information was available. The discounted cash flow method values a company on a going concern basis and is based on the concept that the future benefits derived from a particular company can be measured by its sustainable after-tax cash flows in the future. ASB’s discounted cash flow analysis was based on its income statement forecasts and a discount rate of 8.5% was applied to present value the cash flows. ASB used a Capital Asset Pricing Model analysis to determine its discount rate. As of September 30, 2013, the estimated fair value of ASB using this valuation methodology exceeded its book value by approximately 60%. For the three years ended December 31, 2013, there has been no impairment of goodwill.
Amortized intangible assets. The table below presents the gross carrying amount, accumulated amortization, valuation allowance and net carrying amount of ASB’s mortgage servicing assets as of December 31, 2013 and 2012:
Changes in the valuation allowance for mortgage servicing assets were as follows:
The estimated aggregate amortization expenses for mortgage servicing assets for 2014, 2015, 2016, 2017 and 2018 are $1.6 million, $1.4 million, $1.3 million, $1.1 million and $1.0 million, respectively. ASB capitalizes mortgage servicing assets acquired through either the purchase or origination of mortgage loans for sale or the securitization of mortgage loans with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing assets. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others which increases the value of mortgage servicing assets, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing assets and increase the amortization of the mortgage servicing assets. In 2013, 2012 and 2011, mortgage servicing assets acquired through the sale or securitization of loans held for sale were $2.6 million, $4.8 million and $2.8 million, respectively. Amortization expenses for ASB’s mortgage servicing assets amounted to $1.8 million, $1.7 million
and $1.1 million for 2013, 2012 and 2011, respectively, and are recorded as a reduction in revenues on the consolidated statements of income.
2 · Segment financial information
The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described for the Company in the summary of significant accounting policies, except as otherwise indicated and except that federal and state income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on net income. Each segment accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest, rent and preferred stock dividends.
Electric utility
Hawaiian Electric and its wholly-owned operating subsidiaries, Hawaii Electric Light and Maui Electric, are public electric utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. The Utilities have been aggregated into the electric utility segment primarily because all three entities: (1) are involved in the business of supplying electric energy in the same geographical location (i.e., the State of Hawaii), (2) have similar production processes that include electric generators (e.g., conventional oil-fired steam units and combustion turbines), (3) serve similar customers within their franchise territories (e.g., residential, commercial and industrial customers), (4) use similar electric grids to distribute the energy to their customers, (5) are regulated by the PUC and undergo similar rate-making processes and (6) have similar economic characteristics. Hawaiian Electric also owns the following nonregulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; HECO Capital Trust III, which is a financing entity; and Uluwehiokama Biofuels Corp. (UBC), which was formed to own a new biodiesel refining plant to be built on the island of Maui, which project has been terminated.
Bank
ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) (previously by the Department of Treasury, Office of Thrift Supervision (OTS)) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System.
Other
“Other” includes amounts for the holding companies (HEI and American Savings Holdings, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.
Segment financial information was as follows:
Intercompany electricity sales of the Utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by the Utilities, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.
Bank fees that ASB charges the Utilities and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.
3 · Electric utility segment
Regulatory assets and liabilities. In accordance with ASC Topic 980, “Regulated Operations,” the Utilities’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that the regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company’s and the Utilities' financial condition, results of operations and/or liquidity.
Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, the Utilities do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, the Utilities include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. In the table below, noted in parentheses are the original PUC authorized amortization or recovery periods and, if different, the remaining amortization or recovery periods as of December 31, 2013 are noted.
Regulatory assets were as follows:
Regulatory liabilities were as follows:
The regulatory asset and liability relating to retirement benefit plans was recorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for the Utilities in 2007 (see Note 10).
Major customers. The Utilities received 11% ($340 million), 11% ($349 million) and 11% ($316 million) of their operating revenues from the sale of electricity to various federal government agencies in 2013, 2012 and 2011, respectively.
Cumulative preferred stock. The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:
Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric's obligation to make payments on its own preferred stock.
Related-party transactions. HEI charged the Utilities $6.2 million, $6.1 million and $4.9 million for general management and administrative services in 2013, 2012 and 2011, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.
Hawaiian Electric’s short-term borrowings from HEI fluctuate during the year, and totaled nil at December 31, 2013 and 2012. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or Hawaiian Electric’s effective weighted average short-term external borrowing rate. If both HEI and Hawaiian Electric do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Wall Street Journal plus 0.15%.
Borrowings among the Utilities are eliminated in consolidation. Interest charged by HEI to Hawaiian Electric was nil in 2013, nil in 2012 and de minimis in 2011.
Commitments and contingencies.
Fuel contracts. The Utilities have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2016. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2013, the estimated cost of minimum purchases under the fuel supply contracts is $0.9 billion in 2014, $0.7 billion in 2015 and $0.4 billion in 2016. The actual cost of purchases in 2014 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. The Utilities purchased $1.1 billion, $1.3 billion and $1.3 billion of fuel under contractual agreements in 2013, 2012 and 2011, respectively.
Hawaiian Electric and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC approved the recovery of costs incurred under this contract on April 30, 2013.
Hawaiian Electric and Tesoro Hawaii Corp. (Tesoro) are parties to an amended LSFO supply contract (LSFO contract), which runs through December 31, 2014 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC approved the recovery of costs incurred under this contract on April 30, 2013. On September 25, 2013, Tesoro sold its Hawaii refinery and related distribution and marketing assets to Hawaii Independent Energy, LLC, a wholly owned subsidiary of Par Petroleum Corporation of Houston Texas.
The Utilities are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Tesoro, respectively, which end December 31, 2015. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.
The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under Hawaiian Electric’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The fuel contract between Kalaeloa and Tesoro term ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.
The costs incurred under the Utilities’ fuel contracts are included in their respective ECACs, to the extent such costs are not recovered through the Utilities’ base rates.
Power purchase agreements. As of December 31, 2013, the Utilities had six firm capacity PPAs for a total of 567 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion for each of 2013, 2012 and 2011. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term (and as amended) and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2014 through 2018 and a total of $0.6 billion in the period from 2019 through 2033.
In general, the Utilities base their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. The Utilities pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. The Utilities do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to Hawaiian Electric or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.
Purchase power adjustment clause. The PUC has approved purchased power adjustment clauses (PPACs) for the Utilities. Purchased power capacity, O&M and other non-energy costs previously recovered through base rates are now recovered in the PPACs, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs outside of a rate case. Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates.
Hawaii Clean Energy Initiative. In January 2008, the State of Hawaii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism (DBEDT), the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs and the Utilities (collectively, the parties), signed an agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC.
Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.
In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for Hawaiian Electric’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the EOTP Phase I project cost issues and, in March 2013, the PUC eliminated the requirement for an audit of the CIP CT-1 and CIS project costs as described below.
On January 28, 2013, the Utilities and the Consumer Advocate signed a settlement agreement (2013 Agreement), subject to PUC approval, to write off $40 million of costs in lieu of conducting the regulatory audits of the CIP CT-1 project and the CIS project. Based on the 2013 Agreement, as of December 31, 2012, the Utilities recorded an after-tax charge to net income of approximately $24 million - $17.1 million for Hawaiian Electric, $3.4 million for Hawaii Electric Light, and $3.2 million for Maui Electric. The remaining recoverable costs for these projects of $52 million were included in rate base as of December 31, 2012.
As part of the 2013 Agreement, Hawaii Electric Light would withdraw its 2013 test year rate case, and delay filing a new rate case until a 2016 test year. Additionally, Hawaiian Electric would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. For both Utilities, the existing terms of the last rate case decisions would continue. Hawaiian Electric would also be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting on January 1 of 2014, 2015 and 2016. The cash collection of RAM revenues would remain unchanged, starting June 1 of each year through May 31 of the following year.
On March 19, 2013, the PUC issued a decision and order (2013 D&O) approving the 2013 Agreement, with the following clarifications, none of which changed the financial impact of the settlement recorded as of December 31, 2012: (1) the PUC reiterated its authority to examine and ascertain what post go-live CIS costs would be subject to regulatory review in future rate cases; (2) the PUC discouraged requesting single issue cost deferral accounting and/or cost recovery mechanisms during the period of rate case deferral by Hawaiian Electric and Hawaii Electric Light; (3) the PUC approved the agreed-upon recovery of CIP CT-1 and CIS project costs through the RAM, as set forth in the 2013 Agreement, however not setting a precedent for future projects; and (4) the PUC reaffirmed its right to rule on the substance of the Maui Electric 2012 test year rate case in its ongoing rate case proceeding. On May 31, 2013, the PUC issued a final D&O in the Maui Electric 2012 test year rate case. See “Maui Electric 2012 test year rate case” below.
In March 2012, the PUC approved a settlement agreement reached among Hawaiian Electric, the Consumer Advocate and the Department of Defense, under which, in lieu of a regulatory audit, Hawaiian Electric would write off $9.5 million of EOTP Phase 1 gross plant in service and associated adjustments. This resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million and the elimination of the requirement for a Phase 1 regulatory audit. The PUC also provided for an additional increase of approximately $5 million in Hawaiian Electric’s 2011 test year rate case for the additional revenue requirements reflecting all remaining Phase 1 costs not previously included in rates or agreed to be written off.
Renewable energy projects. The Utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard (RPS) goal of 40% renewable energy by 2030 and to meeting their commitments relating to decreasing the State’s dependence on imported fossil fuels under their 2008 Energy Agreement with the Governor, the DBEDT and the Consumer Advocate (Energy Agreement). The Utilities continue to evaluate and pursue opportunities with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others.
In December 2009, the PUC allowed Hawaiian Electric to defer the costs of studies for a large wind project for later review of prudence and reasonableness. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.
In November 2011, Hawaiian Electric and Maui Electric filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between Hawaiian Electric and Maui Electric) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed Hawaiian Electric and Maui Electric to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, were to be determined at a later date.
