-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, CdJO78eof4ZCixcZtFReQ2S38JGjFHsVb2At+0vnv0BqD5XGGTb5eClElb5PXG4R /IEHHXskCZmqHUoBemPgEw== 0000898430-99-004226.txt : 19991115 0000898430-99-004226.hdr.sgml : 19991115 ACCESSION NUMBER: 0000898430-99-004226 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HAWAIIAN ELECTRIC INDUSTRIES INC CENTRAL INDEX KEY: 0000354707 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 990208097 STATE OF INCORPORATION: HI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08503 FILM NUMBER: 99750991 BUSINESS ADDRESS: STREET 1: 900 RICHARDS ST CITY: HONOLULU STATE: HI ZIP: 96813 BUSINESS PHONE: 8085435662 MAIL ADDRESS: STREET 1: 900 RICHARDS STREET CITY: HONOLULU STATE: HI ZIP: 96813 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HAWAIIAN ELECTRIC CO INC CENTRAL INDEX KEY: 0000046207 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 990040500 STATE OF INCORPORATION: HI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-04955 FILM NUMBER: 99750992 BUSINESS ADDRESS: STREET 1: 900 RICHARDS ST CITY: HONOLULU STATE: HI ZIP: 96813 BUSINESS PHONE: 8085437771 MAIL ADDRESS: STREET 1: 900 RICHARDS STREET CITY: HONOLULU STATE: HI ZIP: 96813 FORMER COMPANY: FORMER CONFORMED NAME: HAWAIIAN ELECTRIC CO LTD DATE OF NAME CHANGE: 19670212 10-Q 1 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1999 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Exact Name of Registrant as Commission I.R.S. Employer Specified in Its Charter File Number Identification No. - --------------------------- ----------- ------------------ HAWAIIAN ELECTRIC INDUSTRIES, INC. 1-8503 99-0208097 and Principal Subsidiary HAWAIIAN ELECTRIC COMPANY, INC. 1-4955 99-0040500 State of Hawaii - -------------------------------------------------------------------------------- (State or other jurisdiction of incorporation or organization) 900 Richards Street, Honolulu, Hawaii 96813 - -------------------------------------------------------------------------------- (Address of principal executive offices and zip code) Hawaiian Electric Industries, Inc. ----- (808) 543-5662 Hawaiian Electric Company, Inc. ----- (808) 543-7771 - -------------------------------------------------------------------------------- (Registrant's telephone number, including area code) None - -------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) ================================================================================ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Class of Common Stock Outstanding November 5, 1999 - --------------------------------------------------------------------------------------------------------- Hawaiian Electric Industries, Inc. (Without Par Value).... 32,212,763 Shares Hawaiian Electric Company, Inc. ($6 2/3 Par Value)........ 12,805,843 Shares (not publicly traded) =========================================================================================================
Hawaiian Electric Industries, Inc. and subsidiaries Hawaiian Electric Company, Inc. and subsidiaries Form 10-Q--Quarter ended September 30, 1999 INDEX
Page No. Glossary of terms.......................................................... ii Forward-looking information................................................ v
PART I. FINANCIAL INFORMATION
Item 1. Financial statements Hawaiian Electric Industries, Inc. and subsidiaries --------------------------------------------------- Consolidated balance sheets (unaudited) - September 30, 1999 and December 31, 1998................ 1 Consolidated statements of income (unaudited) - three and nine months ended September 30, 1999 and 1998. 2 Consolidated statements of retained earnings (unaudited) - three and nine months ended September 30, 1999 and 1998. 3 Consolidated statements of cash flows (unaudited) - nine months ended September 30, 1999 and 1998........... 4 Notes to consolidated financial statements (unaudited)..... 5 Hawaiian Electric Company, Inc. and subsidiaries ------------------------------------------------ Consolidated balance sheets (unaudited) - September 30, 1999 and December 31, 1998................ 12 Consolidated statements of income (unaudited) - three and nine months ended September 30, 1999 and 1998. 13 Consolidated statements of retained earnings (unaudited) - three and nine months ended September 30, 1999 and 1998. 13 Consolidated statements of cash flows (unaudited) - nine months ended September 30, 1999 and 1998........... 14 Notes to consolidated financial statements (unaudited)..... 15 Item 2. Management's discussion and analysis of financial condition and results of operations............................... 27 Item 3. Quantitative and qualitative disclosures about market risk. 43
PART II. OTHER INFORMATION
Item 1. Legal proceedings........................................... 44 Item 5. Other information........................................... 44 Item 6. Exhibits and reports on Form 8-K............................ 46 Signatures................................................................ 47
i Hawaiian Electric Industries, Inc. and subsidiaries Hawaiian Electric Company, Inc. and subsidiaries Form 10-Q--Quarter ended September 30, 1999 GLOSSARY OF TERMS Terms Definitions - ----- ----------- AFUDC Allowance for funds used during construction ASB American Savings Bank, F.S.B., a wholly owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp., ASB Service Corporation, AdCommunications, Inc., American Savings Mortgage Co., Inc. and ASB Realty Corporation BaoSteel Baotou Iron & Steel (Group) Co., Ltd. BIF Bank Insurance Fund BLNR Board of Land and Natural Resources of the State of Hawaii CDUP Conservation District Use Permit CEPALCO Cagayan Electric Power & Light Co., Inc. Company Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust I, HECO Capital Trust II, HEI Investment Corp., Hawaiian Tug & Barge Corp., Young Brothers, Limited, HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, HEI Properties, Inc., Pacific Energy Conservation Services, Inc., HEI Power Corp. and its subsidiaries, HEI District Cooling, Inc., ProVision Technologies, Inc., Hycap Management, Inc., Hawaiian Electric Industries Capital Trust I, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, HEI Preferred Funding, LP and Malama Pacific Corp. and its subsidiaries D&O Decision and order DLNR Department of Land and Natural Resources of the State of Hawaii DOH Department of Health of the State of Hawaii EAB Environmental Appeals Board Encogen Encogen Hawaii, L.P. Enserch Enserch Development Corporation EPA Environmental Protection Agency - federal ii GLOSSARY OF TERMS, continued Terms Definitions - ----- ----------- FASB Financial Accounting Standards Board FDIC Federal Deposit Insurance Corporation federal U.S. Government FHLB Federal Home Loan Bank FICO Financing Corporation GAAP Generally accepted accounting principles GPA Guam Power Authority HCPC Hilo Coast Power Company, formerly Hilo Coast Processing Company HECO Hawaiian Electric Company, Inc., a wholly owned electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust I and HECO Capital Trust II HEI Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Investment Corp., Hawaiian Tug & Barge Corp., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Power Corp., HEI District Cooling, Inc., ProVision Technologies, Inc., Hycap Management, Inc., Hawaiian Electric Industries Capital Trust I, Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and Malama Pacific Corp. HEIDI HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B. and HEI Properties, Inc. HEIIC HEI Investment Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. HEIPC HEI Power Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of several subsidiaries HEIPC Group HEI Power Corp. and its subsidiaries HELCO Hawaii Electric Light Company, Inc., a wholly owned electric utility subsidiary of Hawaiian Electric Company, Inc. HPG HEI Power Corp. Guam, a wholly owned subsidiary of HEI Power Corp. iii GLOSSARY OF TERMS, continued Terms Definitions - ----- ----------- HTB Hawaiian Tug & Barge Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and parent company of Young Brothers, Limited. On November 10, 1999, HTB sold YB and substantially all HTB's operating assets. IPP Independent power producer KCP Kawaihae Cogeneration Partners KWH Kilowatthour MECO Maui Electric Company, Limited, a wholly owned electric utility subsidiary of Hawaiian Electric Company, Inc. MPC Malama Pacific Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and parent company of several real estate subsidiaries. On September 14, 1998, the HEI Board of Directors adopted a plan to exit the residential real estate development business engaged in by Malama Pacific Corp. and its subsidiaries. MW Megawatt NOV Notice of Violation OTS Office of Thrift Supervision, Department of Treasury PSD permit Prevention of Significant Deterioration/Covered Source permit PUC Public Utilities Commission of the State of Hawaii ROACE Return on average common equity SAIF Savings Association Insurance Fund SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards YB Young Brothers, Limited, a wholly owned subsidiary of Hawaiian Tug & Barge Corp. On November 10, 1999, HTB sold YB. iv Forward-looking information This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and its subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Except for historical information contained herein, the matters set forth are forward-looking statements that involve certain risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements. Potential risks and uncertainties include, but are not limited to, such factors as the effect of international, national and local economic conditions, including the condition of the Hawaii tourist and construction industries and the Hawaii housing market; the effects of weather and natural disasters; product demand and market acceptance risks; increasing competition in the electric utility and banking industries; capacity and supply constraints or difficulties; new technological developments; governmental and regulatory actions, including decisions in rate cases and on permitting issues; the results of financing efforts; the timing and extent of changes in interest rates and foreign currency exchange rates; the convertibility and availability of foreign currency; political and business risks inherent in doing business in developing countries; and the risks associated with the installation of new computer systems and the avoidance of Year 2000 problems. Investors are also referred to other risks and uncertainties discussed elsewhere in this report and in other periodic reports previously and subsequently filed by HEI and/or Hawaiian Electric Company, Inc. (HECO) with the Securities and Exchange Commission. v
PART I - FINANCIAL INFORMATION - ----------------------------------------------------------------------------------------------------------------- Item 1. Financial statements - ----------------------------- Hawaiian Electric Industries, Inc. and subsidiaries Consolidated balance sheets (unaudited) September 30, December 31, (in thousands) 1999 1998 - ----------------------------------------------------------------------------------------------------------------- Assets - ------ Cash and equivalents............................................ $ 209,430 $ 412,254 Accounts receivable and unbilled revenues, net.................. 155,306 156,220 Investment and mortgage/asset-backed securities................. 2,070,881 1,902,927 Loans receivable, net........................................... 3,215,717 3,143,197 Property, plant and equipment, net of accumulated depreciation and amortization of $1,147,935 and $1,063,023... 2,089,605 2,093,398 Regulatory assets............................................... 114,581 110,459 Other........................................................... 277,323 265,799 Goodwill and other intangibles.................................. 108,805 115,006 ---------- ---------- $8,241,648 $8,199,260 ========== ========== Liabilities and stockholders' equity - ------------------------------------ Liabilities Accounts payable................................................ $ 123,008 $ 107,863 Deposit liabilities............................................. 3,559,269 3,865,736 Short-term borrowings........................................... 164,610 222,847 Securities sold under agreements to repurchase.................. 426,519 515,330 Advances from Federal Home Loan Bank............................ 1,082,081 805,581 Long-term debt.................................................. 978,676 899,598 Deferred income taxes........................................... 181,963 186,138 Contributions in aid of construction............................ 198,478 198,904 Other........................................................... 453,464 285,243 ---------- ---------- 7,168,068 7,087,240 ---------- ---------- HEI- and HECO-obligated preferred securities of trust subsidiaries directly or indirectly holding solely HEI and HEI-guaranteed and HECO and HECO-guaranteed subordinated debentures..................................... 200,000 200,000 Preferred stock of electric utility subsidiaries Subject to mandatory redemption............................. - 33,080 Not subject to mandatory redemption......................... 34,293 48,293 Minority interests.............................................. 3,494 3,675 ---------- ---------- 237,787 285,048 ---------- ---------- Stockholders' equity Preferred stock, no par value, authorized 10,000 shares; issued: none............................................... - - Common stock, no par value, authorized 100,000 shares; issued and outstanding: 32,212 shares and 32,116 shares............ 665,275 661,720 Retained earnings............................................... 170,518 165,252 ---------- ---------- 835,793 826,972 ---------- ---------- $8,241,648 $8,199,260 ========== ========== See accompanying notes to consolidated financial statements.
