PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (unaudited)
| Three months ended March 31 |
| (in thousands, except per share amounts) | 2017 | 2016 |
| Revenues |
| Electric utility | $ | 518,611 | $ | 482,052 |
| Bank | 72,856 | 68,840 |
| Other | 95 | 68 |
| Total revenues | 591,562 | 550,960 |
| Expenses |
| Electric utility | 469,673 | 426,726 |
| Bank | 48,696 | 49,246 |
| Other | 5,331 | 6,137 |
| Total expenses | 523,700 | 482,109 |
| Operating income (loss) |
| Electric utility | 48,938 | 55,326 |
| Bank | 24,160 | 19,594 |
| Other | (5,236 | ) | (6,069 | ) |
| Total operating income | 67,862 | 68,851 |
| Interest expense, net—other than on deposit liabilities and other bank borrowings | (19,568 | ) | (20,126 | ) |
| Allowance for borrowed funds used during construction | 889 | 662 |
| Allowance for equity funds used during construction | 2,399 | 1,739 |
| Income before income taxes | 51,582 | 51,126 |
| Income taxes | 16,916 | 18,301 |
| Net income | 34,666 | 32,825 |
| Preferred stock dividends of subsidiaries | 473 | 473 |
| Net income for common stock | $ | 34,193 | $ | 32,352 |
| Basic earnings per common share | $ | 0.31 | $ | 0.30 |
| Diluted earnings per common share | $ | 0.31 | $ | 0.30 |
| Dividends per common share | $ | 0.31 | $ | 0.31 |
| Weighted-average number of common shares outstanding | 108,674 | 107,620 |
| Net effect of potentially dilutive shares | 184 | 161 |
| Weighted-average shares assuming dilution | 108,858 | 107,781 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (unaudited)
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Net income for common stock | $ | 34,193 | $ | 32,352 |
| Other comprehensive income (loss), net of taxes: |
| Net unrealized gains on available-for-sale investment securities: |
| Net unrealized gains on available-for-sale investment securities arising during the period, net of taxes of $148 and $4,905, respectively | 223 | 7,428 |
| Derivatives qualifying as cash flow hedges: |
| Effective portion of foreign currency hedge net unrealized gains arising during the period, net of taxes of nil and $638, respectively | — | 1,002 |
| Reclassification adjustment to net income, net of tax benefits of $289 and $35, respectively | 454 | 54 |
| Retirement benefit plans: |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,502 and $2,257, respectively | 3,921 | 3,538 |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,301 and $2,052, respectively | (3,613 | ) | (3,222 | ) |
| Other comprehensive income, net of taxes | 985 | 8,800 |
| Comprehensive income attributable to Hawaiian Electric Industries, Inc. | $ | 35,178 | $ | 41,152 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (unaudited)
| (dollars in thousands) | March 31, 2017 | December 31, 2016 |
| Assets |
| Cash and cash equivalents | $ | 234,230 | $ | 278,452 |
| Accounts receivable and unbilled revenues, net | 252,416 | 237,950 |
| Available-for-sale investment securities, at fair value | 1,228,922 | 1,105,182 |
| Stock in Federal Home Loan Bank, at cost | 11,706 | 11,218 |
| Loans receivable held for investment, net | 4,669,274 | 4,683,160 |
| Loans held for sale, at lower of cost or fair value | 10,454 | 18,817 |
| Property, plant and equipment, net of accumulated depreciation of $2,475,562 and $2,444,348 at March 31, 2017 and December 31, 2016, respectively | 4,641,514 | 4,603,465 |
| Regulatory assets | 945,409 | 957,451 |
| Other | 467,160 | 447,621 |
| Goodwill | 82,190 | 82,190 |
| Total assets | $ | 12,543,275 | $ | 12,425,506 |
| Liabilities and shareholders’ equity |
| Liabilities |
| Accounts payable | $ | 160,819 | $ | 143,279 |
| Interest and dividends payable | 27,407 | 25,225 |
| Deposit liabilities | 5,675,090 | 5,548,929 |
| Short-term borrowings—other than bank | 2,300 | — |
| Other bank borrowings | 200,154 | 192,618 |
| Long-term debt, net—other than bank | 1,618,651 | 1,619,019 |
| Deferred income taxes | 740,506 | 728,806 |
| Regulatory liabilities | 419,940 | 410,693 |
| Contributions in aid of construction | 541,574 | 543,525 |
| Defined benefit pension and other postretirement benefit plans liability | 632,964 | 638,854 |
| Other | 423,989 | 473,512 |
| Total liabilities | 10,443,394 | 10,324,460 |
| Preferred stock of subsidiaries - not subject to mandatory redemption | 34,293 | 34,293 |
| Commitments and contingencies (Notes 4 and 5) |
| Shareholders’ equity |
| Preferred stock, no par value, authorized 10,000,000 shares; issued: none | — | — |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 108,745,265 shares and 108,583,413 shares at March 31, 2017 and December 31, 2016, respectively | 1,658,280 | 1,660,910 |
| Retained earnings | 439,452 | 438,972 |
| Accumulated other comprehensive loss, net of tax benefits | (32,144 | ) | (33,129 | ) |
| Total shareholders’ equity | 2,065,588 | 2,066,753 |
| Total liabilities and shareholders’ equity | $ | 12,543,275 | $ | 12,425,506 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Industries, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Shareholders’ Equity (unaudited)
| Common stock | Retained | Accumulatedothercomprehensive |
| (in thousands) | Shares | Amount | Earnings | income (loss) | Total |
| Balance, December 31, 2016 | 108,583 | $ | 1,660,910 | $ | 438,972 | $ | (33,129 | ) | $ | 2,066,753 |
| Net income for common stock | — | — | 34,193 | — | 34,193 |
| Other comprehensive income, net of taxes | — | — | — | 985 | 985 |
| Issuance of common stock, net of expenses | 162 | (2,630 | ) | — | — | (2,630 | ) |
| Common stock dividends | — | — | (33,713 | ) | — | (33,713 | ) |
| Balance, March 31, 2017 | 108,745 | $ | 1,658,280 | $ | 439,452 | $ | (32,144 | ) | $ | 2,065,588 |
| Balance, December 31, 2015 | 107,460 | $ | 1,629,136 | $ | 324,766 | $ | (26,262 | ) | $ | 1,927,640 |
| Net income for common stock | — | — | 32,352 | — | 32,352 |
| Other comprehensive income, net of taxes | — | — | — | 8,800 | 8,800 |
| Issuance of common stock, net of expenses | 416 | 6,754 | — | — | 6,754 |
| Common stock dividends | — | — | (33,367 | ) | — | (33,367 | ) |
| Balance, March 31, 2016 | 107,876 | $ | 1,635,890 | $ | 323,751 | $ | (17,462 | ) | $ | 1,942,179 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Industries, Inc. and Subsidiaries
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Cash flows from operating activities |
| Net income | $ | 34,666 | $ | 32,825 |
| Adjustments to reconcile net income to net cash provided by operating activities |
| Depreciation of property, plant and equipment | 50,051 | 48,594 |
| Other amortization | 2,372 | 1,928 |
| Provision for loan losses | 3,907 | 4,766 |
| Loans receivable originated and purchased, held for sale | (35,725 | ) | (42,719 | ) |
| Proceeds from sale of loans receivable, held for sale | 40,588 | 40,363 |
| Deferred income taxes | 10,096 | 13,008 |
| Share-based compensation expense | 1,056 | 1,013 |
| Allowance for equity funds used during construction | (2,399 | ) | (1,739 | ) |
| Other | (347 | ) | 1,702 |
| Changes in assets and liabilities |
| Decrease (increase) in accounts receivable and unbilled revenues, net | (12,337 | ) | 28,108 |
| Decrease (increase) in fuel oil stock | (7,444 | ) | 22,812 |
| Decrease in regulatory assets | 5,909 | 1,585 |
| Increase in accounts, interest and dividends payable | 71,846 | 30,135 |
| Change in prepaid and accrued income taxes, tax credits and utility revenue taxes | (42,175 | ) | (14,343 | ) |
| Increase in defined benefit pension and other postretirement benefit plans liability | 1,012 | 137 |
| Change in other assets and liabilities | (27,142 | ) | 2,797 |
| Net cash provided by operating activities | 93,934 | 170,972 |
| Cash flows from investing activities |
| Available-for-sale investment securities purchased | (171,878 | ) | (122,387 | ) |
| Principal repayments on available-for-sale investment securities | 48,200 | 48,819 |
| Purchase of stock from Federal Home Loan Bank | (488 | ) | (1,373 | ) |
| Redemption of stock from Federal Home Loan Bank | — | 833 |
| Net decrease (increase) in loans held for investment | 890 | (28,137 | ) |
| Proceeds from sale of commercial loans | 13,493 | — |
| Proceeds from sale of real estate acquired in settlement of loans | 185 | 232 |
| Capital expenditures | (138,185 | ) | (127,818 | ) |
| Contributions in aid of construction | 10,650 | 13,761 |
| Other | 5,709 | 819 |
| Net cash used in investing activities | (231,424 | ) | (215,251 | ) |
| Cash flows from financing activities |
| Net increase in deposit liabilities | 126,161 | 114,678 |
| Net increase (decrease) in short-term borrowings with original maturities of three months or less | 2,300 | (7,578 | ) |
| Net increase in retail repurchase agreements | 21,071 | 19,041 |
| Proceeds from other bank borrowings | — | 20,835 |
| Repayments of other bank borrowings | (13,534 | ) | (39,369 | ) |
| Proceeds from issuance of long-term debt | — | 75,000 |
| Repayment of long-term debt | — | (75,000 | ) |
| Withheld shares for employee taxes on vested share-based compensation | (3,687 | ) | (2,335 | ) |
| Net proceeds from issuance of common stock | — | 3,022 |
| Common stock dividends | (33,713 | ) | (27,716 | ) |
| Preferred stock dividends of subsidiaries | (473 | ) | (473 | ) |
| Other | (4,857 | ) | (1,561 | ) |
| Net cash provided by financing activities | 93,268 | 78,544 |
| Net increase (decrease) in cash and cash equivalents | (44,222 | ) | 34,265 |
| Cash and cash equivalents, beginning of period | 278,452 | 300,478 |
| Cash and cash equivalents, end of period | $ | 234,230 | $ | 334,743 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (unaudited)
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Revenues | $ | 518,611 | $ | 482,052 |
| Expenses |
| Fuel oil | 144,270 | 113,740 |
| Purchased power | 127,124 | 115,859 |
| Other operation and maintenance | 100,240 | 103,908 |
| Depreciation | 48,216 | 46,781 |
| Taxes, other than income taxes | 49,823 | 46,438 |
| Total expenses | 469,673 | 426,726 |
| Operating income | 48,938 | 55,326 |
| Allowance for equity funds used during construction | 2,399 | 1,739 |
| Interest expense and other charges, net | (17,504 | ) | (17,308 | ) |
| Allowance for borrowed funds used during construction | 889 | 662 |
| Income before income taxes | 34,722 | 40,419 |
| Income taxes | 12,758 | 14,553 |
| Net income | 21,964 | 25,866 |
| Preferred stock dividends of subsidiaries | 229 | 229 |
| Net income attributable to Hawaiian Electric | 21,735 | 25,637 |
| Preferred stock dividends of Hawaiian Electric | 270 | 270 |
| Net income for common stock | $ | 21,465 | $ | 25,367 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
HEI owns all of the common stock of Hawaiian Electric. Therefore, per share data with respect to shares of common stock of Hawaiian Electric are not meaningful.
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (unaudited)
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Net income for common stock | $ | 21,465 | $ | 25,367 |
| Other comprehensive income, net of taxes: |
| Derivatives qualifying as cash flow hedges: |
| Effective portion of foreign currency hedge net unrealized gains arising during the period, net of taxes of nil and $638, respectively | — | 1,002 |
| Reclassification adjustment to net income, net of tax benefits of $289 and nil, respectively | 454 | — |
| Retirement benefit plans: |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,304 and $2,061, respectively | 3,618 | 3,236 |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,301 and $2,052, respectively | (3,613 | ) | (3,222 | ) |
| Other comprehensive income, net of taxes | 459 | 1,016 |
| Comprehensive income attributable to Hawaiian Electric Company, Inc. | $ | 21,924 | $ | 26,383 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Company, Inc. and Subsidiaries
| (dollars in thousands, except par value) | March 31, 2017 | December 31, 2016 |
| Assets |
| Property, plant and equipment |
| Utility property, plant and equipment |
| Land | $ | 53,157 | $ | 53,153 |
| Plant and equipment | 6,651,094 | 6,605,732 |
| Less accumulated depreciation | (2,399,222 | ) | (2,369,282 | ) |
| Construction in progress | 230,072 | 211,742 |
| Utility property, plant and equipment, net | 4,535,101 | 4,501,345 |
| Nonutility property, plant and equipment, less accumulated depreciation of $1,232 at March 31, 2017 and December 31, 2016 | 7,410 | 7,407 |
| Total property, plant and equipment, net | 4,542,511 | 4,508,752 |
| Current assets |
| Cash and cash equivalents | 13,207 | 74,286 |
| Customer accounts receivable, net | 117,990 | 123,688 |
| Accrued unbilled revenues, net | 97,632 | 91,693 |
| Other accounts receivable, net | 20,388 | 5,233 |
| Fuel oil stock, at average cost | 73,874 | 66,430 |
| Materials and supplies, at average cost | 57,045 | 53,679 |
| Prepayments and other | 28,934 | 23,100 |
| Regulatory assets | 81,952 | 66,032 |
| Total current assets | 491,022 | 504,141 |
| Other long-term assets |
| Regulatory assets | 863,457 | 891,419 |
| Unamortized debt expense | 183 | 208 |
| Other | 71,869 | 70,908 |
| Total other long-term assets | 935,509 | 962,535 |
| Total assets | $ | 5,969,042 | $ | 5,975,428 |
| Capitalization and liabilities |
| Capitalization |
| Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 16,019,785 shares at March 31, 2017 and December 31, 2016) | $ | 106,818 | $ | 106,818 |
| Premium on capital stock | 601,491 | 601,491 |
| Retained earnings | 1,091,323 | 1,091,800 |
| Accumulated other comprehensive income (loss), net of taxes | 137 | (322 | ) |
| Common stock equity | 1,799,769 | 1,799,787 |
| Cumulative preferred stock — not subject to mandatory redemption | 34,293 | 34,293 |
| Long-term debt, net | 1,318,871 | 1,319,260 |
| Total capitalization | 3,152,933 | 3,153,340 |
| Commitments and contingencies (Note 4) |
| Current liabilities |
| Short-term borrowings from non-affiliates | 1,500 | — |
| Accounts payable | 129,863 | 117,814 |
| Interest and preferred dividends payable | 26,174 | 22,838 |
| Taxes accrued | 131,330 | 172,730 |
| Regulatory liabilities | 2,691 | 3,762 |
| Other | 56,235 | 55,221 |
| Total current liabilities | 347,793 | 372,365 |
| Deferred credits and other liabilities |
| Deferred income taxes | 746,017 | 733,659 |
| Regulatory liabilities | 417,249 | 406,931 |
| Unamortized tax credits | 91,012 | 88,961 |
| Defined benefit pension and other postretirement benefit plans liability | 593,856 | 599,726 |
| Other | 78,608 | 76,921 |
| Total deferred credits and other liabilities | 1,926,742 | 1,906,198 |
| Contributions in aid of construction | 541,574 | 543,525 |
| Total capitalization and liabilities | $ | 5,969,042 | $ | 5,975,428 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Common Stock Equity (unaudited)
| Common stock | Premiumoncapital | Retained | Accumulatedothercomprehensive |
| (in thousands) | Shares | Amount | stock | earnings | income (loss) | Total |
| Balance, December 31, 2016 | 16,020 | $ | 106,818 | $ | 601,491 | $ | 1,091,800 | $ | (322 | ) | $ | 1,799,787 |
| Net income for common stock | — | — | — | 21,465 | — | 21,465 |
| Other comprehensive income, net of taxes | — | — | — | — | 459 | 459 |
| Common stock dividends | — | — | — | (21,942 | ) | — | (21,942 | ) |
| Balance, March 31, 2017 | 16,020 | $ | 106,818 | $ | 601,491 | $ | 1,091,323 | $ | 137 | $ | 1,799,769 |
| Balance, December 31, 2015 | 15,805 | $ | 105,388 | $ | 578,930 | $ | 1,043,082 | $ | 925 | $ | 1,728,325 |
| Net income for common stock | — | — | — | 25,367 | — | 25,367 |
| Other comprehensive income, net of taxes | — | — | — | — | 1,016 | 1,016 |
| Common stock dividends | — | — | — | (23,400 | ) | — | (23,400 | ) |
| Common stock issuance expenses | — | — | (4 | ) | — | — | (4 | ) |
| Balance, March 31, 2016 | 15,805 | $ | 105,388 | $ | 578,926 | $ | 1,045,049 | $ | 1,941 | $ | 1,731,304 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (unaudited)
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Cash flows from operating activities |
| Net income | $ | 21,964 | $ | 25,866 |
| Adjustments to reconcile net income to net cash provided by operating activities |
| Depreciation of property, plant and equipment | 48,216 | 46,781 |
| Other amortization | 1,949 | 1,774 |
| Deferred income taxes | 11,064 | 13,558 |
| Allowance for equity funds used during construction | (2,399 | ) | (1,739 | ) |
| Other | 436 | 1,702 |
| Changes in assets and liabilities |
| Decrease (increase) in accounts receivable | (7,328 | ) | 28,297 |
| Increase in accrued unbilled revenues | (5,939 | ) | (858 | ) |
| Decrease (increase) in fuel oil stock | (7,444 | ) | 22,812 |
| Decrease (increase) in materials and supplies | (3,366 | ) | 173 |
| Decrease in regulatory assets | 5,909 | 1,585 |
| Increase in accounts payable | 64,174 | 27,766 |
| Change in prepaid and accrued income taxes, tax credits and revenue taxes | (43,984 | ) | (42,018 | ) |
| Increase in defined benefit pension and other postretirement benefit plans liability | 264 | 205 |
| Change in other assets and liabilities | (4,694 | ) | 20,967 |
| Net cash provided by operating activities | 78,822 | 146,871 |
| Cash flows from investing activities |
| Capital expenditures | (131,655 | ) | (125,183 | ) |
| Contributions in aid of construction | 10,650 | 13,761 |
| Other | 2,702 | 45 |
| Net cash used in investing activities | (118,303 | ) | (111,377 | ) |
| Cash flows from financing activities |
| Common stock dividends | (21,942 | ) | (23,400 | ) |
| Preferred stock dividends of Hawaiian Electric and subsidiaries | (499 | ) | (499 | ) |
| Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less | 1,500 | 12,998 |
| Other | (657 | ) | — |
| Net cash used in financing activities | (21,598 | ) | (10,901 | ) |
| Net increase (decrease) in cash and cash equivalents | (61,079 | ) | 24,593 |
| Cash and cash equivalents, beginning of period | 74,286 | 24,449 |
| Cash and cash equivalents, end of period | $ | 13,207 | $ | 49,042 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 · Basis of presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited condensed consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s and Hawaiian Electric’s Form 10-K for the year ended December 31, 2016.
In the opinion of HEI’s and Hawaiian Electric’s management, the accompanying unaudited condensed consolidated financial statements contain all material adjustments required by GAAP to fairly state consolidated HEI’s and Hawaiian Electric’s financial positions as of March 31, 2017 and December 31, 2016 and the results of their operations and their cash flows for the three months ended March 31, 2017 and 2016. All such adjustments are of a normal recurring nature, unless otherwise disclosed below or in other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year.
2 · Termination of proposed merger and other matters
On December 3, 2014, HEI, NextEra Energy, Inc. (NEE) and two subsidiaries of NEE entered into an Agreement and Plan of Merger (the Merger Agreement), under which Hawaiian Electric was to become a subsidiary of NEE. The Merger Agreement contemplated that, prior to the Merger, HEI would distribute to its shareholders all of the common stock of ASB Hawaii, Inc. (ASB Hawaii), the parent company of ASB (such distribution referred to as the Spin-Off).
The closing of the Merger was subject to various conditions, including receipt of regulatory approval from the PUC. In July 2016: (1) the PUC dismissed NEE and Hawaiian Electric’s application requesting approval of the proposed Merger, (2) NEE terminated the Merger Agreement and (3) pursuant to the terms of the Merger Agreement, NEE paid HEI a $90 million termination fee and $5 million for the reimbursement of expenses associated with the transaction. In 2016, the Company recognized $60 million of net income ($2 million of net loss in each of the first and second quarters and $64 million of net income in the third quarter), comprised of the termination fee ($55 million), reimbursements of expenses from NEE and insurance ($3 million), and additional tax benefits on the previously non-tax-deductible merger- and Spin-Off-related expenses incurred through June 30, 2016 ($8 million), less merger- and Spin-Off-related expenses incurred in 2016 ($6 million) (all net of tax impacts). The Spin-Off of ASB Hawaii was cancelled as it was cross-conditioned on the merger consummation.
In May 2016, the Utilities had filed an application for approval of an liquefied natural gas (LNG) supply and transport agreement and LNG-related capital equipment, which application was conditioned on the PUC’s approval of the proposed Merger. Subsequently, the Utilities terminated the LNG agreement and withdrew the application. In 2016, Hawaiian Electric recognized expenses related to the terminated LNG agreement of $1 million, net of tax benefits, in each of the first and second quarters.
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3 · Segment financial information
| (in thousands) | Electric utility | Bank | Other | Total |
| Three months ended March 31, 2017 |
| Revenues from external customers | $ | 518,566 | $ | 72,856 | $ | 140 | $ | 591,562 |
| Intersegment revenues (eliminations) | 45 | — | (45 | ) | — |
| Revenues | $ | 518,611 | $ | 72,856 | $ | 95 | $ | 591,562 |
| Income (loss) before income taxes | $ | 34,722 | $ | 24,160 | $ | (7,300 | ) | $ | 51,582 |
| Income taxes (benefit) | 12,758 | 8,347 | (4,189 | ) | 16,916 |
| Net income (loss) | 21,964 | 15,813 | (3,111 | ) | 34,666 |
| Preferred stock dividends of subsidiaries | 499 | — | (26 | ) | 473 |
| Net income (loss) for common stock | $ | 21,465 | $ | 15,813 | $ | (3,085 | ) | $ | 34,193 |
| Total assets (at March 31, 2017) | $ | 5,969,042 | $ | 6,559,646 | $ | 14,587 | $ | 12,543,275 |
| Three months ended March 31, 2016 |
| Revenues from external customers | $ | 482,045 | $ | 68,840 | $ | 75 | $ | 550,960 |
| Intersegment revenues (eliminations) | 7 | — | (7 | ) | — |
| Revenues | $ | 482,052 | $ | 68,840 | $ | 68 | $ | 550,960 |
| Income (loss) before income taxes | $ | 40,419 | $ | 19,594 | $ | (8,887 | ) | $ | 51,126 |
| Income taxes (benefit) | 14,553 | 6,921 | (3,173 | ) | 18,301 |
| Net income (loss) | 25,866 | 12,673 | (5,714 | ) | 32,825 |
| Preferred stock dividends of subsidiaries | 499 | — | (26 | ) | 473 |
| Net income (loss) for common stock | $ | 25,367 | $ | 12,673 | $ | (5,688 | ) | $ | 32,352 |
| Total assets (at December 31, 2016) | $ | 5,975,428 | $ | 6,421,357 | $ | 28,721 | $ | 12,425,506 |

Intercompany electricity sales of the Utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by the Utilities and the profit on such sales is nominal.
Bank fees that ASB charges the Utilities and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution and the profit on such fees is nominal.
4 · Electric utility segment
Revenue taxes. The Utilities’ revenues include amounts for the recovery of various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, the Utilities’ revenue tax payments to the taxing authorities in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). The Utilities included in the three months ended March 31, 2017 and 2016 approximately $46 million and $43 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.
Recent tax developments. The extension of bonus depreciation under the “Protecting Americans from Tax Hikes (PATH) Act of 2015” continues to be the most significant recent tax change. The PATH Act provides 50% bonus depreciation through 2017, phases down the percentage to 40% in 2018 and 30% in 2019 and then terminates bonus depreciation thereafter. Tax depreciation is expected to increase by approximately $121 million in 2017 due to bonus depreciation, which has the effect of increasing accumulated deferred tax liabilities. However, the rate of growth of accumulated deferred tax liabilities is decreasing over time as book depreciation “catches up” with the tax depreciation taken in the past.
Congressional action on tax reform for 2017 has not progressed sufficiently to estimate the impact of any such proposed reform on the Utilities’ future results of operation and financial condition.
Unconsolidated variable interest entities.
HECO Capital Trust III. HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to Hawaiian Electric, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by Hawaiian Electric in the principal amount of $31.5 million and issued by Hawaii Electric Light and Maui Electric each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other
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activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of the Utilities under an expense agreement and Hawaiian Electric’s obligations under its trust guarantee and its guarantee of the obligations of Hawaii Electric Light and Maui Electric under their respective debentures, are the sole assets of Trust III. Taken together, Hawaiian Electric’s obligations under the Hawaiian Electric debentures, the Hawaiian Electric indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in the aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. Trust III has at all times been an unconsolidated subsidiary of Hawaiian Electric. Since Hawaiian Electric, as the holder of 100% of the trust common securities, does not absorb the majority of the variability of Trust III, Hawaiian Electric is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheets as of March 31, 2017 and December 31, 2016 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for the three months ended March 31, 2017 consisted of $0.8 million of interest income received from the 2004 Debentures; $0.8 million of distributions to holders of the Trust Preferred Securities; and $25,000 of common dividends on the trust common securities to Hawaiian Electric. As long as the 2004 Trust Preferred Securities are outstanding, Hawaiian Electric is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by Hawaiian Electric in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event any of the Utilities elect to defer payment of interest on any of their respective 2004 Debentures, then Hawaiian Electric will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.
Power purchase agreements. As of March 31, 2017, the Utilities had five power purchase agreements (PPAs) for firm capacity and other PPAs with IPPs and Schedule Q providers (e.g., customers with cogeneration and/or power production facilities who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Purchases from all IPPs were as follows:
| Three months ended March 31 |
| (in millions) | 2017 | 2016 |
| Kalaeloa | $ | 40 | $ | 29 |
| AES Hawaii | 29 | 38 |
| HPOWER | 17 | 16 |
| Puna Geothermal Venture | 8 | 7 |
| HEP | 7 | 11 |
| Other IPPs 1 | 26 | 15 |
| Total IPPs | $ | 127 | $ | 116 |

| 1 | Includes wind power, solar power, feed-in tariff projects and other PPAs. |