A revised draft Request for Proposals (RFP) for 200MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands was posted on Hawaiian Electric's website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted Hawaiian Electric’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million. On July 11, 2013, the PUC issued orders related to the 200 MW RFP. First, it issued an order that Hawaiian Electric shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order. Second, it initiated an investigative proceeding to review the progress of the Lanai Wind Project stating that there was an uncertainty whether the project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. The PUC also stated that it will review the PPA (if one is completed) and, as part of that process, determine whether the Lanai Wind Project should be developed taking into account potential as-available renewable energy projects and grid infrastructure options. The PUC stated it intends to evaluate the project as a combined resources proposal (i.e., wind project and generation tie transmission cable between the islands of Oahu and Lanai). Third, the PUC initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.
In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, Hawaii Electric Light filed an application to defer 2012 costs related to the Geothermal RFP. In February 2013, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.
In June 2013, Hawaiian Electric filed an application requesting PUC approval of Waivers from the Framework for Competitive Bidding for 5 projects (4 photovoltaic and 1 wind) selected as part of Hawaiian Electric’s “Invitation for Low Cost
Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.” Subsequently, two of the projects were withdrawn and in February 2014, three of the projects were granted waivers from the Competitive Bidding Framework. In November 2013, Hawaiian Electric filed a second waiver application requesting PUC approval for two additional projects (6 photovoltaic) selected as part of Hawaiian Electric's pricing refresh opportunity provided to developers that originally submitted proposals in response to the “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.”
Environmental regulation. The Utilities are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.
On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at Hawaiian Electric’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual O&M expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule.
On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, Hawaiian Electric has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric also has pending with the EPA a Petition for Reconsideration and Stay dated April 16, 2012, and a Request for Expedited Consideration dated August 14, 2013. The submittals ask the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. The Petition and Request submittals to the EPA included additional data to demonstrate that the existing standard is erroneous. Hawaiian Electric has been in contact with the EPA regarding the status of its Petition and does not expect a decision before mid-2014.
On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide NAAQS implementation plans. Hawaiian Electric will work with the DOH and the EPA in the rulemaking process for these implementation plans to ensure development of cost-effective strategies for NAAQS compliance. Based on the February 6, 2013 EPA guidance document, current estimates of the compliance date for the one-hour sulfur dioxide NAAQS is in the 2022 or later timeframe. Pending litigation may result in an accelerated timeframe, but the impact of the litigation cannot be predicted at this time.
Depending upon the final outcome of the CWA 316(b) regulations,the specific measures required for MATS compliance, and the rules and guidance developed for implementation of more stringent National Ambient Air Quality Standards, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire or deactivate certain generating units earlier than anticipated.
Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.
Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The EPA referred the matter to the DOJ for enforcement based on Hawaii Electric Light’s and Maui Electric’s responses to information requests in 2010 and 2012. The letter expresses an interest in resolving the matter without the issuance of a notice of violation. The parties are scheduled to meet in February 2014 to engage in settlement discussions. Hawaii Electric Light and Maui Electric cannot currently estimate
the amount or effect of a settlement, if any. Hawaii Electric Light and Maui Electric continue to investigate the potential bases for the DOJ’s claims.
Former Molokai Electric Company generation site. In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although Maui Electric never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, Maui Electric agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, Maui Electric accrued an additional $3.1 million (reserve balance of $3.6 million as of December 31, 2013) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. Maui Electric received DOH and EPA comments on a revised draft site investigation plan for site characterization in October and November 2013, respectively, both of which did not result in a change to the reserve balance. Maui Electric is currently revising the draft site investigation plan to address the DOH and EPA comments.
Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of greenhouse gas (GHG)emissions (including carbon dioxide emissions from the combustion of fossil fuels) to climate change have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.
In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The Utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities. Hawaiian Electric submitted comments on the proposed regulations in January 2013. In October 2013, the DOH announced that it intends to issue a final rule that would change the required emission reduction from 25% to 16% and delay the accrual of GHG emissions fees until after the rule is promulgated, among other changes, but the final rule has not yet been formally approved or released. Hawaiian Electric continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.
Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.
On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The Utilities have submitted the required reports for 2010, 2011 and 2012 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the Utilities’ EGUs.
In June 2010, the EPA issued its GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. On January 8, 2014, the EPA published in the Federal Register its new proposal for New Source Performance Standards for GHG from new generating units. This proposed rule on GHG from new EGUs does not apply to oil-fired combustion turbines or diesel engine generators, and is not otherwise expected to have significant impacts on the Utilities. President Obama also directed the EPA Administrator to issue proposed standards, regulations, or guidelines for GHG emissions from existing, modified and reconstructed power plants by no later than June 1, 2014, and final standards no later than June 1, 2015. Hawaiian Electric will participate in the federal GHG rulemaking process. The Utilities will continue to evaluate the impact of proposed GHG rules and regulations as they develop. Final regulations may impose significant compliance costs, and may require reductions in fossil fuel use and the addition of renewable energy resources in excess of the requirements of the RPS law.
While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.
The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in Hawaiian Electric’s CIP CT-1, using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the Utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the Utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.
Maui Electric 2012 test year rate case. On May 31, 2013, the PUC issued a final D&O in the Maui Electric 2012 test year rate case. Final rates became effective August 1, 2013. The final D&O approved an increase in annual revenues of $5.3 million, which is $7.8 million less than the interim increase in annual revenues that had been in effect since June 1, 2012. Reductions from the interim D&O relate primarily to:
According to the PUC, the reduction in the allowed ROACE from the stipulated 10% to the final approved 9% is composed of 0.5% allocation due to updated economic and financial market conditions manifested in lower interest rates in the 2012 test year and 0.5% for system inefficiencies reflected in over curtailment of renewable energy produced by independent power producers.
The PUC found that the record did not sufficiently support the normalization of 2013 and 2014 Customer Information System costs into the 2012 test year and ordered a downward adjustment to remove these costs from the test year.
The reduction in the pension and OPEB expense is due to applying a 3-year average in the calculation of pension costs for the purpose of the 2012 test year. This is not a PUC decision to change the pension and OPEB tracking mechanisms, although the PUC emphasizes the need to evaluate alternatives to decrease or limit the growth in employee benefits costs.
The PUC removed integrated resource planning (IRP) expenses from the test year as it could not determine whether these expenses have been reasonably incurred for the 2012 test year as required by the PUC’s IRP Framework and stated that it will determine the appropriate level and method of cost recovery for Maui Electric’s IRP expenses in the pending IRP proceeding.
The PUC reduced operational and renewable energy integration study costs because of the uncertainty regarding the scope of work and actual costs of these studies.
The PUC also continued Maui Electric’s existing energy cost adjustment clause (ECAC) and power purchase adjustment clause (PPAC) design. The PUC stated that it will consider the Utilities' future actions to reduce fuel costs and increase use of renewable energy as it continues to review the design of the ECAC in the future.
On July 2, 2013, the PUC issued an order denying Maui Electric’s requests for an evidentiary hearing and for partial reconsideration of the final D&O, and dismissed Maui Electric’s motion for partial stay. The order allowed Maui Electric to defer IRP costs incurred since June 2012, which through December 31, 2013 totaled approximately $0.9 million, until the level of costs are determined and a method of recovery is decided in the IRP proceeding.
Since the final rate increase was lower than the interim increase previously in effect, Maui Electric recorded a charge, net of revenue taxes, of $7.6 million in the second quarter of 2013 and refunded to customers approximately $9.7 million (which
includes interest accrued since June 1, 2012) between September 2013 and early November 2013. As a result of the D&O, in the second quarter of 2013 Maui Electric also recorded adjustments to reduce expenses by reducing employee benefits expenses by $1.8 million for adjustments to pension and OPEB costs, and to reclassify $0.7 million of IRP costs to deferred accounts.
As directed by the PUC, in June 2013 Maui Electric made its curtailment information available to the public on its website and in July 2013 filed documentation regarding the re-setting of its target heat rates to take into account the operation of the Auwahi wind farm.
In addition, as required by the final D&O, Maui Electric filed in September 2013 a System Improvement and Curtailment Reduction Plan, which identified actions that Maui Electric had already implemented to increase the use of wind energy and further actions that it is committed to implement to benefit customers. In separate filings in October 2013, Maui Electric submitted additional information on the re-setting of its target heat rates and metrics to measure the success of its efforts to reduce or limit curtailment and execute on key actions. In December 2013, Maui Electric filed documentation regarding the re-setting of its target heat rates based on certain operational changes identified in the System Improvement and Curtailment Reduction Plan to be effective in May 2014. Management cannot predict any actions by the PUC as a result of these filings.
Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The Utilities’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.
Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by Hawaiian Electric on March 1, 2011, by Hawaii Electric Light on April 9, 2012 and by Maui Electric on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual 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 revenue adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the 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 below PUC-allowed returns.
On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. The Utilities 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, consistent with the 2013 Agreement, unless the Utilities and the Consumer Advocate mutually agree to the change in this proceeding. The PUC granted several parties’ motions to intervene. In October 2013, the PUC issued orders that bifurcated the proceeding (Schedule A and Schedule B) and identified issues and procedural schedules for both Schedules. The schedule B part of the proceeding is intended to take place over a longer period, with panel hearings scheduled for August 2014.
Schedule A issues include:
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for the RBA, the reasonableness of the interest rate related to the carrying charge of the outstanding RBA balance and whether there should be a risk sharing adjustment to the RBA;
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for the RAM, whether it is reasonable to true up all actual prior year baseline projects, which are those capital projects less than $2.5 million, at year end or implement alternative methods to calculate the RAM rate base;
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whether a risk sharing mechanism should be incorporated into the RBA;
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whether performance metrics should be determined and reported; and
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whether other factors should be considered if potential changes to existing RBA and RAM provisions are required.
Schedule B issues include:
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whether performance metrics and incentives (rewards or penalties) should be implemented to control costs and encourage the Utilities to make necessary or appropriate changes to strategic and action plans;
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whether the allocation of risk as a result of the decoupling mechanism is fairly reflected in the cost of capital allowed in rates;
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changes or alternatives to the existing RAM; and
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changes to ratemaking procedures to improve efficiency and/or effectiveness.
Oral arguments on Schedule A issues were held in January 2014. On February 7, 2014, the PUC issued a D&O on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O requires:
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An adjustment to the Rate Base RAM Adjustment to include 90% of the amount of the current RAM Period Rate Base RAM Adjustment that exceeds the Rate Base RAM Adjustment from the prior year, to be effective with the Utilities’ 2014 decoupling filing.