1
Hawaiian Electric Industries, Inc. and subsidiaries Consolidated statements of income (unaudited) Three months ended Nine months ended September 30, September 30, (in thousands, except per share amounts and -------------------------------- ------------------------------------ ratio of earnings to fixed charges) 1999 1998 1999 1998 - --------------------------------------------------------- ------------------------------------------------------------------------ Revenues Electric utility.................................... $277,283 $259,684 $767,346 $762,494 Savings bank........................................ 102,624 103,229 304,663 306,324 Other............................................... 12,543 14,405 42,376 44,023 ---------- ---------- ---------- ---------- 392,450 377,318 1,114,385 1,112,841 ---------- ---------- ---------- ---------- Expenses Electric utility.................................... 230,811 208,418 635,637 626,969 Savings bank........................................ 87,705 89,831 258,824 264,245 Other............................................... 17,383 16,770 50,631 48,753 ---------- ---------- ---------- ---------- 335,899 315,019 945,092 939,967 ---------- ---------- ---------- ---------- Operating income (loss) Electric utility.................................... 46,472 51,266 131,709 135,525 Savings bank........................................ 14,919 13,398 45,839 42,079 Other............................................... (4,840) (2,365) (8,255) (4,730) ---------- ---------- ---------- ---------- 56,551 62,299 169,293 172,874 ---------- ---------- ---------- ---------- Interest expense--electric utility and other........ (17,600) (17,601) (54,488) (53,345) Allowance for borrowed funds used during construction.............................. 716 1,826 1,955 5,145 Preferred stock dividends of electric utility subsidiaries............................. (498) (1,499) (1,624) (4,507) Preferred securities distributions of trust subsidiaries..................................... (4,009) (3,097) (12,016) (9,289) Allowance for equity funds used during construction..................................... 1,176 3,139 3,202 8,781 ---------- ---------- ---------- ---------- Income from continuing operations before income taxes.............................. 36,336 45,067 106,322 119,659 Income taxes........................................ 14,704 17,288 41,180 46,140 ---------- ---------- ---------- ---------- Income from continuing operations................... 21,632 27,779 65,142 73,519 ---------- ---------- ---------- ---------- Discontinued operations, net of income taxes Loss from operations............................. - (12,474) - (13,598) Net gain on disposals............................ - 3,781 - 3,781 ---------- ---------- ---------- ---------- Loss from discontinued operations................... - (8,693) - (9,817) ---------- ---------- ---------- ---------- Net income.......................................... $ 21,632 $ 19,086 $ 65,142 $ 63,702 ========== ========== ========== ========== Basic earnings (loss) per common share Continuing operations............................ $ 0.67 $ 0.87 $ 2.02 $ 2.30 Discontinued operations.......................... - (0.27) - (0.31) ---------- ---------- ---------- ---------- $ 0.67 $ 0.60 $ 2.02 $ 1.99 ========== ========== ========== ========== Diluted earnings (loss) per common share Continuing operations............................ $ 0.67 $ 0.86 $ 2.02 $ 2.29 Discontinued operations.......................... - (0.27) - (0.31) ---------- ---------- ---------- ---------- $ 0.67 $ 0.59 $ 2.02 $ 1.98 ========== ========== ========== ========== Dividends per common share.......................... $ 0.62 $ 0.62 $ 1.86 $ 1.86 ========== ========== ========== ========== Weighted-average number of common shares outstanding (basic earnings per common share).... 32,203 32,010 32,180 31,992 Dilutive effect of stock options and dividend equivalents...................... 91 128 97 138 ---------- ---------- ---------- ---------- Adjusted weighted-average shares (diluted earnings per common share).............. 32,294 32,138 32,277 32,130 ========== ========== ========== ========== Ratio of earnings to fixed charges (SEC method) Excluding interest on ASB deposits............. 1.78 1.90 ========== ========== Including interest on ASB deposits............. 1.46 1.49 ========== ==========
See accompanying notes to consolidated financial statements. 2
Hawaiian Electric Industries, Inc. and subsidiaries Consolidated statements of retained earnings (unaudited) Three months ended Nine months ended September 30, September 30, -------------------------------- -------------------------------- (in thousands) 1999 1998 1999 1998 - ---------------------------------------------------------------------------------------------------------------------------------- Retained earnings, beginning of period................ $168,858 $164,807 $165,252 $159,862 Net income............................................ 21,632 19,086 65,142 63,702 Common stock dividends................................ (19,972) (19,847) (59,876) (59,518) -------- -------- -------- -------- Retained earnings, end of period...................... $170,518 $164,046 $170,518 $164,046 ======== ======== ======== ========
See accompanying notes to consolidated financial statements. 3
Hawaiian Electric Industries, Inc. and subsidiaries Consolidated statements of cash flows (unaudited) Nine months ended September 30, ---------------------------------- (in thousands) 1999 1998 - ------------------------------------------------------------------------------------- ---------------------------------- Cash flows from continuing operating activities Income from continuing operations........................................................... $ 65,142 $ 73,519 Adjustments to reconcile income from continuing operations to net cash provided by continuing operating activities Depreciation and amortization of property, plant and equipment........................ 81,871 74,588 Other amortization.................................................................... 11,345 11,397 Provision for loan losses............................................................. 10,848 9,473 Deferred income taxes................................................................. (4,175) (864) Allowance for equity funds used during construction................................... (3,202) (8,781) Changes in assets and liabilities Decrease in accounts receivable and unbilled revenues, net...................... 914 1,639 Increase (decrease) in accounts payable......................................... 15,145 (34,711) Changes in other assets and liabilities......................................... 1,711 54,110 --------- --------- Net cash provided by continuing operating activities........................................ 179,599 180,370 --------- --------- Cash flows from investing activities Held-to-maturity mortgage/asset-backed securities purchased................................. (623,942) (401,740) Principal repayments on held-to-maturity mortgage/asset-backed securities................... 470,063 402,288 Held-to-maturity investment securities purchased............................................ (54,782) (200,982) Principal repayments on held-to-maturity investment securities.............................. 43,000 159,982 Loans receivable originated and purchased................................................... (528,777) (494,683) Principal repayments on loans receivable.................................................... 435,725 358,582 Capital expenditures........................................................................ (88,444) (124,290) Cash paid to Bank of America, FSB for the purchase of loans receivable and other assets, net of the assumption of deposit and other liabilities..................... - (24,018) Proceeds from loans returned to Bank of America, FSB........................................ - 28,104 Other....................................................................................... 19,585 16,906 --------- --------- Net cash used in investing activities....................................................... (327,572) (279,851) --------- --------- Cash flows from financing activities Net decrease in deposit liabilities......................................................... (306,467) (85,155) Net decrease in short-term borrowings with original maturities of three months or less...... (58,237) (103,307) Net increase (decrease) in retail repurchase agreements..................................... 167,765 (2,971) Proceeds from securities sold under agreements to repurchase................................ 290,000 474,812 Repurchase of securities sold under agreements to repurchase................................ (378,612) (316,000) Proceeds from advances from Federal Home Loan Bank.......................................... 684,100 661,500 Principal payments on advances from Federal Home Loan Bank.................................. (407,600) (574,893) Proceeds from issuance of long-term debt.................................................... 167,452 185,394 Repayment of long-term debt................................................................. (88,500) (59,400) Redemption of electric utility subsidiaries' preferred stock................................ (47,080) (2,590) Net proceeds from issuance of common stock.................................................. 3,432 4,553 Common stock dividends...................................................................... (59,876) (59,518) Preferred securities distributions of trust subsidiaries.................................... (12,016) (9,289) Other....................................................................................... (9,212) (3,728) --------- --------- Net cash provided by (used in) financing activities......................................... (54,851) 109,408 --------- --------- Net cash provided by discontinued operations................................................ - 11,265 --------- --------- Net increase (decrease) in cash and equivalents............................................. (202,824) 21,192 Cash and equivalents, beginning of period................................................... 412,254 253,910 --------- --------- Cash and equivalents, end of period......................................................... $ 209,430 $ 275,102 ========= ========= See accompanying notes to consolidated financial statements.