Some of the IPPs provided sufficient information for Hawaiian Electric to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. Other IPPs declined to provide the information necessary for Hawaiian Electric to determine the applicability of accounting standards for VIEs. Since 2004, Hawaiian Electric has continued its efforts to obtain from the other IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2016, 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 Partners, L.P. (Kalaeloa) later agreed to provide the information pursuant to the amendments to its PPA (see below). During the negotiations of an amendment to the PPA with AES Hawaii, Inc. (AES Hawaii), management determined that Hawaiian Electric was not the primary beneficiary of AES Hawaii and consolidation was not required (see below). 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.
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
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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 continue to be recovered through the ECAC to the extent they are not recovered through base rates.
Kalaeloa Partners, L.P. In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 megawatts (MW) of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that Hawaiian Electric makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.
Hawaiian Electric and Kalaeloa are in negotiations to address the PPA term that ended on May 23, 2016. The PPA automatically extends on a month-to-month basis as long as the parties are still negotiating in good faith. The month-to-month term extensions shall end 60 days after either party notifies the other in writing that negotiations have terminated.
On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the Kalaeloa PPA prior to October 31, 2017.
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 unaudited condensed consolidated financial statements. The energy payments paid by Hawaiian Electric will fluctuate as fuel prices change, but 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 March 31, 2017, Hawaiian Electric’s accounts payable to Kalaeloa for electricity purchased amounted to $11 million.
AES Hawaii, Inc. In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc.), which, as amended (through Amendment No. 2) and approved by the PUC, provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 30 years beginning in September 1992. In November 2015, Hawaiian Electric entered into Amendment No. 3 for which PUC approval was requested and subsequently denied in January 2017. The payments that Hawaiian Electric makes to AES Hawaii for energy associated with the first 180 MW of firm capacity include a fuel component, a variable O&M component and a fixed O&M component, all of which are subject to adjustment based on changes in the Gross National Product Implicit Price Deflator.
Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in AES Hawaii by reason of the provisions within the executed PPA. However, management has concluded that Hawaiian Electric is not the primary beneficiary of AES Hawaii because Hawaiian Electric does not have the power to control the most significant activities of AES Hawaii that impact its economic performance, including operations and maintenance of its facility. Thus, Hawaiian Electric has not consolidated AES Hawaii in its consolidated financial statements. As of March 31, 2017, Hawaiian Electric’s accounts payable to AES Hawaii for electricity purchased, amounted to $13 million.
Commitments and contingencies.
Fuel contracts. The Utilities have contractual agreements to purchase minimum quantities of low sulfur fuel oil (LSFO), medium sulfur fuel oil (MSFO), diesel fuel and biodiesel for multi-year periods, some through December 2019. Fossil fuel prices are tied to the market prices of crude oil fand 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.
On February 18, 2016, the Companies signed two fuel supply contracts with Chevron Products Company (Chevron) for: (1) Oahu’s LSFO and diesel (for purposes of blending with LSFO) to meet the Environmental Protection Agency’s Mercury and Air Toxic Standards; and (2) MSFO, diesel and ultra-low sulfur diesel for Oahu, Maui, Molokai and the island of Hawaii. The contract began on January 1, 2017, terminates on December 31, 2019, and may automatically renew for annual terms thereafter unless terminated earlier by either party. Both of these fuel contracts were recently assigned to Island Energy Services, LLC, a subsidiary of One Rock Capital Partners, L.P., who purchased Chevron’s Hawaii assets on November 1, 2016. Both of these fuel
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contracts replace prior fuel supply contracts with Chevron and Par Hawaii Refining, LLC (Par), which both expired on December 31, 2016.
Hawaii Electric Light also signed a contract with Chevron, now Island Energy Services, LLC, for terminalling services in Hilo, Hawaii for 2017 through 2019. The terminalling services were provided by Chevron as part of the fuel supply contract but as mentioned above, that contract expired December 31, 2016. Now Hilo terminalling services are contracted in a stand-alone contract.
The PUC approved all of the contracts with Chevron, now Island Energy Services, LLC. All of the costs incurred under these contracts are included in the Utilities’ respective Energy Cost Adjustment Clauses (ECACs) to the extent such costs are not recovered through the base rates.
Hawaiian Electric also has three contracts for biodiesel. Two of the contracts are with Pacific Biodiesel Technologies, LLC (PBT) and one contingency contract is in place with REG Marketing & Logistics, LLC (REG). PBT has agreed to supply biodiesel to Hawaiian Electric’s Campbell Industrial Park (CIP) generating facility through November 2017. The contract extends for one-year if either party does not give notice otherwise within 90 days of November 2017. While fuel is delivered to CIP, the contract provides that biodiesel can be trucked to the Honolulu International Airport Emergency Facility and to any other generating facility on Oahu owned by Hawaiian Electric. Hawaiian Electric intends to shift the biodiesel supply to Schofield generating station when that new facility comes online and as long as the PBT contract remains in effect. PBT also has a spot buy contract with Hawaiian Electric to purchase additional quantities of biodiesel at or below the price of diesel. Very few purchases of “at parity” biodiesel have been made; however, the contract remains in effect and was recently extended through June 2018.
Hawaiian Electric also has a contingency contract with REG. REG will supply biodiesel in the event PBT is unable to supply quantities above the contract maximum volume, should something unexpected occur. Hawaiian Electric did not purchase any biofuel from REG during 2016. Hawaiian Electric secured a one-year extension of this contract through November 2017.
The costs incurred under the Utilities’ biodiesel contracts are included in their respective ECACs, to the extent such costs are not recovered through the Utilities’ base rates.
The energy charge for energy purchased from Kalaeloa under Hawaiian Electric’s PPA with Kalaeloa is based in part on the price Kalaeloa pays PAR (formerly known as Hawaii Independent Energy, LLC) for LSFO in a fuel contract between the two parties.
Hawaiian Electric and Kalaeloa are currently in negotiations to address the PPA term that ended on May 23, 2016. See “Unconsolidated variable interest entities - Kalaeloa Partners, L.P.” above.
The costs incurred for LSFO under Hawaiian Electric's fuel contract with Kalaeloa is included in Hawaiian Electric's ECAC, to the extent such costs are not recovered through base rates.
AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended (through Amendment No. 2) for a period of 30 years beginning September 1992, Hawaiian Electric agreed to purchase 180 MW of firm capacity from AES Hawaii. In August 2012, Hawaiian Electric filed an application with the PUC seeking an exemption from the PUC’s Competitive Bidding Framework to negotiate an amendment to the PPA to purchase 186 MW of firm capacity, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013, but Hawaiian Electric and AES Hawaii were not able to reach an agreement on the amendment. In June 2015, AES Hawaii filed an arbitration demand regarding a dispute about whether Hawaiian Electric was obligated to buy up to 9 MW of additional capacity based on a 1992 letter. Hawaiian Electric responded to the arbitration demand and in October 2015, AES Hawaii and Hawaiian Electric entered into a Settlement Agreement to stay the arbitration proceeding. The Settlement Agreement included certain conditions precedent which, if satisfied, would have released the parties from the claims under the arbitration proceeding. Among the conditions precedent was the successful negotiation and PUC approval of an amendment to the existing PPA.
In November 2015, Hawaiian Electric entered into Amendment No. 3 for which PUC approval was requested and subsequently denied in January 2017. Approval of Amendment No. 3 would have satisfied the final condition for effectiveness of the Settlement Agreement and resolved AES Hawaii's claims. Following the PUC's decision, the parties agreed to extend the stay of the arbitration proceeding, while settlement discussions continue.
Hu Honua Bioenergy, LLC. In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy, LLC (Hu Honua) for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii. Per the terms of the PPA, the Hu Honua plant was scheduled to be in service in 2016. However, Hu Honua encountered construction delays, failed to meet its obligations under the PPA and failed to provide adequate assurances that it could perform or had the financial means to perform. Hawaii Electric Light terminated the PPA on March 1, 2016. Hawaii Electric Light and Hu Honua were in discussions regarding the possibility of reinstating the PPA under
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revised terms and conditions. However, on November 30, 2016, Hu Honua filed a civil complaint in the United States District Court for the District of Hawaii which included claims purportedly arising out of the termination of Hu Honua’s PPA. The complaint named HEI, Hawaiian Electric and Hawaii Electric Light as defendants. HEI, Hawaiian Electric and Hawaii Electric Light believe the allegations in the complaint are without merit and intend to defend these lawsuits vigorously.
Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, or if PUC imposed caps on project costs are exceeded, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.
Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) Implementation Project. The Utilities submitted their Enterprise Information System Roadmap to the PUC in June 2014 and refiled an application for an ERP/EAM Implementation Project in July 2014 with an estimated cost of $82.4 million.
In October 2015, the PUC issued a decision and order (D&O) (1) finding that there is a need to replace the Utilities’ existing ERP/EAM system, (2) denying the Utilities request to defer the costs for the ERP software purchased in 2012 and (3) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under two options (in consideration of the then potential merger with NEE). As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015 and in April 2016, the Utilities filed additional information per the two options on the costs and benefits of the project and the Consumer Advocate subsequently submitted its reply.
On August 11, 2016, the PUC issued a second D&O approving the Utilities’ request to commence the ERP/EAM Implementation Project, subject to certain conditions, including a $77.6 million cap on cost recovery as well as a requirement that the Utilities pass onto customers a minimum of $244 million in savings associated with the system over its 12-year service life. Pursuant to the D&O and subsequent orders, the Utilities are required to file a bottom-up, low-level analysis of the project’s benefits; performance metrics and tracking mechanism for passing the project’s benefits on to customers by September 2017; and monthly reports on the status and costs of the project.
On March 31, 2017, the Utilities filed their proposed methods of passing on to customers the estimated monetary savings attributable to the project. The project is expected to go live by October 1, 2018.
Schofield Generating Station Project. In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for the construction of a 50 MW utility owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks. In September 2015, the PUC approved Hawaiian Electric’s application to expend $167 million for the project. In approving the project, the PUC placed a cost cap of $167 million for the project, stated 90% of the cap is allowed for cost recovery through cost recovery mechanisms other than base rates, and stated the $167 million cap will be adjusted downward due to any reduction in the cost of the engine contract due to a reduction in the foreign exchange rate. Hawaiian Electric was required to take all necessary steps to lock in the lowest possible exchange rate. On January 5, 2016, Hawaiian Electric executed window forward contracts, which lowered the cost of the engine contract by $9.7 million, resulting in a revised project cost cap of $157.3 million. Hawaiian Electric has received all of the major permits for the project, including a 35 year site lease from the U.S. Army. Construction of the facility began in October 2016, and the facility is expected to be placed in service in the first quarter of 2018.
Hamakua Energy Partners, L.P. (HEP) Asset Purchase Agreement. Hawaii Electric Light has been purchasing up to 60 MW (net) of firm capacity from HEP under a PPA that expires on December 30, 2030. The HEP plant currently contributes about 23% of the island of Hawaii’s generating capacity. On December 22, 2015, Hawaii Electric Light entered into an agreement, subject to PUC approval, to acquire the assets of HEP for approximately $84.5 million. If approved by the PUC, the agreement to purchase the existing HEP generating assets will terminate the existing PPA. The elimination of certain required capacity payments under the PPA is expected to result in lower costs to customers. Additionally, by owning the plant, Hawaii Electric Light will be able to manage HEP’s efficient generating units more productively, providing greater flexibility to cycle HEP’s generating units to more effectively manage the Hawaii Island grid. This increased operational flexibility will be essential to support and facilitate Hawaii Electric Light’s efforts to integrate more renewable energy onto the grid.
Hawaii Electric Light applied for approval of the Asset Purchase Agreement in February 2016. The Consumer Advocate has recommended approval of the application, subject to certain proposed conditions including a lower purchase price, and three participants in the proceeding have recommended denial of the application. A decision by the PUC on the application is pending.
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Environmental regulation. The Utilities are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act and Clean Water Act (CWA), have increased significantly.
Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases into the environment associated with current or previous operations. The Utilities report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.
Clean Water Act Section 316(b). On August 14, 2014, the Environmental Protection Agency (EPA) published in the Federal Register the final regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The regulations were effective October 14, 2014 and apply to the cooling water systems for the steam generating units at three of Hawaiian Electric’s power plants on the island of Oahu. The regulations prescribe a process, including a number of required site-specific studies, for states to develop facility-specific entrainment and impingement controls to be incorporated in each facility’s National Pollutant Discharge Elimination System permit. Hawaiian Electric submitted the final site specific studies for the Honolulu and Waiau power plants to the Hawaii Department of Health (DOH) in December 2016, and the final site specific study for Kahe will be submitted to the DOH no later than October 2017. Hawaiian Electric will work with the DOH to identify the appropriate compliance methods for the 316(b) rule.
Mercury Air Toxics Standards. On February 16, 2012, the EPA published the final rule establishing the National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs) in the Federal Register. The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS established the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Hawaiian Electric received a one-year extension to comply by April 16, 2016. Hawaiian Electric initially selected a MATS compliance strategy based on switching to lower emission fuels, but has since continued developing and refining its emission control strategy. Hawaiian Electric’s liquid oil-fired steam generating units that are subject to the MATS limits are able to comply with the new standards without a significant fuel switch in combination with a suite of operational changes.
Hawaiian Electric has proceeded with the implementation of its MATS Compliance Plan and has met all compliance requirements to date.
1-Hour Sulfur Dioxide National Ambient Air Quality Standard. On August 1, 2015, the EPA published the Data Requirements Rule for the 2010 1-Hour Sulfur Dioxide (SO2) Primary National Ambient Air Quality Standard (NAAQS). Hawaiian Electric is working with the DOH to gather data the EPA requires through the installation and operation of two new 1-hour SO2 air quality monitoring stations on the island of Oahu. This data will be integrated into the DOH’s statewide monitoring network and will assist the State’s development of its strategy to maintain the NAAQS and comply with the new 1-Hour SO2 Rule in its State Implementation Plan. The two new 1-hour SO2 air quality monitoring stations have been installed and were placed into operation prior to the EPA regulatory deadline of January 1, 2017.
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) alleging potential violations of the Prevention of Significant Deterioration and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. In correspondence dated November 4, 2014, the DOJ also identified potential violations by Hawaiian Electric at its Kahe facility and proposed resolving the identified, potential violations by entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities continue to negotiate with the DOJ to resolve these issues, but are unable to estimate the effect or costs of a consent decree, if any, at this time.
Former Molokai Electric Company generation site. In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since identified environmental impacts in the subsurface soil at the Site. Although Maui Electric never operated at the Site or owned the Site property, after discussions with the EPA and the DOH, Maui Electric agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of environmental contamination. A 2011 assessment by a Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, residual fuel oils and other subsurface contaminants. Maui Electric has a reserve balance of $3.6 million as of March 31, 2017, representing the probable and reasonably estimated cost to complete the additional
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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.
Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is a Potentially Responsible Party responsible for cleanup of PCB contamination in sediment in the area offshore of the Waiau Power Plant as part of the Pearl Harbor Superfund Site. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to investigate the area. The Navy has completed a remedial investigation and a feasibility study (FS) for the remediation of contaminated sediment at several locations in Pearl Harbor and issued its Final FS Report on June 29, 2015. On February 2, 2016, the Navy released the Proposed Plan for Pearl Harbor Sediment Remediation and Hawaiian Electric submitted comments. The extent of the contamination, the appropriate remedial measures to address it and Hawaiian Electric’s potential responsibility for any associated costs have not been determined.
On March 23, 2015, Hawaiian Electric received a letter from the EPA requesting that Hawaiian Electric submit a work plan to assess potential sources and extent of PCB contamination onshore at the Waiau Power Plant. Hawaiian Electric submitted a sampling and analysis (SAP) work plan to the EPA and the DOH. Onshore sampling at the Waiau Power Plant was completed in two phases in December 2015 and June 2016. The extent of the onshore contamination, the appropriate remedial measures to address it and any associated costs have not yet been determined.
As of March 31, 2017, the reserve account balance recorded by Hawaiian Electric to address the PCB contamination was $5.0 million. The reserve represents the probable and reasonably estimable cost to complete the onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment. The final remediation costs will depend on the results of the onshore investigation and assessment of potential source control requirements, as well as the further investigation of contaminated sediment offshore from the Waiau Power Plant.
Global climate change and greenhouse gas emissions reduction. Concerns about climate change and the contribution of greenhouse gas (GHG) emissions (including carbon dioxide emissions from the combustion of fossil fuels) to climate change have led to regulatory action by the State of Hawaii to reduce GHG emissions.
In 2007, the State Legislature passed Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 (i.e., the final GHG rule), which went into effect on June 30, 2014. In general, Act 234 and the corresponding GHG rule require affected sources (that have the potential to emit GHGs in excess of established thresholds) to reduce their GHG emissions by 16% below 2010 emission levels by 2020. In accordance with the GHG rule, the Utilities submitted their Emissions Reduction Plan (EmRP) to the DOH on June 30, 2015, demonstrating how they will comply. The Utilities have committed to a 16% reduction in GHG emissions company-wide. Pursuant to the State’s GHG rule, the DOH will incorporate the proposed facility-specific GHG emission limits into each facility’s covered source permit based on the 2020 levels specified in Hawaiian Electric’s approved EmRP.
The GHG rule also requires affected sources to pay an annual fee that is based on tons per year of GHG emissions starting on the effective date of the regulations. The fee for the Utilities is estimated to be approximately $0.5 million annually. The latest assessment of the state GHG rules is that the continued growth in renewable power generation will significantly reduce the compliance costs and risk for the Utilities.
The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in Hawaiian Electric’s Campbell Industrial Park combustion turbine No. 1 (CIP CT-1), using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities will continue to pursue the use of cleaner fuels to replace, at least in part, petroleum. Management is unable to evaluate the ultimate impact on the Utilities’ operations of more comprehensive GHG regulations that might be promulgated; however, the various initiatives that the Utilities are pursuing are likely to provide a sound basis for appropriately managing the Utilities’ carbon footprint and thereby meet state GHG reduction goals.
While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise. This effect could potentially result in impacts to coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and result in increased flooding and storm damage due to heavy rainfall, increased rates of beach erosion, saltwater intrusion into freshwater aquifers and terrestrial ecosystems, and higher water tables in low-lying areas. The effects of climate change on the weather (for example, more intense or more frequent rain events, flooding, or hurricanes), sea levels and freshwater availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.
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Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the ultimate 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 associated with the ultimate retirement of plant and equipment, including removal of asbestos and other hazardous materials.
Hawaiian Electric has recorded estimated AROs related to removing retired generating units at its Honolulu and Waiau power plants. These removal projects are ongoing, with activity and expenditures occurring in partial settlement of these liabilities. Both removal projects are expected to continue through 2017.
Changes to the ARO liability included in “Other liabilities” on Hawaiian Electric’s balance sheet were as follows:
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Balance, beginning of period | $ | 25,589 | $ | 26,848 |
| Accretion expense | 3 | 3 |
| Liabilities incurred | — | — |
| Liabilities settled | (403 | ) | (138 | ) |
| Revisions in estimated cash flows | — | — |
| Balance, end of period | $ | 25,189 | $ | 26,713 |

Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by Hawaiian Electric on March 1, 2011, by Hawaii Electric Light on April 9, 2012 and by Maui Electric on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual rate adjustments for certain 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 rate 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. Under the decoupling tariff approved in 2011, the annual RAM is accrued and billed from June 1 of each year through May 31 of the following year.
As part of a January 2013 Settlement Agreement with the Consumer Advocate, which was approved by the PUC, for the RAM years 2014 - 2016, Hawaiian Electric was allowed to record RAM revenue beginning on January 1 and to bill such amounts from June 1 of the applicable year through May 31 of the following year (current accrual method). Subsequent to 2016, Hawaiian Electric reverted to the RAM provisions initially approved in March 2011—i.e., RAM is both accrued and billed from June 1 of each year through May 31 of the following year.
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 RBA mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. In October 2013, the PUC issued orders that bifurcated the proceeding (into Schedule A and Schedule B issues).
On February 7, 2014, the PUC issued a D&O on the Schedule A issues, which made certain modifications to the decoupling mechanism. The D&O required a 90% limitation on the incremental current year Rate Base RAM adjustment effective with the Utilities’ 2014 decoupling filing and that effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case (ranging from 1.25% to 3.25%), instead of the 6% that had been previously approved.
On March 31, 2015, the PUC issued an Order (the 2015 Decoupling Order) related to the Schedule B portion of the proceeding to make certain further modifications to the decoupling mechanism, and to establish a briefing schedule with respect to certain issues in the proceeding. The 2015 Decoupling Order modified the RAM portion of the decoupling mechanism to be capped at the lesser of the RAM revenue adjustment as then determined (adjusted to eliminate the 90% limitation on the current RAM Period Rate Base RAM adjustment that was ordered in the Schedule A portion of the proceeding) and a RAM revenue adjustment calculated based on the cumulative annual compounded increase in Gross Domestic Product Price Index (GDPPI) applied to the 2014 annualized target revenues (adjusted for certain items specified in the Order) (the RAM Cap). The 2014
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annualized target revenues represent the target revenues from the last rate case, plus RAM revenues, offset by earnings sharing credits, if any, allowed under the decoupling mechanism through the 2014 decoupling filing. The triennial rate case cycle required under the decoupling mechanism continues to serve as the maximum period between the filing of general rate cases.
The RAM Cap impacted the Utilities' recovery of capital investments as follows:
| • | Hawaiian Electric's RAM revenues were limited to the RAM Cap in 2015 and 2016, and the RAM filing for 2017 reflects a limitation to the RAM Cap. In October, 2015, Hawaiian Electric filed an application to recover the revenue requirements associated with certain 2015 underground cable and transmission net plant additions through the RAM above the 2015 RAM Cap. In August 2016, the PUC dismissed Hawaiian Electric's October 2015 above the RAM Cap application because the application did not also request approval of the commitment of capital expenditures. Return on plant additions in excess of the amount provided by the RAM is being requested in the Hawaiian Electric 2017 test year rate case. |

| • | Maui Electric's RAM revenues were limited to the RAM Cap in 2015 and 2016, however, the RAM filing for 2017 reflects RAM revenues below the RAM Cap. |

| • | Hawaii Electric Light’s RAM revenues were below the RAM Cap in 2015 or 2016, and the RAM filing for 2017 continues to reflects RAM revenues below the RAM Cap. |

On April 27, 2017, the PUC issued an Order (the 2017 Decoupling Order) related to Schedule B issues outstanding from the 2015 Decoupling Order. The 2017 Decoupling Order requires the establishment of specific performance incentive mechanisms and provides guidelines for interim recovery of revenues to support major projects placed in service between general rate cases.
The performance incentive mechanisms to be established are:
| • | Service reliability performance standards to include: 1) System Average Interruption Duration Index based on the average customer interruption time and 2) System Average Interruption Frequency Index based on the average number of customer interruptions. Target performance for each is based on each utilities’ historical 10 year average performance with a dead band of one standard deviation. Management believes that the maximum penalty for each is 20 basis points of return on equity (or approximately $3 million for each of the standards in total for the three utilities). These performance standards have penalties only. |

| • | Call Center Performance based on utility call center percentage of calls answered within 30 seconds. Target performance is based on the annual average performance for each utility for the most recent 8 quarters with a dead band of 3% above and below the target. Management believes that the maximum incentive is based on 8 basis points of return on equity (or approximately $1.2 million in total for the three utilities). |

The Utilities are required to file proposed tariffs for the performance incentive mechanisms and sample calculations based on hypothetical future performance within 30 days.
The Parties may file comments on the Utilities’ proposed tariffs and sample calculations within 60 days of the date of the 2017 Decoupling Order, after which the PUC is expected to issue an order on the tariffs.
The 2017 Decoupling Order also established guidelines for Major Project Interim Recovery (MPIR). Projects eligible for recovery through the MPIR adjustment mechanism are major projects (i.e., projects with capital expenditures net of customer contributions in excess of $2.5 million), including but not restricted to renewable energy, energy efficiency, utility scale generation, grid modernization and smaller qualifying projects grouped into programs for review. The MPIR adjustment mechanism provides the opportunity to recover revenues for net costs of approved eligible projects placed in service between general rate cases wherein cost recovery is limited by a revenue cap and is not provided by other effective recovery mechanisms. The request for PUC approval must include a business case and all costs that are allowed to be recovered through the MPIR adjustment mechanism shall be offset by any related benefits. The guidelines provide for accrual of revenues approved for recovery upon in-service date to be collected from customers through the annual Revenue Balancing Account tariff.
In the 2017 Decoupling Order, the PUC indicated that in pending and subsequent rate cases, the PUC intends to require all fuel expenses and purchased energy expenses be recovered through an appropriately modified energy cost adjustment mechanism rather than through base rates, and will consider adopting processes to periodically reset fuel efficiency measures embedded in the energy cost adjustment mechanism to account for changes in the generating system.
Annual decoupling filings. On March 31, 2017, the Utilities submitted to the PUC, their annual decoupling filings for tariffed rates that will be effective from June 1, 2017, through May 31, 2018. The net annual incremental amounts proposed to be collected (refunded) were as follows:
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| ($ in millions) | Hawaiian Electric | Hawaii Electric Light | Maui Electric |
| 2017 Annual incremental RAM adjusted revenues | $ | 12.7 | $ | 3.2 | $ | 2.4 |
| Annual change in accrued earnings sharing credits | $ | — | $ | — | $ | — |
| Annual change in accrued RBA balance as of December 31, 2016 (and associated revenue taxes) (refunded) | $ | (2.4 | ) | $ | (2.5 | ) | $ | (0.2 | ) |
| Net annual incremental amount to be collected under the tariffs | $ | 10.3 | $ | 0.7 | $ | 2.2 |
| Impact on typical residential customer monthly bill (in dollars) * | $ | 0.60 | $ | 0.15 | $ | 1.18 |

* Based on a 500 kilowatthour (KWH) bill for Hawaiian Electric, Maui Electric, and Hawaii Electric Light. The bill impact for Lanai and Molokai customers is expected to be an increase of $0.95, based on a 400 KWH bill.
Hawaiian Electric consolidated 2014 test year abbreviated and 2017 test year rate cases. In December 2016, the PUC issued an order consolidating the Hawaiian Electric filings for the 2014 test year abbreviated rate case and the 2017 test year rate case. The order also found and concluded that Hawaiian Electric's abbreviated 2014 rate case filing did not comply with: (1) the Mandatory Triennial Rate Case Cycle requirement in the decoupling order that Hawaiian Electric file an application for a general rate case every three years and (2) the requirement that Hawaiian Electric file its 2014 calendar test year rate case application by June 27, 2014. The order then stated that: “[T]he determination and disposition of any rates, accounts, adjustment mechanisms, and practices that would have been subject to review in the context of a 2014 test year rate case proceeding are subject to appropriate adjustment based on evidence and findings in the consolidated rate case proceeding.”
In January 2017, Hawaiian Electric filed a motion for clarification and/or partial reconsideration of the PUC’s order. In March 2017, the PUC issued an order to address Hawaiian Electric’s motion, stating that the PUC is not initiating an investigation/enforcement proceeding against Hawaiian Electric regarding its compliance with the decoupling order, and the transfer and consolidation of Hawaiian Electric’s 2014 abbreviated rate case with the 2017 rate case is intended to ensure that ratepayers receive the attendant benefits of Hawaiian Electric’s decision to voluntarily forgo a general rate increase in base rates for its mandated 2014 test year. As directed, in April 2017, Hawaiian Electric filed a supplement to its 2017 rate case filing, addressing the items raised in the order and explaining why Hawaiian Electric’s forgoing of a general rate increase in the 2014 test year should not result in any further adjustments to Hawaiian Electric’s revenue requirement in the 2017 test year.
In April 2017, the PUC issued an Order regarding the supplement to Hawaiian Electric’s 2017 rate case filing, requesting updated pension and OPEB regulatory asset and liability schedules, by May 12, 2017, to reflect the use of the 2014 NPPC and NPBC for the pension and OPEB tracking mechanisms and with amortization of such regulatory assets and liabilities beginning May 1, 2015.
Hawaiian Telcom. The Utilities each have separate agreements for the joint ownership and maintenance of utility poles with Hawaiian Telcom, Inc. (Hawaiian Telcom), the respective county or counties in which each utility operates and other third parties, such as the State of Hawaii. The agreements set forth various circumstances requiring pole removal/installation/replacement and the sharing of costs among the joint pole owners. The agreements allow for the cost of work done by one joint pole owner to be shared by the other joint pole owners based on the apportionment of costs in the agreements. The Utilities have maintained, replaced and installed the majority of the jointly-owned poles in each of the respective service territories, and have billed the other joint pole owners for their respective share of the costs. The counties and the State have been reimbursing the Utilities for their share of the costs. However, Hawaiian Telcom has been delinquent in reimbursing the Utilities for its share of the costs.
Hawaiian Electric has initiated a dispute resolution process to collect the unpaid amounts from Hawaiian Telcom as specified by the joint pole agreement. For Hawaii Electric Light, the agreement does not specify an alternative dispute resolution process, and thus a complaint for payment was filed with the Circuit Court in June 2016. Maui Electric has not yet commenced any legal action to recover the delinquent amounts. As of March 31, 2017, total receivables under the joint pole agreement, including interest, from Hawaiian Telcom are $21.7 million ($14.5 million at Hawaiian Electric, $5.9 million at Hawaii Electric Light, and $1.3 million at Maui Electric). Management expects to prevail on these claims but has reserved for the accrued interest of $4.5 million on the receivables.
April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively address certain key policy, resource planning and operational issues for the Utilities. The Utilities addressed these orders as follows:
Integrated Resource Planning. The PUC did not accept the Utilities’ Integrated Resource Plan and Action Plans submission, and, in lieu of an approved plan, has commenced other initiatives to enable resource planning. The PUC directed each of Hawaiian Electric and Maui Electric to file their respective Power Supply Improvement Plans (PSIPs), which they did in August 2014. The PUC also provided its inclinations on the future of Hawaii’s electric utilities in an exhibit to the order. The exhibit provides the PUC’s perspectives on the vision, business strategies and regulatory policy changes required to align the Utilities' business model with customers’ interests and the state’s public policy goals.
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Reliability Standards Working Group. The PUC ordered the Utilities to take timely actions intended to lower energy costs, improve system reliability and address emerging challenges to integrate additional renewable energy. In addition to the PSIPs mentioned above, the PUC ordered certain filing requirements, which include the following:
| • | Distributed Generation Interconnection Plan - the Utilities’ Plan was filed in August 2014. |

| • | Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters - the Utilities’ Plan was filed in June 2014. |

| • | Action Plan for improving efficiencies in the interconnection requirements studies - the Utilities’ Plan was filed in May 2014. |