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Effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case (ranging from 1.25% to 3.25%), instead of the 6% that has been previously approved.
The D&O requires the Utilities to immediately investigate the possibility of deferring the payment of income taxes on the accrued amounts of decoupling revenue, and to report the results with recommendations to the PUC within 120 days. The PUC reserves the right to determine in the next decoupling and rate case filings whether each Utilities’ allowed income taxes should be adjusted for this change.
The Utilities are required to develop websites to present certain performance metrics first for review by the PUC and the parties and then to the public following PUC approval.
The Schedule A issues on whether it is reasonable to automatically include all actual prior year capital expenditures on baseline projects in the Rate Base RAM and whether a risk sharing mechanism should be incorporated into the RBA, particularly with respect to the PUC’s concerns regarding maintaining and enhancing the Utilities' incentives to control costs and appropriately allocating risk and compensation for risk, will be addressed in the Schedule B proceedings.
Management cannot predict the outcome of the proceedings or the ultimate impact of the proceedings on the results of operation of the Utilities.
Consolidating financial information (unaudited). Hawaiian Electric is not required to provide separate financial statements or other disclosures concerning Hawaii Electric Light and Maui Electric to holders of the 2004 Debentures issued by Hawaii Electric Light and Maui Electric to HECO Capital Trust III (Trust III) since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by Hawaiian Electric. Consolidating information is provided below for Hawaiian Electric and each of its subsidiaries for the periods ended and as of the dates indicated.
Hawaiian Electric also unconditionally guarantees Hawaii Electric Light’s and Maui Electric’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of Hawaii Electric Light and Maui Electric and (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder (see Hawaiian Electric and Subsidiaries' Consolidated Statements of Capitalization) and (c) relating to the trust preferred securities of Trust III (see Note 5). Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.
Consolidating statement of income
Year ended December 31, 2013
Consolidating statement of comprehensive income
Year ended December 31, 2013
Consolidating statement of income
Year ended December 31, 2012
Consolidating statement of comprehensive income
Year ended December 31, 2012
Consolidating statement of income
Year ended December 31, 2011
Consolidating statement of comprehensive income
Year ended December 31, 2011
Consolidating balance sheet
December 31, 2013
Consolidating balance sheet
December 31, 2012
Consolidating statements of changes in common stock equity
Consolidating statement of cash flows
Year ended December 31, 2013
Consolidating statement of cash flows
Year ended December 31, 2012
Consolidating statement of cash flows
Year ended December 31, 2011
Explanation of consolidating adjustments on consolidating schedules:
[1]
Eliminations of intercompany receivables and payables and other intercompany transactions.
[2]
Elimination of investment in subsidiaries, carried at equity.
[3]
Reclassification of accrued income taxes for financial statement presentation.
4 · Bank subsidiary (HEI only)
Selected financial information
American Savings Bank, F.S.B.
Statements of Income Data
Statements of Comprehensive Income
Balance Sheet Data
Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.
Investment and mortgage-related securities. ASB owns investment securities (federal agency obligations) and mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and municipal bonds.
As of December 31, 2013, ASB’s investment portfolio distribution was 70% mortgage-related securities issued by FNMA, FHLMC or GNMA, 15% federal agency obligations and 15% municipal bonds. These investment and mortgage-related securities are widely traded in the market and have observable transactions that allow them to be readily priced.
Prices for investments and mortgage-related securities are provided by an independent third party pricing service and are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities
which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its findings on an on-going basis by monitoring market activity and events.
Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.
Federal agency obligations have contractual terms to maturity. Mortgage-related securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages (see contractual maturities table below).
The contractual maturities of available-for-sale securities were as follows:
All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual maturities will likely differ from these contractual maturities because borrowers have the right to prepay obligations with or without prepayment penalties.
In 2013, 2012 and 2011, proceeds from sales of available-for-sale mortgage-related securities were nil, $3.5 million and $30.7 million, resulting in gross realized gains of nil, $0.1 million and $0.4 million, respectively, and there were no gross realized losses. In 2013, proceeds from the sale of federal agency obligations were $71.4 million resulting in gross realized gains of $1.2 million and no gross realized losses. There were no federal agency obligation sales in 2012 and 2011. In 2011, proceeds from the sale of municipal bonds were $2.1 million resulting in gross realized gains of $5,000 and no gross realized losses. There were no sales of municipal bonds in 2013 and 2012.
ASB pledged mortgage-related securities and federal agency obligations with a market value of approximately $87.1 million and $98.0 million as of December 31, 2013 and 2012, respectively, as collateral for public funds deposits, automated clearinghouse transactions with Bank of Hawaii, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2013 and 2012, mortgage-related securities and federal agency obligations with a carrying value of $187.1 million and $189.3 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.
FHLB of Seattle stock. As of December 31, 2013 and 2012, ASB’s investment in stock of the FHLB of Seattle was carried at cost because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and/or borrowing levels. Periodically and as conditions warrant, ASB reviews its investment in the stock of the FHLB of Seattle for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2013, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2013 based on its evaluation of the underlying investment, including:
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the net income and growth in retained earnings recorded by the FHLB of Seattle in the first nine months of 2013;
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compliance by the FHLB of Seattle with all of its regulatory capital requirements and being classified “adequately capitalized” by the Federal Housing Finance Agency (Finance Agency);
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being allowed by the Finance Agency to repurchase excess stock;
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commitments by the FHLB of Seattle to make payments required by law or regulation and the level of such payments in relation to the operating performance of the FHLB of Seattle;
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the impact of legislative and regulatory changes on institutions and, accordingly, on the customer base of the FHLB of Seattle;
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the liquidity position of the FHLB of Seattle; and
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ASB’s intent and assessment of whether it will more likely than not be required to sell the FHLB stock before recovery of its par value.
Deterioration in the FHLB of Seattle’s financial position may result in future impairment losses.
Other-than-temporary impaired securities. All securities are reviewed for impairment in accordance with accounting standards for OTTI recognition. Under these standards ASB’s intent to sell the security, the probability of more-likely-than-not being forced to sell the position prior to recovery of its cost basis and the probability of more-likely-than-not recovering the amortized cost of the position was determined. If ASB’s intent is to hold positions determined to be other-than-temporarily impaired, credit losses, which are recognized in earnings, are quantified using the position’s pre-impairment discount rate and the net present value of cash flows expected to be collected from the security. Non-credit related impairments are reflected in other comprehensive income. ASB did not recognize OTTI for 2013, 2012 or 2011.
Loans receivable.
As of December 31, 2013 and 2012, ASB’s commitments to originate loans approximated $163.7 million and $97.9 million, respectively. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any
condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory and property, plant and equipment.
As of December 31, 2013 and 2012, standby, commercial and banker’s acceptance letters of credit totaled $15.7 million and $10.5 million, respectively. Letters of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. ASB holds collateral supporting those commitments for which collateral is deemed necessary. As of December 31, 2013 and 2012, undrawn consumer lines of credit, including credit cards, totaled $1.1 billion and $1.0 billion, respectively, and undrawn commercial loans including lines of credit totaled $396.4 million and $376.2 million, respectively.
ASB services real estate loans for investors ($1.4 billion, $1.3 billion and $1.0 billion as of December 31, 2013, 2012 and 2011, respectively), which are not included in the accompanying consolidated balance sheet data. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan servicing costs to expense as incurred.
As of December 31, 2013 and 2012, ASB had pledged loans with an amortized cost of approximately $1.7 billion and $1.0 billion, respectively, as collateral to secure advances from the FHLB of Seattle.
As of December 31, 2013 and 2012, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board (FRB) Regulation O) of such individuals, was $45.8 million and $70.9 million, respectively. The $25.1 million decrease in such loans in 2013 was attributed to new commitments and loans of $0.5 million to new and existing directors and executive officers, offset by closed lines of credits and repayments of $25.6 million. As of December 31, 2013 and 2012, $40.5 million and $65.9 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms except that residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. Management believes these loans do not represent more than a normal risk of collection.
Allowance for loan losses. As discussed in Note 1, ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.
Segmentation. ASB segments its loan portfolio by three levels. In the first level, the loan portfolio is separated into homogeneous and non-homogeneous loan portfolios. Residential, consumer and credit scored business loans are considered homogeneous loans. These are loans that are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. Commercial loans and commercial real estate (CRE) loans are defined as non-homogeneous loans and ASB utilitizes a uniform ten-point risk rating system for evaluating the credit quality of the loans. These are loans where the underwriting criteria are not uniform and the risk rating classification is based upon considerations broader than just delinquency performance.
In the second level of segmentation, the loan portfolios are further stratified into individual products with common risk characteristics. For residential loans, the loan portfolio is segmented by loan categories and geographic location first within the State of Hawaii (Oahu vs. the neighbor islands) and second collectively outside of the state. The consumer loan portfolio is segmented into various secured and unsecured loan product types. The credit scored business loan portfolio is segmented by loans under lines of credit or term loans. For commercial loans, the portfolio is differentiated by separating Commercial & Industrial (C&I) loans, C&I National Lending loans and C&I loans guaranteed by Small Business Administration programs while CRE loans are grouped by owner-occupied loans, investor loans, construction loans, and vacant land loans.
For the third and last level of segmentation, loans are categorized into the regulatory asset quality classifications - Pass, Substandard, and Loss for homogeneous loans based primarily on delinquency status, and Pass (Risk Rating 1 to 6), Special Mention (Risk Rating 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) for non-homogeneous loans based on credit quality.
Specific allocation.
Residential real estate. All residential real estate loans that are 180 days delinquent, or where ASB has initiated foreclosure action or have been modified in a TDR are reviewed for impairment based on the fair value of the collateral, net of costs to sell. Generally, impairment amounts derived under this method are immediately charged off.
Consumer. The consumer loan portfolio specific allocation is determined based on delinquency; unsecured consumer loans are generally charged-off based on delinquency status varying from 120 to 180 days.
Commercial and CRE. A specific allocation is determined for impaired commercial and CRE loans. See further discussion in Note 1.
Pooled allocation.
Residential real estate and consumer. Pooled allocation for non-impaired residential real estate and consumer loans are determined using a historical loss rate analysis and qualitative factor considerations.