4 Hawaiian Electric Industries, Inc. and subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 1999 and 1998 (Unaudited) (1) Basis of presentation - -------------------------- The accompanying unaudited consolidated financial statements have been prepared in conformity with generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Securities and Exchange Commission (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 consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto incorporated by reference in HEI's Annual Report on SEC Form 10-K for the year ended December 31, 1998 and the consolidated financial statements and the notes thereto in HEI's Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 1999 and June 30, 1999. In the opinion of HEI's management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company's financial position as of September 30, 1999 and December 31, 1998, the results of its operations for the three and nine months ended September 30, 1999 and 1998, and its cash flows for the nine months ended September 30, 1999 and 1998. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. Certain reclassifications have been made to prior periods' consolidated financial statements to conform to the 1999 presentation. 5 (2) Segment financial information - ---------------------------------- Segment financial information was as follows:
Electric Savings Holding Elimi- ($ in thousands) utility bank Other companies nations Total - ------------------------------------------------------------------------------------------------ Quarter ended September 30, 1999 Revenues from external customers................... 277,274 102,616 13,142 (582) - 392,450 Intersegment revenues........ 9 8 2,711 2,792 (5,520) - ------------------------------------------------------------------ Revenues................. 277,283 102,624 15,853 2,210 (5,520) 392,450 =================================================================== Profit (loss)*............... 33,704 13,569 (1,506) (9,431) - 36,336 Income taxes (benefit)....... 13,389 5,070 582 (4,337) - 14,704 ------------------------------------------------------------------- Income (loss) from continuing operations. 20,315 8,499 (2,088) (5,094) - 21,632 =================================================================== Nine months ended September 30, 1999 Revenues from external customers................... 767,337 304,640 41,834 574 - 1,114,385 Intersegment revenues........ 9 23 8,083 6,348 (14,463) - ------------------------------------------------------------------- Revenues................. 767,346 304,663 49,917 6,922 (14,463) 1,114,385 =================================================================== Profit (loss)*............... 92,740 41,789 (950) (27,257) - 106,322 Income taxes (benefit)....... 36,120 15,708 1,493 (12,141) - 41,180 ------------------------------------------------------------------- Income (loss) from continuing operations. 56,620 26,081 (2,443) (15,116) - 65,142 =================================================================== Quarter ended September 30, 1998 Revenues from external customers................... 259,684 103,221 14,282 131 - 377,318 Intersegment revenues........ - 8 2,704 2,241 (4,953) - ------------------------------------------- Revenues................. 259,684 103,229 16,986 2,372 (4,953) 377,318 =================================================================== Profit (loss)*............... 41,656 12,048 (351) (8,286) - 45,067 Income taxes (benefit)....... 16,680 4,144 500 (4,036) - 17,288 ------------------------------------------------------------------- Income (loss) from continuing operations. 24,976 7,904 (851) (4,250) - 27,779 =================================================================== Nine months ended September 30, 1998 Revenues from external customers................... 762,494 306,301 43,783 263 - 1,112,841 Intersegment revenues........ - 23 8,035 6,355 (14,413) - ------------------------------------------------------------------- Revenues................. 762,494 306,324 51,818 6,618 (14,413) 1,112,841 =================================================================== Profit (loss)*............... 105,141 38,029 989 (24,500) - 119,659 Income taxes (benefit)....... 42,214 14,413 1,998 (12,485) - 46,140 ------------------------------------------------------------------- Income (loss) from continuing operations. 62,927 23,616 (1,009) (12,015) - 73,519 ===================================================================
* Income before income taxes and discontinued operations. Revenues attributed to foreign countries for the periods identified above were not significant. 6 (3) Electric utility subsidiary - -------------------------------- For Hawaiian Electric Company, Inc.'s consolidated financial information, including its commitments and contingencies, see pages 12 through 26. (4) Savings bank subsidiary - ---------------------------- Selected consolidated financial information American Savings Bank, F.S.B. and subsidiaries Income statement data
Three months ended Nine months ended September 30, September 30, ------------------------------ -------------------------- (in thousands) 1999 1998 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Interest income.......................................... $ 95,402 $ 95,385 $281,840 $285,437 Interest expense......................................... 51,592 56,214 153,351 163,265 -------- -------- -------- -------- Net interest income...................................... 43,810 39,171 128,489 122,172 Provision for losses..................................... (4,750) (3,125) (10,848) (9,473) Other income............................................. 7,222 7,844 22,823 20,887 Operating, administrative and general expenses........... (31,363) (30,492) (94,625) (91,507) -------- -------- -------- -------- Operating income......................................... 14,919 13,398 45,839 42,079 Income taxes............................................. 5,070 4,144 15,708 14,413 -------- -------- -------- -------- Income before preferred stock dividends.................. 9,849 9,254 30,131 27,666 Dividends on preferred stock held by parent.............. 1,350 1,350 4,050 4,050 -------- -------- -------- -------- Net income............................................... $ 8,499 $ 7,904 $ 26,081 $ 23,616 ======== ======== ======== ========
American Savings Bank, F.S.B. and subsidiaries Balance sheet data
(in thousands) September 30, 1999 December 31, 1998 - ------------------------------------------------------------------------------------------------------------------------------ Assets Cash and equivalents............................................................ $ 178,121 $ 352,566 Held-to-maturity investment securities.......................................... 127,563 111,574 Held-to-maturity mortgage/asset-backed securities............................... 1,943,318 1,791,353 Loans receivable, net........................................................... 3,215,717 3,143,197 Other........................................................................... 179,908 177,976 Goodwill and other intangibles.................................................. 108,805 115,006 ------------------ -------------------- $5,753,432 $5,691,672 ================== ==================== Liabilities and equity Deposit liabilities............................................................. $3,559,269 $3,865,736 Securities sold under agreements to repurchase.................................. 426,519 515,330 Advances from Federal Home Loan Bank............................................ 1,082,081 805,581 Other........................................................................... 258,109 92,153 ------------------ -------------------- 5,325,978 5,278,800 Minority interests.............................................................. 113 113 Preferred stock held by parent.................................................. 75,000 75,000 Common stock equity............................................................. 352,341 337,759 ------------------ -------------------- $5,753,432 $5,691,672 ================== ====================
7 Deposit-insurance premiums The Savings Association Insurance Fund (SAIF) insures the deposit accounts of ASB and other thrifts. The Bank Insurance Fund (BIF) insures the deposit accounts of commercial banks. The Federal Deposit Insurance Corporation (FDIC) administers the SAIF and BIF. In December 1996, the FDIC adopted a risk-based assessment schedule for SAIF institutions, effective January 1, 1997, that was identical to the existing base rate schedule for BIF institutions: zero to 27 cents per $100 of deposits. Added to this base rate schedule through 1999 will be the assessment to fund the Financing Corporation's (FICO's) interest obligations. In December 1997, ASB acquired BIF-assessable deposits as well as SAIF-assessable deposits from Bank of America, FSB. As a "well-capitalized" thrift, ASB's base deposit insurance premium effective for the September 30, 1999 quarterly payment is zero and its assessment for funding FICO interest payments is 5.9 cents per $100 of SAIF- assessable deposits and 1.2 cents per $100 of BIF-assessable deposits, on an annual basis, based on deposits as of June 30, 1999. SAIF-assessable deposits represented 89% of total deposits as of June 30, 1999. (5) Cash flows - --------------- Supplemental disclosures of cash flow information Cash paid for interest (net of capitalized amounts) and income taxes was as follows:
Nine months ended September 30, ------------------------------------------ (in thousands) 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------ Interest (including interest paid by savings bank, but excluding interest paid on nonrecourse debt on leveraged leases).............................................. $199,198 $200,453 ================== ================== Income taxes........................................................................ $ 38,289 $ 27,325 ================== ==================
The increase in income taxes paid for the nine months ended September 30, 1999 compared to the same period in 1998 was primarily due to a change in the timing of the recognition of ASB's loan portfolio taxable income, partly offset by a change in the timing of Public Service Company tax deductions. Supplemental disclosures of noncash activities The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $3.2 million and $8.8 million for the nine months ended September 30, 1999 and 1998, respectively. The decrease in 1999 was due to the nonaccrual of AFUDC with respect to HELCO's Keahole project and a lower construction in progress base on which AFUDC is calculated because of the completion of projects and their addition to plant in 1998. (6) Accounting changes - ----------------------- Costs of computer software developed or obtained for internal use and start-up activities In March 1998, the AICPA Accounting Standards Executive Committee issued Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use," which requires that certain costs, including certain payroll and payroll-related costs, be capitalized and amortized over the estimated useful life of the software. In April 1998, the AICPA Accounting Standards Executive Committee issued SOP 98-5, "Reporting on the Costs of Start-up Activities," which requires that costs of start-up activities, including organization costs, be expensed as incurred. The provisions of SOP 98-1 and SOP 98-5 are effective for fiscal years beginning after December 15, 1998. The Company adopted SOP 98-1 and SOP 98-5 effective 8 January 1, 1999. The adoption of SOP 98-1 and SOP 98-5 did not have a material effect on the Company's financial condition, results of operations or liquidity. Derivative instruments and hedging activities In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," which establishes accounting and reporting standards for derivative instruments and hedging activities and requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. In June 1999, the provisions of SFAS No. 133 were amended by SFAS No. 137 to be effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The Company will adopt SFAS No. 133, as amended, on January 1, 2001, but has not yet determined the impact, if any, of adoption. (7) Commitments and contingencies - ---------------------------------- Environmental regulation In early 1995, the Department of Health of the State of Hawaii (DOH) initially advised HECO, Hawaiian Tug & Barge Corp. (HTB), Young Brothers, Limited (YB) and others that it was conducting an investigation to determine the nature and extent of actual or potential releases of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor. The DOH issued letters in December 1995, indicating that it had identified a number of parties, including HECO, HTB and YB, who appear to be potentially responsible for the contamination and/or to operate their facilities upon contaminated land. The DOH met with these identified parties in January 1996 and certain of the identified parties including HECO, Chevron Products Company, Equilon Enterprises LLC (formerly Shell Oil Products Company), the State of Hawaii Department of Transportation Harbors Division and others formed a Technical Work Group and a Legal Work Group which now function together as the Honolulu Harbor Working Group. Effective January 30, 1998, the Honolulu Harbor Working Group and the DOH entered into a voluntary agreement and scope of work to determine the nature and extent of any contamination, the responsible parties and appropriate remedial actions. On April 19, 1999, the Honolulu Harbor Working Group submitted to the DOH a "Data Assimilation and Review" report, which presents the results of a study conducted by a consultant to document environmental conditions in the Iwilei Unit of the Honolulu Harbor study area related to potential petroleum impacts. The location and sources (confirmed and potential) of petroleum releases were identified. On September 3, 1999, the Honolulu Harbor Working Group submitted a report that included the identification and evaluation of potential hazardous areas, a preliminary risk screening and recommendations for additional data gathering to allow an assessment of the need for risk-based corrective action. The Honolulu Harbor Working Group engaged PHR Environmental Consultants, Inc. (PHR) to assist in identifying additional potentially responsible parties, and on October 7, 1999, PHR submitted a report to the DOH identifying 26 additional potentially responsible parties, including YB. Under the terms of the agreement for the sale of YB, HEI has certain indemnity obligations, including obligations with respect to the Honolulu Harbor investigation. Because the process for determining appropriate remedial and cleanup action, if any, is at an early stage, management cannot predict at this time the costs of further site analysis or future remediation and cleanup requirements, nor can it estimate when such costs would be incurred. Certain of the costs incurred may be claimed and covered under insurance policies, but such coverage is not determinable at this time. China project In September 1998, HEI Power Corp. (HEIPC), through a wholly owned subsidiary's 80% ownership of a Mauritius Company, acquired an effective 60% interest in a joint venture, Baotou Tianjiao Power Co., Ltd. (Tianjiao), formed to design, construct, own, operate and manage a 200 megawatt (MW) coal-fired power plant to be located inside Baotou Iron & Steel (Group) Co., Ltd.'s (BaoSteel's) complex in Inner 9 Mongolia, People's Republic of China (PRC). BaoSteel, a state-owned enterprise and the fifth largest steel company in China, is a 25% partner in the joint venture and will purchase all the electricity generated. Ownership of the plant will be transferred, without charge, to BaoSteel in approximately 20 years. As of September 30, 1999, HEIPC and its subsidiaries (the HEIPC Group) had invested approximately $17 million and are committed to invest up to an additional $83 million toward the China project, subject to certain conditions. Completion of construction is dependent on BaoSteel making satisfactory arrangements with the Inner Mongolia Power (Group) Co. Ltd. for BaoSteel's interconnection to the grid. In early November 1999, the PRC central government directed the Inner Mongolia government to coordinate the finalization of an interconnection agreement. (8) Discontinued operations - --- ----------------------- Malama Pacific Corp. (MPC) On September 14, 1998, the HEI Board of Directors adopted a plan to exit the residential real estate development business (engaged by MPC and its subsidiaries) by September 1999. Accordingly, MPC management commenced a program to sell all of MPC's real estate assets and investments and HEI reported MPC as a discontinued operation in the Company's consolidated statements of income in the third quarter of 1998. In the slow Hawaii real estate market, however, the plan to dispose of MPC's real estate assets and investments is taking longer than expected. Summary financial information for the discontinued operations of MPC is as follows:
Three months Nine months ended ended September 30, September 30, (in thousands) 1998 1998 - ------------------------------------------------------------------------------------------------------------------------------- Operations Revenues........................................................................ $ 743 $ 3,313 Operating loss (including impairment writedowns)................................ $(19,881) $(20,648) Interest expense................................................................ (538) (1,609) Income tax benefits............................................................. 7,945 8,659 ------------------ --------------------- Loss from operations............................................................ $(12,474) $(13,598) ------------------ --------------------- Disposal Loss, including provision of $5,000 for loss from operations during phase-out period...................................................... $(16,343) $(16,343) Income tax benefits............................................................. 6,359 6,359 ------------------ --------------------- Loss on disposal................................................................ $ (9,984) $ (9,984) ------------------ --------------------- Loss from discontinued operations of MPC........................................ $(22,458) $(23,582) ================== ===================== Basic and diluted loss per common share......................................... $(0.70) $(0.74) ================== =====================
As of September 30, 1999, the remaining net assets of the discontinued residential real estate development operations amounted to $20 million (included in "Other" assets) and consisted primarily of real estate assets, receivables and deferred tax assets, reduced by loans, accounts payable and a reserve for the net loss from operations during the disposal period. The amounts that MPC will ultimately realize from the sale of the real estate assets could differ materially from the recorded amounts as of September 30, 1999. In the second quarter of 1999, MPC closed the sale of one property and received proceeds, net of selling expenses, of $3.8 million. The remaining MPC and/or its joint ventures' properties to be sold consist of approximately 400 acres on three islands. MPC is currently in active negotiations for the sale of approximately 150 acres. 10 The Hawaiian Insurance & Guaranty Company, Limited (HIG) HIG and its subsidiaries (collectively, the HIG Group) were property and casualty insurance companies. In December 1992, due to a significant increase in the estimate of policyholder claims from Hurricane Iniki, the HEI Board of Directors concluded it would not contribute additional capital to HIG and the remaining investment in the HIG Group was written off. On December 24, 1992, a formal rehabilitation order vested full control over the HIG Group in the Insurance Commissioner of the State of Hawaii (the Rehabilitator) and her deputies. HEI Diversified, Inc. (HEIDI) was the holder of record of all the common stock of HIG until August 16, 1994. In 1994, the Company settled a lawsuit stemming from this situation, with the Company making a settlement payment of $32 million to the Rehabilitator. HEI and HEIDI sought reimbursement for the settlement, interest and defense costs from three director and officer liability insurance carriers. In August 1998, the Company settled all claims with the three former insurance carriers relating to the 1994 settlement payment. The Company received $24.5 million ($13.8 million net of estimated expenses and income taxes or $0.43 in basic and diluted earnings per share for the quarter and nine months ended September 30, 1998), and recorded the settlement as net gain on disposal of discontinued operations in the third quarter of 1998. (9) Sale of maritime freight transportation operations - ------------------------------------------------------ On August 4, 1999, HEI signed agreements for the sale of YB and certain operating assets of HTB to Saltchuk Resources, Inc. of Seattle, Washington. On November 10, 1999, the sale of YB and substantially all of the operating assets of HTB was closed. HEI plans to sell the remaining assets of HTB to other parties. The Company expects an after-tax loss of approximately $2 million on the transactions and accrued the loss in the third quarter of 1999. 11
Hawaiian Electric Company, Inc. and subsidiaries Consolidated balance sheets (unaudited) September 30, December 31, (in thousands, except par value) 1999 1998 - ------------------------------------------------------------------------------------------------------------------ Assets Utility plant, at cost Land.................................................................. $ 28,284 $ 30,312 Plant and equipment................................................... 2,802,830 2,750,487 Less accumulated depreciation......................................... (1,056,196) (982,172) Plant acquisition adjustment, net..................................... 471 510 Construction in progress.............................................. 164,649 144,035 --------------- ------------------ Net utility plant............................................... 1,940,038 1,943,172 --------------- ------------------ Current assets Cash and equivalents.................................................. 26,179 54,783 Customer accounts receivable, net..................................... 67,452 69,170 Accrued unbilled revenues, net........................................ 47,568 43,445 Other accounts receivable, net........................................ 1,665 4,082 Fuel oil stock, at average cost....................................... 26,571 16,778 Materials and supplies, at average cost............................... 19,310 17,266 Prepayments and other................................................. 3,751 3,858 --------------- ------------------ Total current assets............................................ 192,496 209,382 --------------- ------------------ Other assets Regulatory assets..................................................... 112,582 108,344 Other................................................................. 47,234 50,355 --------------- ------------------ Total other assets.............................................. 159,816 158,699 --------------- ------------------ $ 2,292,350 $2,311,253 =============== ================== Capitalization and liabilities Capitalization Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares........................... $ 85,387 $ 85,387 Premium on capital stock.............................................. 295,468 295,344 Retained earnings..................................................... 421,840 405,836 --------------- ------------------ Common stock equity............................................. 802,695 786,567 Cumulative preferred stock - not subject to mandatory redemption...... 34,293 34,293 HECO-obligated mandatorily redeemable trust preferred securities of subsidiary trusts holding solely HECO and HECO-guaranteed debentures......................................................... 100,000 100,000 Long-term debt, net................................................... 645,176 621,998 --------------- ------------------ Total capitalization............................................ 1,582,164 1,542,858 --------------- ------------------ Current liabilities Preferred stock sinking fund and optional redemption payments......... - 47,080 Short-term borrowings - nonaffiliates................................. 103,111 133,863 Short-term borrowings - affiliate..................................... - 5,550 Accounts payable...................................................... 50,749 40,008 Interest and preferred dividends payable.............................. 16,739 11,214 Taxes accrued......................................................... 70,649 58,335 Other................................................................. 21,658 30,166 --------------- ------------------ Total current liabilities....................................... 262,906 326,216 --------------- ------------------ Deferred credits and other liabilities Deferred income taxes................................................. 128,640 128,327 Unamortized tax credits............................................... 48,502 48,130 Other................................................................. 71,660 66,818 --------------- ------------------ Total deferred credits and other liabilities.................... 248,802 243,275 --------------- ------------------ Contributions in aid of construction..................................... 198,478 198,904 --------------- ------------------ $ 2,292,350 $2,311,253 =============== ================== See accompanying notes to HECO's consolidated financial statements.
12
Hawaiian Electric Company, Inc. and subsidiaries Consolidated statements of income (unaudited) Three months ended Nine months ended (in thousands, except for ratio of earnings September 30, September 30, --------------------------------- --------------------------------- to fixed charges) 1999 1998 1999 1998 - --------------------------------------------------------------------------------------------------------------------------------- Operating revenues.................................... $275,925 $257,368 $763,408 $755,615 -------------- -------------- -------------- -------------- Operating expenses Fuel oil.............................................. 58,942 48,554 151,046 149,734 Purchased power....................................... 71,952 69,148 199,581 204,822 Other operation....................................... 35,730 34,286 100,530 104,251 Maintenance........................................... 14,436 10,508 41,324 31,738 Depreciation and amortization......................... 23,322 21,448 70,041 64,336 Taxes, other than income taxes........................ 26,039 24,263 72,459 71,609 Income taxes.......................................... 13,419 16,693 36,208 42,253 -------------- -------------- -------------- -------------- 243,840 224,900 671,189 668,743 -------------- -------------- -------------- -------------- Operating income...................................... 32,085 32,468 92,219 86,872 -------------- -------------- -------------- -------------- Other income Allowance for equity funds used during construction................................ 1,176 3,139 3,202 8,781 Other, net............................................ 998 2,117 3,370 6,439 -------------- -------------- -------------- -------------- 2,174 5,256 6,572 15,220 -------------- -------------- -------------- -------------- Income before interest and other charges.............. 34,259 37,724 98,791 102,092 -------------- -------------- -------------- -------------- Interest and other charges Interest on long-term debt............................ 10,313 9,910 30,139 30,602 Amortization of net bond premium and expense.......... 436 374 1,203 1,096 Other interest charges................................ 1,494 1,785 5,414 5,086 Allowance for borrowed funds used during construction................................ (716) (1,826) (1,955) (5,145) Preferred stock dividends of subsidiaries............. 229 638 716 1,915 Preferred securities distributions of trust subsidiaries................................. 1,919 1,006 5,746 3,019 -------------- -------------- -------------- -------------- 13,675 11,887 41,263 36,573 -------------- -------------- -------------- -------------- Income before preferred stock dividends of HECO............................................ 20,584 25,837 57,528 65,519 Preferred stock dividends of HECO..................... 269 861 908 2,592 -------------- -------------- -------------- -------------- Net income for common stock........................... $ 20,315 $ 24,976 $ 56,620 $ 62,927 ============== ============== ============== ============== Ratio of earnings to fixed charges (SEC method)...... 3.07 3.36 ============== ==============
Hawaiian Electric Company, Inc. and subsidiaries Consolidated statements of retained earnings (unaudited)
Three months ended Nine months ended September 30, September 30, --------------------------------- --------------------------------- (in thousands) 1999 1998 1999 1998 - --------------------------------------------------------------------------------------------------------------------------------- Retained earnings, beginning of period................ $415,944 $410,207 $405,836 $387,582 Net income for common stock........................... 20,315 24,976 56,620 62,927 Common stock dividends................................ (14,419) (28,464) (40,616) (43,790) -------------- -------------- -------------- -------------- Retained earnings, end of period...................... $421,840 $406,719 $421,840 $406,719 ============== ============== ============== ============== HEI owns all the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful. See accompanying notes to HECO's consolidated financial statements.