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

| • | Integrated interconnection queue for each distribution circuit for each island grid - the Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015. |

The PUC also stated it would be opening new dockets to address (1) reliability standards, (2) the technical, economic and policy issues associated with distributed energy resources (see “Distributed Energy Resources (DER) Investigative Proceeding” below) and (3) the Hawaii electricity reliability administrator, which is a third party position which the legislature has authorized the PUC to create by contract to provide support for the PUC in developing and periodically updating local grid reliability standards and procedures and interconnection requirements and overseeing grid access and operation.
Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop an integrated Demand Response (DR) Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. Subsequently, the Utilities submitted status updates and an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special adviser to guide, monitor and review the Utility’s Plan design and implementation. On December 30, 2015, the Utilities filed applications with the PUC for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs. The Utilities filed an updated DR Portfolio on February 10, 2017. In May 2017, the Utilities plan to file their reply to the statements of position submitted by the other parties in April 2017. In the DRMS proceeding, the parties filed Statements of Position in December 2016 and are awaiting a PUC decision.
Review of PSIPs. Collectively, the PUC's April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities' strategies and plans going forward.
PSIPs for the Utilities were filed in August 2014. The PSIPs each included a tactical plan to transform how electric utility services will be offered to meet customer needs and produce higher levels of renewable energy. Each plan contained a diversified mix of technologies, including significant distributed and utility‑scale renewable resources, that are expected to result, on a consolidated basis, in over 65% of the Utilities’ energy being produced from renewable resources by 2030. Under these plans, the Utilities would support sustainable growth of private rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil to lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generators and lower full service residential customer bills in real dollars.
In November 2015, the PUC issued an order in the proceeding to review the PSIPs filed. The order provided observations and concerns on the PSIPs submitted. As required by the order, the Utilities submitted a Proposed Revision Plan in November 2015, which included a schedule and a work plan to supplement, amend and update the PSIPs in order to address the PUC’s observations and concerns. The parties and participants filed comments on the Utilities Proposed Revision Plan in January 2016. The updated PSIPs, filed by the Utilities on April 1, 2016, provide the Utilities’ assumptions, analyses and plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045.
As required by the PUC, on December 23, 2016, the Utilities filed their PSIP Update Report: December 2016. The updated plans describe greater and faster expansion of the Utilities’ renewable energy portfolio than in the plans filed in April 2016 and emphasize work that is in progress or planned over the next five years on each of the five islands the Utilities serve. The final step in the procedural schedule was the filing of the parties and participants’ respective statements of position in February 2017.
Distributed Energy Resources (DER) Investigative Proceeding. In March 2015, the PUC issued an order to address DER issues.
On June 29, 2015, the Utilities submitted their final Statement of Position in the DER proceeding, which included:
| (1) | new pricing provisions for future private rooftop photovoltaic (PV) systems, |

| (2) | technical standards for advanced inverters, |

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

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| (4) | a pilot time-of-use rate, |

| (5) | an improved method of calculating the amount of private rooftop PV that can be safely installed, and |

| (6) | a streamlined and standardized PV application process. |

On October 12, 2015, the PUC issued a D&O establishing DER reforms that: (1) promote rapid adoption of the next generation of solar PV and other distributed energy technologies; (2) encourage more competitive pricing of distributed energy resource systems; (3) lower overall energy supply costs for all customers; and (4) help to manage DER in terms of each island’s limited grid capacity.
The D&O approved a customer self-supply tariff and a customer grid supply tariff to govern customer generators connected to the Utilities’ systems. These tariffs replace the Net Energy Metering (NEM) program.
In June 2016, the PUC approved the Utilities Advanced Inverter Test Plan and the Utilities submitted the results of the testing to the PUC.
Pursuant to a PUC order, in October 2016, the Utilities submitted tariffs for a Residential Interim Time of Use program, which is limited to 2 years and 5,000 customers. The primary objective is to encourage more efficient use of the electric system and enable more cost-effective integration of renewable energy by shifting customer load from the system’s higher cost, peak demand period to the mid-day period when relatively inexpensive renewable resources are abundant.
The DER Phase 2 of this proceeding is focused on further developing competitive markets for distributed energy resources, including storage. On December 9, 2016, the PUC issued an order, establishing the statement of issues and procedural schedule to govern Phase 2 of this proceeding. Technical track issues, including DER integration analyses and revisions to interconnection standards, will be addressed before the end of 2017. More complex market issues will be addressed in late 2018.
Pursuant to PUC order, in January and February 2017, the Utilities and various DER parties submitted tariff proposals to modify existing interim DER option and proposals, and interconnection standards to facilitate or enable interim DER options, as well as provided comments and reply comments on such tariff proposals. A PUC decision is pending.
| March 31, 2017 | December 31, 2016 |
| (dollars in thousands) | Notional amount | Fair value | Notional amount | Fair value |
| Window forward contracts | $ | 15,838 | $ | (277 | ) | $ | 20,734 | $ | (743 | ) |

Condensed consolidating financial information. Hawaiian Electric is not required to provide separate financial statements or other disclosures concerning Hawaii Electric Light and Maui Electric to holders of the 2004 Debentures issued by Hawaii Electric Light and Maui Electric to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by Hawaiian Electric. Consolidating information is provided below for Hawaiian Electric and each of its subsidiaries for the periods ended and as of the dates indicated.
Hawaiian Electric also unconditionally guarantees Hawaii Electric Light’s and Maui Electric’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of Hawaii Electric Light and Maui Electric, (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder and (c) relating to the trust preferred securities of Trust III. Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.
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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
Three months ended March 31, 2017
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Other subsidiaries | Consolidating adjustments | Hawaiian ElectricConsolidated |
| Revenues | $ | 362,843 | 78,982 | 76,793 | — | (7 | ) | $ | 518,611 |
| Expenses |
| Fuel oil | 98,001 | 17,257 | 29,012 | — | — | 144,270 |
| Purchased power | 100,147 | 18,589 | 8,388 | — | — | 127,124 |
| Other operation and maintenance | 67,278 | 15,516 | 17,446 | — | — | 100,240 |
| Depreciation | 32,722 | 9,685 | 5,809 | — | — | 48,216 |
| Taxes, other than income taxes | 35,040 | 7,450 | 7,333 | — | — | 49,823 |
| Total expenses | 333,188 | 68,497 | 67,988 | — | — | 469,673 |
| Operating income | 29,655 | 10,485 | 8,805 | — | (7 | ) | 48,938 |
| Allowance for equity funds used during construction | 2,056 | 115 | 228 | — | — | 2,399 |
| Equity in earnings of subsidiaries | 8,603 | — | — | — | (8,603 | ) | — |
| Interest expense and other charges, net | (12,057 | ) | (3,004 | ) | (2,450 | ) | — | 7 | (17,504 | ) |
| Allowance for borrowed funds used during construction | 749 | 45 | 95 | — | — | 889 |
| Income before income taxes | 29,006 | 7,641 | 6,678 | — | (8,603 | ) | 34,722 |
| Income taxes | 7,271 | 2,923 | 2,564 | — | — | 12,758 |
| Net income | 21,735 | 4,718 | 4,114 | — | (8,603 | ) | 21,964 |
| Preferred stock dividends of subsidiaries | — | 134 | 95 | — | — | 229 |
| Net income attributable to Hawaiian Electric | 21,735 | 4,584 | 4,019 | — | (8,603 | ) | 21,735 |
| Preferred stock dividends of Hawaiian Electric | 270 | — | — | — | — | 270 |
| Net income for common stock | $ | 21,465 | 4,584 | 4,019 | — | (8,603 | ) | $ | 21,465 |

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
Three months ended March 31, 2017
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Net income for common stock | $ | 21,465 | 4,584 | 4,019 | — | (8,603 | ) | $ | 21,465 |
| Other comprehensive income (loss), net of taxes: |
| Derivatives qualifying as cash flow hedges: |
| Reclassification adjustment to net income, net of tax benefits | 454 | — | — | — | — | 454 |
| Retirement benefit plans: |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits | 3,618 | 503 | 466 | — | (969 | ) | 3,618 |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes | (3,613 | ) | (503 | ) | (467 | ) | — | 970 | (3,613 | ) |
| Other comprehensive income (loss), net of taxes | 459 | — | (1 | ) | — | 1 | 459 |
| Comprehensive income attributable to common shareholder | $ | 21,924 | 4,584 | 4,018 | — | (8,602 | ) | $ | 21,924 |

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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Income (unaudited)
Three months ended March 31, 2016
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Other subsidiaries | Consolidating adjustments | Hawaiian ElectricConsolidated |
| Revenues | $ | 337,175 | 73,183 | 71,706 | — | (12 | ) | $ | 482,052 |
| Expenses |
| Fuel oil | 74,085 | 14,374 | 25,281 | — | — | 113,740 |
| Purchased power | 91,917 | 16,797 | 7,145 | — | — | 115,859 |
| Other operation and maintenance | 69,558 | 16,441 | 17,909 | — | — | 103,908 |
| Depreciation | 31,522 | 9,449 | 5,810 | — | — | 46,781 |
| Taxes, other than income taxes | 32,684 | 6,891 | 6,863 | — | — | 46,438 |
| Total expenses | 299,766 | 63,952 | 63,008 | — | — | 426,726 |
| Operating income | 37,409 | 9,231 | 8,698 | — | (12 | ) | 55,326 |
| Allowance for equity funds used during construction | 1,406 | 127 | 206 | — | — | 1,739 |
| Equity in earnings of subsidiaries | 7,929 | — | — | — | (7,929 | ) | — |
| Interest expense and other charges, net | (11,865 | ) | (2,965 | ) | (2,490 | ) | — | 12 | (17,308 | ) |
| Allowance for borrowed funds used during construction | 529 | 49 | 84 | — | — | 662 |
| Income before income taxes | 35,408 | 6,442 | 6,498 | — | (7,929 | ) | 40,419 |
| Income taxes | 9,771 | 2,346 | 2,436 | — | — | 14,553 |
| Net income | 25,637 | 4,096 | 4,062 | — | (7,929 | ) | 25,866 |
| Preferred stock dividends of subsidiaries | — | 134 | 95 | — | — | 229 |
| Net income attributable to Hawaiian Electric | 25,637 | 3,962 | 3,967 | — | (7,929 | ) | 25,637 |
| Preferred stock dividends of Hawaiian Electric | 270 | — | — | — | — | 270 |
| Net income for common stock | $ | 25,367 | 3,962 | 3,967 | — | (7,929 | ) | $ | 25,367 |

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (unaudited)
Three months ended March 31, 2016
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Net income for common stock | $ | 25,367 | 3,962 | 3,967 | — | (7,929 | ) | $ | 25,367 |
| Other comprehensive income, net of taxes: |
| Derivatives qualifying as cash flow hedges: |
| Effective portion of foreign currency hedge net unrealized gain, net of taxes | 1,002 | — | — | — | — | 1,002 |
| Retirement benefit plans: |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits | 3,236 | 458 | 418 | — | (876 | ) | 3,236 |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes | (3,222 | ) | (458 | ) | (418 | ) | — | 876 | (3,222 | ) |
| Other comprehensive income, net of taxes | 1,016 | — | — | — | — | 1,016 |
| Comprehensive income attributable to common shareholder | $ | 26,383 | 3,962 | 3,967 | — | (7,929 | ) | $ | 26,383 |

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Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet (unaudited)
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consoli-datingadjustments | Hawaiian ElectricConsolidated |
| Assets |
| Property, plant and equipment |
| Utility property, plant and equipment |
| Land | $ | 43,950 | 6,191 | 3,016 | — | — | $ | 53,157 |
| Plant and equipment | 4,272,395 | 1,261,079 | 1,117,620 | — | — | 6,651,094 |
| Less accumulated depreciation | (1,404,024 | ) | (511,473 | ) | (483,725 | ) | — | — | (2,399,222 | ) |
| Construction in progress | 196,535 | 13,249 | 20,288 | — | — | 230,072 |
| Utility property, plant and equipment, net | 3,108,856 | 769,046 | 657,199 | — | — | 4,535,101 |
| Nonutility property, plant and equipment, less accumulated depreciation | 5,763 | 115 | 1,532 | — | — | 7,410 |
| Total property, plant and equipment, net | 3,114,619 | 769,161 | 658,731 | — | — | 4,542,511 |
| Investment in wholly owned subsidiaries, at equity | 552,688 | — | — | — | (552,688 | ) | — |
| Current assets |
| Cash and cash equivalents | 8,617 | 2,952 | 1,537 | 101 | — | 13,207 |
| Advances to affiliates | — | 6,500 | 2,500 | — | (9,000 | ) | — |
| Customer accounts receivable, net | 82,389 | 18,735 | 16,866 | — | — | 117,990 |
| Accrued unbilled revenues, net | 70,398 | 13,883 | 13,351 | — | — | 97,632 |
| Other accounts receivable, net | 24,489 | 2,526 | 1,125 | — | (7,752 | ) | 20,388 |
| Fuel oil stock, at average cost | 56,473 | 6,744 | 10,657 | — | — | 73,874 |
| Materials and supplies, at average cost | 32,195 | 8,494 | 16,356 | — | — | 57,045 |
| Prepayments and other | 21,150 | 4,621 | 3,163 | — | — | 28,934 |
| Regulatory assets | 73,548 | 4,210 | 4,194 | — | — | 81,952 |
| Total current assets | 369,259 | 68,665 | 69,749 | 101 | (16,752 | ) | 491,022 |
| Other long-term assets |
| Regulatory assets | 637,014 | 119,783 | 106,660 | — | — | 863,457 |
| Unamortized debt expense | 133 | 20 | 30 | — | — | 183 |
| Other | 44,598 | 13,120 | 14,151 | — | — | 71,869 |
| Total other long-term assets | 681,745 | 132,923 | 120,841 | — | — | 935,509 |
| Total assets | $ | 4,718,311 | 970,749 | 849,321 | 101 | (569,440 | ) | $ | 5,969,042 |
| Capitalization and liabilities |
| Capitalization |
| Common stock equity | $ | 1,799,769 | 292,001 | 260,586 | 101 | (552,688 | ) | $ | 1,799,769 |
| Cumulative preferred stock—not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 |
| Long-term debt, net | 915,175 | 213,732 | 189,964 | — | — | 1,318,871 |
| Total capitalization | 2,737,237 | 512,733 | 455,550 | 101 | (552,688 | ) | 3,152,933 |
| Current liabilities |
| Short-term borrowings from non-affiliates | 1,500 | — | — | — | — | 1,500 |
| Short-term borrowings from affiliate | 9,000 | — | — | — | (9,000 | ) | — |
| Accounts payable | 103,957 | 14,665 | 11,241 | — | — | 129,863 |
| Interest and preferred dividends payable | 18,172 | 4,007 | 3,997 | — | (2 | ) | 26,174 |
| Taxes accrued | 90,035 | 21,965 | 19,330 | — | — | 131,330 |
| Regulatory liabilities | — | 2,004 | 687 | — | — | 2,691 |
| Other | 42,721 | 7,938 | 13,326 | — | (7,750 | ) | 56,235 |
| Total current liabilities | 265,385 | 50,579 | 48,581 | — | (16,752 | ) | 347,793 |
| Deferred credits and other liabilities |
| Deferred income taxes | 532,497 | 109,733 | 103,572 | — | 215 | 746,017 |
| Regulatory liabilities | 288,748 | 96,380 | 32,121 | — | — | 417,249 |
| Unamortized tax credits | 58,691 | 16,941 | 15,380 | — | — | 91,012 |
| Defined benefit pension and other postretirement benefit plans liability | 440,246 | 74,100 | 79,510 | — | — | 593,856 |
| Other | 49,630 | 12,996 | 16,197 | — | (215 | ) | 78,608 |
| Total deferred credits and other liabilities | 1,369,812 | 310,150 | 246,780 | — | — | 1,926,742 |
| Contributions in aid of construction | 345,877 | 97,287 | 98,410 | — | — | 541,574 |
| Total capitalization and liabilities | $ | 4,718,311 | 970,749 | 849,321 | 101 | (569,440 | ) | $ | 5,969,042 |

25
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet (unaudited)
December 31, 2016
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consoli-datingadjustments | Hawaiian ElectricConsolidated |
| Assets |
| Property, plant and equipment |
| Utility property, plant and equipment |
| Land | $ | 43,956 | 6,181 | 3,016 | — | — | $ | 53,153 |
| Plant and equipment | 4,241,060 | 1,255,185 | 1,109,487 | — | — | 6,605,732 |
| Less accumulated depreciation | (1,382,972 | ) | (507,666 | ) | (478,644 | ) | — | — | (2,369,282 | ) |
| Construction in progress | 180,194 | 12,510 | 19,038 | — | — | 211,742 |
| Utility property, plant and equipment, net | 3,082,238 | 766,210 | 652,897 | — | — | 4,501,345 |
| Nonutility property, plant and equipment, less accumulated depreciation | 5,760 | 115 | 1,532 | — | — | 7,407 |
| Total property, plant and equipment, net | 3,087,998 | 766,325 | 654,429 | — | — | 4,508,752 |
| Investment in wholly owned subsidiaries, at equity | 550,946 | — | — | — | (550,946 | ) | — |
| Current assets |
| Cash and cash equivalents | 61,388 | 10,749 | 2,048 | 101 | — | 74,286 |
| Advances to affiliates | — | 3,500 | 10,000 | — | (13,500 | ) | — |
| Customer accounts receivable, net | 86,373 | 20,055 | 17,260 | — | — | 123,688 |
| Accrued unbilled revenues, net | 65,821 | 13,564 | 12,308 | — | — | 91,693 |
| Other accounts receivable, net | 7,652 | 2,445 | 1,416 | — | (6,280 | ) | 5,233 |
| Fuel oil stock, at average cost | 47,239 | 8,229 | 10,962 | — | — | 66,430 |
| Materials and supplies, at average cost | 29,928 | 7,380 | 16,371 | — | — | 53,679 |
| Prepayments and other | 16,502 | 5,352 | 2,179 | — | (933 | ) | 23,100 |
| Regulatory assets | 60,185 | 3,483 | 2,364 | — | — | 66,032 |
| Total current assets | 375,088 | 74,757 | 74,908 | 101 | (20,713 | ) | 504,141 |
| Other long-term assets |
| Regulatory assets | 662,232 | 120,863 | 108,324 | — | — | 891,419 |
| Unamortized debt expense | 151 | 23 | 34 | — | — | 208 |
| Other | 43,743 | 13,573 | 13,592 | — | — | 70,908 |
| Total other long-term assets | 706,126 | 134,459 | 121,950 | — | — | 962,535 |
| Total assets | $ | 4,720,158 | 975,541 | 851,287 | 101 | (571,659 | ) | $ | 5,975,428 |
| Capitalization and liabilities |
| Capitalization |
| Common stock equity | $ | 1,799,787 | 291,291 | 259,554 | 101 | (550,946 | ) | $ | 1,799,787 |
| Cumulative preferred stock—not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 |
| Long-term debt, net | 915,437 | 213,703 | 190,120 | — | — | 1,319,260 |
| Total capitalization | 2,737,517 | 511,994 | 454,674 | 101 | (550,946 | ) | 3,153,340 |
| Current liabilities |
| Short-term borrowings from affiliate | 13,500 | — | — | — | (13,500 | ) | — |
| Accounts payable | 86,369 | 18,126 | 13,319 | — | — | 117,814 |
| Interest and preferred dividends payable | 15,761 | 4,206 | 2,882 | — | (11 | ) | 22,838 |
| Taxes accrued | 120,176 | 28,100 | 25,387 | — | (933 | ) | 172,730 |
| Regulatory liabilities | — | 2,219 | 1,543 | — | — | 3,762 |
| Other | 41,352 | 7,637 | 12,501 | — | (6,269 | ) | 55,221 |
| Total current liabilities | 277,158 | 60,288 | 55,632 | — | (20,713 | ) | 372,365 |
| Deferred credits and other liabilities |
| Deferred income taxes | 524,433 | 108,052 | 100,911 | — | 263 | 733,659 |
| Regulatory liabilities | 281,112 | 93,974 | 31,845 | — | — | 406,931 |
| Unamortized tax credits | 57,844 | 15,994 | 15,123 | — | — | 88,961 |
| Defined benefit pension and other postretirement benefit plans liability | 444,458 | 75,005 | 80,263 | — | — | 599,726 |
| Other | 49,191 | 13,024 | 14,969 | — | (263 | ) | 76,921 |
| Total deferred credits and other liabilities | 1,357,038 | 306,049 | 243,111 | — | — | 1,906,198 |
| Contributions in aid of construction | 348,445 | 97,210 | 97,870 | — | — | 543,525 |
| Total capitalization and liabilities | $ | 4,720,158 | 975,541 | 851,287 | 101 | (571,659 | ) | $ | 5,975,428 |

26
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Changes in Common Stock Equity (unaudited)
Three months ended March 31, 2017
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Balance, December 31, 2016 | $ | 1,799,787 | 291,291 | 259,554 | 101 | (550,946 | ) | $ | 1,799,787 |
| Net income for common stock | 21,465 | 4,584 | 4,019 | — | (8,603 | ) | 21,465 |
| Other comprehensive income (loss), net of taxes | 459 | — | (1 | ) | — | 1 | 459 |
| Common stock dividends | (21,942 | ) | (3,874 | ) | (2,986 | ) | — | 6,860 | (21,942 | ) |
| Balance, March 31, 2017 | $ | 1,799,769 | 292,001 | 260,586 | 101 | (552,688 | ) | $ | 1,799,769 |

Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Changes in Common Stock Equity (unaudited)
Three months ended March 31, 2016
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Balance, December 31, 2015 | $ | 1,728,325 | 292,702 | 263,725 | 101 | (556,528 | ) | $ | 1,728,325 |
| Net income for common stock | 25,367 | 3,962 | 3,967 | — | (7,929 | ) | 25,367 |
| Other comprehensive income, net of taxes | 1,016 | — | — | — | — | 1,016 |
| Common stock dividends | (23,400 | ) | (3,302 | ) | (3,265 | ) | — | 6,567 | (23,400 | ) |
| Common stock issuance expenses | (4 | ) | (4 | ) | (1 | ) | — | 5 | (4 | ) |
| Balance, March 31, 2016 | $ | 1,731,304 | 293,358 | 264,426 | 101 | (557,885 | ) | $ | 1,731,304 |

27
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Cash Flows (unaudited)
Three months ended March 31, 2017
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Cash flows from operating activities |
| Net income | $ | 21,735 | 4,718 | 4,114 | — | (8,603 | ) | $ | 21,964 |
| Adjustments to reconcile net income to net cash provided by operating activities: |
| Equity in earnings of subsidiaries | (8,628 | ) | — | — | — | 8,603 | (25 | ) |
| Common stock dividends received from subsidiaries | 6,910 | — | — | — | (6,860 | ) | 50 |
| Depreciation of property, plant and equipment | 32,722 | 9,685 | 5,809 | — | — | 48,216 |
| Other amortization | 914 | 442 | 593 | — | — | 1,949 |
| Deferred income taxes | 6,810 | 1,700 | 2,602 | — | (48 | ) | 11,064 |
| Allowance for equity funds used during construction | (2,056 | ) | (115 | ) | (228 | ) | — | — | (2,399 | ) |
| Other | 661 | (138 | ) | (87 | ) | — | — | 436 |
| Changes in assets and liabilities: |
| Decrease (increase) in accounts receivable | (10,724 | ) | 1,239 | 685 | — | 1,472 | (7,328 | ) |
| Increase in accrued unbilled revenues | (4,577 | ) | (319 | ) | (1,043 | ) | — | — | (5,939 | ) |
| Decrease (increase) in fuel oil stock | (9,234 | ) | 1,485 | 305 | — | — | (7,444 | ) |
| Decrease (increase) in materials and supplies | (2,267 | ) | (1,114 | ) | 15 | — | — | (3,366 | ) |
| Decrease (increase) in regulatory assets | 7,711 | (677 | ) | (1,125 | ) | — | — | 5,909 |
| Increase in accounts payable | 59,861 | 2,735 | 1,578 | — | — | 64,174 |
| Change in prepaid and accrued income taxes, tax credits and revenue taxes | (32,272 | ) | (5,352 | ) | (6,408 | ) | — | 48 | (43,984 | ) |
| Increase in defined benefit pension and other postretirement benefit plans liability | 240 | 14 | 10 | — | — | 264 |
| Change in other assets and liabilities | (4,249 | ) | 805 | 197 | — | (1,472 | ) | (4,719 | ) |
| Net cash provided by operating activities | 63,557 | 15,108 | 7,017 | — | (6,860 | ) | 78,822 |
| Cash flows from investing activities |
| Capital expenditures | (101,953 | ) | (16,890 | ) | (12,812 | ) | — | — | (131,655 | ) |
| Contributions in aid of construction | 8,934 | 915 | 801 | — | — | 10,650 |
| Other | 2,352 | 78 | 272 | — | — | 2,702 |
| Advances from affiliates | — | (3,000 | ) | 7,500 | — | (4,500 | ) | — |
| Net cash used in investing activities | (90,667 | ) | (18,897 | ) | (4,239 | ) | — | (4,500 | ) | (118,303 | ) |
| Cash flows from financing activities |
| Common stock dividends | (21,942 | ) | (3,874 | ) | (2,986 | ) | — | 6,860 | (21,942 | ) |
| Preferred stock dividends of Hawaiian Electric and subsidiaries | (270 | ) | (134 | ) | (95 | ) | — | — | (499 | ) |
| Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less | (3,000 | ) | — | — | — | 4,500 | 1,500 |
| Other | (449 | ) | — | (208 | ) | — | — | (657 | ) |
| Net cash used in financing activities | (25,661 | ) | (4,008 | ) | (3,289 | ) | — | 11,360 | (21,598 | ) |
| Net increase (decrease) in cash and cash equivalents | (52,771 | ) | (7,797 | ) | (511 | ) | — | — | (61,079 | ) |
| Cash and cash equivalents, beginning of period | 61,388 | 10,749 | 2,048 | 101 | — | 74,286 |
| Cash and cash equivalents, end of period | $ | 8,617 | 2,952 | 1,537 | 101 | — | $ | 13,207 |