Commercial and CRE. Pooled allocation for pass, special mention, substandard, and doubtful grade commercial and CRE loans that share common risk characteristics and properties are determined using a historical loss rate analysis and qualitative factor considerations.
Qualitative adjustments. Qualitative adjustments to historical loss rates or other static sources may be necessary since these rates may not fully consider all losses inherent in the current portfolio (for example, risks in growing and/or unseasoned portfolios). To estimate the level of adjustments, management considers factors, including levels and trends in problem loans, the nature, volume and term of the loan portfolios, changes in lending policies and practices, changes in management and staffing, economic conditions, industry trends, and credit concentrations.
Unallocated allowance. ASB’s allowance incorporates an unallocated portion to cover risk factors and events that may have occurred as of the evaluation date that have not been reflected in the risk measures due to inherent limitations to the precision of the estimation process. These risk factors, in addition to micro- and macro- economic factors, past, current and anticipated events based on facts at the balance sheet date, and realistic courses of action that management expects to take, are assessed in determining the level of unallocated allowance.
The allowance for loan losses (balances and changes) and financing receivables were as follows:
Changes in the allowance for loan losses were as follows:
Credit quality. ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and industrial, commercial real estate and commercial construction loans.
A dual ten-point risk rating system is used to reflect the probability of default (borrower risk rating) and loss given default (transaction risk rating). The borrower risk rating addresses risk presented by the individual borrower and is based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors. Separately, the transaction risk rating addresses risk in the transaction and is a function of the type of collateral control exercised over the collateral, loan structure, guarantees, and other structural support or enhancements to the loan.
The numerical representation of the risk categories are:
Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.
The credit risk profile by internally assigned grade for loans was as follows:
The increase in commercial real estate and commercial construction loans graded special mention, substandard or doubtful was due to the downgrade of a small number of specific large commercial credits that are being closely monitored and managed. This risk migration reflects both adverse financial trends affecting those borrowers and improved risk rating accuracy of loans across all portfolios.
The credit risk profile based on payment activity for loans was as follows:
The credit risk profile based on nonaccrual loans and accruing loans 90 days or more past due was as follows:
The total carrying amount and the total unpaid principal balance of impaired loans was as follows:
Troubled debt restructurings. A loan modification is deemed to be a TDR when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.
ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period, and temporary deferral of principal payments. ASB generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally,
additional collateral and/or guaranties are obtained.
All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell, or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Loan modifications that occurred were as follows for the indicated periods:
Loans modified in TDRs that experienced a payment default of 90 days or more in 2013, 2012 and 2011, and for which the payment default occurred within one year of the modification, were as follows:
If loans modified in a TDR subsequently default, ASB evaluates the loan for further impairment. Based on its evaluation, adjustments may be made in the allocation of the allowance or partial charge-offs may be taken to further write-down the carrying value of the loan. Commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs totaled $0.3 million at December 31, 2013.
Deposit liabilities.
As of December 31, 2013 and 2012, certificate accounts of $100,000 or more totaled $102 million and $106 million, respectively.
The approximate amounts of term certificates outstanding as of December 31, 2013 with scheduled maturities for 2014 through 2018 were $244 million in 2014, $94 million in 2015, $46 million in 2016, $22 million in 2017, $16 million in 2018, and $5 million thereafter.
Interest expense on deposit liabilities by type of deposit was as follows:
Other borrowings.
Securities sold under agreements to repurchase. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the balance sheet. All such agreements are subject to master netting arrangements, which provide for a right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:
Callable quarterly at par until maturity in 2016.
The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts and segregated safekeeping accounts at the FHLB of Seattle. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.
Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:
Advances from Federal Home Loan Bank.
Callable quarterly at par until maturity in 2017.
ASB and the FHLB of Seattle are parties to an Advances, Security and Deposit Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB of Seattle makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB of Seattle’s credit policies, and makes certain warranties and representations to the FHLB of Seattle. Upon the occurrence of and during the continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Advances Agreement or other credit arrangements between the parties), the FHLB of Seattle may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB of Seattle are collateralized by loans and stock in the FHLB of Seattle. ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB of Seattle. ASB was in compliance with all Advances Agreement requirements as of December 31, 2013 and 2012.
Common stock equity. In 1988, HEI agreed with the OTS predecessor regulatory agency at the time, to contribute additional capital to ASB up to a maximum aggregate amount of approximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2013, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement has been reduced to approximately $28.3 million. As of December 31, 2013, ASB was in compliance with the minimum capital requirements under OCC regulations.
In 2013, ASB paid cash dividends of $40 million to HEI, compared to cash dividends of $45 million in 2012. The FRB and OCC approved the dividends.
Related-party transactions. HEI charged ASB $2.3 million, $1.9 million and $1.4 million for general management and administrative services in 2013, 2012 and 2011, respectively. The amounts charged by HEI for services performed by HEI employees to its subsidiaries are allocated primarily on the basis of time expended in providing such services.
Derivative Financial Instruments. ASB enters into interest rate lock commitments with borrowers, and forward commitments to sell loans or to-be-announced mortgage-backed securities to investors to hedge against the inherent interest rate and pricing risk associated with selling loans.
ASB enters into interest rate lock commitments (IRLCs) for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. IRLCs that relate to the origination of mortgage loans that will be held for sale are considered derivative financial instruments under applicable accounting guidance. Outstanding IRLCs expose ASB to the risk that the price of the mortgage loans underlying the commitments may decline due to increases in mortgage interest rates from inception of the rate lock to the funding of the loan. The IRLCs are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
ASB enters into forward commitments to hedge the interest rate risk for rate locked mortgage applications in process and closed mortgage loans held for sale. These commitments are primarily forward sales of to-be-announced mortgage backed securities. Generally, when mortgage loans are closed, the forward commitment is liquidated and replaced with a mandatory delivery forward sale of the mortgage to a secondary market investor. In some cases, a best-efforts forward sale agreement is utilized as the forward commitment. These commitments are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
Changes in the fair value of IRLCs and forward commitments subsequent to inception are based on changes in the fair value of the underlying loan resulting from the fulfillment of the commitment and changes in the probability that the loan will fund within the terms of the commitment, which is affected primarily by changes in interest rates and the passage of time.
The notional amount and fair value of ASB’s derivative financial instruments as of December 31, 2013 and 2012 were as follows:
The following table presents ASB’s derivative financial instruments, their fair values, and balance sheet location as of December 31, 2013 and 2012:
1 Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.
The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in the statements of income for the years ended December 31, 2013, 2012 and 2011.
There were no significant gains or losses on derivatives in 2012 or 2011.
Guarantees. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into a judgment and loss sharing agreement with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2012, a federal judge granted preliminary approval to a proposed settlement between merchants and Visa over credit card fees and in December 2013, a federal judge granted final approval to the settlement. Some merchants and trade organizations have filed a notice of appeal shortly after the approval was issued. As of December 31, 2013, ASB had accrued $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.
Federal Deposit Insurance Corporation restoration plan. In November 2009, the Board of Directors of the Federal Deposit Insurance Corporation (FDIC) approved a restoration plan that required banks to prepay, by December 30, 2009, their estimated quarterly, risk-based assessments for the fourth quarter of 2009, and for all of 2010, 2011 and 2012. For the fourth quarter of 2009 and all of 2010, the prepaid assessment rate was assessed according to a risk-based premium schedule adopted earlier in 2009. The prepaid assessment rate for 2011 and 2012 was the current assessment rate plus 3 basis points. The prepaid assessment was recorded as a prepaid asset as of December 30, 2009, and each quarter thereafter ASB recorded a charge to earnings for its regular quarterly assessment and offset the prepaid expense until the asset was exhausted. ASB’s prepaid assessment was approximately $24 million. For the year ended December 31, 2010, ASB’s assessment rate was 14 basis points of deposits, or $5.7 million.
In February 2011, the FDIC finalized rules to change its assessment base from total domestic deposits to average total assets minus average tangible equity, as required in the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-
Frank Act). Assessment rates were reduced to a range of 2.5 to 9 basis points on the new assessment base for financial institutions in the lowest risk category. Financial institutions in the highest risk category have assessment rates of 30 to 45 basis points. The new rate schedule was effective April 1, 2011. For the years ended December 31, 2013 and 2012, ASB’s FDIC insurance assessments were $2.9 million and $3.0 million, respectively. In June 2013, the FDIC returned the remaining amount of the prepaid assessment. The cash received was included in the change in other assets and liabilities on HEI’s consolidated statements of cash flows.
The FDIC may impose additional special assessments in the future if it is deemed necessary to ensure the Deposit Insurance Fund ratio does not decline to a level that is close to zero or that could otherwise undermine public confidence in federal deposit insurance.
Litigation. In March 2011, a purported class action lawsuit was filed in the First Circuit Court of the state of Hawaii by a customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. The lawsuit is still in its preliminary stage. ASB filed a motion to dismiss the lawsuit on the basis that as a bank chartered under federal law, ASB believes its business practices are governed by federal regulations established for federal savings banks and not by state law. In July 2011, the Circuit Court denied ASB’s motion and ASB appealed that decision. ASB’s appeal is currently pending before the Hawaii Supreme Court. The probable outcome and range of reasonably possible loss remains indeterminable at this time.
ASB is subject in the normal course of business to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial position. However, ASB cannot rule out the possibility that such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.
5 · Unconsolidated variable interest entities
HECO Capital Trust III. Trust III was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to Hawaiian Electric, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by Hawaiian Electric in the principal amount of $31.5 million and issued by Hawaii Electric Light and Maui Electric each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of the Utilities under an expense agreement and Hawaiian Electric’s obligations under its trust guarantee and its guarantee of the obligations of Hawaii Electric Light and Maui Electric under their respective debentures, are the sole assets of Trust III. Taken together, Hawaiian Electric’s obligations under the Hawaiian Electric debentures, the Hawaiian Electric indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in the aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. Trust III has at all times been an unconsolidated subsidiary of Hawaiian Electric. Since Hawaiian Electric, as the holder of 100% of the trust common securities, does not absorb the majority of the variability of Trust III, Hawaiian Electric is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheet as of December 31, 2013 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2013 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to Hawaiian Electric. So long as the 2004 Trust Preferred Securities are outstanding, Hawaiian Electric is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by Hawaiian Electric in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event any of the Utilities elect to defer payment of interest on any of their respective 2004 Debentures, then Hawaiian Electric will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.