13
Hawaiian Electric Company, Inc. and subsidiaries Consolidated statements of cash flows (unaudited) Nine months ended September 30, -------------------------------------------- (in thousands) 1999 1998 - ----------------------------------------------------------------------------------------------------------------------- Cash flows from operating activities Income before preferred stock dividends of HECO............................ $ 57,528 $ 65,519 Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities Depreciation and amortization of property, plant and equipment............................................... 70,041 64,336 Other amortization................................................... 4,718 5,204 Deferred income taxes................................................ 313 1,830 Tax credits, net..................................................... 1,568 3,829 Allowance for equity funds used during construction.................. (3,202) (8,781) Changes in assets and liabilities Decrease in accounts receivable................................. 4,135 1,972 Decrease (increase) in accrued unbilled revenues................ (4,123) 1,191 Decrease (increase) in fuel oil stock........................... (9,793) 9,971 Decrease (increase) in materials and supplies................... (2,044) 1,998 Increase in regulatory assets................................... (2,464) (2,914) Increase (decrease) in accounts payable......................... 10,741 (11,557) Changes in other assets and liabilities......................... 17,546 (495) ------------------- ------------------- Net cash provided by operating activities.................................. 144,964 132,103 ------------------- ------------------- Cash flows from investing activities Capital expenditures....................................................... (68,714) (98,016) Contributions in aid of construction....................................... 6,327 6,310 Proceeds from sales of assets.............................................. 1,499 - Payments on notes receivable............................................... 1,199 1,141 ------------------- ------------------- Net cash used in investing activities...................................... (59,689) (90,565) ------------------- ------------------- Cash flows from financing activities Common stock dividends..................................................... (40,616) (43,790) Preferred stock dividends.................................................. (908) (2,592) Preferred securities distributions of trust subsidiaries................... (5,746) (3,019) Proceeds from issuance of long-term debt................................... 73,052 72,894 Repayment of long-term debt................................................ (50,000) (57,500) Redemption of preferred stock.............................................. (47,080) (2,590) Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less.......... (36,302) (147) Other...................................................................... (6,279) (974) ------------------- ------------------- Net cash used in financing activities...................................... (113,879) (37,718) ------------------- ------------------- Net increase (decrease) in cash and equivalents............................ (28,604) 3,820 Cash and equivalents, beginning of period.................................. 54,783 1,676 ------------------- ------------------- Cash and equivalents, end of period........................................ $ 26,179 $ 5,496 =================== =================== See accompanying notes to HECO's consolidated financial statements.
14 Hawaiian Electric Company, Inc. and subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 1999 and 1998 (Unaudited) - -------------------------------------------------------------------------------- (1) Basis of presentation - -------------------------- The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information and with 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 consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto incorporated by reference in HECO's Annual Report on SEC Form 10-K for the year ended December 31, 1998 and the consolidated financial statements and the notes thereto in HECO's Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 1999 and June 30, 1999. In the opinion of HECO's management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of September 30, 1999 and December 31, 1998, the results of their operations for the three and nine months ended September 30, 1999 and 1998, and their cash flows for the nine months ended September 30, 1999 and 1998. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. Certain reclassifications have been made to prior periods' consolidated financial statements to conform to the 1999 presentation. (2) Cash flows - --------------- Supplemental disclosures of cash flow information Cash paid for interest (net of capitalized amounts) and income taxes was as follows:
Nine months ended September 30, ----------------------------------------- (in thousands) 1999 1998 - -------------------------------------------------------------------------------------------------------------------- Interest................................................................... $28,786 $26,249 ================== ================== Income taxes............................................................... $17,352 $22,277 ================== ==================
The decrease in income taxes paid for the nine months ended September 30, 1999 compared to the same period in 1998 was primarily due to a change in the timing of Public Service Company tax deductions. 15 Supplemental disclosure of noncash activities The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $3.2 million and $8.8 million for the nine months ended September 30, 1999 and 1998, respectively. The decrease in 1999 was due to the nonaccrual of AFUDC with respect to HELCO's Keahole project and a lower construction in progress base on which AFUDC is calculated because of the completion of projects and their addition to plant in 1998. (3) Commitments and contingencies - ---------------------------------- HELCO power situation Background. In 1991, HELCO identified the need, beginning in 1994, for - ---------- additional generation to provide for forecast load growth while maintaining a satisfactory generation reserve margin, to address uncertainties about future deliveries of power from existing firm power producers and to permit the retirement of older generating units. Accordingly, HELCO proceeded with plans to install at its Keahole power plant site two 20 megawatt (MW) combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time these units would be converted to a 58 MW dual-train combined-cycle (DTCC) unit. In January 1994, the Public Utilities Commission of the State of Hawaii (PUC) approved expenditures for CT-4, which HELCO had planned to install in late 1994. The timing of the installation of HELCO's phased DTCC unit at the Keahole power plant site has been revised on several occasions due to delays, described below, in (a) obtaining approval from the Hawaii Board of Land and Natural Resources (BLNR) of a Conservation District Use Permit (CDUP) amendment and (b) obtaining from the Department of Health of the State of Hawaii (DOH) and the U.S. Environmental Protection Agency (EPA) a Prevention of Significant Deterioration/Covered Source permit (PSD permit) for the Keahole power plant site. The delays are primarily attributable to lawsuits, claims and petitions filed by independent power producers and other parties. CDUP amendment. On July 10, 1997, the Third Circuit Court of the State of Hawaii - --------------- issued its Amended Findings of Fact, Conclusions of Law, Decision and Order addressing HELCO's appeal of an order of the BLNR, along with other consolidated civil cases relating to HELCO's application for a CDUP amendment. Because the BLNR failed to take valid agency action or render a proper decision within the 180 day statutory deadline (as calculated by the Court), the Court ruled that HELCO was automatically entitled to put its land to the uses requested in its CDUP amendment application pursuant to the default provision of Section 183-41, Hawaii Revised Statutes (HRS). This decision allows HELCO to use its Keahole property as requested in its application. An amended order to the same effect was issued on August 18, 1997. Final judgments have been entered in all of the consolidated cases. Appeals with respect to the final judgments for certain of the cases have been filed with the Hawaii Supreme Court. Motions filed with the Third Circuit Court to stay the effectiveness of the judgments pending resolution of the appeals were denied in April and July 1998 (in response to a motion for reconsideration). In August 1998, the Hawaii Supreme Court denied nonhearing motions for stay of final judgment pending resolution of the appeals. Management believes that HELCO will ultimately prevail on appeal and that the final judgments of the Third Circuit Court will be upheld. The final judgment with respect to HELCO's entitlement to automatically put its land to the uses requested in its CDUP amendment application (which is in part 1 of the final judgment, and is referred to as HELCO's "default entitlement") was entered February 11, 1998. The final judgment states that HELCO must comply with the conditions in its application (part 2 of the final judgment), and that the standard conditions in Section 13-2-21 of the Hawaii Administrative Rules (HAR), the rules of the Department of Land and Natural Resources (DLNR), do not apply to the extent the standard conditions are incompatible with HRS Section 183-41 (part 3 of the final judgment). On August 17, 1999, certain plaintiffs filed a joint motion to enforce parts 2 and 3 of the final judgment (relating to applicable conditions) and to stay part 1 of the final judgment (the default entitlement) until such time as the applicable conditions were identified and it was determined whether HELCO had or could meet the applicable conditions. At a September 23, 1999 hearing, the Third Circuit Court ruled that the BLNR 16 must issue a written decision by November 30, 1999 on certain issues raised in the administrative petition filed by the Keahole Defense Coalition (KDC) in August 1998, including specific determinations of which conditions are not inconsistent with HELCO's ability to proceed under the default entitlement. If a written decision on the applicable conditions has not been distributed by the BLNR by that date, the Court stated that it would impose a stay on HELCO's ability to proceed under the default entitlement, effective as of noon on November 30, 1999. At a BLNR meeting on October 22, 1999, the BLNR determined that all 15 standard land use conditions in HAR 13-2-21(a) applied to HELCO's default entitlement and that the conditions in HELCO's pre-existing CDUP and amendments continue to apply with respect to those existing permits. The BLNR specifically did not address at that time the question of HELCO's compliance with each of those conditions. HELCO's position is that once a written decision is issued by the BLNR to interested parties, the Court's order would have been satisfied and the issue of a stay should be moot. See "BLNR petition" herein. Although the BLNR has not yet issued a written decision, certain plaintiffs have filed two motions in the Third Circuit Court attempting to implement their interpretation of the BLNR's ruling. On November 2, 1999, those plaintiffs filed a Second Joint Motion to Enforce Part Two and Part Three of the Final Judgment. In that motion, they allege that the Keahole project cannot meet the conditions relating to compatibility with the surrounding area and improvement of the existing physical and environmental aspects of the subject area. Furthermore, they claim that the project would be a prohibited use that cannot be placed in the conservation district, relying on zoning rules implemented by BLNR in 1994 in furtherance of Act 270, which prohibited fossil fuel fired generating units in the conservation district. However, the Third Circuit Court has earlier ruled that Act 270 does not apply to HELCO's application, which was filed prior to the effective date of Act 270. Plaintiffs ask that HELCO be enjoined from placing further structures and improvements on the Keahole site and be ordered to remove all existing structures and improvements. On November 5, 1999, the same plaintiffs filed a Third Joint Motion to Enforce Judgment. In this motion, they ask that the Court void HELCO's default entitlement on the basis that HELCO forfeited its default entitlement by allegedly electing through