28
Hawaiian Electric Company, Inc. and Subsidiaries
Condensed Consolidating Statement of Cash Flows (unaudited)
Three months ended March 31, 2016
| (in thousands) | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Othersubsidiaries | Consolidatingadjustments | Hawaiian ElectricConsolidated |
| Cash flows from operating activities |
| Net income | $ | 25,637 | 4,096 | 4,062 | — | (7,929 | ) | $ | 25,866 |
| Adjustments to reconcile net income to net cash provided by operating activities: |
| Equity in earnings of subsidiaries | (7,954 | ) | — | — | — | 7,929 | (25 | ) |
| Common stock dividends received from subsidiaries | 6,592 | — | — | — | (6,567 | ) | 25 |
| Depreciation of property, plant and equipment | 31,522 | 9,449 | 5,810 | — | — | 46,781 |
| Other amortization | 1,045 | 268 | 461 | — | — | 1,774 |
| Deferred income taxes | 9,764 | 1,277 | 2,517 | — | — | 13,558 |
| Allowance for equity funds used during construction | (1,406 | ) | (127 | ) | (206 | ) | — | — | (1,739 | ) |
| Other | 1,386 | 154 | 162 | — | — | 1,702 |
| Changes in assets and liabilities: |
| Decrease in accounts receivable | 22,606 | 2,113 | 3,563 | — | 15 | 28,297 |
| Decrease (increase) in accrued unbilled revenues | 58 | (326 | ) | (590 | ) | — | — | (858 | ) |
| Decrease in fuel oil stock | 14,902 | 2,622 | 5,288 | — | — | 22,812 |
| Decrease (increase) in materials and supplies | 378 | (27 | ) | (178 | ) | — | — | 173 |
| Increase in regulatory assets | 79 | 397 | 1,109 | — | — | 1,585 |
| Increase in accounts payable | 24,827 | 1,652 | 1,287 | — | — | 27,766 |
| Change in prepaid and accrued income taxes, tax credits and revenue taxes | (31,916 | ) | (1,634 | ) | (8,466 | ) | — | (2 | ) | (42,018 | ) |
| Increase in defined benefit pension and other postretirement benefit plans liability | 177 | 13 | 15 | — | — | 205 |
| Change in other assets and liabilities | 15,249 | 5,562 | 169 | — | (13 | ) | 20,967 |
| Net cash provided by operating activities | 112,946 | 25,489 | 15,003 | — | (6,567 | ) | 146,871 |
| Cash flows from investing activities |
| Capital expenditures | (97,363 | ) | (16,649 | ) | (11,171 | ) | — | — | (125,183 | ) |
| Contributions in aid of construction | 11,585 | 969 | 1,207 | — | — | 13,761 |
| Other | 22 | 23 | — | — | — | 45 |
| Advances from affiliates | — | 3,000 | 500 | — | (3,500 | ) | — |
| Net cash used in investing activities | (85,756 | ) | (12,657 | ) | (9,464 | ) | — | (3,500 | ) | (111,377 | ) |
| Cash flows from financing activities |
| Common stock dividends | (23,400 | ) | (3,302 | ) | (3,265 | ) | — | 6,567 | (23,400 | ) |
| Preferred stock dividends of Hawaiian Electric and subsidiaries | (270 | ) | (134 | ) | (95 | ) | — | — | (499 | ) |
| Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less | 9,498 | — | — | — | 3,500 | 12,998 |
| Other | 8 | (8 | ) | — | — | — | — |
| Net cash used in financing activities | (14,164 | ) | (3,444 | ) | (3,360 | ) | — | 10,067 | (10,901 | ) |
| Net increase in cash and cash equivalents | 13,026 | 9,388 | 2,179 | — | — | 24,593 |
| Cash and cash equivalents, beginning of period | 16,281 | 2,682 | 5,385 | 101 | — | 24,449 |
| Cash and cash equivalents, end of period | $ | 29,307 | 12,070 | 7,564 | 101 | — | $ | 49,042 |

29
5 · Bank segment
Selected financial information
American Savings Bank, F.S.B.
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Interest and dividend income |
| Interest and fees on loans | $ | 50,742 | $ | 48,437 |
| Interest and dividends on investment securities | 6,980 | 5,017 |
| Total interest and dividend income | 57,722 | 53,454 |
| Interest expense |
| Interest on deposit liabilities | 2,103 | 1,592 |
| Interest on other borrowings | 816 | 1,485 |
| Total interest expense | 2,919 | 3,077 |
| Net interest income | 54,803 | 50,377 |
| Provision for loan losses | 3,907 | 4,766 |
| Net interest income after provision for loan losses | 50,896 | 45,611 |
| Noninterest income |
| Fees from other financial services | 5,610 | 5,499 |
| Fee income on deposit liabilities | 5,428 | 5,156 |
| Fee income on other financial products | 1,866 | 2,205 |
| Bank-owned life insurance | 983 | 998 |
| Mortgage banking income | 789 | 1,195 |
| Other income, net | 458 | 333 |
| Total noninterest income | 15,134 | 15,386 |
| Noninterest expense |
| Compensation and employee benefits | 23,237 | 22,434 |
| Occupancy | 4,154 | 4,138 |
| Data processing | 3,280 | 3,172 |
| Services | 2,360 | 2,911 |
| Equipment | 1,748 | 1,663 |
| Office supplies, printing and postage | 1,535 | 1,365 |
| Marketing | 517 | 861 |
| FDIC insurance | 728 | 884 |
| Other expense | 4,311 | 3,975 |
| Total noninterest expense | 41,870 | 41,403 |
| Income before income taxes | 24,160 | 19,594 |
| Income taxes | 8,347 | 6,921 |
| Net income | $ | 15,813 | $ | 12,673 |

American Savings Bank, F.S.B.
Statements of Comprehensive Income Data (unaudited)
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Net income | $ | 15,813 | $ | 12,673 |
| Other comprehensive income, net of taxes: |
| Net unrealized gains on available-for-sale investment securities: |
| Net unrealized gains on available-for-sale investment securities arising during the period, net of taxes of $148 and $4,905, respectively | 223 | 7,429 |
| Retirement benefit plans: |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $404 and $137, respectively | 612 | 208 |
| Other comprehensive income, net of taxes | 835 | 7,637 |
| Comprehensive income | $ | 16,648 | $ | 20,310 |

30
American Savings Bank, F.S.B.
Balance Sheets Data (unaudited)
| (in thousands) | March 31, 2017 | December 31, 2016 |
| Assets |
| Cash and due from banks | $ | 125,901 | $ | 137,083 |
| Interest-bearing deposits | 94,573 | 52,128 |
| Restricted cash | — | 1,764 |
| Available-for-sale investment securities, at fair value | 1,228,922 | 1,105,182 |
| Stock in Federal Home Loan Bank, at cost | 11,706 | 11,218 |
| Loans receivable held for investment | 4,725,271 | 4,738,693 |
| Allowance for loan losses | (55,997 | ) | (55,533 | ) |
| Net loans | 4,669,274 | 4,683,160 |
| Loans held for sale, at lower of cost or fair value | 10,454 | 18,817 |
| Other | 336,626 | 329,815 |
| Goodwill | 82,190 | 82,190 |
| Total assets | $ | 6,559,646 | $ | 6,421,357 |
| Liabilities and shareholder’s equity |
| Deposit liabilities—noninterest-bearing | $ | 1,696,390 | $ | 1,639,051 |
| Deposit liabilities—interest-bearing | 3,978,700 | 3,909,878 |
| Other borrowings | 200,154 | 192,618 |
| Other | 98,223 | 101,635 |
| Total liabilities | 5,973,467 | 5,843,182 |
| Commitments and contingencies |
| Common stock | 1 | 1 |
| Additional paid in capital | 343,435 | 342,704 |
| Retained earnings | 264,381 | 257,943 |
| Accumulated other comprehensive loss, net of tax benefits |
| Net unrealized losses on securities | $ | (7,708 | ) | $ | (7,931 | ) |
| Retirement benefit plans | (13,930 | ) | (21,638 | ) | (14,542 | ) | (22,473 | ) |
| Total shareholder’s equity | 586,179 | 578,175 |
| Total liabilities and shareholder’s equity | $ | 6,559,646 | $ | 6,421,357 |
| Other assets |
| Bank-owned life insurance | $ | 144,661 | $ | 143,197 |
| Premises and equipment, net | 94,865 | 90,570 |
| Prepaid expenses | 4,031 | 3,348 |
| Accrued interest receivable | 16,508 | 16,824 |
| Mortgage-servicing rights | 9,294 | 9,373 |
| Low-income housing equity investments | 46,782 | 47,081 |
| Real estate acquired in settlement of loans, net | 1,242 | 1,189 |
| Other | 19,243 | 18,233 |
| $ | 336,626 | $ | 329,815 |
| Other liabilities |
| Accrued expenses | $ | 32,324 | $ | 36,754 |
| Federal and state income taxes payable | 10,642 | 4,728 |
| Cashier’s checks | 23,777 | 24,156 |
| Advance payments by borrowers | 6,134 | 10,335 |
| Other | 25,346 | 25,662 |
| $ | 98,223 | $ | 101,635 |

31
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.
Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of $100 million and $100 million, respectively, as of March 31, 2017 and $93 million and $100 million, respectively, as of December 31, 2016.
| Amortized cost | Gross unrealized gains | Gross unrealized losses | Estimated fair value | Gross unrealized losses |
| Less than 12 months | 12 months or longer |
| (dollars in thousands) | Number of issues | Fair value | Amount | Number of issues | Fair value | Amount |
| March 31, 2017 |
| Available-for-sale |
| U.S. Treasury and federal agency obligations | $ | 189,420 | $ | 928 | $ | (1,991 | ) | $ | 188,357 | 14 | $ | 97,572 | $ | (1,855 | ) | 1 | $ | 3,492 | $ | (136 | ) |
| Mortgage-related securities- FNMA, FHLMC and GNMA | 1,036,872 | 1,719 | (13,453 | ) | 1,025,138 | 96 | 792,672 | (11,920 | ) | 13 | 45,025 | (1,533 | ) |
| Mortgage revenue bond | 15,427 | — | — | 15,427 | — | — | — | — | — | — |
| $ | 1,241,719 | $ | 2,647 | $ | (15,444 | ) | $ | 1,228,922 | 110 | $ | 890,244 | $ | (13,775 | ) | 14 | $ | 48,517 | $ | (1,669 | ) |
| December 31, 2016 |
| Available-for-sale |
| U.S. Treasury and federal agency obligations | $ | 193,515 | $ | 920 | $ | (2,154 | ) | $ | 192,281 | 18 | $ | 123,475 | $ | (2,010 | ) | 1 | $ | 3,485 | $ | (144 | ) |
| Mortgage-related securities- FNMA, FHLMC and GNMA | 909,408 | 1,742 | (13,676 | ) | 897,474 | 88 | 709,655 | (12,143 | ) | 13 | 47,485 | (1,533 | ) |
| Mortgage revenue bond | 15,427 | — | — | 15,427 | — | — | — | — | — | — |
| $ | 1,118,350 | $ | 2,662 | $ | (15,830 | ) | $ | 1,105,182 | 106 | $ | 833,130 | $ | (14,153 | ) | 14 | $ | 50,970 | $ | (1,677 | ) |

ASB does not believe that the investment securities that were in an unrealized loss position at March 31, 2017, represent an other-than-temporary impairment. Total gross unrealized losses were primarily attributable to rising interest rates relative to when the investment securities were purchased and not due to the credit quality of the investment securities. The contractual cash flows of the U.S. Treasury, federal agency obligations and mortgage-related securities are backed by the full faith and credit guaranty of the United States government or an agency of the government. ASB does not intend to sell the securities before the recovery of its amortized cost basis and there have been no adverse changes in the timing of the contractual cash flows for the securities. ASB did not recognize OTTI for the quarters ended March 31, 2017 and 2016.
U.S. Treasury, federal agency obligations, and the mortgage revenue bond 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.
| March 31, 2017 | Amortized cost | Fair value |
| (in thousands) |
| Due in one year or less | $ | 9,986 | $ | 9,993 |
| Due after one year through five years | 77,165 | 77,274 |
| Due after five years through ten years | 78,014 | 77,582 |
| Due after ten years | 39,682 | 38,935 |
| 204,847 | 203,784 |
| Mortgage-related securities-FNMA, FHLMC and GNMA | 1,036,872 | 1,025,138 |
| Total available-for-sale securities | $ | 1,241,719 | $ | 1,228,922 |

32
Allowance for loan losses. The allowance for loan losses (balances and changes) and financing receivables were as follows:
| (in thousands) | Residential 1-4 family | Commercial real estate | Homeequity line of credit | Residential land | Commercial construction | Residential construction | Commercial loans | Consumer loans | Unallo-cated | Total |
| Three months ended March 31, 2017 |
| Allowance for loan losses: |
| Beginning balance | $ | 2,873 | $ | 16,004 | $ | 5,039 | $ | 1,738 | $ | 6,449 | $ | 12 | $ | 16,618 | $ | 6,800 | $ | — | $ | 55,533 |
| Charge-offs | (6 | ) | — | (14 | ) | — | — | — | (1,510 | ) | (2,810 | ) | — | (4,340 | ) |
| Recoveries | 9 | — | 91 | 203 | — | — | 297 | 297 | — | 897 |
| Provision | (95 | ) | 500 | 301 | (462 | ) | 808 | (1 | ) | (503 | ) | 3,359 | — | 3,907 |
| Ending balance | $ | 2,781 | $ | 16,504 | $ | 5,417 | $ | 1,479 | $ | 7,257 | $ | 11 | $ | 14,902 | $ | 7,646 | $ | — | $ | 55,997 |
| March 31, 2017 |
| Ending balance: individually evaluated for impairment | $ | 1,386 | $ | 74 | $ | 228 | $ | 660 | $ | — | $ | — | $ | 1,318 | $ | 34 | $ | 3,700 |
| Ending balance: collectively evaluated for impairment | $ | 1,395 | $ | 16,430 | $ | 5,189 | $ | 819 | $ | 7,257 | $ | 11 | $ | 13,584 | $ | 7,612 | $ | — | $ | 52,297 |
| Financing Receivables: |
| Ending balance | $ | 2,058,202 | $ | 790,191 | $ | 866,880 | $ | 16,888 | $ | 130,808 | $ | 13,694 | $ | 661,016 | $ | 192,113 | $ | 4,729,792 |
| Ending balance: individually evaluated for impairment | $ | 19,340 | $ | 1,515 | $ | 6,803 | $ | 2,863 | $ | — | $ | — | $ | 9,175 | $ | 69 | $ | 39,765 |
| Ending balance: collectively evaluated for impairment | $ | 2,038,862 | $ | 788,676 | $ | 860,077 | $ | 14,025 | $ | 130,808 | $ | 13,694 | $ | 651,841 | $ | 192,044 | $ | 4,690,027 |
| Three months ended March 31, 2016 |
| Allowance for loan losses: |
| Beginning balance | $ | 4,186 | $ | 11,342 | $ | 7,260 | $ | 1,671 | $ | 4,461 | $ | 13 | $ | 17,208 | $ | 3,897 | $ | — | $ | 50,038 |
| Charge-offs | (45 | ) | — | — | — | — | — | (1,343 | ) | (1,570 | ) | — | (2,958 | ) |
| Recoveries | 17 | — | 15 | 103 | — | — | 135 | 210 | — | 480 |
| Provision | 435 | 464 | (103 | ) | (34 | ) | 1,703 | (1 | ) | 991 | 1,311 | — | 4,766 |
| Ending balance | $ | 4,593 | $ | 11,806 | $ | 7,172 | $ | 1,740 | $ | 6,164 | $ | 12 | $ | 16,991 | $ | 3,848 | $ | — | $ | 52,326 |
| December 31, 2016 |
| Ending balance: individually evaluated for impairment | $ | 1,352 | $ | 80 | $ | 215 | $ | 789 | $ | — | $ | — | $ | 1,641 | $ | 6 | $ | 4,083 |
| Ending balance: collectively evaluated for impairment | $ | 1,521 | $ | 15,924 | $ | 4,824 | $ | 949 | $ | 6,449 | $ | 12 | $ | 14,977 | $ | 6,794 | $ | — | $ | 51,450 |
| Financing Receivables: |
| Ending balance | $ | 2,048,051 | $ | 800,395 | $ | 863,163 | $ | 18,889 | $ | 126,768 | $ | 16,080 | $ | 692,051 | $ | 178,222 | $ | 4,743,619 |
| Ending balance: individually evaluated for impairment | $ | 19,854 | $ | 1,569 | $ | 6,158 | $ | 3,629 | $ | — | $ | — | $ | 20,539 | $ | 10 | $ | 51,759 |
| Ending balance: collectively evaluated for impairment | $ | 2,028,197 | $ | 798,826 | $ | 857,005 | $ | 15,260 | $ | 126,768 | $ | 16,080 | $ | 671,512 | $ | 178,212 | $ | 4,691,860 |

Credit quality. ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial, commercial real estate and commercial construction loans.
Each loan is assigned an Asset Quality Rating (AQR) reflecting the likelihood of repayment or orderly liquidation of that loan transaction pursuant to regulatory credit classifications: Pass, Special Mention, Substandard, Doubtful and Loss. The AQR is a function of the probability of default model rating, the loss given default and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens and major changes in business and economic conditions. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt. Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that the Bank may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable. An asset classified Loss is considered uncollectible and has such little value that its continuance as a bankable asset is not warranted.
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The credit risk profile by internally assigned grade for loans was as follows:
| March 31, 2017 | December 31, 2016 |
| (in thousands) | Commercialreal estate | Commercialconstruction | Commercial | Commercialreal estate | Commercialconstruction | Commercial |
| Grade: |
| Pass | $ | 669,117 | $ | 84,495 | $ | 605,256 | $ | 701,657 | $ | 102,955 | $ | 614,139 |
| Special mention | 89,370 | 22,500 | 22,568 | 65,541 | — | 25,229 |
| Substandard | 31,704 | 23,813 | 33,192 | 33,197 | 23,813 | 52,683 |
| Doubtful | — | — | — | — | — | — |
| Loss | — | — | — | — | — | — |
| Total | $ | 790,191 | $ | 130,808 | $ | 661,016 | $ | 800,395 | $ | 126,768 | $ | 692,051 |

The credit risk profile based on payment activity for loans was as follows:
| (in thousands) | 30-59dayspast due | 60-89dayspast due | Greaterthan90 days | Totalpast due | Current | Totalfinancingreceivables | Recordedinvestment>90 days andaccruing |
| March 31, 2017 |
| Real estate: |
| Residential 1-4 family | $ | 3,557 | $ | 2,982 | $ | 3,419 | $ | 9,958 | $ | 2,048,244 | $ | 2,058,202 | $ | — |
| Commercial real estate | — | — | — | — | 790,191 | 790,191 | — |
| Home equity line of credit | 594 | 571 | 1,532 | 2,697 | 864,183 | 866,880 | — |
| Residential land | — | 318 | 79 | 397 | 16,491 | 16,888 | — |
| Commercial construction | — | — | — | — | 130,808 | 130,808 | — |
| Residential construction | — | — | — | — | 13,694 | 13,694 | — |
| Commercial | 1,255 | 928 | 847 | 3,030 | 657,986 | 661,016 | — |
| Consumer | 1,809 | 917 | 908 | 3,634 | 188,479 | 192,113 | — |
| Total loans | $ | 7,215 | $ | 5,716 | $ | 6,785 | $ | 19,716 | $ | 4,710,076 | $ | 4,729,792 | $ | — |
| December 31, 2016 |
| Real estate: |
| Residential 1-4 family | $ | 5,467 | $ | 2,338 | $ | 3,505 | $ | 11,310 | $ | 2,036,741 | $ | 2,048,051 | $ | — |
| Commercial real estate | 2,416 | — | — | 2,416 | 797,979 | 800,395 | — |
| Home equity line of credit | 1,263 | 381 | 1,342 | 2,986 | 860,177 | 863,163 | — |
| Residential land | — | — | 255 | 255 | 18,634 | 18,889 | — |
| Commercial construction | — | — | — | — | 126,768 | 126,768 | — |
| Residential construction | — | — | — | — | 16,080 | 16,080 | — |
| Commercial | 413 | 510 | 1,303 | 2,226 | 689,825 | 692,051 | — |
| Consumer | 1,945 | 1,001 | 963 | 3,909 | 174,313 | 178,222 | — |
| Total loans | $ | 11,504 | $ | 4,230 | $ | 7,368 | $ | 23,102 | $ | 4,720,517 | $ | 4,743,619 | $ | — |

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The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due and TDR loans was as follows:
| (in thousands) | March 31, 2017 | December 31, 2016 |
| Real estate: |
| Residential 1-4 family | $ | 11,709 | $ | 11,154 |
| Commercial real estate | 218 | 223 |
| Home equity line of credit | 3,340 | 3,080 |
| Residential land | 695 | 878 |
| Commercial construction | — | — |
| Residential construction | — | — |
| Commercial | 2,016 | 6,708 |
| Consumer | 1,410 | 1,282 |
| Total nonaccrual loans | $ | 19,388 | $ | 23,325 |
| Real estate: |
| Residential 1-4 family | $ | — | $ | — |
| Commercial real estate | — | — |
| Home equity line of credit | — | — |
| Residential land | — | — |
| Commercial construction | — | — |
| Residential construction | — | — |
| Commercial | — | — |
| Consumer | — | — |
| Total accruing loans 90 days or more past due | $ | — | $ | — |
| Real estate: |
| Residential 1-4 family | $ | 13,661 | $ | 14,450 |
| Commercial real estate | 1,297 | 1,346 |
| Home equity line of credit | 4,894 | 4,934 |
| Residential land | 2,246 | 2,751 |
| Commercial construction | — | — |
| Residential construction | — | — |
| Commercial | 7,234 | 14,146 |
| Consumer | 69 | 10 |
| Total troubled debt restructured loans not included above | $ | 29,401 | $ | 37,637 |

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The total carrying amount and the total unpaid principal balance of impaired loans were as follows:
| March 31, 2017 | Three months ended March 31, 2017 |
| (in thousands) | Recordedinvestment | Unpaidprincipalbalance | RelatedAllowance | Averagerecordedinvestment | Interestincomerecognized* |
| With no related allowance recorded |
| Real estate: |
| Residential 1-4 family | $ | 9,145 | $ | 9,980 | $ | — | $ | 9,555 | $ | 84 |
| Commercial real estate | 218 | 227 | — | 220 | — |
| Home equity line of credit | 2,376 | 2,829 | — | 2,004 | 14 |
| Residential land | 954 | 1,401 | — | 957 | 26 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 2,315 | 5,391 | — | 4,907 | 6 |
| Consumer | — | — | — | — | — |
| $ | 15,008 | $ | 19,828 | $ | — | $ | 17,643 | $ | 130 |
| With an allowance recorded |
| Real estate: |
| Residential 1-4 family | $ | 10,195 | $ | 10,398 | $ | 1,386 | $ | 10,048 | $ | 119 |
| Commercial real estate | 1,297 | 1,297 | 74 | 1,300 | 14 |
| Home equity line of credit | 4,427 | 4,443 | 228 | 4,562 | 49 |
| Residential land | 1,909 | 1,909 | 660 | 2,076 | 37 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 6,860 | 6,860 | 1,318 | 7,268 | 401 |
| Consumer | 69 | 69 | 34 | 30 | — |
| $ | 24,757 | $ | 24,976 | $ | 3,700 | $ | 25,284 | $ | 620 |
| Total |
| Real estate: |
| Residential 1-4 family | $ | 19,340 | $ | 20,378 | $ | 1,386 | $ | 19,603 | $ | 203 |
| Commercial real estate | 1,515 | 1,524 | 74 | 1,520 | 14 |
| Home equity line of credit | 6,803 | 7,272 | 228 | 6,566 | 63 |
| Residential land | 2,863 | 3,310 | 660 | 3,033 | 63 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 9,175 | 12,251 | 1,318 | 12,175 | 407 |
| Consumer | 69 | 69 | 34 | 30 | — |
| $ | 39,765 | $ | 44,804 | $ | 3,700 | $ | 42,927 | $ | 750 |

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| December 31, 2016 | Three months ended March 31, 2016 |
| (in thousands) | Recordedinvestment | Unpaidprincipalbalance | Relatedallowance | Averagerecordedinvestment | Interestincomerecognized* |
| With no related allowance recorded |
| Real estate: |
| Residential 1-4 family | $ | 9,571 | $ | 10,400 | $ | — | $ | 10,392 | $ | 51 |
| Commercial real estate | 223 | 228 | — | 1,173 | — |
| Home equity line of credit | 1,500 | 1,900 | — | 849 | — |
| Residential land | 1,218 | 1,803 | — | 1,590 | 16 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 6,299 | 8,869 | — | 4,999 | 6 |
| Consumer | — | — | — | — | — |
| $ | 18,811 | $ | 23,200 | $ | — | $ | 19,003 | $ | 73 |
| With an allowance recorded |
| Real estate: |
| Residential 1-4 family | $ | 10,283 | $ | 10,486 | $ | 1,352 | $ | 12,018 | $ | 122 |
| Commercial real estate | 1,346 | 1,346 | 80 | 854 | — |
| Home equity line of credit | 4,658 | 4,712 | 215 | 2,944 | 27 |
| Residential land | 2,411 | 2,411 | 789 | 3,378 | 67 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 14,240 | 14,240 | 1,641 | 16,970 | 30 |
| Consumer | 10 | 10 | 6 | 13 | — |
| $ | 32,948 | $ | 33,205 | $ | 4,083 | $ | 36,177 | $ | 246 |
| Total |
| Real estate: |
| Residential 1-4 family | $ | 19,854 | $ | 20,886 | $ | 1,352 | $ | 22,410 | $ | 173 |
| Commercial real estate | 1,569 | 1,574 | 80 | 2,027 | — |
| Home equity line of credit | 6,158 | 6,612 | 215 | 3,793 | 27 |
| Residential land | 3,629 | 4,214 | 789 | 4,968 | 83 |
| Commercial construction | — | — | — | — | — |
| Residential construction | — | — | — | — | — |
| Commercial | 20,539 | 23,109 | 1,641 | 21,969 | 36 |
| Consumer | 10 | 10 | 6 | 13 | — |
| $ | 51,759 | $ | 56,405 | $ | 4,083 | $ | 55,180 | $ | 319 |

| * | Since loan was classified as impaired. |

Troubled debt restructurings. A loan modification is deemed to be a troubled debt restructuring (TDR) when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectibility 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 or
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reduction of principal payments. ASB generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.
All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Loan modifications that occurred during the first quarters of 2017 and 2016 and the impact on the allowance for loan losses were as follows:
| Three months ended March 31, 2017 |
| Number of contracts | Outstanding recorded investment1 | Net increase in allowance |
| (dollars in thousands) | Pre-modification | Post-modification | (as of period end) |
| Troubled debt restructurings |
| Real estate: |
| Residential 1-4 family | 3 | $ | 512 | $ | 520 | $ | 45 |
| Commercial real estate | — | — | — | — |
| Home equity line of credit | 8 | 226 | 212 | 34 |
| Residential land | — | — | — | — |
| Commercial construction | — | — | — | — |
| Residential construction | — | — | — | — |
| Commercial | 1 | 342 | 342 | — |
| Consumer | 1 | 59 | 59 | 27 |
| 13 | $ | 1,139 | $ | 1,133 | $ | 106 |

| Three months ended March 31, 2016 |
| Number of contracts | Outstanding recorded investment1 | Net increase in allowance |
| (dollars in thousands) | Pre-modification | Post-modification | (as of period end) |
| Troubled debt restructurings |
| Real estate: |
| Residential 1-4 family | 4 | $ | 1,097 | $ | 1,215 | $ | 161 |
| Commercial real estate | — | — | — | — |
| Home equity line of credit | 10 | 669 | 669 | 74 |
| Residential land | — | — | — | — |
| Commercial construction | — | — | — | — |
| Residential construction | — | — | — | — |
| Commercial | 3 | 16,200 | 16,200 | 525 |
| Consumer | — | — | — | — |
| 17 | $ | 17,966 | $ | 18,084 | $ | 760 |

| 1 | The reported balances include loans that became TDR during the period, and were fully paid-off, charged-off, or sold prior to period end. |

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Loans modified in TDRs that experienced a payment default of 90 days or more during the first quarters of 2017 and 2016, and for which the payment of default occurred within one year of the modification, were as follows:
| Three months ended March 31, 2017 | Three months ended March 31, 2016 |
| (dollars in thousands) | Number of contracts | Recorded investment | Number of contracts | Recorded investment |
| Troubled debt restructurings that subsequently defaulted |
| Real estate: |
| Residential 1-4 family | 1 | $ | 301 | 1 | $ | 488 |
| Commercial real estate | — | — | — | — |
| Home equity line of credit | — | — | — | — |
| Residential land | — | — | — | — |
| Commercial construction | — | — | — | — |
| Residential construction | — | — | — | — |
| Commercial | — | — | — | — |
| Consumer | — | — | — | — |
| 1 | $ | 301 | 1 | $ | 488 |