Power purchase agreements. As of December 31, 2013, the Utilities had six PPAs for firm capacity and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kilowatts (kWs) or less who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of the firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs were as follows:
Some of the IPPs provided sufficient information for Hawaiian Electric to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. Other IPPs, including the three largest, declined to provide the information necessary for Hawaiian Electric to determine the applicability of accounting standards for VIEs.
Since 2004, Hawaiian Electric has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2013, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.
If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs.
Kalaeloa Partners, L.P. In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that Hawaiian Electric makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.
Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in Kalaeloa by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, Hawaiian Electric has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses Hawaiian Electric could potentially absorb is the fact that Hawaiian Electric’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although Hawaiian Electric absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose Hawaiian Electric to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through Hawaiian Electric’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of December 31, 2013, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $23 million.
6 · Interest rate swap agreements
In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. The FSS entitled HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to the notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges. Changes in fair value were recognized (1) in other comprehensive income to the extent that they were considered effective, and (2) in “Interest expense-other than on deposit liabilities and other bank borrowings” for any portion considered ineffective.
In 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 million was the ineffective portion ($2.5 million recognized in 2011) and $1.9 million being amortized to interest expense over 5 years beginning March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a private placement).
7 · Short-term borrowings
As of December 31, 2013 and 2012, HEI had $105 million and $84 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.7% and 0.9%, respectively, and Hawaiian Electric had no commercial paper outstanding.
As of December 31, 2013, HEI and Hawaiian Electric each maintained a syndicated credit facility of $125 million and $175 million, respectively. HEI borrowed under its facility in August 2012 and repaid such borrowings in the same month. HEI had no borrowings under its facility during 2013 and Hawaiian Electric had no borrowings under its facility during 2013 and 2012. None of the facilities are collateralized.
Credit agreements.
HEI. Effective December 5, 2011, HEI and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HEI’s $125 million line of credit facility (with a letter of credit sub-facility) and extended the term of the facility to December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 basis points; or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement contains customary conditions which must be met in order to draw on it, including compliance with its 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, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its 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 December 31, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.8 billion as of December 31, 2013, as calculated under the agreement), or if HEI no longer owns Hawaiian Electric.
The facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.
Hawaiian Electric. Effective December 5, 2011, Hawaiian Electric and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of Hawaiian Electric’s $175 million line of credit facility (with a letter of credit sub-facility). The credit agreement, as amended, has a term which expires on December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 basis points; or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement contains customary conditions that must be met in order to draw on the credit facility, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to
guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for Hawaii Electric Light and 43% for Maui Electric as of December 31, 2013, as calculated under the agreement)). In addition to customary defaults, Hawaiian Electric’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if Hawaiian Electric fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 56% as of December 31, 2013, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.
The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay Hawaiian Electric’s short-term indebtedness, to make loans to subsidiaries and for Hawaiian Electric’s capital expenditures, working capital and general corporate purposes.
See components of "Total long-term debt" and unamortized discount in Hawaiian Electric and subsidiaries' Consolidated Statements of Capitalization.
As of December 31, 2013, the aggregate principal payments required on the Company's long-term debt for 2014 through 2018 are $111 million in 2014, nil in 2015, $75 million in 2016, nil in 2017 and $50 million in 2018. As of December 31, 2013, the aggregate payments of principal required on the Utilities' long-term debt for 2014 through 2018 are $11 million in 2014, nil in 2015, 2016 and 2017, and $50 million in 2018.
The HEI medium-term notes and 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). The HEI senior notes also contain provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement, expiring on December 5, 2016. Upon a change of control or certain dispositions of assets (as defined in the Master Note Purchase Agreement dated March 24, 2011), HEI is required to offer to prepay the senior notes.
The Utilities' senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by Hawaiian Electric, and each of Hawaii Electric Light and Maui Electric, of certain financial ratios generally consistent with those in Hawaiian Electric’s existing amended revolving noncollateralized credit agreement, expiring on December 5, 2016.
March 6, 2013 senior notes. On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011. Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement. The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.
October 3, 2013 senior notes. On October 3, 2013, Hawaiian Electric, Hawaii Electric Light and Maui Electric each entered into its separate note purchase agreement with various purchasers of their taxable unsecured senior notes (Notes) with an aggregate principal amount of $236 million. The Utilities issued through a private placement the following notes:
Proceeds were used in October 2013 to redeem the following special purpose revenue bonds (SPRBs) and refunding SPRBs of the same maturities issued by the Department of Budget and Finance of the State of Hawaii for the benefit of the Utilities in an aggregate principal amount of $166 million:
Proceeds were used by the respective utility to finance their capital expenditures and/or for the reimbursement of funds used for the payment of capital expenditures.
Hawaiian Electric has guaranteed the obligations of Hawaii Electric Light and Maui Electric under their respective Notes.
9 · Shareholders’ equity
Reserved shares. As of December 31, 2013, HEI had reserved (a) a total of 16,231,674 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP), the 1987 Stock Option and Incentive Plan, the HEI 2011 Nonemployee Director Stock Plan, the ASB 401(k) Plan and the 2010 Executive Incentive Plan and (b) a total of 5.7 million shares of common stock for future issuance in connection with the equity forward transaction described below.
Equity forward transaction. On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering on that date of 6.1 million shares of HEI common stock at $26.75 per share. On March 19, 2013, HEI common stock closed at $27.01 per share. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with the resulting additional 0.9 million shares of HEI common stock.
The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans. Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of the equity forward transactions, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. The equity forward transactions must be settled fully by March 25, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 25, 2015.
The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI receives proceeds from the sale of common stock when the equity forward transactions are settled and records the proceeds at that time in equity. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC 480, "Distinguishing Liabilities from Equity," and ASC 815, "Derivatives and Hedging," and that they qualified for an exception from derivative accounting under ASC 815 because the forward sale transactions were indexed to its own stock. On December 19, 2013, HEI settled 1.3 million shares under the equity forward for proceeds of $32.1 million (net of the underwriting discount of $1.3 million), which funds were ultimately used to purchase Hawaiian Electric shares. HEI anticipates settling the remaining 5.7 million shares remaining under the equity forward transactions through physical settlement.
At December 31, 2013, the 5.7 million shares remaining under the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $141 million. At December 31, 2013, the shares remaining under the equity forward transactions could also have been cash settled, with delivery of cash of approximately $5 million (which amount includes $6 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 188,000 shares of common stock to the forward counterparty.
Prior to their settlement, the shares remaining under the equity forward transactions will be reflected in HEI’s diluted EPS calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted EPS for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.
Accordingly, before physical or net share settlement of the equity forward transactions, and subject to the occurrence of certain events, HEI anticipates that the forward sale agreement and additional forward sale agreement will have a dilutive effect on HEI’s EPS only during periods when the applicable average market price per share of HEI’s common stock is above the per share adjusted forward sale price, as described above. However, if HEI decides to physically or net share settle the forward sale agreement and additional forward sale agreement, any delivery by HEI of shares upon settlement could result in dilution to HEI’s EPS.
For 2013, the equity forward transactions did not have a material dilutive effect on HEI’s EPS.
Accumulated other comprehensive income/(loss). Reclassifications out of AOCI were as follows:
Defined benefit plans. Substantially all of the employees of HEI and the Utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI Pension Plan). Substantially all of the employees of ASB and its subsidiaries participated in the American Savings Bank Retirement Plan (ASB Pension Plan) until it was frozen on December 31, 2007. The HEI Pension Plan and the ASB Pension Plan (collectively, the Plans) are qualified, noncontributory defined benefit pension plans and include, in the case of the HEI Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the Utilities and the union. The Plans are subject to the provisions of ERISA. In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.
The continuation of the Plans and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The ASB Pension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontributory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.
Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.
To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified under “Defined benefit pension and other postretirement benefit plans information” below.
Postretirement benefits other than pensions. HEI and the Utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (Hawaiian Electric Benefits Plan). Eligibility of employees and dependents are based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.
The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees and retirees of Hawaiian Electric in August 2009, Hawaii Electric Light in November 2010, and Maui Electric in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargaining agreement.
The Company’s and Utilities' cost for OPEB has been adjusted to reflect the plan amendments, which reduced benefits. The elimination of the electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized. Each participating employer reserves the right to terminate its participation in the Hawaiian Electric Benefits Plan at any time.
Balance sheet recognition of the funded status of retirement plans. Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO), to calculate the funded status).
The PUC allowed the Utilities to adopt pension and OPEB tracking mechanisms in previous rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the Utilities’ tracking mechanisms, any actual costs determined in accordance with GAAP that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit
expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.2 million in 2013 and $1.6 million in 2012) determined in accordance with GAAP will be recovered.
Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The Utilities have reclassified to a regulatory asset/(liability) charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge to AOCI of $(364) million pretax and $124 million pretax for 2013 and 2012, respectively).
In 2007, the PUC allowed Hawaii Electric Light to record a regulatory asset in the amount of $12.8 million (representing Hawaii Electric Light’s prepaid pension asset and reflecting the accumulated pension contributions to its pension fund in excess of accumulated NPPC), which is included in rate base, and allowed recovery of that asset over a period of five years. Hawaii Electric Light is required to make contributions to the pension trust in the amount of the actuarially calculated NPPC that would be allowed without penalty by the tax laws.
In 2007, the PUC declined to allow Hawaiian Electric and Maui Electric to include their pension assets (representing the accumulated contributions to their pension fund in excess of accumulated NPPC), in their rate bases. However, under the tracking mechanisms, Hawaiian Electric and Maui Electric are required to fund only the minimum level required under the law until their pension assets are reduced to zero, at which time Hawaiian Electric and Maui Electric will make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.
The PUC’s exclusion of Hawaiian Electric’s and Maui Electric’s pension assets from rate base does not allow Hawaiian Electric and Maui Electric to earn a return on the pension asset, but this exclusion does not result in the exclusion of any pension benefit costs from their rates. The pension asset is to be (and has been, in the case of Maui Electric) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2013, Hawaiian Electric’s pension asset had been reduced to nil.
The OPEB tracking mechanisms generally require the Utilities to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.