HELCO's construction of the pre-PSD portions of the project, to build a project different from that described in its application. They also request that HELCO be enjoined from continuing construction activity at the site and ordered to restore the Keahole site to its pre-August 1992 condition. Both of these motions, which HELCO intends to oppose vigorously, are scheduled to be heard on November 29, 1999. PSD permit. In November 1995, the EPA declined to sign HELCO's PSD permit for - ---------- the combined-cycle unit. HELCO revised its permit application and, in 1997, the EPA approved a revised draft permit and the DOH issued a final PSD permit for HELCO's DTCC unit. Nine appeals of the issuance of the permit were filed with the EPA's Environmental Appeals Board (EAB) in December 1997. On November 25, 1998, the EAB issued an Order Denying Review in Part and Remanding in Part. The EAB denied appeals of the permit that were based on challenges to (1) the DOH's use of a netting analysis (with respect to nitrogen oxide (NOx) emissions), (2) the DOH's determination of Best Available Control Technology (BACT) for control of sulfur dioxide emissions, and (3) certain aspects of the DOH's ambient air and source impact analysis. However, the EAB concluded that the DOH had not adequately responded to comments that had been made during the public comment period that data relating to certain ambient air concentrations were outdated or were measured at unrepresentative locations. The EAB remanded the proceedings and directed the DOH to reopen the permit for the limited purpose of (1) providing an updated air quality impact report incorporating current data on sulfur dioxide and particulate matter ambient concentrations and (2) providing a sufficient explanation of why the carbon monoxide and ozone data used to support the permit are reasonably representative, or performing a new air quality analysis based on data shown to be representative of the air quality in the area to be affected by the project. The EAB directed the DOH to accept and respond to public comments on the DOH's decisions with respect to these issues and ruled that any further appeals of its decision would be limited to the issues addressed on remand. On March 3, 1999, the EAB issued an Order 17 denying motions for reconsideration which had been filed by HELCO, KDC and Kawaihae Cogeneration Partners (KCP). As a result of the EAB's decision on November 25, 1998 and its denial of all motions for reconsideration on March 3, 1999, there have been further delays in HELCO's construction of CT-4 and CT-5. The actual length of the delays will depend on the actions needed to address the EAB's rulings. HELCO continues to work with the DOH to address the issues specified in the EAB remand order, with the objective of having the final permit reissued by the end of January 2000 and of reaching a final resolution of any appeals to the EAB as expeditiously as possible thereafter. As part of the remand process, DOH held a public hearing on the draft permit on October 7, 1999, limited to the issues remanded by the EAB. The next steps will be for the DOH to respond to the public comments made at the hearing and to submit the proposed permit to the EPA for approval. HELCO believes that the PSD permit will eventually be obtained. KDC declaratory judgment action. In February 1997, KDC and three individuals - ------------------------------- (Plaintiffs) filed a lawsuit in the Third Circuit Court of the State of Hawaii against HELCO, the director of the DOH, and the BLNR, seeking declaratory rulings with regard to five counts alleging that, with regard to the Keahole project, one or more of the defendants had violated, or could not allow the plant to operate without violating, the State Clean Air Act, the State Noise Pollution Act, conditions of HELCO's conditional use permit, covenants of HELCO's land patent and Hawaii administrative rules regarding standard conditions applicable to land permits. The Complaint was amended in March of 1998 to add a sixth count, claiming that an amendment to a provision of the land patent (relating to the conditions under which the State could repurchase the land) is void and that the original provision should be reinstated. On April 12, 1999, the Court ruled that, because there were no remaining issues of fact in the case, a May 1999 trial date was vacated, no further discovery was authorized, and proceedings before the Court were suspended pending any further administrative action by the DOH and the BLNR. The Court's rulings to date on the six counts in the KDC complaint are as follows: 1. Count I (State Clean Air Act): At a hearing on April 5, 1999, the Court ruled that the DOH was within its discretionary authority in granting HELCO's requests for additional extensions of time to file its Title V air permit applications. 2. Count II (State Noise Pollution Act): At a hearing relating to Count II on February 16, 1999, the DOH notified the Court and the parties of a change in its interpretation of the noise rules promulgated under the State Noise Pollution Act. The change in interpretation would apply to the Keahole plant the noise standard applicable to the emitter property (which the DOH claims to be a 55 dBA (daytime) and 45 dBA (nighttime) standard) rather than the previously-applied noise standard of the receptor properties in the surrounding agricultural park (a 70 dBA standard). In response to the new position announced by the DOH, on February 23, 1999 HELCO filed a declaratory judgment action against the DOH, alleging that the noise rules were invalid on constitutional grounds. At a hearing on March 31, 1999, the Court granted KDC's motion to dismiss HELCO's complaint and Plaintiffs' motion for reconsideration on Count II and ruled that the applicable noise standard was 55 dBA daytime and 45 dBA nighttime. The Court specifically reserved ruling on HELCO's claims or potential claims based on estoppel and on the constitutionality of the noise rules "as applied" to HELCO's Keahole plant. On May 12, 1999, the Order dismissing HELCO's declaratory judgment complaint was issued and Final Judgment was entered. The DOH objected to the entry of Final Judgment before all issues in the lawsuit were resolved, but an Order denying that motion was issued on July 26, 1999. HELCO filed a notice of appeal on August 25, 1999 and KDC filed a notice of cross-appeal on September 3, 1999. On March 31, 1999, the Court granted in part and denied in part HELCO's motion for leave to file a cross-claim and a third-party complaint, stating that HELCO may file such motions on 18 the "as applied" and "estoppel" claims once the DOH actually applies the 55/45 dBA noise standard to the Keahole plant. An Order confirming this ruling was entered on June 1, 1999. The DOH has not issued any formal enforcement action applying the 55/45 dBA standard to the Keahole plant. 3. Count III (violation of CDUP): At a hearing on April 12, 1999, the Court granted HELCO's motion for summary judgment and suspended proceedings on this Count pending referral of this matter to the BLNR. (Should DOH find HELCO in violation of the noise rules (see Count II), the BLNR would be called to act on the impact of such violation, if any, on the CDUP.) 4. Count IV (violations of HELCO's land patent): At a hearing on April 12, 1999, the Court granted HELCO's motion for summary judgment and suspended proceedings on this Count pending referral of this matter to the BLNR. (Should DOH find HELCO in violation of the noise rules (see Count II), the BLNR would be called to act on the impact of such violation, if any, on the land patent.) 5. Count V (HELCO's ability to comply with land use regulations): At a hearing on April 12, 1999, the Court granted HELCO's motion for summary judgment and suspended proceedings on this Count pending referral of this matter to the BLNR for resolution of the administrative proceeding now pending before it. (See "BLNR petition" herein.) 6. Count VI (amendment of HELCO's land patent): At the March 31, 1999 hearing, the Court granted Plaintiffs' motion for summary judgment, finding that a 1984 amendment to HELCO's land patent was invalid because the BLNR had failed to comply with the statutory procedure relating to amendments. The amendment was intended to correct an error in the original land patent with regard to the repurchase clause in the patent and to conform the language to the applicable statute, under which the State would have the right to repurchase the site (as opposed to an automatic reversion) if it were no longer used for utility purposes. HELCO and the BLNR have discussed correcting this matter through an administrative or judicial reformation of the land patent. If and when the DOH and the BLNR/DLNR act on the issues relating to Counts II through VI, and depending upon their rulings, the KDC lawsuit may be moot. Meanwhile, HELCO is exploring possible noise mitigation measures, which can be implemented if necessary, for both the existing units and CT-4 and CT-5. Orders were entered on April 16, 1999 with regard to Count I, May 18, 1999 with regard to Count VI, and June 3, 1999 with regard to Counts II through V. On April 30, 1999, KDC filed a motion to determine prevailing party and to tax attorney fees and costs and a motion for discovery sanctions. After hearing, the Court ruled that Plaintiffs were the prevailing party as to Counts II and V and were entitled to fees and costs with regard to those counts, denied Plaintiffs' motion for fees as the prevailing party with regard to Count VI, denied HELCO's motion for fees as the prevailing party with regard to Count I and granted Plaintiffs' request for discovery sanctions against HELCO for late supplementation of responses to discovery requests. HELCO filed motions to alter or amend the orders regarding attorneys' fees and costs, and orders granting those motions were issued on September 22, 1999. HELCO intends to continue to vigorously defend against the claims raised in this case and in related administrative actions. Other complaints. Two additional cases were filed in 1998. First, in March 1998, - ---------------- one of the Plaintiffs filed a complaint for declaratory judgment against HELCO, the BLNR and the DLNR. The complaint alleges a violation of Plaintiff's constitutional due process rights because the land use conditions (if any) which apply to HELCO's use of the Keahole site were determined administratively by the DLNR (through a letter issued to HELCO on January 30, 1998) rather than being decided by the BLNR in a contested case. Also filed with the complaint was a motion to stay enforcement of the DLNR letter, which motion was denied in April 1998. Second, in May 1998, Waimana Enterprises, Inc., whose subsidiary is a partner in KCP, filed a lawsuit in the Third Circuit Court of the State of Hawaii, asking 19 for a declaration that the January 1998 DLNR letter is void and seeking an injunction to prevent HELCO from further construction until the Court or the BLNR, at a public hearing, determines what conditions and limitations apply and whether HELCO is in compliance with them. At a hearing on February 8, 1999, the parties agreed, and the Court orally ordered, the consolidation of the Plaintiff's lawsuit with the KDC lawsuit and the dismissal with prejudice of the Waimana lawsuit. The Plaintiff filed a motion for summary judgment with regard to the claims in her lawsuit and the BLNR and DLNR, joined by HELCO, also filed a motion for summary judgment in that lawsuit. At the March 31, 1999 hearing, the Court granted the BLNR/DLNR motion and HELCO's joinder, finding that the January 30, 1998 letter was a ministerial function properly performed by DLNR. A proposed Order was approved by all counsel, but has not yet been entered by the Court. BLNR petition. On August 5, 1998, KDC filed with the BLNR a Petition for - -------------- Declaratory Ruling under HRS Section 91-8. The petition alleged that the standard conditions in HAR Section 13-2-21 apply to HELCO's default entitlement to use its Keahole site, that the letter issued to HELCO by the DLNR in January 1998 was erroneous because it failed to incorporate all conditions applicable to the existing permits, and that the DOH issued three separate Notices of Violation (NOVs) to HELCO in 1992 and 1998 for violation of clean air rules, which NOVs are alleged to constitute violations under the existing permits and render such permits null and void. The petition requested that the BLNR commence a contested case on the petition; that the BLNR determine that HELCO has violated the terms of its existing conditional use permits, causing such permits to be null and void; and that the BLNR determine that HELCO has violated