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 modified in a TDR totaled $2.1 million at March 31, 2017.
Mortgage servicing rights. In its mortgage banking business, ASB sells residential mortgage loans to government-sponsored entities and other parties, who may issue securities backed by pools of such loans. ASB retains no beneficial interests in these loans other than the servicing rights of certain loans sold.
ASB received proceeds from the sale of residential mortgages of $40.6 million and $40.4 million for the three months ended March 31, 2017 and 2016, respectively, and recognized gains on such sales of $0.8 million and $1.2 million for the three months ended March 31, 2017 and 2016, respectively.
There were no repurchased mortgage loans for the three months ended March 31, 2017 and 2016. The repurchase reserve was $0.1 million as of March 31, 2017 and 2016.
Mortgage servicing fees, a component of other income, net, were $0.8 million and $0.7 million for the three months ended March 31, 2017 and 2016, respectively.
Changes in the carrying value of mortgage servicing rights were as follows:
| (in thousands) | Grosscarrying amount1 | Accumulated amortization1 | Valuation allowance | Netcarrying amount |
| March 31, 2017 | $ | 17,707 | $ | (8,413 | ) | $ | — | $ | 9,294 |
| December 31, 2016 | 17,271 | (7,898 | ) | — | 9,373 |

1 Reflects the impact of loans paid in full.
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Changes related to mortgage servicing rights were as follows:
| (in thousands) | 2017 | 2016 |
| Mortgage servicing rights |
| Balance, January 1 | $ | 9,373 | $ | 8,884 |
| Amount capitalized | 436 | 455 |
| Amortization | (515 | ) | (482 | ) |
| Other-than-temporary impairment | — | — |
| Carrying amount before valuation allowance, March 31 | 9,294 | 8,857 |
| Valuation allowance for mortgage servicing rights |
| Balance, January 1 | — | — |
| Provision (recovery) | — | — |
| Other-than-temporary impairment | — | — |
| Balance, March 31 | — | — |
| Net carrying value of mortgage servicing rights | $ | 9,294 | $ | 8,857 |

ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale with servicing rights retained. On a monthly basis, ASB compares the net carrying value of the mortgage servicing rights to its fair value to determine if there are any changes to the valuation allowance and/or other-than-temporary impairment for the mortgage servicing rights. ASB’s MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15 and 30 year mortgages and note rate in bands of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others, which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing rights and increase the amortization of the mortgage servicing rights. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others.
ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in other income, net in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable.
| (dollars in thousands) | March 31, 2017 | December 31, 2016 |
| Unpaid principal balance | $ | 1,205,197 | $ | 1,188,380 |
| Weighted average note rate | 3.95 | % | 3.96 | % |
| Weighted average discount rate | 9.5 | % | 9.4 | % |
| Weighted average prepayment speed | 8.2 | % | 8.5 | % |

The sensitivity analysis of fair value of MSRs to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions was as follows:
| (dollars in thousands) | March 31, 2017 | December 31, 2016 |
| Prepayment rate: |
| 25 basis points adverse rate change | $ | (556 | ) | $ | (567 | ) |
| 50 basis points adverse rate change | (1,144 | ) | (1,154 | ) |
| Discount rate: |
| 25 basis points adverse rate change | (134 | ) | (128 | ) |
| 50 basis points adverse rate change | (266 | ) | (254 | ) |

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The effect of a variation in certain assumptions on fair value is calculated without changing any other assumptions. This analysis typically cannot be extrapolated because the relationship of a change in one key assumption to the changes in the fair value of MSRs typically is not linear.
| (in millions) | Gross amount ofrecognized liabilities | Gross amount offset inthe Balance Sheet | Net amount of liabilities presentedin the Balance Sheet |
| Repurchase agreements |
| March 31, 2017 | $100 | $— | $100 |
| December 31, 2016 | 93 | — | 93 |

| Gross amount not offset in the Balance Sheet |
| (in millions) | Net amount of liabilities presentedin the Balance Sheet | Financialinstruments | Cashcollateralpledged |
| March 31, 2017 |
| Financial institution | $ | — | $ | — | $ | — |
| Government entities | — | — | — |
| Commercial account holders | 100 | 119 | — |
| Total | $ | 100 | $ | 119 | $ | — |
| December 31, 2016 |
| Financial institution | $ | — | $ | — | $ | — |
| Government entities | 14 | 15 | — |
| Commercial account holders | 79 | 101 | — |
| Total | $ | 93 | $ | 116 | $ | — |

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts or into segregated tri-party custodial accounts at the FHLB. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.
Derivative financial instruments. ASB enters into interest rate lock commitments (IRLCs) with borrowers, and forward commitments to sell loans or to-be-announced mortgage-backed securities to investors to hedge against the inherent interest rate and pricing risks associated with selling loans.
ASB enters into IRLCs for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. IRLCs that relate to the origination of mortgage loans that will be held for sale are considered derivative financial instruments under applicable accounting guidance. Outstanding IRLCs expose ASB to the risk that the price of the mortgage loans underlying the commitments may decline due to increases in mortgage interest rates from inception of the rate lock to the funding of the loan. The IRLCs are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
ASB enters into forward commitments to hedge the interest rate risk for rate locked mortgage applications in process and closed mortgage loans held for sale. These commitments are primarily forward sales of to-be-announced mortgage backed securities. Generally, when mortgage loans are closed, the forward commitment is liquidated and replaced with a mandatory delivery forward sale of the mortgage to a secondary market investor. In some cases, a best-efforts forward sale agreement is utilized as the forward commitment. These commitments are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.
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Changes in the fair value of IRLCs and forward commitments subsequent to inception are based on changes in the fair value of the underlying loan resulting from the fulfillment of the commitment and changes in the probability that the loan will fund within the terms of the commitment, which is affected primarily by changes in interest rates and the passage of time.
The notional amount and fair value of ASB’s derivative financial instruments were as follows:
| March 31, 2017 | December 31, 2016 |
| (in thousands) | Notional amount | Fair value | Notional amount | Fair value |
| Interest rate lock commitments | $ | 21,771 | $ | 317 | $ | 25,883 | $ | 421 |
| Forward commitments | 22,120 | (104 | ) | 30,813 | (177 | ) |

ASB’s derivative financial instruments, their fair values and balance sheet location were as follows:
| Derivative Financial Instruments Not Designated as Hedging Instruments 1 | March 31, 2017 | December 31, 2016 |
| (in thousands) | Asset derivatives | Liabilityderivatives | Asset derivatives | Liabilityderivatives |
| Interest rate lock commitments | $ | 317 | $ | — | $ | 445 | $ | 24 |
| Forward commitments | — | 104 | 8 | 185 |
| $ | 317 | $ | 104 | $ | 453 | $ | 209 |

1 Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.
The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in the statements of income:
| Derivative Financial Instruments Not Designated as Hedging Instruments | Location of net gains (losses) recognized in the Statement of Income | Three months ended March 31 |
| (in thousands) | 2017 | 2016 |
| Interest rate lock commitments | Mortgage banking income | $ | (104 | ) | $ | 271 |
| Forward commitments | Mortgage banking income | 73 | (163 | ) |
| $ | (31 | ) | $ | 108 |

Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $14.4 million and $14.0 million at March 31, 2017 and December 31, 2016, respectively. These unfunded commitments were unconditional and legally binding and are recorded in other liabilities with a corresponding increase in other assets. Cash contributions and payments made on commitments to LIHTC investment partnerships are classified as operating activities in the Company’s consolidated statements of cash flows. As of March 31, 2017, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investment partnerships.
Contingencies. 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.
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6 · Retirement benefits
Defined benefit pension and other postretirement benefit plans information. For the first three months of 2017, the Company contributed $17 million ($17 million by the Utilities) to its pension and other postretirement benefit plans, compared to $16 million ($16 million by the Utilities) in the first three months of 2016. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2017 is $67 million ($66 million by the Utilities, $1 million by HEI and nil by ASB), compared to $65 million ($64 million by the Utilities, $1 million by HEI and nil by ASB) in 2016. In addition, the Company expects to pay directly $2 million ($1 million by the Utilities) of benefits in 2017, compared to $2 million ($1 million by the Utilities) paid in 2016.
The components of net periodic benefit cost for HEI consolidated and Hawaiian Electric consolidated were as follows:
| Three months ended March 31 |
| Pension benefits | Other benefits |
| (in thousands) | 2017 | 2016 | 2017 | 2016 |
| HEI consolidated |
| Service cost | $ | 16,494 | $ | 15,391 | $ | 840 | $ | 836 |
| Interest cost | 20,216 | 20,277 | 2,411 | 2,474 |
| Expected return on plan assets | (25,721 | ) | (24,664 | ) | (3,066 | ) | (3,052 | ) |
| Amortization of net prior service loss (gain) | (14 | ) | (14 | ) | (449 | ) | (448 | ) |
| Amortization of net actuarial loss | 6,513 | 5,969 | 366 | 287 |
| Net periodic benefit cost | 17,488 | 16,959 | 102 | 97 |
| Impact of PUC D&Os | (5,156 | ) | (4,046 | ) | 146 | 189 |
| Net periodic benefit cost (adjusted for impact of PUC D&Os) | $ | 12,332 | $ | 12,913 | $ | 248 | $ | 286 |
| Hawaiian Electric consolidated |
| Service cost | $ | 16,094 | $ | 14,933 | $ | 835 | $ | 822 |
| Interest cost | 18,589 | 18,603 | 2,327 | 2,389 |
| Expected return on plan assets | (24,011 | ) | (22,932 | ) | (3,017 | ) | (3,003 | ) |
| Amortization of net prior service loss (gain) | 2 | 4 | (451 | ) | (451 | ) |
| Amortization of net actuarial loss | 6,006 | 5,461 | 359 | 284 |
| Net periodic benefit cost | 16,680 | 16,069 | 53 | 41 |
| Impact of PUC D&Os | (5,156 | ) | (4,046 | ) | 146 | 189 |
| Net periodic benefit cost (adjusted for impact of PUC D&Os) | $ | 11,524 | $ | 12,023 | $ | 199 | $ | 230 |

HEI consolidated recorded retirement benefits expense of $9 million ($8 million by the Utilities) and $9 million ($8 million by the Utilities) in the first three months of 2017 and 2016, respectively, and charged the remaining net periodic benefit cost primarily to electric utility plant.
The Utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the issuance of the PUC’s D&O in the respective utility’s next rate case.
Defined contribution plans information. For the first three months of 2017 and 2016, the Company’s expenses for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan were $1.5 million and $1.4 million, respectively, and cash contributions were $2.9 million and $2.7 million, respectively. For the first three months of 2017 and 2016, the Utilities’ expenses for its defined contribution pension plan under the HEIRSP were $0.5 million and $0.4 million, respectively, and cash contributions were $0.5 million and $0.4 million, respectively.
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7 · Share-based compensation
Under the 2010 Equity and Incentive Plan, as amended, HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards. The 2010 Equity and Incentive Plan (original EIP) was amended and restated effective March 1, 2014 (EIP) and an additional 1.5 million shares was added to the shares available for issuance under these programs.
As of March 31, 2017, approximately 3.3 million shares remained available for future issuance under the terms of the EIP, assuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards, including an estimated 0.4 million shares that could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals for awards outstanding under long-term incentive plans (assuming that such performance goals are achieved at maximum levels).
Under the 2011 Nonemployee Director Stock Plan (2011 Director Plan), HEI can issue shares of common stock as compensation to nonemployee directors of HEI, Hawaiian Electric and ASB. As of March 31, 2017, there were 120,428 shares remaining available for future issuance under the 2011 Director Plan.
Share-based compensation expense and the related income tax benefit were as follows:
| Three months ended March 31 |
| (in millions) | 2017 | 2016 |
| HEI consolidated |
| Share-based compensation expense 1 | $ | 1.1 | $ | 1.0 |
| Income tax benefit | 0.3 | 0.3 |
| Hawaiian Electric consolidated |
| Share-based compensation expense 1 | 0.5 | 0.3 |
| Income tax benefit | 0.2 | 0.1 |

| 1 | For the three months ended March 31, 2017 and 2016, the Company has not capitalized any share-based compensation. |

Stock awards. HEI granted HEI common stock to a nonemployee director of HEI and Hawaiian Electric under the 2011 Director Plan as follows:
| ($ in thousands) | Three months ended March 31, 2017 |
| Shares granted | 770 |
| Fair value | $ | 25 |
| Income tax benefit | 10 |

The number of shares issued to the nonemployee director of HEI and Hawaiian Electric is determined based on the closing price of HEI Common Stock on the grant date.
Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:
| Three months ended March 31 |
| 2017 | 2016 |
| Shares | (1) | Shares | (1) |
| Outstanding, beginning of period | 220,683 | $ | 29.57 | 210,634 | $ | 28.82 |
| Granted | 96,977 | 33.48 | 94,282 | 29.90 |
| Vested | (81,624 | ) | 28.85 | (78,379 | ) | 27.92 |
| Forfeited | — | — | — | — |
| Outstanding, end of period | 236,036 | $ | 31.42 | 226,537 | $ | 29.59 |
| Total weighted-average grant-date fair value of shares granted ($ millions) | $ | 3.2 | $ | 2.8 |

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

For the first three months of 2017 and 2016, total restricted stock units that vested and related dividends had a fair value of $3.1 million and $2.5 million, respectively, and the related tax benefits were $1.1 million and $0.9 million, respectively.
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As of March 31, 2017, there was $6.1 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 3.0 years.
Long-term incentive plan payable in stock. The 2017-2019 long-term incentive plan (LTIP) provides for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals, including a market condition goal. 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 and calculated dividend equivalents. The potential payout varies from 0% to 200% of the number of target shares depending on the achievement of the goals. The market condition goal is based on HEI’s total return to shareholders (TRS) compared to the Edison Electric Institute Index over the three-year period. The other performance condition goals relate to EPS growth, return on average common equity (ROACE) and ASB’s efficiency ratio. The 2015-2017 and 2016-2018 LTIPs provide for performance awards payable in cash, and thus are not included in the tables below.
| Three months ended March 31 |
| 2017 | 2016 |
| Shares | (1) | Shares | (1) |
| Outstanding, beginning of period | 83,106 | $ | 22.95 | 162,500 | $ | 27.66 |
| Granted (target level) | 36,971 | 39.51 | — | — |
| Vested (issued or unissued and cancelled) | (83,106 | ) | 22.95 | (78,553 | ) | 32.69 |
| Forfeited | — | — | — | — |
| Outstanding, end of period | 36,971 | $ | 39.51 | 83,947 | $ | 22.95 |
| Total weighted-average grant-date fair value of shares granted ($ millions) | $ | 1.5 | $ | — |

| (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:
| 2017 |
| Risk-free interest rate | 1.46 | % |
| Expected life in years | 3 |
| Expected volatility | 20.1 | % |
| Range of expected volatility for Peer Group | 15.4% to 26.0% |
| Grant date fair value (per share) | $ | 39.51 |

For the three months ended March 31, 2017, total vested LTIP awards linked to TRS and related dividends had a fair value of $1.9 million and the related tax benefits were $0.7 million. For the three months ended March 31, 2016, all vested shares in the table above were unissued and cancelled (i.e., lapsed) because the TRS goal was not met.
As of March 31, 2017, there was $1.3 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 2.8 years.
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| Three months ended March 31 |
| 2017 | 2016 |
| Shares | (1) | Shares | (1) |
| Outstanding, beginning of period | 109,816 | $ | 25.18 | 222,647 | $ | 26.02 |
| Granted (target level) | 147,888 | 33.48 | — | — |
| Vested (issued) | (109,816 | ) | 25.18 | (109,097 | ) | 26.89 |
| Forfeited | — | — | — | — |
| Outstanding, end of period | 147,888 | $ | 33.48 | 113,550 | $ | 25.18 |
| Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions) | $ | 5.0 | $ | — |

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

For the three months ended March 31, 2017 and 2016, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $4.2 million and $3.6 million and the related tax benefits were $1.6 million and $1.4 million, respectively.
As of March 31, 2017, there was $4.2 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 2.8 years.
8 · Shareholders’ equity
Accumulated other comprehensive income/(loss). Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:
| HEI Consolidated | Hawaiian Electric Consolidated |
| (in thousands) | Net unrealized gains (losses) on securities | Unrealized gains (losses) on derivatives | Retirement benefit plans | AOCI | Unrealized gains (losses) on derivatives | Retirement benefit plans | AOCI |
| Balance, December 31, 2016 | $ | (7,931 | ) | $ | (454 | ) | $ | (24,744 | ) | $ | (33,129 | ) | $ | (454 | ) | $ | 132 | $ | (322 | ) |
| Current period other comprehensive income | 223 | 454 | 308 | 985 | 454 | 5 | 459 |
| Balance, March 31, 2017 | $ | (7,708 | ) | $ | — | $ | (24,436 | ) | $ | (32,144 | ) | $ | — | $ | 137 | $ | 137 |
| Balance, December 31, 2015 | $ | (1,872 | ) | $ | (54 | ) | $ | (24,336 | ) | $ | (26,262 | ) | $ | — | $ | 925 | $ | 925 |
| Current period other comprehensive income | 7,428 | 1,056 | 316 | 8,800 | 1,002 | 14 | 1,016 |
| Balance, March 31, 2016 | $ | 5,556 | $ | 1,002 | $ | (24,020 | ) | $ | (17,462 | ) | $ | 1,002 | $ | 939 | $ | 1,941 |

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Reclassifications out of AOCI were as follows:
| Amount reclassified from AOCI |
| Three months ended March 31 | Affected line item in the |
| (in thousands) | 2017 | 2016 | Statement of Income |
| HEI consolidated |
| Derivatives qualifying as cash flow hedges |
| Window forward contracts | $ | 454 | $ | — | Revenue-electric utilities (losses on window forward contracts - see Note 4 for additional details) |
| Interest rate contracts (settled in 2011) | $ | — | $ | 54 | Interest expense |
| Retirement benefit plan items |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost | 3,921 | 3,537 | See Note 6 for additional details |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets | (3,613 | ) | (3,222 | ) | See Note 6 for additional details |
| Total reclassifications | $ | 762 | $ | 369 |
| Hawaiian Electric consolidated |
| Derivatives qualifying as cash flow hedges |
| Window forward contracts | $ | 454 | $ | — | Revenue (losses on window forward contracts - see Note 4 for additional details) |
| Retirement benefit plan items |
| Adjustment for amortization of prior service credit and net losses recognized during the period in net periodic benefit cost | 3,618 | 3,236 | See Note 6 for additional details |
| Reclassification adjustment for impact of D&Os of the PUC included in regulatory assets | (3,613 | ) | (3,222 | ) | See Note 6 for additional details |
| Total reclassifications | $ | 459 | $ | 14 |

9 · Fair value measurements
Fair value estimates are estimates of the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company and the Utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company or the Utilities were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s and the Utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
The Company and the Utilities group their financial assets measured at fair value in three levels outlined as follows:
Level 1: Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used to measure fair value whenever available.
Level 2: Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.
Level 3: Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow
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methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
Classification in the hierarchy is based upon the lowest level input that is significant to the fair value measurement of the asset or liability. For instruments classified in Level 1 and 2 where inputs are primarily based upon observable market data, there is less judgment applied in arriving at the fair value. For instruments classified in Level 3, management judgment is more significant due to the lack of observable market data.
Fair value is also used on a nonrecurring basis to evaluate certain assets for impairment or for disclosure purposes. Examples of nonrecurring uses of fair value include mortgage servicing rights accounted for by the amortization method, loan impairments for certain loans and goodwill.
Fair value measurement and disclosure valuation methodology. The following are descriptions of the valuation methodologies used for assets and liabilities recorded at fair value and for estimating fair value for financial instruments not carried at fair value:
Short-term borrowings—other than bank. The carrying amount of short-term borrowings approximated fair value because of the short maturity of these instruments.
Investment securities. The fair value of ASB’s investment securities is determined quarterly through pricing obtained from independent third-party pricing services or from brokers not affiliated with the trade. Non-binding broker quotes are infrequent and generally occur for new securities that are settled close to the month-end pricing date. The third-party pricing vendors ASB uses for pricing its securities are reputable firms that provide pricing services on a global basis and have processes in place to ensure quality and control. The third-party pricing services use a variety of methods to determine the fair value of securities that fall under Level 2 of the ASB’s fair value measurement hierarchy. Among the considerations are quoted prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds, and other observable market factors.
To enhance the robustness of the pricing process, ASB will on a quarterly basis compare its standard third-party vendor’s price with that of another third-party vendor. If the prices are within an acceptable tolerance range, the price of the standard vendor will be accepted. If the variance is beyond the tolerance range, an evaluation will be conducted by ASB and a challenge to the price may be made. Fair value in such cases will be based on the value that best reflects the data and observable characteristics of the security. In all cases, the fair value used will have been independently determined by a third-party pricing vendor or non-affiliated broker and not by ASB.
The fair value of the mortgage revenue bond is estimated using a discounted cash flow model to calculate the present value of future principal and interest payments and, therefore is classified within Level 3 of the valuation hierarchy.
Loans held for sale. Loans carried at the lower of cost or market are valued using market observable pricing inputs, which are derived from third party loan sales and securitizations and, therefore, are classified within Level 2 of the valuation hierarchy. ASB transferred $6.1 million of loans receivable out of Level 3 into Level 2 due to changes in the observability of significant inputs during the quarter ended March 31, 2017.
Loans held for investment. Fair value of loans held for investment is derived using a discounted cash flow approach which includes an evaluation of the underlying loan characteristics. The valuation model uses loan characteristics which includes product type, maturity dates and the underlying interest rate of the portfolio. This information is input into the valuation models along with various forecast valuation assumptions including prepayment forecasts, to determine the discount rate. These assumptions are derived from internal and third party sources. Noting the valuation is derived from model-based techniques, ASB includes loans held for investment within Level 3 of the valuation hierarchy.
Impaired loans. At the time a loan is considered impaired, it is valued at the lower of cost or fair value. Fair value is determined primarily by using an income, cost or market approach and is normally provided through appraisals. Impaired loans carried at fair value generally receive specific allocations within the allowance for loan losses. For collateral-dependent loans, fair value is commonly based on recent real estate appraisals. These appraisals may utilize a single valuation approach or a combination of approaches including comparable sales and the income approach. Adjustments are routinely made in the appraisal process by the independent appraisers to adjust for differences between the comparable sales and income data available. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. Non-real estate collateral may be valued using an appraisal, net book value per the borrower’s financial statements, or aging reports, adjusted or discounted based on management’s historical knowledge, changes in market conditions from the time of the valuation and management’s expertise and knowledge of the client and client’s business, resulting in a Level 3 fair value classification. Generally, impaired loans are evaluated quarterly for additional impairment and adjusted accordingly.
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Real estate acquired in settlement of loans. Foreclosed assets are carried at fair value (less estimated costs to sell) and are generally based upon appraisals or independent market prices that are periodically updated subsequent to classification as real estate owned. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. ASB estimates the fair value of collateral-dependent loans and real estate owned using the sales comparison approach.
Mortgage servicing rights. Mortgage servicing rights (MSRs) are capitalized at fair value based on market data at the time of sale and accounted for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing rights are evaluated for impairment at each reporting date. ASB's MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type and note rate. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in "Revenues - bank" in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable. ASB compares the fair value of MSRs to an estimated value calculated by an independent third-party. The third-party relies on both published and unpublished sources of market related assumptions and their own experience and expertise to arrive at a value. ASB uses the third-party value only to assess the reasonableness of its own estimate.
Time deposits. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.
Other borrowings. For fixed-rate advances and repurchase agreements, fair value is estimated using quantitative discounted cash flow models that require the use of interest rate inputs that are currently offered for advances and repurchase agreements of similar remaining maturities. The majority of market inputs are actively quoted and can be validated through external sources, including broker market transactions and third party pricing services.
Long-term debt—other than bank. Fair value of long-term debt of HEI and the Utilities was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities and from discounting the future cash flows using the current rates offered for debt of the same or similar remaining maturities.
Interest rate lock commitments (IRLCs). The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.
Forward sales commitments. To be announced (TBA) mortgage-backed securities forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined using quoted prices in the market place that are observable and are classified as Level 2 measurements.
Window forward contracts. The estimated fair value of the Utilities’ window forward contracts was obtained from a third-party financial services provider based on the effective exchange rate offered for the foreign currency denominated transaction. Window forward contracts are classified as Level 2 measurements.
The following table presents the carrying or notional amount, fair value and placement in the fair value hierarchy of the Company’s financial instruments. For stock in Federal Home Loan Bank, the carrying amount is a reasonable estimate of fair value because it can only be redeemed at par. For bank-owned life insurance, the carrying amount is the cash surrender value of the insurance policies, which is a reasonable estimate of fair value. For financial liabilities such as noninterest-bearing demand, interest-bearing demand, and savings and money market deposits, the carrying amount is a reasonable estimate of fair value as these liabilities have no stated maturity.
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| Estimated fair value |
| Carrying or notional amount | Quoted prices inactive marketsfor identical assets | Significant other observable inputs | Significantunobservableinputs |
| (in thousands) | (Level 1) | (Level 2) | (Level 3) | Total |
| March 31, 2017 |
| Financial assets |
| HEI consolidated |
| Money market funds | $ | 6 | $ | — | $ | 6 | $ | — | $ | 6 |
| Available-for-sale investment securities | 1,228,922 | — | 1,213,495 | 15,427 | 1,228,922 |
| Stock in Federal Home Loan Bank | 11,706 | — | 11,706 | — | 11,706 |
| Loans receivable, net | 4,679,728 | — | 10,881 | 4,816,099 | 4,826,980 |
| Mortgage servicing rights | 9,294 | — | — | 13,650 | 13,650 |
| Bank-owned life insurance | 144,661 | — | 144,661 | — | 144,661 |
| Derivative assets | 22,986 | — | 317 | — | 317 |
| Financial liabilities |
| HEI consolidated |
| Deposit liabilities | 5,675,090 | — | 5,671,729 | — | 5,671,729 |
| Short-term borrowings—other than bank | 2,300 | — | 2,300 | — | 2,300 |
| Other bank borrowings | 200,154 | — | 201,000 | — | 201,000 |
| Long-term debt, net—other than bank | 1,618,651 | — | 1,707,954 | — | 1,707,954 |
| Derivative liabilities | 36,743 | 98 | 283 | — | 381 |
| Hawaiian Electric consolidated |
| Short-term borrowings | 1,500 | — | 1,500 | — | 1,500 |
| Long-term debt, net | 1,318,871 | — | 1,402,690 | — | 1,402,690 |
| Derivative liabilities | 15,838 | — | 277 | — | 277 |
| December 31, 2016 |
| Financial assets |
| HEI consolidated |
| Money market funds | $ | 13,085 | $ | — | $ | 13,085 | $ | — | $ | 13,085 |
| Available-for-sale investment securities | 1,105,182 | — | 1,089,755 | 15,427 | 1,105,182 |
| Stock in Federal Home Loan Bank | 11,218 | — | 11,218 | — | 11,218 |
| Loans receivable, net | 4,701,977 | — | 13,333 | 4,839,493 | 4,852,826 |
| Mortgage servicing rights | 9,373 | — | — | 13,216 | 13,216 |
| Bank-owned life insurance | 143,197 | — | 143,197 | — | 143,197 |
| Derivative assets | 23,578 | — | 453 | — | 453 |
| Financial liabilities |
| HEI consolidated |
| Deposit liabilities | 5,548,929 | — | 5,546,644 | — | 5,546,644 |
| Short-term borrowings—other than bank | — | — | — | — | — |
| Other bank borrowings | 192,618 | — | 193,991 | — | 193,991 |
| Long-term debt, net—other than bank | 1,619,019 | — | 1,704,717 | — | 1,704,717 |
| Derivative liabilities | 53,852 | 129 | 823 | — | 952 |
| Hawaiian Electric consolidated |
| Long-term debt, net | 1,319,260 | — | 1,399,490 | — | 1,399,490 |
| Derivative liabilities | 20,734 | — | 743 | — | 743 |