Retirement benefits expense for the Utilities for 2013, 2012 and 2011 was $30 million, $32 million and $34 million, respectively.
Retirement benefit plan changes. On March 11, 2011, the Utilities’ bargaining unit employees ratified a new benefit agreement, which included changes to retirement benefits. Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) (with a lower payment formula than the formula in the plan for employees hired before May 1, 2011) and the addition of a 50% match by the applicable employer on the first 6% of employee elective deferrals by such employees through the defined contribution plan (under the HEIRSP). In addition, new eligibility rules and contribution levels applicable to existing and new HEI and utility employees were adopted for postretirement welfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.
Defined benefit pension and other postretirement benefit plans information. The changes in the obligations and assets of the Company’s and Utilities' retirement benefit plans and the changes in AOCI (gross) for 2013 and 2012 and the funded status of these plans and amounts related to these plans reflected in the Company’s and Utilities' consolidated balance sheet as of December 31, 2013 and 2012 were as follows:
The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2013, 2012 and 2011.
On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply MAP-21 for 2012, which improved the plans’ Adjusted Funding Target Attainment Percentage for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HEI and the Utilities. MAP-21 caused the minimum required funding under ERISA to be less than the net periodic cost for 2013 and is expected to have the same effect in 2014; therefore, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities expect to contribute the net periodic cost in 2014.
The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. However, the
HEI Retirement Plan met the threshold requirements in each of 2012 and 2013 so that the more conservative assumptions do not apply for either the 2013 or 2014 valuation of plan liabilities for purposes of calculating the minimum required contribution. Other factors could cause changes to the required contribution levels.
The Company and the Utilities have determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years - 0% in the first year and 25% in each of years two through five - and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual NPBC.
A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.
The weighted-average asset allocation of defined benefit retirement plans was as follows:
See Note 16 for additional disclosures about the fair value of the retirement benefit plans’ assets.
The following weighted-average assumptions were used in the accounting for the plans:
NA Not applicable
The Company and the Utilities based their selection of an assumed discount rate for 2014 NPBC and December 31, 2013 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2013. In selecting the expected rate of return on plan assets of 7.75% for 2014 NPBC, the Company and the Utilities considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets.
As of December 31, 2013, the assumed health care trend rates for 2014 and future years were as follows: medical, 7.5%, grading down to 5% for 2024 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2012, the assumed health care trend rates for 2013 and future years were as follows: medical, 8.0%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. Medicare Advantage reimbursements are expected to phase out by 2016; therefore, post age 65 medical trends are adjusted to reflect anticipated increases above the ordinary medical trend rates. For post age 65, the medical trend is 4% higher than pre-65 for 2013 through 2014 and 3% higher in 2015.
The components of NPBC were as follows:
The estimated prior service credit, net actuarial loss and net transition obligation for defined benefit plans that will be amortized from AOCI or regulatory assets into net periodic benefit cost during 2014 is as follows:
The Company recorded pension expense of $34 million, $35 million and $32 million and OPEB expense of $0.4 million, $1 million and $4 million in 2013, 2012 and 2011, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $30 million, $32 million and $31 million and OPEB expense of nil, $0.4 million and $3 million in 2013, 2012 and 2011, respectively, and charged the remaining amounts primarily to electric utility plant.
The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2013, for the Company, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the accumulated postretirement benefit obligation (APBO) by $4.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $4.9 million. As of December 31, 2013, for the Utilities, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the APBO by $4.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $4.8 million.
HEI consolidated. The defined benefit pension plans with accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), in excess of plan assets as of December 31, 2013 and 2012, had aggregate ABOs of $1.2 billion and $1.4 billion, respectively, and plan assets of $1.1 billion and $1.0 billion, respectively. The defined benefit pension plans with PBOs in excess of plan assets as of December 31, 2013, had aggregate PBOs of $1.4 billion and plan assets of $1.1 billion. As of December 31, 2012, all the defined benefit pension plans shown in the table above had PBOs in excess of plan assets. The other postretirement benefit plans with ABOs in excess of plan assets as of December 31, 2013 had aggregate ABOs of $0.4 million and plan assets of nil. As of December 31, 2012, all the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets.
The Company estimates that the cash funding for the qualified defined benefit pension plans in 2014 will be $59 million, which should fully satisfy the minimum required contributions to those plans, including requirements of the Utilities’ pension tracking mechanisms and the Plan’s funding policy. The Company's current estimate of contributions to its other postretirement benefit plans in 2014 is de minimis.
As of December 31, 2013, the benefits expected to be paid under all retirement benefit plans in 2014, 2015, 2016, 2017, 2018 and 2019 through 2023 amounted to $72 million, $75 million, $78 million, $81 million, $85 million and $483 million, respectively.
Hawaiian Electric consolidated. The defined benefit pension plans with ABOs in excess of plan assets as of December 31, 2013 and 2012, had aggregate ABOs of $1.2 billion and $1.2 billion, respectively, and plan assets of $1.1 billion and $0.9 billion, respectively. All the defined benefit pension plans shown in the table above had PBOs in excess of plan assets as of December 31, 2013 and 2012. As of December 31, 2013, the other postretirement benefit plan shown in the table above had plan assets in excess of ABO. As of December 31, 2012, the other postretirement benefit plan shown in the table above had an ABO in excess of plan assets.
The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2014 will be $58 million, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanisms and the Plan’s funding policy. The Utilities' current estimate of contributions to its other postretirement benefit plans in 2014 is nil.
As of December 31, 2013, the benefits expected to be paid under all retirement benefit plans in 2014, 2015, 2016, 2017, 2018 and 2019 through 2023 amounted to $67 million, $69 million, $72 million, $75 million, $77 million and $441 million, respectively.
Defined contribution plans information. The ASB 401(k) Plan is a defined contribution plan, which includes a discretionary employer profit sharing contribution by ASB (AmeriShare) and a matching contribution by ASB on the first 4% of employee deferrals (AmeriMatch).
Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan).
For 2013, 2012 and 2011, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $5 million, $4 million and $3 million, respectively, and cash contributions were $4 million for each year. The Utilities’ expense for its defined contribution pension plan under the HEIRSP Plan for 2013 was $0.6 million and for 2012 and 2011 was de minimis.
Under the 2010 Equity and Incentive Plan (EIP) HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards.
As of December 31, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.2 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).
Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), there are possible future issuances of an estimated 2,000 shares upon exercise of outstanding stock appreciation rights (SARs) and dividend equivalents based on the market price of shares on December 31, 2013. As of May 11, 2010 (when the EIP became effective), no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.
For the SARs outstanding under the SOIP, the exercise price of each SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. SARs and related dividend equivalents issued in the form of stock awards generally became exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.
The restricted shares that have been issued under the EIP become unrestricted in four equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become unrestricted for terminations of employment during the vesting period, except accelerated vesting is provided for terminations by reason of death, disability and termination without cause. Restricted shares compensation expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares are paid quarterly in cash.
Restricted stock units awarded under the EIP in 2013, 2012 and 2011 will vest and be issued in unrestricted stock in four equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become vested for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units awarded under the SOIP and EIP in 2010 and prior years generally vest and will be issued as unrestricted stock four years after the date of the grant and are forfeited for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid at the end of the restriction period when the associated restricted stock units vest.
Stock performance awards granted under the 2011-2013, 2012-2014 and 2013-2015 LTIPs entitle the grantee to shares of common stock with dividend equivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.
Under the 2011 Nonemployee Director Stock Plan (2011 Director Plan), HEI can issue shares of common stock as compensation to nonemployee directors of HEI, Hawaiian Electric and ASB. As of December 31, 2013, there were 202,460 shares remaining available for future issuance under the 2011 Director Plan.
The Company’s share-based compensation expense and related income tax benefit were as follows:
The Company has not capitalized any share-based compensation cost.
The Company has revised its prior year disclosure to correct for an error that excluded from the disclosure amounts for stock awards to non-employee directors of HEI, Hawaiian Electric and ASB. The amounts excluded from the disclosure were not considered to be material to previously issued financial statements. The table below illustrates the effects of this revision on the previous disclosure (the revised disclosure had no impact on the Company’s Consolidated Balance Sheets, Consolidated Statements of Income or Consolidated Statements of Cash Flows):
Stock awards. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:
The number of shares issued to each nonemployee director of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI Common Stock on grant date.
Nonqualified stock options. Information about HEI’s NQSOs was as follows:
(1)
Weighted-average exercise price
As of December 31, 2013, there were no NQSOs outstanding.
NQSO activity and statistics were as follows:
Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.
Stock appreciation rights. Information about HEI’s SARs is summarized as follows:
(1)
Weighted-average exercise price
As of December 31, 2013, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.1 million.
SARs activity and statistics were as follows:
Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the right.
Restricted shares and restricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards was as follows:
(1)
Weighted-average grant-date fair value per share based on the closing or average price of HEI common stock on the date of grant.
For 2013, 2012 and 2011, total restricted stock vested had a grant-date fair value of $0.1 million, $0.9 million and $1.0 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were nil for 2013, $0.2 million for 2012 and $0.2 million for 2011.
As of December 31, 2013, there was $0.1 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 0.9 years.
Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:
(1)
Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $2.4 million and $0.7 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.
As of December 31, 2013, there was $3.7 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.5 years.
LTIP payable in stock. The 2011-2013 LTIP, 2012-2014 LTIP and 2013-2015 LTIP provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2011-2013 LTIP, 2012-2014 LTIP and 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated net income, Hawaiian Electric consolidated ROACE, ASB net income and ASB return on assets - all based on the applicable three-year averages.
LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS was as follows:
(1)
Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period.
The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:
For 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively. Of the 87,753 shares vested and granted (at target level based on the satisfaction of TRS performance) for the 2010-2012 LTIP, the HEI Compensation Committee approved settlement of 70,205 shares of HEI common stock in February 2013 (17,548 of the vested shares lapsed).
As of December 31, 2013, there was $2.4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.5 years.
LTIP awards linked to other performance conditions. Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:
(1)
Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
For 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.
As of December 31, 2013, there was $3.1 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.5 years.