the conditions applicable to its default entitlement, such that HELCO should be enjoined from using the Keahole property under such default entitlement. The BLNR requested that each of the parties submit statements of position on the issues and HELCO filed its statement in October 1998. The last of the responsive submissions of the parties was filed in December 1998. Pursuant to a ruling from the Third Circuit Court that the BLNR decide certain issues raised in this petition by November 30, 1999 (see "CDUP amendment" herein), these issues were discussed at an October 22, 1999 BLNR meeting. The BLNR determined that none of the standard land use conditions were inconsistent with HELCO's ability to proceed under its default entitlement and, therefore, each of the standard land use conditions applied to the expansion. However, the BLNR has not yet determined whether HELCO has complied with the applicable conditions. The BLNR also determined that specific conditions imposed by the BLNR on HELCO's original CDUP and amendments thereto continue to apply to the existing plant but not to the expansion under the default entitlement. The BLNR still needs to address the remaining issues raised in the petition. IPP complaints. Two independent power producers (IPPs), KCP and Enserch - -------------- Development Corporation (Enserch), filed separate complaints against HELCO with the PUC in 1993 and 1994, respectively, alleging that they are entitled to power purchase contracts to provide HELCO with additional capacity, which they claimed would be a substitute for HELCO's planned 58 MW DTCC unit at Keahole. In September 1995, the PUC allowed HELCO to continue to pursue construction of and commit expenditures for the second combustion turbine (CT-5) and the steam recovery generator (ST-7) for its planned DTCC unit, but stated in its order that "no part of the project may be included in HELCO's rate base unless and until the project is in fact installed, and is used and useful for utility purposes." The PUC also ordered HELCO to continue negotiating with the IPPs and held that the facility to be built (i.e., either HELCO's or one of the IPP's) should be the one that can be most expeditiously put into service at "allowable cost." The current status of the IPPs' PUC complaints, and of a complaint filed by Hilo Coast Power Company (HCPC) in April 1997, is as follows: Enserch complaint. On January 16, 1998, HELCO filed with the PUC an ----------------- application for approval of a power purchase agreement for a 60 MW (net) facility and an interconnection agreement with Encogen Hawaii, L.P. (Encogen), an Enserch affiliate, both dated October 22, 1997. The PUC issued a decision and order approving the agreements on July 14, 1999. The decision was amended at HELCO's request on July 21, 1999 and became final and nonappealable on August 23, 1999. According to Encogen, its first phase of 22 MW is expected to be in-service in July 20 2000 and the remainder of its 60 MW facility is expected to be in-service in November 2000. Encogen is currently pursuing the replacement of the existing partnership. The change is not expected to affect completion of the facility as scheduled. KCP complaint. In January 1996, the PUC ordered HELCO to continue in good ------------- faith to negotiate a power purchase agreement with KCP. In May 1997, KCP filed a motion for unspecified "sanctions" against HELCO for allegedly failing to negotiate in good faith. In June 1997, KCP filed a motion asking the PUC to designate KCP's facility as the next generating unit on the HELCO system and to determine the "allowable cost" which would be payable by HELCO to KCP. HELCO filed memoranda in opposition to KCP's motions. The PUC held an evidentiary hearing in August 1997. KCP filed two other motions, which HELCO opposed, to supplement the record. The PUC issued an Order in June 1998 which denied all of KCP's pending motions; provided rulings and/or guidance on certain avoided cost and contract issues; directed HELCO to prepare an updated avoided cost calculation that includes the Encogen agreement; and directed HELCO and KCP to resume contract negotiations. HELCO filed a motion for partial reconsideration with respect to one avoided cost issue. The PUC granted HELCO's motion and modified its order in July 1998. HELCO resumed negotiations with KCP in 1998 in compliance with the Order, but no agreement has been reached. On November 20, 1998, KCP filed a motion asking the PUC to appoint a hearings officer to make a recommendation to the PUC regarding the terms and conditions of a power purchase agreement and the calculation of avoided cost. HELCO filed a memorandum in opposition to KCP's motion on December 2, 1998. On July 9, 1999, KCP filed an additional motion, asking the PUC to reopen its complaint docket and to enforce the Public Utility Regulatory Policies Act of 1978 by calculating the utility's avoided cost. HELCO filed a memorandum in opposition to KCP's motion on July 16, 1999, KCP filed a reply on July 22, 1999 and the Consumer Advocate filed a statement of position on August 2, 1999. On October 29, 1999, the Third Circuit Court ruled that the lease between Waimana and the Department of Hawaiian Home Lands for the site on which KCP's plant was proposed to be built was invalid. HCPC complaint. In April 1997, HCPC filed a complaint against HELCO with -------------- the PUC, requesting an immediate hearing on HCPC's offer for a new 20-year power purchase agreement for its existing facility, which is proposed to be expanded from 22 MW to 32 MW. HCPC's existing power purchase agreement is scheduled to terminate at the end of 1999. The PUC converted the HCPC complaint into a purchased power contract negotiation proceeding. HCPC submitted a new proposal in the proceeding in March 1998 for a 32-year power purchase agreement. An evidentiary hearing, which was limited to three issues affecting the calculation of avoided costs, was held in April 1998. On November 25, 1998, the PUC issued a Decision and Order in the HCPC complaint docket and directed that HCPC and HELCO continue to negotiate a power purchase agreement and by February of 1999 submit to the PUC either a finalized agreement or reports informing the PUC of the matters preventing the finalization of an agreement. The parties entered into negotiations but did not finalize an agreement at that time. Status reports were filed by HCPC and HELCO in February 1999. In its status report, HELCO requested a hearing with respect to pricing and avoided cost issues. The PUC issued an Order reopening the docket to further assist HELCO and HCPC in negotiating an agreement and giving each party an opportunity to file supplemental memoranda. HELCO filed a Motion for Partial Reconsideration of the Order, stating that it would waive its right to a hearing if it were allowed to present oral arguments to the PUC. The PUC granted HELCO's motion, and oral arguments were held on March 25, 1999. On June 24, 1999, the PUC issued an Order in which it agreed with HELCO's avoided cost calculation. The PUC ordered HELCO and HCPC to continue negotiations consistent with the Order and to submit either a finalized agreement or, if no agreement is reached, to submit written reports informing the PUC of the matters that are 21 preventing finalization of an agreement. Reports were submitted by HCPC and HELCO on August 18, 1999. Subsequently, HELCO and HCPC reached agreement on an amended and restated agreement in October 1999. The term of the agreement, which is for the provision of 22 MW, is for five years (through December 31, 2004) and may continue beyond that time unless either party provides notice of termination to the other party by May 31 in the year of termination. HELCO has the right to terminate the contract as of the end of 2002, 2003 or 2004 for amounts specified in the contract. The agreement is subject to PUC approval, and provides that the agreement will be void unless an acceptable interim or final PUC approval order is issued by November 30, 1999 (unless such date is extended). An application for approval was submitted to the PUC on October 12, 1999. The PUC issued information requests to HELCO on October 20, 1999 and responses were filed on or about October 29, 1999. On November 5, 1999, the agreement was amended to extend the date for a final PUC approval order to December 10, 1999. The CA issued information requests on November 5, 1999 and responses are due on November 12, 1999. Management cannot determine at this time whether the amended and restated agreement with HCPC will be approved by the PUC or whether the negotiations with KCP or related PUC proceedings will result in the execution and/or PUC approval of an additional power purchase agreement. Pre-PSD work and notices of violation. The costs for the CT-4 project (and, to a - ------------------------------------- lesser extent, the CT-5 project) include the costs of certain facilities that benefit the existing Keahole power plant, but were originally scheduled to be installed at the same time as the new generating units. HELCO proceeded with the construction of the facilities that could be constructed prior to receipt of the PSD permits for CT-4 and CT-5 (pre-PSD facilities) after receipt of the CDUP amendment (as a result of the Third Circuit Court orders). (See "CDUP amendment" herein.) Pre-PSD facilities. The pre-PSD facilities include a ------------------ shop/warehouse/administration building (completed in 1998), fire protection system upgrades (completed in September 1999), and a new water treatment system (which is expected to be completed by the end of 1999, and will supply the demineralized water needs of the existing CT at Keahole). DOH notice of violation. In July 1998, the DOH issued an NOV to HELCO for ------------------------ items allegedly constituting unauthorized construction activity at the Keahole Generating Station prior to receipt of an effective PSD permit for CT-4 and CT-5. The NOV required HELCO to immediately halt construction activities on pipe rack foundations, a retaining wall and an oil/water separator, and imposed a fine of $48,800. HELCO complied with the stop work order on the designated items and paid the fine. EPA notice of violation. In September 1998, the EPA issued an NOV to HELCO ----------------------- stating that HELCO violated the Hawaii State Implementation Plan by commencing construction activities at the Keahole generating station without first obtaining a final air permit. By law, 30 days after the NOV, the EPA may issue an order requiring compliance with applicable laws, assessing penalties and/or commencing a civil action seeking an injunction; however, no order has yet been issued. HELCO has put the EPA on notice that certain construction activities not affected by the NOV are continuing, and has received approval to proceed with certain construction activities. However, HELCO has halted work on other construction activities at Keahole until further notice is provided or approval is obtained from the EPA, or until the final air permit is received. Contingency planning. In June 1995, HELCO filed with the PUC its generation - --------------------- resource contingency plan detailing alternatives and mitigation measures to address the delays that have occurred in adding new generation. Actions under the plan (such as deferring the retirements of older, smaller units) have helped HELCO maintain its reserve margin and reduce the risk of near-term capacity shortages. In January 1996, the PUC opened a proceeding to evaluate HELCO's contingency resource plan and HELCO's efforts to insure system reliability. HELCO has filed reports with the PUC from time to time 22 updating the contingency plan and the status of implementing the plan. The last update was filed on March 1, 1999, and another update is planned to be filed shortly. The first increment of new generation is now expected to be added in July 2000 (Encogen's 22 MW CT), at the earliest. Despite delays in adding new generation, HELCO's mitigation measures (including an extension of power purchases from HCPC) should provide HELCO with sufficient generation reserve margin to cover its projected monthly system peaks with units on scheduled maintenance until new generation is added in 2000 or 2001. However, if the amended and restated HCPC agreement (extending HCPC's provision of 22 MW of firm capacity beyond December 31, 1999) is not approved (see "IPP complaints, HCPC complaint" herein), HELCO's reserve margin (based on firm capacity without considering as-available resources such as wind and run-of-the-river hydroelectric generators) in 2000 will be less than the margin called for by its generation planning criteria until new