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| March 31, 2017 | December 31, 2016 |
| Fair value measurements using | Fair value measurements using |
| (in thousands) | Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 |
| Money market funds (“other” segment) | $ | — | $ | 6 | $ | — | $ | — | $ | 13,085 | $ | — |
| Available-for-sale investment securities (bank segment) |
| Mortgage-related securities-FNMA, FHLMC and GNMA | $ | — | $ | 1,025,138 | $ | — | $ | — | $ | 897,474 | $ | — |
| U.S. Treasury and federal agency obligations | — | 188,357 | — | — | 192,281 | — |
| Mortgage revenue bond | — | — | 15,427 | — | — | 15,427 |
| $ | — | $ | 1,213,495 | $ | 15,427 | $ | — | $ | 1,089,755 | $ | 15,427 |
| Derivative assets (bank segment) 1 |
| Interest rate lock commitments | $ | — | $ | 317 | $ | — | $ | — | $ | 445 | $ | — |
| Forward commitments | — | — | — | — | 8 | — |
| $ | — | $ | 317 | $ | — | $ | — | $ | 453 | $ | — |
| Derivative liabilities |
| Interest rate lock commitments (bank segment) 1 | $ | — | $ | — | $ | — | $ | — | $ | 24 | $ | — |
| Forward commitments (bank segment) 1 | 98 | 6 | — | 129 | 56 | — |
| Window forward contracts (electric utility segment)2 | — | 277 | — | — | 743 | — |
| $ | 98 | $ | 283 | $ | — | $ | 129 | $ | 823 | $ | — |

1 Derivatives are carried at fair value with changes in value reflected in the balance sheet in other assets or other liabilities and included in mortgage banking income.
2 Liability derivatives are included in other current liabilities in the balance sheets.
There were no transfers of financial assets and liabilities between Level 1 and Level 2 of the fair value hierarchy during the quarter ended March 31, 2017.
The changes in Level 3 assets and liabilities measured at fair value on a recurring basis were as follows:
| Mortgage revenue bond | 2017 | 2016 |
| (in thousands) |
| Balance, January 1 | $ | 15,427 | $ | — |
| Principal payments received | — | — |
| Purchases | — | — |
| Unrealized gain (loss) included in other comprehensive income | — | — |
| Balance, March 31 | $ | 15,427 | $ | — |

ASB holds one mortgage revenue bond issued by the Department of Budget and Finance of the State of Hawaii. The Company estimates the fair value by using a discounted cash flow model to calculate the present value of estimated future principal and interest payments. The unobservable input used in the fair value measurement is the weighted average discount rate. As of March 31, 2017, the weighted average discount rate was 2.658% which was derived by incorporating a credit spread over the one month LIBOR rate. Significant increases (decreases) in the weighted average discount rate could result in a significantly lower (higher) fair value measurement.
Fair value measurements on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis and therefore are not included in the tables above. These measurements primarily result from assets carried at the lower of cost or fair value or from impairment of individual assets. The carrying value of assets measured at fair value on a nonrecurring basis were as follows:
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| Fair value measurements |
| (in thousands) | Balance | Level 1 | Level 2 | Level 3 |
| March 31, 2017 |
| Loans | $ | 1,281 | $ | — | $ | — | $ | 1,281 |
| December 31, 2016 |
| Loans | 2,767 | — | — | 2,767 |
| Real estate acquired in settlement of loans | 1,189 | — | — | 1,189 |

For three months ended March 31, 2017 and 2016, there were no adjustments to fair value for ASB’s loans held for sale.
The following table presents quantitative information about Level 3 fair value measurements for financial instruments measured at fair value on a nonrecurring basis:
| Significant unobservable input value (1) |
| ($ in thousands) | Fair value | Valuation technique | Significant unobservable input | Range | WeightedAverage |
| March 31, 2017 |
| Residential loan | $ | 222 | Fair value of property or collateral | Appraised value less 7% selling cost | N/A (2) |
| Commercial loan | 810 | Sales price | Sales price | N/A (2) |
| Commercial loan | 249 | Fair value of property or collateral | Fair value of business assets | N/A (2) |
| Total loans | $ | 1,281 |
| December 31, 2016 |
| Residential loans | $ | 2,468 | Sales price | Sales price | 95-100% | 97% |
| Residential loans | 287 | Fair value of property or collateral | Appraised value less 7% selling cost | 42-65% | 61% |
| Home equity lines of credit | 12 | Fair value of property or collateral | Appraised value less 7% selling cost | N/A (2) |
| Total loans | $ | 2,767 |
| Real estate acquired in settlement of loans | $ | 1,189 | Fair value of property or collateral | Appraised value less 7% selling cost | 100% | 100% |

(1) Represent percent of outstanding principal balance.
(2) N/A - Not applicable. There is one loan in each fair value measurement type.
Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurements.
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10 · Cash flows
| Three months ended March 31 | 2017 | 2016 |
| (in millions) |
| Supplemental disclosures of cash flow information |
| HEI consolidated |
| Interest paid to non-affiliates | $ | 19 | $ | 20 |
| Income taxes paid (including refundable credits) | 4 | 1 |
| Income taxes refunded (including refundable credits) | — | 45 |
| Hawaiian Electric consolidated |
| Interest paid to non-affiliates | 13 | 12 |
| Income taxes paid (including refundable credits) | 2 | — |
| Income taxes refunded (including refundable credits) | — | 20 |
| Supplemental disclosures of noncash activities |
| HEI consolidated |
| Common stock dividends reinvested in HEI common stock (financing)1 | — | 6 |
| Loans transferred from held for investment to held for sale (investing) | 9 | — |
| Common stock issued (gross) for director and executive/management compensation (financing)2 | 9 | 6 |
| Obligations to fund low income housing investments (operating) | 1 | — |
| HEI consolidated and Hawaiian Electric consolidated |
| Electric utility property, plant and equipment |
| AFUDC-equity (operating) | 2 | 2 |
| Estimated fair value of noncash contributions in aid of construction (investing) | — | 1 |
| Change in unpaid invoices and accruals (investing) | (52 | ) | (48 | ) |

1 The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.
2 The amounts shown represent the market value of common stock issued for director and executive/management compensation and withheld to satisfy statutory tax liabilities.
11 · Recent accounting pronouncements
Revenues from contracts with customers. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The core principle of the guidance in ASU No. 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should: (1) identify the contract/s with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies a performance obligation. ASU No. 2014-09 also requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
As of March 31, 2017, the Company has identified its revenue streams from, and performance obligations to, customers. The Company continues to monitor development of industry-specific application guidance and is currently evaluating the impacts of adoption of ASU No. 2014-09.
The Company plans to adopt ASU No. 2014-09 (and subsequently issued revenue-related ASUs, as applicable) in the first quarter of 2018, but has not determined the method of adoption (full or modified retrospective application). The Company expects to present additional revenue disclosures, but the full impact of adoption of ASU No. 2014-09 on its results of operations, financial condition and liquidity cannot be determined until its evaluation process is complete.
Financial instruments. In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which, among other things:
| • | Requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. |

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| • | Requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes. |

| • | Requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (i.e., securities or loans and receivables). |

| • | Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. |

The Company plans to adopt ASU No. 2016-01 in the first quarter of 2018 and has not yet determined the impact of adoption.
Leases. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which requires that lessees recognize a liability to make lease payments (the lease liability) and a right-of-use asset, representing its right to use the underlying asset for the lease term, for all leases (except short-term leases) at the commencement date. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election and recognize lease expense for such leases generally on a straight-line basis over the lease term. For finance leases, a lessee is required to recognize interest on the lease liability separately from amortization of the right-of-use asset in the statement of comprehensive income. For operating leases, a lessee is required to recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis.
The Company plans to adopt ASU No. 2016-02 in the first quarter of 2019 (using a modified retrospective transition approach for leases existing at, or entered into after, January 1, 2017) and has not yet determined the impact of adoption.
Stock compensation. In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment transactions.
The Company adopted ASU No. 2016-09 in the first quarter of 2017. From January 1, 2017, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement. From January 1, 2017, no excess tax benefits and deficiencies are included in determining the assumed proceeds under the treasury stock method of calculating diluted EPS. As of January 1, 2017, HEI adopted an accounting policy to account for forfeitures when they occur.
From January 1, 2017, HEI retrospectively applied the cashflow guidance for taxes paid (equivalent to the value of withheld shares for tax withholding purposes) and excess tax benefits. Excess tax benefits will be classified along with other income tax cash flows as an operating activity and the cash payments made to taxing authorities on the employees’ behalf for withheld shares will be classified as financing activities on the HEI Consolidated Statements of Cash Flows for all periods that are presented.
Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. ASU No. 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts) and enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. In addition, ASU No. 2016-13 amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The other-than-temporary impairment model of accounting for credit losses on AFS debt securities will be replaced with an estimate of expected credit losses only when the fair value is below the amortized cost of the asset. The length of time the fair value of an AFS debt security has been below the amortized cost will no longer impact the determination of whether a credit loss exists. The AFS debt security model will also require the use of an allowance to record the estimated losses (and subsequent recoveries). The accounting for the initial recognition of the estimated expected credit losses for purchased financial assets with credit deterioration would be recognized through an allowance for loan losses with an offset to the cost basis of the related financial asset at acquisition (i.e., there is no impact to net income at initial recognition).
The Company plans to adopt ASU No. 2016-13 in the first quarter of 2020 and has not yet determined the impact of adoption.
Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides guidance on eight specific cash flow issues - debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life
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insurance policies (including bank-owned life insurance policies), distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle.
The Company plans to adopt ASU No. 2016-15 in the first quarter of 2018 using a retrospective transition method and has not yet determined the impact of adoption.
Intra-entity transfers of assets other than inventory. In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which changes current guidance that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party by requiring the recognition of the income tax consequences of such transfer when it occurs.
The Company plans to adopt ASU No. 2016-16 in the first quarter of 2018 using a modified retrospective transition method and believes the impact of adoption will be immaterial to the Company’s and Hawaiian Electric’s condensed consolidated financial statements.
Restricted cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents.
The Company plans to adopt ASU No. 2016-18 in the first quarter of 2018 using a retrospective transition method and believes the impact of adoption will not be material to the Company’s and Hawaiian Electric’s consolidated statements of cash flows.
Goodwill impairment. In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” Prior to the adoption of ASU No. 2017-04, an entity was required to perform a two-step test to determine the amount, if any, of goodwill impairment. In Step 1, an entity compared the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeded its fair value, the entity performed Step 2 and compared the implied fair value of goodwill with the carrying amount of that goodwill for that reporting unit. An impairment charge equal to the amount by which the carrying amount of goodwill for the reporting unit exceeded the implied fair value of that goodwill would then be recorded. ASU No. 2017-04 removes the second step of the test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value. ASU No. 2017-04 does not amend the optional qualitative assessment of goodwill impairment.
The Company plans to adopt ASU No. 2017-04 prospectively in 2017 and does not expect the impact of adoption to be material.
Net periodic pension cost and net periodic postretirement benefit cost. In March 2017, the FASB issued ASU No. 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. It also requires the other components of net periodic pension cost and net periodic postretirement benefit cost as defined in paragraphs 715-30-35-4 and 715-60-35-9 to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable.
The Company plans to adopt ASU No. 2017-07 in the first quarter of 2018 and has not yet determined the impact of adoption.
12 · Credit agreements
HEI. On April 2, 2014, HEI and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (HEI Facility). The HEI Facility increased HEI’s line of credit to $150 million from $125 million, extended the term of the facility to April 2, 2019, and provided improved pricing compared to HEI’s prior facility. Under the HEI Facility, draws would generally bear interest, based on HEI’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The HEI Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the HEI Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. In addition, the HEI Consolidated Net Worth covenant, as defined in the original facility, was removed from the HEI Facility, leaving only one financial covenant (relating to HEI’s ratio of funded debt to total capitalization, each on a non-consolidated basis). Under the credit agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (actual ratio of 13% as of March 31, 2017, as calculated under the agreement) or if HEI no
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longer owns Hawaiian Electric. The HEI Facility continues to contain customary conditions which must be met in order to draw on it, including compliance with covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI).
The HEI Facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.
Hawaiian Electric. On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility continues to contain customary conditions which must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for Hawaii Electric Light and 42% for Maui Electric as of March 31, 2017, 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 57% as of March 31, 2017, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.
The Hawaiian Electric 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.
13 · Related party transactions
For general management and administrative services in the three months ended March 31, 2017 and 2016, HEI charged the Utilities $1.4 million and $2.1 million, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.
Mr. Timothy Johns, a member of the Hawaiian Electric Board of Directors, is an executive officer of Hawaii Medical Service Association (HMSA). Ms. Susan Li, an executive of Hawaiian Electric, is the Chair of the Hawaii Dental Service (HDS) Board of Directors. The Company’s HMSA costs and expense (for health insurance premiums, claims plus administration expense and stop-loss insurance coverages) and HDS costs and expense (for dental insurance premiums) and the Utilities’ HMSA costs and expense (for health insurance premiums) and HDS costs and expense (for dental insurance premiums) were as follows:
| Three months ended March 31 |
| (in millions) | 2017 | 2016 |
| HEI consolidated |
| HMSA costs | $ | 7 | $ | 7 |
| HMSA expense* | 5 | 5 |
| HDS costs | 1 | 1 |
| HDS expense* | 1 | 1 |
| Hawaiian Electric consolidated |
| HMSA costs | 6 | 6 |
| HMSA expense* | 4 | 3 |
| HDS costs | 1 | 1 |
| HDS expense* | — | — |

* Charged the remaining costs primarily to electric utility plant.
The costs and expense in the table above are gross amounts (i.e., not net of employee contributions to employee benefits).
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and Hawaiian Electric’s 2016 Form 10-K and should be read in conjunction with such discussion and the 2016 annual consolidated financial statements of HEI and Hawaiian Electric and notes thereto included in HEI’s and Hawaiian Electric’s 2016 Form 10-K, as well as the quarterly (as of and for the three months ended March 31, 2017) financial statements and notes thereto included in this Form 10-Q.
HEI consolidated
RESULTS OF OPERATIONS
| (in thousands, except per | Three months ended March 31 | % |
| share amounts) | 2017 | 2016 | change | Primary reason(s)* |
| Revenues | $ | 591,562 | $ | 550,960 | 7 | Increase for the electric utility and bank segments |
| Operating income | 67,862 | 68,851 | (1 | ) | Decrease for the electric utility segment, partly offset by an increase at the bank segment and lower losses for the “other” segment |
| Net income for common stock | 34,193 | 32,352 | 6 | Higher net income at the bank segment and lower net loss for the “other” segment, partly offset by lower net income for the electric utility segment |
| Basic earnings per common share | $ | 0.31 | $ | 0.30 | 3 | Higher net income, partly offset by the impact of higher weighted average shares outstanding |
| Weighted-average number of common shares outstanding | 108,674 | 107,620 | 1 | Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans |

| * | Also, see segment discussions which follow. |

Notes: The Company’s effective tax rates (combined federal and state income tax rates) for the first three months of 2017 and 2016 were 33% and 36%, respectively. The effective tax rate was lower for the three months ended March 31, 2017 compared to the same period in 2016 due primarily to first quarter 2016 nondeductible merger- and spin-off-related expenses.
HEI’s consolidated ROACE was 12.5% for the twelve months ended March 31, 2017 and 8.4% for the twelve months ended March 31, 2016. The higher ROACE for the twelve months ended March 31, 2017 was largely due to the merger termination fee received in July 2016.
Dividends. The payout ratios for the first three months of 2017 and full year 2016 were 99% and 54%, respectively. HEI currently expects to maintain its dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company and current and expected future economic conditions.
Economic conditions.
Note: The statistical data in this section is from public third-party sources that management believes to be reliable (e.g., Department of Business, Economic Development and Tourism (DBEDT), University of Hawaii Economic Research Organization, U.S. Bureau of Labor Statistics, Department of Labor and Industrial Relations (DLIR), Hawaii Tourism Authority (HTA), Honolulu Board of REALTORS® and national and local newspapers).
Hawaii’s tourism industry, a significant driver of Hawaii’s economy, continues growing, ending the first quarter of 2017 with record highs in both visitor spending and arrivals. Visitor expenditures increased 10.4% and arrivals increased 3.1% compared to the first quarter of 2016. Looking ahead, the Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the second quarter of 2017 to increase marginally by 0.9% over the second quarter of 2016 driven primarily by an increase in seats from the East coast and Japan.
Hawaii’s unemployment rate remained relatively stable at 2.7% in March 2017, lower than the state’s 3.1% rate in March 2016 and the March 2017 national unemployment rate of 4.5%.
Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices in 2017. Median sales prices for single family residential homes and condominiums on Oahu during the first quarter of 2017 were higher by 3.5% and 2.6%, respectively, over the first quarter of 2016. The number of closed sales for both single family residential homes and condominiums during the first quarter of 2017 were also up compared to first quarter of 2016 by 1.0% and 7.1%, respectively.
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Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. Through the first two months of 2016, the price of crude oil reached a historical low. Since then, the price of crude oil has steadily increased to levels previously seen in 2015.
At its March 2017 meeting, the Federal Open Market Committee (FOMC) increased the federal funds rate target for the second time in a decade. The FOMC raised the target range of “0.5% to 0.75%” to “0.75% to 1%”. FOMC has indicated a slight uptick in the inflation rate to 1.9%, nearing the FOMC target of 2%.
Overall, Hawaii is expected to see a slight slowing in economic growth. Tourism will be aided by HTA’s marketing efforts targeting Japan and the East coast. However, growth in the construction industry is dampening as the value of private building permits is in decline. Slowing in construction could be tied to a weakening in the retail environment with the closing of stores by common anchor tenant retailers like Sports Authority and Sears. Geopolitical uncertainties could also negatively impact tourism but would accelerate the U.S. military pivot to Asia-Pacific, positively influencing the local economy.
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 | Primary reason(s) |
| Revenues | $ | 95 | $ | 68 |
| Operating loss | (5,236 | ) | (6,069 | ) | First quarter 2016 merger and spin-off-related expenses (see below), partly offset by higher administrative and general expenses in the first quarter of 2017 |
| Net loss | (3,085 | ) | (5,688 | ) | Lower operating loss, lower interest expense due to lower interest rates and higher tax benefits relative to the operating loss (due to non-deductibility of certain merger- and spin-off-related expenses in first quarter 2016 and the recognition of excess tax benefits on share-based compensation after the adoption of ASU No. 2016-09 on January 1, 2017) |

The “other” business segment includes results of the stand-alone corporate operations of HEI and ASB Hawaii, Inc. (ASBH), both holding companies; HEI Properties, Inc., a company which held passive, venture capital investments (all of which have been sold or abandoned prior to its dissolution in December 2015); and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999, but has remaining employee benefit payments; as well as eliminations of intercompany transactions. Expenses recorded at HEI related to the previously proposed merger with NEE and spin-off of ASBH amounted to $1.5 million for the first quarter of 2016. See Note 2, “Termination of proposed merger and other matters,”
FINANCIAL CONDITION
Liquidity and capital resources. The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements for the foreseeable future.
| (dollars in millions) | March 31, 2017 | December 31, 2016 |
| Short-term borrowings—other than bank | $ | 2 | — | % | $ | — | — | % |
| Long-term debt, net—other than bank | 1,619 | 43 | 1,619 | 43 |
| Preferred stock of subsidiaries | 34 | 1 | 34 | 1 |
| Common stock equity | 2,066 | 56 | 2,067 | 56 |
| $ | 3,721 | 100 | % | $ | 3,720 | 100 | % |

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HEI’s short-term borrowings and HEI’s line of credit facility were as follows:
| Average balance | Balance |
| (in millions) | Three months ended March 31, 2017 | March 31, 2017 | December 31, 2016 |
| Short-term borrowings 1 |
| Commercial paper | $ | — | $ | 1 | $ | — |
| Line of credit draws | — | — | — |
| Undrawn capacity under HEI’s line of credit facility | 150 | 150 |

1 This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” The maximum amount of HEI’s external short-term borrowings during the first three months of 2017 was $0.8 million. As of April 27, 2017, HEI had $3.1 million of outstanding commercial paper, and its line of credit facility was undrawn.
HEI has a line of credit facility, as amended and restated on April 2, 2014, of $150 million. See Note 12 of the Condensed Consolidated Financial Statements.
From December 7, 2016 to date, HEI satisfied the share purchase requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances.
In October 2015, HEI amended and extended a two-year $125 million term loan agreement that it entered into on May 2, 2014, which extended term loan now matures on October 6, 2017. In March 2016, HEI entered into a $75 million term loan agreement with Bank of America, N.A., which matures on March 23, 2018.
In December 2014, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities.
For the first three months of 2017, net cash provided by operating activities of HEI consolidated was $94 million. Net cash used by investing activities for the same period was $231 million, primarily due to Hawaiian Electric’s consolidated capital expenditures and ASB’s purchases of investment securities, partly offset by ASB’s receipt of repayments from investment securities, proceeds from the sale of commercial loans and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $93 million as a result of several factors, including increases in ASB’s deposit liabilities and net increases in ASB’s retail purchase agreements, partly offset by the payment of common stock dividends and repayments of other bank borrowings. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition—Liquidity and capital resources” sections below.) During the first three months of 2017, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $22 million and $9 million, respectively.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION
The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 47, 62 to 64, and 73 to 75 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2016 Form 10-K.
Additional factors that may affect future results and financial condition are described on pages iv and v under “Cautionary Note Regarding Forward-Looking Statements.”
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments.
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For information about these material estimates and critical accounting policies, see pages 48 to 49, 64 to 65, and 75 to 78 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2016 Form 10-K.
Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
Electric utility
RESULTS OF OPERATIONS
Results.
| Three months ended March 31 | Increase |
| 2017 | 2016 | (decrease) | (dollars in millions, except per barrel amounts) |
| $ | 519 | $ | 482 | $ | 37 | Revenues. Net increase largely due to: |
| $ | 34 | higher fuel oil prices1 |
| 21 | higher purchased power energy costs2 |
| (11 | ) | lower RAM revenues due to expiration of 2013 settlement agreement that allowed the accrual of RAM revenues on January 1 for years 2014 to 2016 at Hawaiian Electric |
| (5 | ) | lower PPAC revenues |
| (3 | ) | lower KWH purchased |
| 1 | higher KWH generated |
| 144 | 114 | 30 | Fuel oil expense. Increase due to higher fuel oil prices |
| 127 | 116 | 11 | Purchased power expense. Increase due to higher fuel oil prices |
| 100 | 104 | (4 | ) | Operation and maintenance expenses. Net decrease due to: |
| (3 | ) | PSIP consulting costs incurred in 2016, in order to complete the PSIP update in April 2016 |
| (2 | ) | LNG consulting costs incurred in 2016 to negotiate an LNG contract that was subsequently terminated following HEI/NextEra merger termination |
| 1 | additional reserves for environmental costs in 20173 |
| 98 | 93 | 5 | Other expenses. Increase due to higher revenue taxes from higher revenue, coupled with higher depreciation expense for plant investments in 2016 |
| 49 | 55 | (6 | ) | Operating income. Decrease due to higher revenue taxes and depreciation expense |
| 21 | 25 | (4 | ) | Net income for common stock. Decrease due to lower operating income |
| 2,038 | 2,085 | (47 | ) | Kilowatthour sales (millions)4 |
| 884 | 884 | — | Cooling degree days (Oahu) |
| $ | 65.85 | $ | 53.99 | $ | 11.86 | Average fuel oil cost per barrel1 |
| 460,724 | 458,464 | 2,260 | Customer accounts (end of period) |

| 1 | 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. |

| 2 | The rate schedules of the electric utilities currently contain purchase power adjustment clauses (PPAC) through which changes in purchase power expenses (except purchased energy costs) are passed on to customers. |

| 3 | Increase reserve for additional costs for investigation of PCB contamination onshore and offshore of Waiau Power Plant |

| 4 | KWH sales were lower when compared to the same quarter in the prior year due largely to continued energy efficiency and conservation efforts by customers and increasing levels of private customer-sited renewable generation. |

Notes: The Utilities effective tax rates (combined federal and state income tax rates) for the first three months of 2017 and 2016 were 37% and 36%, respectively.
Hawaiian Electric’s consolidated ROACE was 7.8% for the twelve months ended March 31, 2017 and 7.9% for the twelve months ended March 31, 2016.
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The Utilities’ consolidated KWH sales have declined each year since 2007. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the Utilities’ full year 2017 KWH sales are expected to be below the 2016 level.
The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of March 31, 2017 amounted to $4 billion, of which approximately 25% related to production PPE, 66% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 2% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission. See “Adequacy of supply” below.
See “Economic conditions” in the “HEI Consolidated” section above.
Executive overview and strategy. The Utilities provide electricity on all the principal islands in the state other than Kauai and operate five separate grids. The Utilities’ mission is to provide innovative energy leadership for Hawaii, to meet the needs and expectations of customers and communities, and to empower them with affordable, reliable and clean energy. The goal is to create a modern, flexible and dynamic electric grid that enables an optimal mix of distributed energy resources (such as private rooftop solar), demand response and grid-scale resources to achieve the statutory goal of 100% renewable energy by 2045.
Transition to renewable energy. The Utilities are committed to assisting the State of Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy by 2045. Hawaii’s RPS law was revised in the 2015 Legislature and requires electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045, respectively. Energy savings resulting from DSM energy efficiency programs and solar water heating do not count toward these RPS. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems and exceeded the 2015 RPS goal. The Utilities' RPS for 2016 was about 26% and on its way to achieving the 2020 RPS goal of 30%. The Utilities led the nation in 2016 and 2015 in the percentage of its customers who have installed PV systems. (See "Developments in renewable energy efforts” below).
In 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed proposed Power Supply Improvement Plans (PSIPs) with the PUC, as required by PUC orders issued in April 2014 (see “April 2014 regulatory orders” in Note 4 of the Condensed Consolidated Financial Statements). Updated PSIPs were filed in April 2016 providing plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045. Under these plans, the Utilities will support sustainable growth of private rooftop solar, expand use of energy storage systems, empower customers by developing smart grids and offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs). In December 2016, the Utilities filed a PSIP Update Report as ordered by the PUC. The updated plans describe greater and faster expansion of the Utilities’ renewable energy portfolio than in the plans filed in April 2016, and emphasize work that is in progress or planned over the next five years on each of the five islands the Utilities serve. The plans include the continued growth of private rooftop solar and describe the grid and generation modernization work needed to reliably integrate an estimated total of 165,000 private systems by 2030, more than double today’s total of 79,000, and additional grid-scale renewable energy resources. The Utilities already have the highest percentage of customers using private rooftop solar of any utility in the U.S. and customer-sited resources are seen as a key contributor to the growth of the renewable portfolio on every island. In addition, the plans forecast the addition of 360 MW of grid-scale solar and 157 MW of grid-scale wind, with 32 MW derived from community-based renewable energy (CBRE). The plans also include 115 MW from Demand Response (DR) programs, which can shift customer use of electricity to times when more renewable energy is available, potentially making room to add even more renewable resources. Unlike the April 2016 updated PSIPs, the December 2016 update does not include the use of LNG to generate power in the near-term or the Kahe 3x1 Combined Cycle Plant. While LNG remains a potential lower-cost bridge fuel to be evaluated, the Utilities’ priority is to continue replacing fossil fuel generation with renewables over the next five years as federal tax incentives for renewables begin to phase out. An interisland cable is not in the near-term plan, which states that its costs and benefits should continue to be evaluated.
On October 1, 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed a proposed CBRE program and tariff with the PUC that will allow customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. The program, if approved by the PUC, would allow customers to buy an interest in electricity generated by community renewable projects on their island without installing systems on their own roofs or property. In November 2015, the PUC suspended the tariff submittal and opened an investigatory docket. In February 2017, the PUC issued a proposed CBRE Program Framework and a Proposed Model Tariff Language, and requested comments and feedback from the parties by March 1, 2017. Under the proposed CBRE Program Framework, the CBRE program will utilize a phased approach. The Program Framework proposes a Phase 1 with an 80 MW capacity statewide with 73 MW allocated to the Utilities' service territories. During the two year initial phase, the Utilities' primary role is to serve as the program administrator. In addition, the Framework requires a minimum allocation of 7.5 MW to develop CBRE targeting low-to-moderate income subscribers with 6.75 MW allocated to the Utilities' service territories.
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After launching a smart grid customer engagement plan during the second quarter of 2014, Hawaiian Electric replaced approximately 5,200 residential and commercial meters with smart meters, 160 direct load control switches, fault circuit indicators and remote controlled switches in selected areas across Oahu as part of the Smart Grid Initial Phase implementation. Also under the Initial Phase a grid efficiency measure called Volt/Var Optimization (or Conservation Voltage Reduction) was enabled, customer energy portals were launched and are available for customer use and a PrePay Application was launched. The Initial Phase implementation was completed in 2015. The smart grid provides benefits such as customer tools to manage their electric bills, potentially shortening outages and enabling the Utilities to integrate more low-cost renewable energy, like wind and solar, which will reduce Hawaii’s dependence on imported oil. In March 2016, the Utilities sought PUC approval to commit funds for an expansion of the smart grid project. The proposed smart grid project was estimated to cost $340 million and be implemented over 5 years (beginning in 2017 for Oahu and 2018 for Hawaii Island and Maui County). On January 4, 2017, the PUC issued an order dismissing the application without prejudice and directing the Utilities to submit a Grid Modernization Strategy.
The PUC indicated that the overall goal of the Grid Modernization Strategy is to deploy modern grid investments at an appropriate priority, sequence and pace to cost-effectively maximize flexibility, minimize the risk of redundancy and obsolescence, deliver customer benefits and enable greater DER and renewable energy integration. The Utilities will file an initial draft of the Grid Modernization Strategy for stakeholder review by June 30, 2017 and final Grid Modernization Strategy by August 29, 2017.
Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 and 2012. The decoupling model delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. In May 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. In February 2014, March 2015, and April 2017, the PUC issued orders to make certain modifications to the decoupling mechanism. See "Decoupling" in Note 4 of the Condensed Consolidated Financial Statements for a discussion of changes to the RAM component of decoupling.
As part of decoupling, the Utilities also track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility's rate-making ROACE is compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. Annual earnings of a utility over and above the ROACE allowed by the PUC are shared between the utility and its ratepayers on a tiered basis. Results for 2016 and 2015 did not trigger the earnings sharing mechanism for the Utilities. For 2014, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric credited $0.5 million to its customers for their portion of the earnings sharing during the period between June 2015 to May 2016. Earnings sharing credits are included in the annual decoupling filing for the following year.
Annual decoupling filings. See “Decoupling” in Note 4 of the Condensed Consolidated Financial Statements for a discussion of the 2017 annual decoupling filings.
| % | Return on rate base (RORB)* | ROACE** | Rate-making ROACE*** |
| Twelve months ended March 31, 2017 | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Hawaiian Electric | Hawaii Electric Light | Maui Electric | Hawaiian Electric | Hawaii Electric Light | Maui Electric |
| Utility returns | 7.21 | 6.96 | 7.12 | 7.88 | 7.47 | 8.07 | 8.90 | 7.99 | 8.56 |
| PUC-allowed returns | 8.11 | 8.31 | 7.34 | 10.00 | 10.00 | 9.00 | 10.00 | 10.00 | 9.00 |
| Difference | (0.90 | ) | (1.35 | ) | (0.22 | ) | (2.12 | ) | (2.53 | ) | (0.93 | ) | (1.10 | ) | (2.01 | ) | (0.44 | ) |

* Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.
** Recorded net income divided by average common equity.
*** ROACE adjusted to remove items not included by the PUC in establishing rates, such as incentive compensation and certain advertising.
The gap between PUC-allowed ROACEs and the ROACEs actually achieved is primarily due to: the consistent exclusion of certain expenses from rates, the low RBA interest rate (currently a short-term debt rate rather than the actual cost of capital), O&M increases and return on capital additions since the last rate case in excess of indexed escalations, and the portion of the pension regulatory asset not earning a return due to pension contributions and pension costs in excess of the pension amount in rates.
The PUC approved a two-year special medical needs pilot program, which will provide residential customers who depend on life support a discounted non-fuel energy charge. The program will be effective from April 1, 2017 to March 31, 2019, with a maximum savings of $20 per month per participant and limited to 2,000 participants. The discount will not be reflected as part of the target adjusted revenues in the Revenue Balancing Account Provision.
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Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility is currently required by PUC order to initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and to allow the utility to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
| Test year(dollars in millions) | Date(filed/implemented) | Amount | % over rates in effect | ROACE(%) | RORB(%) | Rate base | Commonequity% | Stipulated agreement reached withConsumerAdvocate |
| Hawaiian Electric |
| 2011 (1) |
| Request | 7/30/10 | $ | 113.5 | 6.6 | 10.75 | 8.54 | $ | 1,569 | 56.29 | Yes |
| Interim increase | 7/26/11 | 53.2 | 3.1 | 10.00 | 8.11 | 1,354 | 56.29 |
| Interim increase (adjusted) | 4/2/12 | 58.2 | 3.4 | 10.00 | 8.11 | 1,385 | 56.29 |
| Interim increase (adjusted) | 5/21/12 | 58.8 | 3.4 | 10.00 | 8.11 | 1,386 | 56.29 |
| Final increase | 9/1/12 | 58.1 | 3.4 | 10.00 | 8.11 | 1,386 | 56.29 |
| 2014 (2) |
| Request | 6/27/14 |
| 2017 (3) |
| Request | 12/16/16 | $ | 106.4 | 6.9 | 10.60 | 8.28 | $ | 2,002 | 57.36 |
| Hawaii Electric Light |
| 2010 (4) |
| Request | 12/9/09 | $ | 20.9 | 6.0 | 10.75 | 8.73 | $ | 487 | 55.91 | Yes |
| Interim increase | 1/14/11 | 6.0 | 1.7 | 10.50 | 8.59 | 465 | 55.91 |
| Interim increase (adjusted) | 1/1/12 | 5.2 | 1.5 | 10.50 | 8.59 | 465 | 55.91 |
| Final increase | 4/9/12 | 4.5 | 1.3 | 10.00 | 8.31 | 465 | 55.91 |
| 2013 (5) |
| Request | 8/16/12 | $ | 19.8 | 4.2 | 10.25 | 8.30 | $ | 455 | 57.05 |
| Closed | 3/27/13 |
| 2016 (6) |
| Request | 9/19/16 | $ | 19.3 | 6.5 | 10.60 | 8.44 | $ | 479 | 57.12 |
| Maui Electric |
| 2012 (7) |
| Request | 7/22/11 | $ | 27.5 | 6.7 | 11.00 | 8.72 | $ | 393 | 56.85 | Yes |
| Interim increase | 6/1/12 | 13.1 | 3.2 | 10.00 | 7.91 | 393 | 56.86 |
| Final increase | 8/1/13 | 5.3 | 1.3 | 9.00 | 7.34 | 393 | 56.86 |
| 2015 (8) |
| Request | 12/30/14 |

Note: The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases.
(1) Hawaiian Electric filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by Hawaiian Electric in a separate depreciation proceeding. Hawaiian Electric’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.
The $53.2 million, $58.2 million and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.
(2) See “Hawaiian Electric 2014 test year rate case” below.
(3) See “Hawaiian Electric 2017 test year rate case” below.
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| (4) | 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. |

(5) 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 a 2013 agreement with the Consumer Advocate, which was approved by the PUC in March 2013, the rate case was withdrawn and the docket was closed.
| (6) | See “Hawaii Electric Light 2016 test year rate case” below. |

(7) 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. The final D&O approved an increase in annual revenue of $5.3 million, which was $7.8 million less than the interim increase in annual revenues that had been in effect since June 1, 2012. Maui Electric refunded to customers approximately $9.7 million (which included interest accrued) between September 2013 and early November 2013.
| (8) | See “Maui Electric 2015 test year rate case” below. |

Hawaiian Electric 2014 test year rate case. On June 27, 2014, Hawaiian Electric submitted an abbreviated rate case filing (abbreviated filing), stating that it intends to forgo the opportunity to seek a general rate increase in base rates and, if approved, this filing would result in no change in base rates. Hawaiian Electric stated that it is foregoing a rate increase request in recognition that its customers are already in a challenging high electricity bill environment, and further explained its view that the abbreviated filing satisfies the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O.
On December 27, 2016, the PUC issued an order consolidating the filings for this rate case with the Hawaiian Electric 2017 test year rate case and closed the docket.
Maui Electric 2015 test year rate case. On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby forgoing the opportunity to seek a general rate increase. Maui Electric stated that, if it were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 RAM revenues. The indicated normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%.
Management cannot predict whether the PUC will accept this abbreviated filing to satisfy Maui Electric’s obligation to file a rate case in 2015, whether additional material will be required to be submitted or whether Maui Electric will be required to proceed with a traditional rate proceeding.
Hawaii Electric Light 2016 test year rate case. On September 19, 2016, Hawaii Electric Light filed an application with the PUC for a general rate increase of $19.3 million over revenues at current effective rates (for a 6.5% increase in revenues), based on an 8.44% rate of return (which incorporates a return on equity of 10.60%). The last rate increase in base rates for Hawaii Electric Light was in January 2011. The $19.3 million requested is to cover higher operating costs (including expanded vegetation management focusing on albizia tree removal and increased pension costs) and system upgrades to increase reliability, improve customer service and integrate more renewable energy. As part of this case, Hawaii Electric Light is also taking steps towards innovative ratemaking by proposing implementation of performance based regulation (PBR) mechanisms to measure and link certain revenues to its performance in areas of customer service, reliability and communication relating to the private rooftop solar interconnection process. Hawaii Electric Light proposed an expansion of the range of fuel usage efficiencies under which fuel costs would be fully passed through to customers, and an additional trigger that would allow a re-establishment of fuel usage efficiency targets under certain conditions. In addition, Hawaii Electric Light proposed an equal sharing of fuel expenses outside the fuel usage efficiency target range. Hawaii Electric Light also proposed revenue adjustments to recover costs associated with the acquisition and operation of the power plant currently owned by Hamakua Energy Partners, L.P. Hawaii Electric Light requested approval of the acquisition of this power plant in a separate application filed on February 12, 2016.
The PUC held public hearings for this rate case in December 2016. On April 13, 2017, the PUC issued an order allowing the County of Hawaii to participate in the proceeding and denying the motions to intervene of two other parties.
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On April 28, 2017, the Consumer Advocate filed its testimony in the proceeding, recommending an increase of $2.7 million over revenues at current effective rates (for a 0.9% increase in revenues), based on a 7.29% rate of return (which incorporates a return on equity of 8.75%). The stipulated procedural schedule filed by Hawaii Electric Light and the Consumer Advocate, subject to PUC approval, includes an evidentiary hearing at the end of July 2017.
Hawaiian Electric 2017 test year rate case. On December 16, 2016, Hawaiian Electric filed an application with the PUC for a general rate increase of $106.4 million over revenues at current effective rates (for a 6.9% increase in revenues), for a 2017 test year. The request is based on an 8.28% rate of return (which incorporates a return on equity of 10.6% and a capital structure that includes a 57.4% common equity capitalization) on a $2.0 billion rate base. The $106.4 million request is primarily to pay for operating costs and for system upgrades to increase reliability, improve customer service and integrate more renewable energy. The application is also proposing a step adjustment to increase base rates by an additional $20.6 million when the Schofield Generation Station is placed in service, which is expected in the first quarter of 2018. As in Hawaii Electric Light’s rate increase application filed in September 2016, Hawaiian Electric’s application is taking steps toward innovative ratemaking by proposing implementation of PBR mechanisms related to its performance in areas of customer service, reliability and communication relating to the private rooftop solar interconnection process. Hawaiian Electric proposed an expansion of the range of fuel usage efficiencies under which fuel costs would be fully passed through to customers, and an additional trigger that would allow a re-establishment of fuel usage efficiency targets under certain conditions. On February 22, 2017, the PUC held public hearings for this rate case. See “Hawaiian Electric consolidated 2014 test year abbreviated and 2017 test year cases” in Note 4 of the Condensed Consolidated Financial Statements.
Developments in renewable energy efforts. Developments in the Utilities’ efforts to further their renewable energy strategy include the following:
| • | In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for construction of a 50-MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu. In September 2015, the PUC approved Hawaiian Electric's application with conditions and limitations. See "Schofield Generating Station Project" in Note 4 of the Condensed Consolidated Financial Statements. Once online, biodiesel currently delivered to Hawaiian Electric's Campbell Industrial Park Combustion Turbine 1 (CIP CT-1) will be diverted to the Schofield Generating Station at no additional cost. |

| • | In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s (NPM) proposed 24-MW wind farm located in the Kahuku area on Oahu from the competitive bidding process and the PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and NPM for the proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA. On September 15, 2016, Hawaiian Electric filed the Amended and Restated PPA, dated August 12, 2016, which reflects the completion of the interconnection requirements study, including, among other things, amendments related to the final design of the facility, scope of work, cost, schedule and reporting milestones. The PUC conducted a public hearing on February 2, 2017, regarding the request for PUC approval to construct an overhead 46 sub-transmission line to accommodate the interconnection of the NPM wind farm. This project is expected to be placed into service by August 31, 2019. |

| • | In July 2015, the PUC approved the PPA for the 27.6 MW Waianae Solar project that is being developed by Eurus Energy America. The project achieved commercial operations in January 2017 and is now the largest solar project in Hawaii. |

| • | In July 2015, Maui Electric signed two PPAs, with Kuia Solar and South Maui Renewable Resources (which subsequently assigned its PPA to SSA Solar of HI 3, LLC), each for a 2.87-MW solar facility. In February 2016, the PUC approved both PPAs, subject to certain conditions and modifications. The guaranteed commercial operations date for the facilities was December 31, 2016, however both projects are experiencing delays and are expected to be completed by the end of the third quarter in 2017. |

| • | In September 2015, the PUC approved Hawaiian Electric’s 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC (PBT) to supply 2 million to 3 million gallons of biodiesel at CIP CT-1 and the Honolulu International Airport Emergency Power Facility beginning in November 2015. The PBT contract was set to expire on November 2, 2017 with possible 1 year extensions. PBT also has a spot buy contract with Hawaiian Electric to purchase additional quantities of biodiesel at or below the price of diesel. Some purchases of “at parity” biodiesel have been made under the spot purchase contract, which was recently extended through June 2018. REG Marketing & Logistics Group, LLC has a contingency supply contract with Hawaiian Electric to also supply biodiesel to CIP CT-1 in the event PBT is not able to supply necessary quantities. This contingency contract has been extended to November 2018, and will continue with no volume purchase requirements. |

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| • | In October 2015, the Utilities filed with the PUC a proposal for a Community-Based Renewable Energy (CBRE) program and tariff that would allow customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. In November 2015, the PUC suspended the filing and opened a docket to investigate the matter. In February 2017, the PUC issued a proposed CBRE Program Framework, a Proposed Model Tariff Language, and requested comments and feedback from the parties by March 1, 2017. Under the proposed CBRE Program Framework, the CBRE program will utilize a phased approach. The Program Framework proposes a Phase 1 with an 80 MW capacity statewide with 73 MW allocated to the Utilities' service territories. During the two year initial phase, the Utilities' primary role is to serve as the program administrator. In addition, the Framework requires a minimum allocation of 7.5 MW to develop CBRE targeting low-to-moderate income subscribers with 6.75 MW allocated to the Utilities' service territories. |

| • | On May 5, 2016, Maui Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Maui Electric Dispatchable Firm Generation Request for Proposals. The solicitation intends to seek approximately 20 MW of new renewable generation capacity and approximately 20 MW of fuel flexible firm generation resources on the island of Maui by 2022. |

| • | On June 6, 2016, Hawaiian Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Hawaiian Electric Renewable Energy Request for Proposals. The solicitation intends to seek new renewable energy generation on the island of Oahu to be placed into service by the end of 2020, consistent with the Five-Year Action Plan proposed in the PSIP Update Report. |

| • | In July 2016, Hawaiian Electric announced plans to build, own and operate a 20-MW solar facility in conjunction with the Department of the Navy at a Navy/Air Force joint base, subject to PUC approval. On October 3, 2016, Hawaiian Electric filed with the PUC a request to waive the $67 million project from the Competitive Bidding Framework and to approve expenditures for the project. If approved by the PUC, the solar facility would generate renewable energy that will feed into Oahu's electrical grid at the low cost of 9.54 cents per KWH. |

| • | The Utilities began accepting energy from feed-in tariff projects in 2011. As of March 31, 2017, there were 29 MW, 3 MW and 4 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively. |

| • | As of March 31, 2017, there were approximately 316 MW, 74 MW and 84 MW of installed distributed renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, for tariff-based private customer generation programs, namely NEM, Customer Grid Supply (CGS) and Customer Self Supply (CSS). As of March 31, 2017, an estimated 26% of single family homes on the islands the Utilities serve have installed private rooftop solar systems, and an estimated 29% of single family homes have installed, or have been approved to install, private rooftop solar systems. As of March 31, 2017, approximately 16% of the Utilities' total customers have solar systems. |

| • | On January 5, 2017, Hawaiian Electric issued an Onshore Wind Expression of Interest requesting expressions of interest from independent power producers that are capable of developing utility scale onshore wind projects that are eligible to capture the federal Investment Tax Credit for Large Wind on the island of Oahu. Responses have been accepted and are being evaluated. |

| • | On January 6, 2017, Hawaii Electric Light and Maui Electric requested the PUC to open dockets to allow them to seek proposals for new renewable energy generation on the islands of Hawaii, Maui, Molokai, and Lanai. |

| • | On December 12, 2016, the Utilities issued a request for information asking interested landowners to provide information about properties on Oahu, Hawaii Island, Maui, Molokai and Lanai available for utility-scale renewable energy projects or for growing biofuel feedstock. Responses have been accepted and are being evaluated. |

| • | Hawaiian Electric had PPAs to purchase solar energy with three affiliates of SunEdison. In February 2016, as a result of the project entities missing contract milestones, Hawaiian Electric terminated the original PPAs for the three projects. SunEdison filed Chapter 11 bankruptcy proceedings and during those proceedings, the three SunEdison affiliates were acquired by an affiliate of NRG Energy, Inc. (NRG). Hawaiian Electric then negotiated with NRG and its newly acquired affiliates and has entered into amended and restated PPAs for solar energy on Oahu, subject to PUC approval, with Waipio PV, LLC for 45.9 MW, Lanikuhana Solar, LLC for 14.7 MW and Kawailoa Solar, LLC for 49 MW. |

Other regulatory matters. In addition to the items below, also see Note 4 of the Condensed Consolidated Financial Statements.
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Adequacy of supply.
Hawaiian Electric. In January 2017, Hawaiian Electric filed its 2017 Adequacy of Supply (AOS) letter, which indicated that based on its October 2016 sales and peak forecast for the 2017 - 2021 time period, Hawaiian Electric's generation capacity will be sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2018, but may have shortfalls in meeting the Utilities’ generating system reliability guideline. The calculated reliability guideline shortfalls are relatively small and Hawaiian Electric can implement mitigation measures.
In accordance to its planning criteria, Hawaiian Electric deactivated two fossil fuel generating units from active service at its Honolulu Power Plant in January 2014 and anticipates deactivating two additional fossil fuel units at its Waiau Power Plant in the 2022 timeframe. Hawaiian Electric is proceeding with future firm capacity additions in coordination with the State of Hawaii Department of Transportation in 2017, and with the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, including black start capabilities, generation security project on federal lands, which is expected to be in service in the first quarter of 2018. Hawaiian Electric is continuing negotiations with firm capacity IPPs on Oahu. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the Kalaeloa PPA prior to October 31, 2017. The PPA with AES Hawaii is scheduled to expire in 2022.
Hawaii Electric Light. In January 2017, Hawaii Electric Light filed its 2017 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2019 is sufficient to meet reasonably expected demands for service and provide for reasonable reserves for emergencies. Additional generation from other renewable resources could be added in the 2020-2025 timeframe.
Maui Electric. In January 2017, Maui Electric filed its 2017 AOS letter, which indicated that Maui Electric’s generation capacity for the islands of Lanai and Molokai for the next three years is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. The 2017 AOS letter also indicated that without the peak reduction benefits of demand response but with the equivalent firm capacity value of wind generation, Maui Electric expects to have a small reserve capacity shortfall from 2017 to 2022 on the island of Maui. Maui Electric is evaluating several measures to mitigate the anticipated reserve capacity shortfall. Maui Electric anticipates needing a significant amount of additional firm capacity on Maui in the 2022 timeframe after the planned retirement of the Kahului Power Plant.
In February 2014, Maui Electric deactivated two fossil fuel generating units, with a combined rating of 11.4 MW-net, at its Kahului Power Plant. Due to various system conditions including lack of wind generation, approaching storms and scheduled and unscheduled outages of generating units, transmission lines and independent power producers, the two deactivated units at Kahului Power Plant were reactivated for several days in 2015 and 2016. Due to the frequency of reactivations of Kahului Units 1 and 2 to meet system requirements, these units were removed from deactivated status and designated as reactivated in September 2016. Considering the time needed to acquire replacement firm generating capacity, Maui Electric now anticipates the retirement of all generating units at the Kahului Power Plant, which have a combined rating of 32.3 MW, in the 2022 timeframe. A capacity planning analysis is in progress to better define generating needs and timing. Maui Electric plans to issue one or more RFPs for energy storage, demand response and firm generating capacity, and to make system improvements needed to ensure reliability and voltage support in this timeframe. In May 2016, Maui Electric requested that the PUC open a new docket for Maui Electric’s competitive bidding process for additional firm capacity resources. In September 2016, Maui Electric submitted an application to purchase and install three temporary mobile distributed generation diesel engines to address increasing reserve capacity shortfalls on the island of Maui, but in February 2017 Maui Electric requested the PUC to suspend the proceeding until the progress in the demand response programs and the DR portfolio proceeding can be further evaluated.
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 “Environmental regulation” and “Recent tax developments” in Note 4 of the Condensed Consolidated Financial Statements.
Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii. Randall Y. Iwase is the Chair of the PUC (for a term that will expire in June 2020) and was formerly a state legislator, Honolulu city council member, supervising deputy attorney general, and Chair of the Hawaii State Tax Review Commission. The other commissioner is Lorraine H. Akiba (for a term that will expire in June 2018), who previously was an attorney in private practice who earlier served as the Director of the State Department of Labor and Industrial Relations. One commission seat is vacant pending an appointment by the Governor and subject to confirmation by the State Senate.
The Division of Consumer Advocacy is led by its Executive Director, Dean Nishina, most recently serving as the division’s Public Utilities Administrator.
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FINANCIAL CONDITION
Liquidity and capital resources. Management believes that Hawaiian Electric’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities and commercial paper and draws on lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.
| (dollars in millions) | March 31, 2017 | December 31, 2016 |
| Short-term borrowings | $ | 1 | — | % | $ | — | — | % |
| Long-term debt, net | 1,319 | 42 | 1,319 | 42 |
| Preferred stock | 34 | 1 | 34 | 1 |
| Common stock equity | 1,800 | 57 | 1,800 | 57 |
| $ | 3,154 | 100 | % | $ | 3,153 | 100 | % |

Information about Hawaiian Electric’s short-term borrowings (other than from Hawaii Electric Light and Maui Electric) and Hawaiian Electric’s line of credit facility were as follows:
| Average balance | Balance |
| (in millions) | Three months ended March 31, 2017 | March 31, 2017 | December 31, 2016 |
| Short-term borrowings 1 |
| Commercial paper | $ | 1 | $ | 1 | $ | — |
| Line of credit draws | — | — | — |
| Borrowings from HEI | — | — | — |
| Undrawn capacity under line of credit facility | 200 | 200 |

1 The maximum amount of external short-term borrowings by Hawaiian Electric during the first three months of 2017 was $16 million. As of March 31, 2017, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $6.5 million and $2.5 million, respectively. As of April 27, 2017, Hawaiian Electric had $3.5 million of outstanding commercial paper, no draws under its line of credit facility and no borrowings from HEI. Also, as of April 27, 2017, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $3.5 million and nil, respectively, which intercompany borrowings are eliminated in consolidation.
Hawaiian Electric has a line of credit facility, as amended and restated on April 2, 2014, of $200 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. See Note 12 of the Condensed Consolidated Financial Statements.
Special purpose revenue bonds (SPRBs) have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of Hawaiian Electric and its subsidiaries, but the sources of their repayment are the non-collateralized obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on the Series 2007A and Refunding Series 2007B SPRBs are insured by Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013, FGIC's plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of FGIC, which at the time the insured obligations were issued were higher than the ratings of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.
In May 2015, up to $80 million of SPRBs ($70 million for Hawaiian Electric, $2.5 million for Hawaii Electric Light and $7.5 million for Maui Electric) were authorized by the Hawaii legislature for issuance, with PUC approval, prior to June 30, 2020 to finance the Utilities’ capital improvement programs.
On April 28, 2017, Hawaiian Electric, Hawaii Electric Light and Maui Electric received PUC approval to issue unsecured obligations bearing taxable interest and/or refunding SPRBs with principal amounts totaling up to $252 million, $88 million and $75 million, respectively, to refinance three series of outstanding revenue bonds. The approval is limited to 2017, and an expedited approval procedure will apply for refinancings during January 2018 through December 2020.
On January 26, 2017, Hawaiian Electric, Hawaii Electric Light and Maui Electric obtained PUC approval to issue, on or before December 31, 2017, unsecured obligations bearing taxable interest (Hawaiian Electric up to $100 million, Hawaii Electric Light up to $10 million and Maui Electric up to $30 million), with the proceeds expected to be used, as applicable, to
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finance capital expenditures, repay long-term and/or short term debt used to finance or refinance capital expenditures and/or to reimburse funds used for payment of capital expenditures.
In March 2017 and amended in April 2017, the Utilities requested PUC approval to issue and sell each utility’s common stock through December 31, 2021 (Hawaiian Electric’s sale/s to HEI of up to $150 million and Hawaii Electric Light’s and Maui Electric’s sale/s to Hawaiian Electric of up to $10 million each) and the purchase of Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric through December 31, 2021.
Cash flows. The following table reflects the changes in cash flows for the three months ended March 31, 2017 compared to the three months ended March 31, 2016:
| Three months ended March 31 |
| (in thousands) | 2017 | 2016 | Change |
| Net cash provided by operating activities | $ | 78,822 | $ | 146,871 | $ | (68,049 | ) |
| Net cash used in investing activities | (118,303 | ) | (111,377 | ) | (6,926 | ) |
| Net cash used in financing activities | (21,598 | ) | (10,901 | ) | (10,697 | ) |

Net cash provided by operating activities. 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.
The decrease in net cash provided by operating activities was impacted by the following:
| • | Lower cash from an increase in accounts receivable due to timing and increase in fuel prices. |

| • | Lower cash from an increase in fuel oil stock due to higher fuel prices. |

| • | Lower cash from refund of federal income taxes based on bonus depreciation enacted in the fourth quarter of 2015 that was subsequently received in 2016 (similar treatment was not granted in the fourth quarter of 2016). |

And partially offset by an increase in net cash from operating activities provided by the following:
| • | Higher cash from an increase in accounts payable due to higher fuel prices. |