The components of income taxes attributable to net income for common stock were as follows:
A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the consolidated statements of income was as follows:
The Company’s and the Utilities' effective tax rate decreased in 2013 compared to 2012 primarily due to $3.5 million lower deferred taxes related to the tax gross-up of AFUDC-equity and a $3.1 million (including $2.7 million related to the Utilities) out-of-period income tax benefit (see “Out-of-period income tax benefit”). The Company's effective tax rate increased slightly from 2011 to 2012 due primarily to lower utility tax credit amortization and its lower relative impact on higher operating income in 2012, and tax-free bank-owned life insurance proceeds received in 2011.
The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company and the Utilities will realize substantially all of the benefits of the deferred tax assets. As of December 31, 2013, the valuation allowance for deferred tax benefits is not significant. In 2013, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation (resulting from the American Taxpayer Relief Act of 2012). The Utilities are included in the consolidated federal and Hawaii income tax returns of HEI and are subject to the provisions of HEI’s tax sharing agreement, which determines each subsidiary’s (or subgroup) income tax return liabilities and refunds on a standalone basis as if it filed a separate return (or subgroup consolidated return). Consequently, although HEI consolidated does not expect any unutilized net operating loss (NOL) as of December 31, 2013, standalone Hawaiian Electric consolidated expects a $55 million (pretax) NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The deferred tax asset associated with this NOL is included in “Prepayments and other.”
HEI consolidated. In 2013, 2012 and 2011, credit adjustments to interest expense on income taxes was reflected in “Interest expense - other than on deposit liabilities and other bank borrowings” in the amount of $0.3 million, $1.4 million and $1.2 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the Internal Revenue Service (IRS). As of December 31, 2013 and 2012, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was $0.4 million and $0.3 million, respectively.
As of December 31, 2013, the total amount of liability for uncertain tax positions was $0.9 million and, of this amount, $0.7 million, if recognized, would affect the Company’s effective tax rate. The Company’s unrecognized tax benefits are primarily the result of differences relating to the tax basis of property and equipment.
Hawaiian Electric consolidated. In 2013, 2012 and 2011, credit adjustments to interest expense on income taxes was reflected in “Interest and other charges” in the amount of $0.3 million, $0.5 million and $1.0 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2013 and 2012, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and preferred dividends payable” was de minimis.
As of December 31, 2013, the total amount of liability for uncertain tax positions was $0.5 million and, if recognized, would affect the Utilities' effective tax rate. The Utilities' unrecognized tax benefits are primarily the result of differences relating to the tax basis of property and equipment.
The changes in total unrecognized tax benefits were as follows:
The 2012 reduction in unrecognized tax benefits was primarily due to the IRS’s acceptance of the deductibility of costs of repairs to utility generation property for tax years 2007-2009. The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance (Revenue Procedure 2011-43, issued in August 2011) on the deductibility of costs of repairs to utility transmission and distribution (T&D) property, including a “safe harbor” method under which taxpayers could transition and minimize the uncertainty of the repairs expense deduction for T&D property. The Company elected the “safe harbor” method in its 2011 tax return, which resulted in the reduction of associated unrecognized tax benefits for 2011.
The IRS is currently auditing tax years 2010 and 2011. Tax years 2007 to 2012 remain subject to examination by the Department of Taxation of the State of Hawaii.
As of December 31, 2013, the disclosures above present the Company’s and the Utilities' accruals for potential tax liabilities and related interest. Based on information currently available, the Company and the Utilities believe these accruals have adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.
Out-of-period income tax benefit. During 2013, the Company recorded a $3.1 million (including $2.7 million related to the Utilities) out-of-period income tax benefit, resulting primarily from the reversal of deferred tax liabilities due to errors in the amount of book over tax basis differences in plant and equipment. Management concluded that this out-of-period adjustment was not material to either the current or any prior period financial statements.
Recent tax developments. In September 2013, the IRS issued final regulations addressing the acquisition, production and improvement of tangible property, which are effective January 1, 2014. Management is currently evaluating the impact of these new regulations, but does not expect a material impact on the Utilities since specific guidance on network (i.e., transmission and distribution) assets and generation property has already been received. The IRS also proposed regulations addressing the disposition of property.
The Utilities adopted the safe harbor guidelines with respect to network assets in 2011 and in June 2013, the IRS released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. Management continues to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when an election should be made.
The amounts shown represents common stock dividends reinvested in HEI common stock under the HEI DRIP in noncash transactions.
As of December 31, 2013, the Utilities could not transfer approximately $674 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.
ASB is required to notify the FRB and OCC prior to making any capital distribution (including dividends) to HEI (through ASHI). Generally, the FRB and OCC may disapprove or deny ASB’s request to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation, or agreement between ASB and the OCC. As of December 31, 2013, ASB could transfer approximately $91 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.
HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.
15 · Significant group concentrations of credit risk
Most of the Company’s business activity is with customers located in the State of Hawaii.
The Utilities are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. The Utilities provide the only electric public utility service on the islands they serve. The Utilities grant credit to customers, all of whom reside or conduct business in the State of Hawaii.
Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment and mortgage-related securities it owns. Substantially all real estate loans receivable are collateralized by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination.
Fair value estimates are estimates of the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company and the Utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company or the Utilities were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s and the Utilities' financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
The Company and the Utilities group their financial assets measured at fair value in three levels outlined as follows:
Level 1:
Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used to measure fair value whenever available.
Level 2:
Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.
Level 3:
Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
The Company and/or the Utilities used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:
Short-term borrowings-other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.
Investment and mortgage-related securities. To determine the fair value of investment securities held in ASB’s available-for-sale portfolio, independent third-party vendor or broker pricing is used on an unadjusted basis. Prices for investments and mortgage-related securities are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA (to be announced) prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.
Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.
Loans receivable. The estimated fair value of loans receivable is determined based on characteristics such as loan category, repricing features and remaining maturity, and includes prepayment estimates.
For residential real estate loans, fair values were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics and remaining maturity.
For other types of loans, fair values were estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.
The fair value of all loans was adjusted to reflect current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below.
Deposit liabilities. The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.
Other bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.
Long-term debt. Fair value was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities and from discounting the future cash flows using the current rates offered for debt of the same or similar remaining maturities.
Derivative financial instruments. See “Fair value measurements on a recurring basis” below.
Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements.
The estimated fair values of certain of the Company’s and the Utilities' financial instruments were as follows:
As of December 31, 2013 and 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $0.2 million and $1.2 million, respectively. As of December 31, 2013 and 2012, loans serviced by ASB for others had notional amounts of $1.4 billion and $1.3 billion, respectively, and the estimated fair value of the servicing rights for such loans was $15.7 million and $11.9 million, respectively.
Fair value measurements on a recurring basis.
Securities. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on
market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.
Derivative financial instruments. ASB enters into interest rate lock commitments (IRLC) for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.
ASB utilizes forward commitments as economic hedges against potential changes in the values of the IRLCs and loans held for sale. To reduce the impact of price fluctuations of IRLC and mortgage loans held for sale, ASB will purchase to be announced (TBA) mortgage-backed securities forward commitments, mandatory and best effort commitments. These commitments help protect ASB's loan sale profit margin from fluctuations in interest rates. The changes in the fair value of these commitments are recognized as part of mortgage banking income on the consolidated statements of income. TBA forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined similarly to the IRLCs using quoted prices in the market place that are observable and are classified as Level 2 measurements.
Assets and liabilities measured at fair value on a recurring basis were as follows:
Derivatives are carried at fair value with changes in value reflected in the balance sheet in other assets or other liabilities and included in mortgage banking income.
Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. See “Goodwill and other intangibles” in Note 1 for ASB’s goodwill valuation methodology. During 2013 and 2012, goodwill was not measured at fair value.
From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of Hawaiian Electric’s ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by Hawaiian Electric’s credit spread (also see Note 3).
Assets measured at fair value on a nonrecurring basis were as follows:
For 2013 and 2012, there were no adjustments to fair value for ASB’s loans held for sale.
Residential loans. The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
Home equity lines of credit. The fair value of ASB’s home equity lines of credit that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
Commercial loans. The fair value of ASB’s commercial loans that were written down due to impairment was determined based on the value placed on the assets of the business, and therefore, is classified as a Level 3 measurement.
Real estate acquired in settlement of loans. The fair value of ASB’s real estate acquired in settlement of loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
For loans and real estate acquired in settlement of loans classified as Level 3 as of December 31, 2013, the significant unobservable inputs used in the fair value measurement were as follows:
Represent percent of outstanding principal balance.
Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurements.
Retirement benefit plans
Assets held in various trusts for the retirement benefit plans are measured at fair value on a recurring basis and were as follows:
The fair values of the financial instruments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability. Those judgments are developed by the Company based on the best information available in the circumstances.
In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.
The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2013 and 2012.
Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds (Level 1). Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds are valued at the closing price reported on the active market on which the individual securities or funds are traded.
Fixed income securities and pooled and mutual funds and other (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings. Pooled and mutual funds include commingled equity funds and other closed funds, respectively, that are not open to public investment and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses, using observable inputs.
Other (Level 3). Venture capital interest is valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.
For 2013 and 2012, the changes in Level 3 assets were as follows:
Selected quarterly information was as follows:
Note: HEI owns all of Hawaiian Electric's common stock, therefore per share data for Hawaiian Electric is not meaningful.
The quarterly basic earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.
The quarterly diluted earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.
Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.
In the fourth quarter of 2012, as part of a settlement agreement with the Consumer Advocate, the Utilities recorded a writedown of $24 million (net of taxes) of CIS project costs in lieu of conducting regulatory audits of the CIP CT-1 and CIS projects
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
HEI and Hawaiian Electric: None
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
HEI:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of December 31, 2013. Based on their evaluations, as of December 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:
(1)
is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and
(2)
is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Annual Report of Management on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2013.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 77.
Changes in Internal Control over Financial Reporting
There have been no changes in internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Hawaiian Electric:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Richard M. Rosenblum, Hawaiian Electric Chief Executive Officer, and Tayne S. Y. Sekimura, Hawaiian Electric Chief Financial Officer, have evaluated the disclosure controls and procedures of Hawaiian Electric as of December 31, 2013. Based on their evaluations, as of December 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by Hawaiian Electric in reports Hawaiian Electric files or submits under the Securities Exchange Act of 1934:
(1)
is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and
(2)
is accumulated and communicated to Hawaiian Electric management, including Hawaiian Electric’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Annual Report of Management on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Hawaiian Electric’s internal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of Hawaiian Electric’s internal control over financial reporting as of December 31, 2013 based on on criteria established in Internal Control - Integrated Framework (1992) issued by COSO. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2013.