Net cash used in investing activities. The increase in net cash used in investing activities was driven primarily by the increased capital expenditures related to construction activities and lower proceeds from contributions in aid of construction.
Net cash used in financing activities. Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. The increase in net cash used in financing activities primarily reflects lower proceeds from short-term borrowings.
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Bank
| Three months ended March 31 | Increase |
| (in millions) | 2017 | 2016 | (decrease) | Primary reason(s) |
| Interest income | $ | 58 | $ | 53 | $ | 5 | The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the three months ended March 31, 2017 increased by $97 million compared to the same period in 2016 as average commercial real estate, consumer and home equity lines of credit balances increased by $102 million, $59 million and $17 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased $78 million primarily due to a decrease in syndicated national credit loan portfolio. The yield on earning assets increased by 4 basis points due to a shift in the mix of the loan portfolio with the growth in the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 13 basis points and repricing of adjustable rate commercial loans with the increase in the prime rate. The average investment securities portfolio balance increased by $305 million due to the use of excess liquidity to purchase investments. |
| Noninterest income | 15 | 16 | (1 | ) | Noninterest income decreased slightly for the three months ended March 31, 2017 compared to noninterest income for the three months ended March 31, 2016 due to lower mortgage banking income and lower fee income on other financial products. |
| Revenues | 73 | 69 | 4 |
| Interest expense | 3 | 3 | — | Interest expense was flat for the three months ended March 31, 2017 compared to the same period in 2016 as higher interest expense from the growth in term certificates was offset by lower interest expense on other borrowings as a result of lower repurchase agreements. Average deposit balances for the three months ended March 31, 2017 increased by $535 million compared to the same period in 2016 due to an increase in core deposits and term certificates of $373 million and $162 million, respectively. Other borrowings decreased by $115 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate decreased by 4 basis points. |
| Provision for loan losses | 4 | 5 | (1 | ) | The provision for loan losses decreased by $0.9 million for the three months ended March 31, 2017 compared to the provision for loan losses for the three months ended March 31, 2016. The provision for loan losses for 2017 was primarily due to increased loan loss reserves for the consumer loan portfolio and additional loan loss reserves for the commercial real estate loan portfolio due to the downgrade of a commercial real estate relationship. The provision for loan losses for 2016 was primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for two commercial borrowers. Delinquency rates have decreased from 0.53% at March 31, 2016 to 0.42% at March 31, 2017. The annualized net charge-off ratio for the three months ended March 31, 2017 was 0.29% compared to an annualized net charge-off ratio of 0.21% for the same period in 2016. The increase in net charge-offs were due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing and loan charge-offs related to specific commercial borrowers. |
| Noninterest expense | 42 | 41 | 1 | The increase in noninterest expense for the three months ended March 31, 2017 compared to the same period in 2016 was primarily due to higher compensation and employee benefits expenses as a result of higher employee benefit costs. |
| Expenses | 49 | 49 | — |
| Operating income | 24 | 20 | 4 | Higher net interest income and lower provision for loan losses was partly offset by higher noninterest expenses and lower noninterest income. |
| Net income | 16 | 13 | 3 |

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See Note 5 of the Condensed Consolidated Financial Statements and “Economic conditions” in the “HEI Consolidated” section above.
ASB continues to maintain its low-risk profile, strong balance sheet and straightforward community banking business model.
| Three months ended March 31 |
| (percent) | 2017 | 2016 |
| Return on average assets | 0.98 | 0.84 |
| Return on average equity | 10.82 | 8.89 |
| Net interest margin | 3.68 | 3.62 |

Average balance sheet and net interest margin. The following tables provide a summary of average balances including major categories of interest-earning assets and interest-bearing liabilities:
| Three months ended March 31 |
| 2017 | 2016 |
| (dollars in thousands) | Averagebalance | Interest1 income/expense | Yield/rate (%) | Averagebalance | Interest1 income/expense | Yield/rate (%) |
| Assets: |
| Interest-earning deposits | $ | 92,590 | $ | 186 | 0.80 | $ | 79,320 | $ | 99 | 0.49 |
| FHLB stock | 11,234 | 48 | 1.72 | 10,779 | 44 | 1.64 |
| Available-for-sale investment securities |
| Taxable | 1,143,915 | 6,649 | 2.32 | 854,401 | 4,874 | 2.28 |
| Non-taxable | 15,427 | 150 | 3.89 | — | — | — |
| Total available-for-sale investment securities | 1,159,342 | 6,799 | 2.35 | 854,401 | 4,874 | 2.28 |
| Loans |
| Residential 1-4 family | 2,073,428 | 21,626 | 4.17 | 2,076,525 | 22,320 | 4.30 |
| Commercial real estate | 910,827 | 9,412 | 4.14 | 808,407 | 8,164 | 4.03 |
| Home equity line of credit | 868,435 | 7,116 | 3.32 | 851,329 | 6,865 | 3.24 |
| Residential land | 18,013 | 278 | 6.18 | 18,206 | 276 | 6.06 |
| Commercial | 670,321 | 7,155 | 4.32 | 748,774 | 7,372 | 3.94 |
| Consumer | 187,316 | 5,155 | 11.16 | 128,189 | 3,440 | 10.79 |
| Total loans 2,3 | 4,728,340 | 50,742 | 4.32 | 4,631,430 | 48,437 | 4.19 |
| Total interest-earning assets 2 | 5,991,506 | 57,775 | 3.88 | 5,575,930 | 53,454 | 3.84 |
| Allowance for loan losses | (56,236 | ) | (50,449 | ) |
| Non-interest-earning assets | 519,941 | 497,204 |
| Total assets | $ | 6,455,211 | $ | 6,022,685 |
| Liabilities and shareholder’s equity: |
| Savings | $ | 2,248,118 | $ | 374 | 0.07 | $ | 2,048,157 | $ | 333 | 0.07 |
| Interest-bearing checking | 885,700 | 55 | 0.03 | 821,868 | 42 | 0.02 |
| Money market | 155,672 | 47 | 0.12 | 167,244 | 53 | 0.13 |
| Time certificates | 661,468 | 1,627 | 1.00 | 499,617 | 1,164 | 0.93 |
| Total interest-bearing deposits | 3,950,958 | 2,103 | 0.22 | 3,536,886 | 1,592 | 0.18 |
| Advances from Federal Home Loan Bank | 100,000 | 775 | 3.10 | 102,061 | 786 | 3.05 |
| Securities sold under agreements to repurchase | 93,673 | 41 | 0.18 | 207,033 | 699 | 1.34 |
| Total interest-bearing liabilities | 4,144,631 | 2,919 | 0.28 | 3,845,980 | 3,077 | 0.32 |
| Non-interest bearing liabilities: |
| Deposits | 1,627,753 | 1,506,595 |
| Other | 98,033 | 100,175 |
| Shareholder’s equity | 584,794 | 569,935 |
| Total liabilities and shareholder’s equity | $ | 6,455,211 | $ | 6,022,685 |
| Net interest income | $ | 54,856 | $ | 50,377 |
| Net interest margin (%) 4 | 3.68 | 3.62 |

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| 1 | Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.05 million and nil for the three months ended March 31, 2017 and 2016, respectively. |

2 Includes loans held for sale, at lower of cost or fair value.
| 3 | Includes recognition of deferred loan fees of $0.5 million and $0.8 million for the three months ended March 31, 2017 and 2016, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans. |

| 4 | Defined as net interest income as a percentage of average total interest-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. These conditions have begun to moderate with the interest rate increases in the past year which resulted in an increase in ASB’s net interest income and net interest margin.
Loan originations and mortgage-related securities are ASB’s primary earning assets.
| March 31, 2017 | December 31, 2016 |
| (dollars in thousands) | Balance | % of total | Balance | % of total |
| Real estate: |
| Residential 1-4 family | $ | 2,058,202 | 43.5 | $ | 2,048,051 | 43.2 |
| Commercial real estate | 790,191 | 16.7 | 800,395 | 16.9 |
| Home equity line of credit | 866,880 | 18.3 | 863,163 | 18.2 |
| Residential land | 16,888 | 0.4 | 18,889 | 0.4 |
| Commercial construction | 130,808 | 2.8 | 126,768 | 2.7 |
| Residential construction | 13,694 | 0.3 | 16,080 | 0.3 |
| Total real estate, net | 3,876,663 | 82.0 | 3,873,346 | 81.7 |
| Commercial | 661,016 | 14.0 | 692,051 | 14.6 |
| Consumer | 192,113 | 4.0 | 178,222 | 3.7 |
| 4,729,792 | 100.0 | 4,743,619 | 100.0 |
| Less: Deferred fees and discounts | (4,521 | ) | (4,926 | ) |
| Allowance for loan losses | (55,997 | ) | (55,533 | ) |
| Total loans, net | $ | 4,669,274 | $ | 4,683,160 |

| March 31, 2017 | December 31, 2016 |
| Outstanding balance of home equity loans (in thousands) | $ | 866,880 | $ | 863,163 |
| Percent of portfolio in first lien position | 45.6 | % | 45.1 | % |
| Annualized net charge-off (recovery) ratio | (0.04 | )% | 0.01 | % |
| Delinquency ratio | 0.31 | % | 0.35 | % |

| End of draw period – interest only | Current |
| March 31, 2017 | Total | Interest only | 2017-2018 | 2019-2021 | Thereafter | amortizing |
| Outstanding balance (in thousands) | $ | 866,880 | $ | 684,552 | $ | 67,020 | $ | 103,440 | $ | 514,092 | $ | 182,328 |
| % of total | 100 | % | 79 | % | 8 | % | 12 | % | 59 | % | 21 | % |

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The HELOC portfolio comprised 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 79% of the total HELOC portfolio and is the current product offering. 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 March 31, 2017, approximately 19% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option.
Loan portfolio risk elements. See Note 5 of the Condensed Consolidated Financial Statements.
Available-for-sale investment securities. ASB’s investment portfolio was comprised as follows:
| March 31, 2017 | December 31, 2016 |
| (dollars in thousands) | Balance | % of total | Balance | % of total |
| U.S. Treasury and federal agency obligations | $ | 188,357 | 15 | % | $ | 192,281 | 18 | % |
| Mortgage-related securities — FNMA, FHLMC and GNMA | 1,025,138 | 84 | 897,474 | 81 |
| Mortgage revenue bond | 15,427 | 1 | 15,427 | 1 |
| Total available-for-sale investment securities | $ | 1,228,922 | 100 | % | $ | 1,105,182 | 100 | % |

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. government.
Deposits and other borrowings. Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the current environment due to competition for deposits and the low level of short-term interest rates. Advances from the FHLB of Des Moines and securities sold under agreements to repurchase continue to be additional sources of funds. As of March 31, 2017 and December 31, 2016, ASB’s costing liabilities consisted of 97% deposits and 3% other borrowings. The weighted average cost of deposits for the first three months of 2017 and 2016 was 0.16% and 0.13%, respectively.
Federal Home Loan Bank of Des Moines. As of March 31, 2017 and December 31, 2016, ASB had $100 million of advances outstanding at the FHLB of Des Moines. As of March 31, 2017, the unused borrowing capacity with the FHLB of Des Moines was $1.8 billion. The FHLB of Des Moines will continue to be a source of liquidity for ASB.
Other factors. Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in the fair value of the investment securities, respectively. In addition, changes in credit spreads also impact the fair values of the investment securities.
As of March 31, 2017, ASB had an unrealized loss, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $7.7 million compared to an unrealized loss, net of taxes, of $7.9 million at December 31, 2016. See “Item 3. Quantitative and qualitative disclosures about market risk” for a discussion of ASB’s interest rate risk sensitivity.
During the first three months of 2017, ASB recorded a provision for loan losses of $3.9 million primarily due to increased loan loss reserves for the consumer loan portfolio and additional loan loss reserves for the commercial real estate loan portfolio due to the downgrade of a commercial real estate relationship. During the first three months of 2016, ASB recorded a provision for loan losses of $4.8 million primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for two commercial borrowers. Financial stress on ASB’s customers may result in higher levels of delinquencies and losses.
| Three months ended March 31 | Year endedDecember 31, |
| (in thousands) | 2017 | 2016 | 2016 |
| Allowance for loan losses, January 1 | $ | 55,533 | $ | 50,038 | $ | 50,038 |
| Provision for loan losses | 3,907 | 4,766 | 16,763 |
| Less: net charge-offs | 3,443 | 2,478 | 11,268 |
| Allowance for loan losses, end of period | $ | 55,997 | $ | 52,326 | $ | 55,533 |
| Ratio of net charge-offs during the period to average loans outstanding (annualized) | 0.29 | % | 0.21 | % | 0.24 | % |

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We maintain a reserve for credit losses that consists of two components, the allowance for loan losses and a reserve for unfunded loan commitments (unfunded reserve). The level of the reserve for unfunded loan commitments is adjusted by recording an expense or recovery in other noninterest expense. As of March 31, 2017 and December 31, 2016, the reserve for unfunded loan commitments was $1.7 million and $1.8 million, respectively.
Legislation and regulation. ASB is subject to extensive regulation, principally by the OCC and the FDIC. Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.”
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI, ASB Hawaii and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASB Hawaii and ASB, under the Dodd-Frank Act all of the functions of the Office of Thrift Supervision transferred on July 21, 2011 to the OCC, the FDIC, the FRB and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASB Hawaii, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, the 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 imposed 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.
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.
Also, the Dodd-Frank Act directs the Bureau to publish rules and forms that combine certain disclosures that consumers receive in connection with applying for and closing on a mortgage loan under the Truth in Lending Act and the Real Estate Settlement Procedures Act. Consistent with this requirement, the Bureau amended Regulation X (Real Estate Settlement Procedures Act) and Regulation Z (Truth in Lending) to establish new disclosure requirements and forms in Regulation Z for most closed-end consumer credit transactions secured by real property. In addition to combining the existing disclosure requirements and implementing new requirements, the final rule provides extensive guidance regarding compliance with those requirements. This rule was effective October 3, 2015.
The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. Financial institutions and their affiliates that have less than $10 billion in assets are exempt from this Amendment; however, on July 1, 2013, ASB became non-exempt as the consolidated assets of HEI exceeded $10 billion. The debit card interchange fees received by ASB have been lower as a result of the application of this Amendment.
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Final Capital Rules. On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies (such as ASB Hawaii). The FRB indicated that it would release a proposal on intermediate holding companies that would specify the criteria for establishing and transferring activities to intermediate holding companies and propose to apply the FRB’s capital requirements to such intermediate holding companies. The FRB has not yet issued such a proposal, or a proposal on how to apply the Basel III capital rules to SLHCs that are substantially engaged in commercial or insurance underwriting activities, such as grandfathered unitary SLHCs like HEI.
Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would initially be subject to the following minimum regulatory capital requirements: a common equity 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 tier 1 leverage ratio of 4%, and these requirements would increase in subsequent years. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization’s total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies’ calculation of risk-weighted assets and address shortcomings in capital requirements identified by the agencies. The phased-in effective dates of the capital requirements under the final rule are:
| Effective dates | 1/1/2015 | 1/1/2016 | 1/1/2017 | 1/1/2018 | 1/1/2019 |
| Capital conservation buffer | 0.625 | % | 1.25 | % | 1.875 | % | 2.50 | % |
| Common equity Tier-1 ratio + conservation buffer | 4.50 | % | 5.125 | % | 5.75 | % | 6.375 | % | 7.00 | % |
| Tier-1 capital ratio + conservation buffer | 6.00 | % | 6.625 | % | 7.25 | % | 7.875 | % | 8.50 | % |
| Total capital ratio + conservation buffer | 8.00 | % | 8.625 | % | 9.25 | % | 9.875 | % | 10.50 | % |
| Tier-1 leverage ratio | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % |
| Countercyclical capital buffer — not applicable to ASB | 0.625 | % | 1.25 | % | 1.875 | % | 2.50 | % |

The final rule was effective January 1, 2015 for ASB. As of March 31, 2017, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.4%, a Tier-1 capital ratio of 12.4%, a Total capital ratio of 13.6% and a Tier-1 leverage ratio of 8.5%.
Subject to the timing and final outcome of the FRB’s SLHC intermediate holding company proposal, HEI anticipates that the capital requirements in the final rule will eventually be effective for HEI or ASB Hawaii as well. If the fully phased-in capital requirements were currently applicable to HEI, management believes HEI would satisfy the capital requirements, including the fully phased-in capital conservation buffer. Management cannot predict what final rule the FRB may adopt concerning intermediate holding companies or their impact on ASB Hawaii, if any.
Military Lending Act. The Department of Defense (DOD) amended its regulation that implements the Military Lending Act (MLA), which became effective on October 3, 2016. The DOD amended its regulation primarily for the purpose of extending the protections of the MLA to a broader range of closed-end and open-end credit products. It initially applied to three narrowly-defined “consumer credit” products: closed-end payday loans; closed-end auto title loans; and closed-end tax refund anticipation loans. The DOD revised the scope of the definition of ‘‘consumer credit’’ to be generally consistent with the credit products that have been subject to the requirements of the Regulation Z, namely: credit offered or extended to a covered borrower primarily for personal, family or household purposes and that is (i) subject to a finance charge or (ii) payable by a written agreement in more than four installments.
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Additionally, the DOD elected to exercise its discretion by generally requiring any fees for credit insurance products or for credit-related ancillary products to be included in the Military Annual Percentage Rate. The DOD also modified the disclosures that a creditor must provide to a covered borrower and implemented the enforcement provisions of the MLA. ASB has modified certain products, practices and associated training to conform to these changes.
Overtime Rules. The Secretary of Labor updated the overtime regulations of the Fair Labor Standards Act to simplify and modernize them. The Department of Labor issued final rules that will raise the salary threshold indicating eligibility from $455/week to $913/week ($47,476 per year), and update automatically the salary threshold every three years, based on wage growth over time, increasing predictability. The final rule was to become effective on December 1, 2016. In late-November 2016 however, the U.S. District Court in the Eastern District of Texas granted a nationwide preliminary injunction that blocked the final rule, saying the Department of Labor's rule exceeds the authority the agency was delegated by Congress. Despite this block, ASB modified its salaries in the fourth quarter of 2016 such that it is in voluntary compliance with the final rule.
FINANCIAL CONDITION
| (dollars in millions) | March 31, 2017 | December 31, 2016 | % change |
| Total assets | $ | 6,560 | $ | 6,421 | 2 |
| Available-for-sale investment securities | 1,229 | 1,105 | 11 |
| Loans receivable held for investment, net | 4,669 | 4,683 | — |
| Deposit liabilities | 5,675 | 5,549 | 2 |
| Other bank borrowings | 200 | 193 | 4 |

As of March 31, 2017, ASB was one of Hawaii’s largest financial institutions based on assets of $6.6 billion and deposits of $5.7 billion.
As of March 31, 2017, ASB’s unused FHLB borrowing capacity was approximately $1.8 billion. As of March 31, 2017, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.8 billion, including commitments to lend $2.1 million to borrowers whose loan terms have been 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.
For the three months ended March 31, 2017, net cash provided by ASB’s operating activities was $25 million. Net cash used during the same period by ASB’s investing activities was $114 million, primarily due to purchases of investment securities of $172 million and additions to premises and equipment of $6 million, partly offset by receipt of repayments from investment securities of $48 million, proceeds from the sale of commercial loans of $13 million and a decrease in restricted cash of $2 million. Net cash provided by financing activities during this period was $120 million, primarily due to increases in deposit liabilities of $126 million and a net increase in retail repurchase agreements of $21 million, partly offset by repayments of securities sold under agreements to repurchase of $14 million, a net decrease in escrow deposits of $4 million and $9 million in common stock dividends to HEI (through ASB Hawaii).
For the three months ended March 31, 2016, net cash provided by ASB’s operating activities was $11 million. Net cash used during the same period by ASB’s investing activities was $104 million, primarily due to purchases of investment securities of $122 million, a net increase in loans receivable of $28 million and additions to premises and equipment of $3 million, partly offset by receipt of repayments and calls of investment securities of $49 million. Net cash provided by financing activities during this period was $102 million, primarily due to increases in deposit liabilities of $115 million and a net increase in retail repurchase agreements of $19 million, partly offset by maturities of securities sold under agreements to repurchase of $19 million, a net decrease in mortgage escrow deposits of $4 million and $9 million in common stock dividends to HEI (through ASB Hawaii).
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 March 31, 2017, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a Common equity Tier-1 ratio of 12.4% (6.5%), a Tier-1 capital ratio of 12.4% (8.0%), a Total capital ratio of 13.6% (10.0%) and a Tier-1 leverage ratio of 8.5% (5.0%). As of December 31, 2016, ASB was well-capitalized with a common equity Tier-1 ratio of 12.2%, Tier-1 capital ratio of 12.2%, a Total capital ratio of 13.4% and a Tier-1 leverage ratio of 8.6%. All dividends are subject to review by the OCC and FRB and receipt of a letter from the FRB communicating the agencies’ non-objection to the payment of any dividend ASB proposes to declare and pay to HEI (through ASB Hawaii).
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see HEI’s and Hawaiian Electric’s Quantitative and Qualitative Disclosures About Market Risk in Part II, Item 7A of HEI’s 2016 Form 10-K (pages 79 to 81).
ASB’s interest-rate risk sensitivity measures as of March 31, 2017 and December 31, 2016 constitute “forward-looking statements” and were as follows:
| Change in interest rates | Change in NII(gradual change in interest rates) | Change in EVE(instantaneous change in interest rates) |
| (basis points) | March 31, 2017 | December 31, 2016 | March 31, 2017 | December 31, 2016 |
| +300 | 2.5 | % | 1.9 | % | (8.0 | )% | (8.0 | )% |
| +200 | 1.5 | 0.8 | (4.6 | ) | (4.6 | ) |
| +100 | 0.5 | — | (1.5 | ) | (1.6 | ) |
| -100 | (1.0 | ) | (0.5 | ) | (2.3 | ) | (1.6 | ) |

Management believes that ASB’s interest rate risk position as of March 31, 2017 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was more asset sensitive for all rate increases as of March 31, 2017 compared to December 31, 2016. The increase in the prime rate from 3.75% to 4.00% and the increase in short-term LIBOR rates improved interest income for commercial and HELOC loans in rising rate scenarios. In addition, the repricing assumptions of certain commercial and consumer loans were updated which resulted in a net increase in NII.
ASB’s base EVE increased slightly to $1.12 billion as of March 31, 2017, compared to $1.09 billion as of December 31, 2016, due to the growth and mix of the balance sheet. Assets increased by $138 million with market valuation exceeding the growth and valuation of funding liabilities.
EVE sensitivity to rising rates remained relatively unchanged as of March 31, 2017 compared to December 31, 2016 as long-term rates remained stable. During the quarter, the purchase of longer duration investment securities was funded by the growth in longer duration core deposits, resulting in minimal impact to EVE sensitivity.
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.
Item 4. Controls and Procedures
HEI:
Disclosure Controls and Procedures
The Company maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
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An evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective, as of the end of the period covered by the report, at the reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in internal control over financial reporting during the first quarter of 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Hawaiian Electric:
Disclosure Controls and Procedures
Hawaiian Electric maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by Hawaiian Electric in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to Hawaiian Electric’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
An evaluation was performed under the supervision and with the participation of Hawaiian Electric’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Hawaiian Electric’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including Hawaiian Electric’s Chief Executive Officer and Chief Financial Officer, concluded that Hawaiian Electric’s disclosure controls and procedures were effective, as of the end of the period covered by the report, at the reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in internal control over financial reporting during the first quarter of 2017 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s and Hawaiian Electric’s 2016 Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this Form 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 4 and 5 of the Condensed Consolidated Financial Statements) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including Hawaiian Electric and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.
Item 1A. Risk Factors
For information about Risk Factors, see pages 25 to 35 of HEI’s and Hawaiian Electric’s 2016 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and the Condensed Consolidated Financial Statements herein. Also, see “Cautionary Note Regarding Forward-Looking Statements” on pages iv and v herein.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Purchases of HEI common shares were made during the first quarter to satisfy the requirements of certain plans as follows:
| Period* | Total Number of Shares Purchased ** | AveragePrice Paidper Share ** | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs |
| January 1 to 31, 2017 | 25,220 | $33.26 | — | NA |
| February 1 to 28, 2017 | 22,122 | $32.85 | — | NA |
| March 1 to 31, 2017 | 201,223 | $33.00 | — | NA |

NA Not applicable.
* Trades (total number of shares purchased) are reflected in the month in which the order is placed.
** The purchases were made to satisfy the requirements of the DRIP, the HEIRSP and the ASB 401(k) Plan for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP, the HEIRSP and the ASB 401(k) Plan. Of the shares listed in column (a), all of the 25,220 shares, 13,322 of the 22,122 shares and 179,053 of the 201,223 shares were purchased for the DRIP; none of the 25,220 shares, 6,700 of the 22,122 shares and 17,800 of the 201,223 shares were purchased for the HEIRSP; and the remainder was purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.
Item 5. Other Information
| Three months ended March 31 | Years ended December 31 |
| 2017 | 2016 | 2016 | 2015 | 2014 | 2013 | 2012 |
| HEI and Subsidiaries |
| Excluding interest on ASB deposits | 3.19 | 3.07 | 5.05 | 3.68 | 3.80 | 3.55 | 3.30 |
| Including interest on ASB deposits | 3.01 | 2.94 | 4.75 | 3.54 | 3.65 | 3.42 | 3.15 |
| Hawaiian Electric and Subsidiaries | 2.77 | 3.12 | 4.11 | 3.97 | 4.04 | 3.72 | 3.37 |

See HEI Exhibit 12.1 and Hawaiian Electric Exhibit 12.2.
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Item 6. Exhibits
| HEI Exhibit 12.1 | Hawaiian Electric Industries, Inc. and SubsidiariesComputation of ratio of earnings to fixed charges, three months ended March 31, 2017 and 2016 and years ended December 31, 2016, 2015, 2014, 2013 and 2012 |
| HEI Exhibit 31.1 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer) |
| HEI Exhibit 31.2 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Gregory C. Hazelton (HEI Chief Financial Officer) |
| HEI Exhibit 32.1 | HEI Certification Pursuant to 18 U.S.C. Section 1350 |
| HEI Exhibit 101.INS | XBRL Instance Document |
| HEI Exhibit 101.SCH | XBRL Taxonomy Extension Schema Document |
| HEI Exhibit 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
| HEI Exhibit 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
| HEI Exhibit 101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
| HEI Exhibit 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
| Hawaiian Electric Exhibit 12.2 | Hawaiian Electric Company, Inc. and SubsidiariesComputation of ratio of earnings to fixed charges, three months ended March 31, 2017 and 2016 and years ended December 31, 2016, 2015, 2014, 2013 and 2012 |
| Hawaiian Electric Exhibit 31.3 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Alan M. Oshima (Hawaiian Electric Chief Executive Officer) |
| Hawaiian Electric Exhibit 31.4 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (Hawaiian Electric Chief Financial Officer) |
| Hawaiian Electric Exhibit 32.2 | Hawaiian Electric Certification Pursuant to 18 U.S.C. Section 1350 |

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.
| HAWAIIAN ELECTRIC INDUSTRIES, INC. | HAWAIIAN ELECTRIC COMPANY, INC. |
| (Registrant) | (Registrant) |
| By | /s/ Constance H. Lau | By | /s/ Alan M. Oshima |
| Constance H. Lau | Alan M. Oshima |
| President and Chief Executive Officer | President and Chief Executive Officer |
| (Principal Executive Officer of HEI) | (Principal Executive Officer of Hawaiian Electric) |
| By | /s/ Gregory C. Hazelton | By | /s/ Tayne S. Y. Sekimura |
| Gregory C. Hazelton | Tayne S. Y. Sekimura |
| Executive Vice President and | Senior Vice President |
| Chief Financial Officer | and Chief Financial Officer |
| (Principal Financial and Accounting | (Principal Financial Officer of Hawaiian Electric) |
| Officer of HEI) |
| Date: May 5, 2017 | Date: May 5, 2017 |

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Question: What could be the estimated annual fee incurred if the average undrawn amount of credit for both the HEI Facility and the Hawaiian Electric Facility in Q1 2017 was 30% of the total available credit, and the company pays annual fees on undrawn commitments of 20 basis points?

Solution:
def solution():
    # Define variables name and value

    total_credit_HEI = 150000  # in thousands

    total_credit_Hawaiian = 200000  # in thousands

    # From the question
    undrawn_ratio = 0.30  # 30%
    basis_points = 0.20  # 20 basis points 

    #Do math calculation to get the answer
    undrawn_credit_HEI = total_credit_HEI * undrawn_ratio
    undrawn_credit_Hawaiian = total_credit_Hawaiian * undrawn_ratio
    annual_fee_HEI = undrawn_credit_HEI * basis_points / 100
    annual_fee_Hawaiian = undrawn_credit_Hawaiian * basis_points / 100
    total_annual_fee = annual_fee_HEI + annual_fee_Hawaiian

    return round(total_annual_fee)  # in thousands


Answer: 210