Changes in Internal Control over Financial Reporting
There have been no changes in internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
HEI and Hawaiian Electric: None
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
HEI:
Information regarding HEI’s executive officers is provided in the “Executive Officers of the Registrant” section following Item 4 of this report.
The remaining information required by this Item 10 for HEI is incorporated herein by reference to the following sections in the HEI 2014 Proxy Statement:
•
“Nominees for Class III directors whose terms expire at the 2017 Annual Meeting”
•
“Continuing Class I directors whose terms expire at the 2015 Annual Meeting”
•
“Continuing Class II directors whose terms expire at the 2016 Annual Meeting”
•
“Committees of the Board” (portions regarding whether HEI has an audit committee and identifying its members; no other portion of the Committees of the Board section is incorporated herein by reference)
•
“Audit Committee Report” (portion identifying audit committee financial experts who serve on the HEI Audit Committee only; no other portion of the Audit Committee Report is incorporated herein by reference)
Family relationships; director arrangements
There are no family relationships between any HEI director or director nominee and any other HEI director or director nominee or any HEI executive officer. There are no arrangements or understandings between any HEI director or director nominee and any other person pursuant to which such director or director nominee was selected.
Code of Conduct
The HEI Board has adopted a Corporate Code of Conduct that includes a code of ethics applicable to, among others, its principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is available on HEI’s website at www.hei.com. HEI elects to disclose the information required by Form 8-K, Item 5.05, “Amendments to the Registrant’s Code of Ethics, or Waiver of a Provision of the Code of Ethics,” through this website and such information will remain available on this website for at least a 12-month period.
Section 16(a) beneficial ownership reporting compliance
Information required to be reported under this caption is incorporated herein by reference to the “Stock Ownership Information-Section 16(a) Beneficial Ownership Reporting Compliance” section in the HEI 2014 Proxy Statement.
Hawaiian Electric:
The information required by this Item 10 for Hawaiian Electric is incorporated herein by reference to pages 1 to 7 of Hawaiian Electric Exhibit 99.1.
HEI:
The information required by this Item 11
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
HEI:
Security Ownership of Certain Beneficial Owners
The information required by this Item 12 for HEI is incorporated herein by reference to the “Stock Ownership Information-Security Ownership of Certain Beneficial Owners” section in the HEI 2014 Proxy Statement.
Equity compensation plan information
Information as of December 31, 2013 about HEI Common Stock that may be issued under all of the Company’s equity compensation plans was as follows:
(1)This column includes the number of shares of HEI Common Stock which may be issued under the HEI 2010 Equity Incentive Plan (EIP) and the 1987 Stock Option and Incentive Plan (SOIP) on account of awards outstanding as of December 31, 2013, including:
*
Under the EIP as of December 31, 2013, RSUs count against the shares authorized for issuance as four shares for every share issued. Accordingly, the 313,206 RSU shares in the table are counted as 1,252,824 shares in determining the 1,581,169 shares available for future issuance under the EIP.
(2)
The weighted average exercise price in this column relates to the outstanding 62,000 stock appreciation rights which were granted in 2004. Excluded from the weighted average exercise price calculation are 102,000 stock appreciation rights whose exercise price was greater than the share price on December 31, 2013 and shares that may be issued without the payment of additional consideration (including the LTIP and restricted stock unit awards).
(3)
This represents the number of shares available as of December 31, 2013 for future awards, including 1,378,709 shares available for future awards under the EIP and 202,460 shares available for future awards under the 2011 Nonemployee Director Plan. As of May 11, 2010, no new awards may be granted under the SOIP.
Hawaiian Electric:
The information required by this Item 12 for Hawaiian Electric is incorporated herein by reference to pages 34 to 35 of Hawaiian Electric Exhibit 99.1.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
HEI:
The information required by this Item 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in the HEI 2014 Proxy Statement.
Hawaiian Electric:
The information required by this Item 13 for Hawaiian Electric is incorporated herein by reference to pages 35 to 36 of Hawaiian Electric Exhibit 99.1.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
HEI:
The information required by this Item 14 for HEI is incorporated herein by reference to the relevant information in the Audit Committee Report in the HEI 2014 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated herein by reference).
Hawaiian Electric:
The information required by this Item 14 for Hawaiian Electric is incorporated herein by reference to page 37 of Hawaiian Electric Exhibit 99.1.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial statements
See Item 8 for the financial statements of HEI and Hawaiian Electric.
(a)(2) and (c) Financial statement schedules
The following financial statement schedules for HEI and Hawaiian Electric are included in this report on the pages indicated below:
Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the Consolidated Financial Statements.
Hawaiian Electric Industries, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED BALANCE SHEETS
The aggregate payments of principal required subsequent to December 31, 2013 on long-term debt are $100 million in 2014, nil in 2015, $75 million in 2016 and nil in 2017 and 2018.
As of December 31, 2013, HEI has a General Agreement of Indemnity in favor of both Liberty Mutual Insurance Company (Liberty) and Travelers Casualty and Surety Company of America (Travelers) for losses in connection with any and all bonds, undertakings or instruments of guarantee and any renewals or extensions thereof executed by Liberty or Travelers, including, but not limited to, a $0.2 million self-insured United States Longshore & Harbor bond and a $0.5 million self-insured automobile bond.
Hawaiian Electric Industries, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
The Company’s financial reporting policy for income tax allocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
STATEMENTS OF COMPREHENSIVE INCOME
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Incorporated by reference are HEI and Subsidiaries’ Statements of Consolidated Comprehensive Income and Consolidated Statements of Changes in Shareholders’ Equity in Part II, Item 8.
Hawaiian Electric Industries, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)
HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
Supplemental disclosures of noncash activities:
In 2013, 2012 and 2011, $2.3 million, $1.8 million and $1.3 million, respectively, of HEI accounts receivable from ASHI were reduced with a corresponding reduction in HEI notes payable to ASHI in noncash transactions.
In 2013, 2012 and 2011, $2.5 million, $2.5 million and $2.0 million, respectively, were contributed as equity by HEI into ASHI with a corresponding increase in HEI notes payable to ASHI in noncash transactions.
Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $24 million, $24 million and $12 million in 2013, 2012 and 2011, respectively. HEI satisfied the requirements of the HEI DRIP, Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and ASB 401(k) Plan (from August 18, 2011 through January 8, 2012) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares.
Note:
The “Notes to Consolidated Financial Statements” in Part II, Item 8 should be read in conjunction with the above HEI (Parent Company) financial statements.
Hawaiian Electric Industries, Inc. and subsidiaries
and Hawaiian Electric Company, Inc. and subsidiaries
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2013, 2012 and 2011
(a)
Primarily recoveries.
(b)
Bad debts charged off.
The Company has revised its previously issued "Schedule II - Valuation and Qualifying Accounts" to correct for an error that resulted from the exclusion of the following line items: (a) Allowance for mortgage servicing assets - bank and (b) Deferred tax valuation allowance - HEI. The amounts excluded from the schedule were not considered to be material to previously issued financial statement schedules and the revisions to the schedule had no impact on the Company's Consolidated Balance Sheets, Consolidated Statements of Income or Consolidated Statements of Cash Flows.
(a)(3) and (b) Exhibits
The Exhibit Index attached to this Form 10-K is incorporated herein by reference. The exhibits listed for HEI and Hawaiian Electric are listed in the index under the headings “HEI” and “Hawaiian Electric,” respectively, except that the exhibits listed under “Hawaiian Electric” are also exhibits for HEI.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.
HAWAIIAN ELECTRIC INDUSTRIES, INC.
HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)
(Registrant)
By
/s/ James A. Ajello
By
/s/ Tayne S. Y. Sekimura
James A. Ajello
Tayne S. Y. Sekimura
Executive Vice President and Chief Financial Officer
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer of HEI)
(Principal Financial Officer of Hawaiian Electric)
Date:
February 21, 2014
Date:
February 21, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on February 21, 2014. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.
Signature
Title
/s/ Constance H. Lau
President of HEI and Director of HEI
Constance H. Lau
Chairman of the Board of Directors of Hawaiian Electric
(Chief Executive Officer of HEI)
/s/ Richard M. Rosenblum
President and Director of Hawaiian Electric
Richard M. Rosenblum
(Chief Executive Officer of Hawaiian Electric)
/s/ James A. Ajello
Executive Vice President and Chief Financial Officer of HEI
James A. Ajello
(Principal Financial and Accounting Officer of HEI)
/s/ Tayne S. Y. Sekimura
Senior Vice President and
Tayne S. Y. Sekimura
Chief Financial Officer of Hawaiian Electric
(Principal Financial Officer of Hawaiian Electric)
/s/ Cathlynn L. Yoshida
Controller of Hawaiian Electric
Cathlynn L. Yoshida
(Principal Accounting Officer of Hawaiian Electric)
SIGNATURES (continued)
Signature
Title
/s/ Don E. Carroll
Director of Hawaiian Electric
Don E. Carroll
/s/ Thomas B. Fargo
Director of HEI and Hawaiian Electric
Thomas B. Fargo
/s/ Peggy Y. Fowler
Director of HEI and Hawaiian Electric
Peggy Y. Fowler
/s/ Timothy E. Johns
Director of Hawaiian Electric
Timothy E. Johns
/s/ Micah A. Kane
Director of Hawaiian Electric
Micah A. Kane
/s/ Bert A. Kobayashi, Jr.
Director of Hawaiian Electric
Bert A. Kobayashi, Jr.
/s/ A. Maurice Myers
Director of HEI
A. Maurice Myers
/s/ Keith P. Russell
Director of HEI
Keith P. Russell
/s/ James K. Scott
Director of HEI
James K. Scott
/s/ Kelvin H. Taketa
Director of HEI and Hawaiian Electric
Kelvin H. Taketa
/s/ Barry K. Taniguchi
Director of HEI
Barry K. Taniguchi
/s/ Jeffrey N. Watanabe
Chairman of the Board of Directors of HEI
Jeffrey N. Watanabe
EXHIBIT INDEX
The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.