generation is added. (HELCO would have sufficient generation to cover projected monthly system peak loads with units on scheduled maintenance, but might not always have enough reserve margin to make up for the unexpected outage of one of its largest generation units beginning in January 2000 until new generation is added.) The five-year extension of power purchases from HCPC, which can be terminated after two years (upon payment of a $1.5 million early termination payment), is intended to allow HELCO to maintain its generation reserve margin at an acceptable level until new generation is added, and to provide HELCO with a reserve cushion in the event of further delays in adding new generation. Additional increments of new firm capacity after Encogen's first CT are expected to be added in November 2000 (the remaining 38 MW of Encogen's 60 MW DTCC unit), and in early 2001 (CT-4 and CT-5). As new generation is added, beginning with the completion of Encogen's 60 MW unit, HELCO will retire its older, smaller generating units. Project status and costs incurred. Although management believes it has acted - --------------------------------- prudently with respect to the Keahole project, effective December 1, 1998, HELCO decided to discontinue, for financial reporting purposes, the accrual of an Allowance For Funds Used During Construction (AFUDC) on CT-4 and CT-5 (which would have been approximately $0.4 million after tax per month). The length of the delays to date and potential further delays were factors considered by management in its decision to discontinue the accrual of AFUDC. HELCO has also deferred plans for ST-7 to approximately 2006 or 2007, unless the Encogen facility is not placed in service as planned. In December 1998, HELCO removed $0.8 million in costs accumulated against ST-7 from construction work-in- progress, writing off $0.6 million and reclassifying $0.2 million in costs to inventory, since ST-7 would not be needed in the immediate future. HELCO believes that issues surrounding the CDUP amendment, the PSD permit, the declaratory judgment actions, the BLNR petition and related matters will be satisfactorily resolved and will not prevent it from constructing CT-4 and CT-5. HELCO's current plan contemplates that CT-4 and CT-5 will be added to its system by early 2001. Under HELCO's current estimate of generating capacity requirements, there will be a need for new capacity after the addition of Encogen. The continuation of power purchases from HCPC, which can be terminated at the end of 2001 upon payment of a $1.5 million early termination amount (see "IPP complaints, HCPC complaint" herein), is intended to allow HELCO to maintain its generation reserve margin at an acceptable level until new generation is added (whether by Encogen or by HELCO) and to provide HELCO with a reserve cushion in the event of further delays in adding new generation, and is not intended to defer the installation of CT-4 and CT-5. If it becomes probable that CT-4 and/or CT-5 will not be installed, HELCO may be required to write-off a material portion of the costs incurred in its efforts to put these units into service. As of September 30, 1999, HELCO's costs incurred in its efforts to put CT-4 and CT-5 into service amounted to $ 77.3 million, including approximately $32.3 million for equipment and material purchases, approximately $23.5 million for planning, engineering, permitting, site development and other costs and approximately $21.5 million for AFUDC accrued through November 30, 1998, after which HELCO stopped accruing AFUDC. Of the $77.3 million referred to above, $18.0 million relates to the cost of the 23 pre-PSD facilities (see "Pre-PSD work and notices of violation" herein). It is the opinion of management that no adjustment is required to these costs as of September 30, 1999. Competition proceeding On December 30, 1996, the PUC instituted a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. After a collaborative process involving the 19 parties to the proceeding, final statements of position were prepared by several of the parties and submitted to the PUC in October 1998. HECO's position is that retail competition is not feasible in Hawaii, but that some of the benefits of competition can be achieved through competitive bidding for new generation, performance-based rate-making and innovative pricing provisions. The other parties to the proceeding advanced numerous other proposals in their statements of position. The PUC will determine what subsequent steps will be followed in the proceeding, but no timetable has been set for such a determination. Some of the parties may seek state legislative action on their proposals. HECO cannot predict what the ultimate outcome of the proceeding will be or which (if any) of the proposals advanced in the proceeding will be implemented. Environmental regulation See discussion of the DOH NOV and the EPA NOV issued to HELCO above and note (7), "Commitments and contingencies," in HEI's "Notes to consolidated financial statements." (4) HECO-obligated mandatorily redeemable trust preferred securities of - ------------------------------------------------------------------------- subsidiary trusts holding solely HECO and HECO-guaranteed debentures -------------------------------------------------------------------- In March 1997, HECO Capital Trust I (Trust I), a grantor trust and a wholly owned subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO- Obligated 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1997 trust preferred securities and the common securities were used by Trust I to purchase 8.05% Junior Subordinated Deferrable Interest Debentures, Series 1997 (1997 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1997 junior deferrable debentures, which bear interest at 8.05% and mature on March 27, 2027, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust I. The 1997 trust preferred securities must be redeemed at the maturity of the underlying debt on March 27, 2027, which maturity may be shortened to a date no earlier than March 27, 2002 or extended to a date no later than March 27, 2046, and are not redeemable at the option of the holders, but may be redeemed by Trust I, in whole or in part, from time to time, on or after March 27, 2002 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust II in the underlying debt securities of HECO, HELCO and MECO. In December 1998, HECO Capital Trust II (Trust II), a grantor trust and a wholly owned subsidiary of HECO, sold (i) in a public offering, 2 million of its HECO- Obligated 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 trust preferred securities) with an aggregate liquidation preference of $50 million and (ii) to HECO, common securities with a liquidation preference of approximately $1.55 million. Proceeds from the sale of the 1998 trust preferred securities and the common securities were used by Trust II to purchase 7.30% Junior Subordinated Deferrable Interest Debentures, Series 1998 (1998 junior deferrable debentures) issued by HECO in the principal amount of $31.55 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million. The 1998 junior deferrable debentures, which bear interest at 7.30% and mature on December 15, 2028, together with the subsidiary guarantees (pursuant to which the obligations of MECO and HELCO under their respective debentures are fully and unconditionally guaranteed by HECO), are the sole assets of Trust II. The 1998 trust preferred securities must be redeemed at the maturity of the underlying debt on December 15, 2028, which maturity may be shortened to a date no earlier than December 15, 2003 or extended to a date no later than December 15, 2047, and are not 24 redeemable at the option of the holders, but may be redeemed by Trust II, in whole or in part, from time to time, on or after December 15, 2003 or upon the occurrence of certain events. All of the proceeds from the sale were invested by Trust II in the underlying debt securities of HECO, HELCO and MECO, who used such proceeds from the sale of the 1998 junior deferrable debentures primarily to effect the redemption of certain series of their preferred stock having a total par value of $47 million. The 1997 and 1998 junior deferrable debentures and the common securities of the Trusts have been eliminated in HECO's consolidated balance sheets as of September 30, 1999 and December 31, 1998. The 1997 and 1998 junior deferrable debentures are redeemable only (i) at the option of HECO, MECO and HELCO, respectively, in whole or in part, on or after March 27, 2002 (1997 junior deferrable debentures) and December 15, 2003 (1998 junior deferrable debentures) or (ii) at the option of HECO, in whole, upon the occurrence of a "Special Event" (relating to certain changes in laws or regulations). (5) Accounting changes - ----------------------- Costs of computer software developed or obtained for internal use and start-up activities In March 1998, the AICPA Accounting Standards Executive Committee issued SOP 98- 1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use," which requires that certain costs, including certain payroll and payroll-related costs, be capitalized and amortized over the estimated useful life of the software. In April 1998, the AICPA Accounting Standards Executive Committee issued SOP 98-5, "Reporting on the Costs of Start-up Activities," which requires that costs of start-up activities, including organization costs, be expensed as incurred. The provisions of SOP 98-1 and SOP 98-5 are effective for fiscal years beginning after December 15, 1998. HECO and its subsidiaries adopted SOP 98-1 and SOP 98-5 effective January 1, 1999. The adoption of SOP 98- 1 and SOP 98-5 did not have a material effect on HECO's consolidated financial condition, results of operations or liquidity. Derivative instruments and hedging activities In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which establishes accounting and reporting standards for derivative instruments and hedging activities and requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. In June 1999, the provisions of SFAS No. 133 were amended by SFAS No. 137 to be effective for all fiscal quarters of fiscal years beginning after June 15, 2000. HECO and its subsidiaries will adopt SFAS No. 133, as amended, on January 1, 2001, but management has not yet determined the impact, if any, of adoption. (6) Summarized financial information - ------------------------------------- Summarized financial information for HECO's subsidiaries, HELCO and MECO, is as follows:
Balance sheet data HELCO MECO --------------------------------- -------------------------------- September 30, December 31, September 30, December 31, (in thousands) 1999 1998 1999 1998 - ------------------------------------------------------------------------------------------------------- Current assets................... $ 39,453 $ 35,473 $ 40,129 $ 41,103 Noncurrent assets................ 423,158 424,278 393,215 382,517 --------------- ------------- ------------ ------------- $462,611 $459,751 $433,344 $423,620 =============== ============= ============ ============= Common stock equity.............. $159,419 $157,269 $165,066 $157,402 Cumulative preferred stock-not subject to mandatory redemption. 7,000 7,000 5,000 5,000 Current liabilities.............. 49,814 62,313 31,926 32,052 Noncurrent liabilities........... 246,378 233,169 231,352 229,166 --------------- ------------- ------------- ------------- $462,611 $459,751 $433,344 $423,620 =============== ============= ============= =============
25
Income statement data HELCO MECO ------------------------------------------------------------------------------------------------------------ Three months ended Nine months ended Three months ended Nine months ended September 30, September 30, September 30, September 30, ------------------- ------------------- ------------------- ------------------- (in thousands) 1999 1998 1999 1998 1999 1998 1999 1998 - ---------------------------------------------------------------------------------------------------------------------------- Operating revenues...... $41,212 $39,159 $116,039 $115,536 $41,795 $35,108 $114,775 $103,353 Operating income........ 6,584 5,153 16,471 14,523 5,566 5,207 17,719 14,570 Net income for common stock.. 3,943 4,498 8,652 12,331 3,418 4,196 10,429 11,378
HECO has not provided separate financial statements and other disclosures concerning MECO and HELCO because in the opinion of management, such financial statements and other information are not material to holders of the 1997 and 1998 junior deferrable debentures issued by MECO and HELCO which have been fully and unconditionally guaranteed by HECO. (7) Reconciliation of electric utility operating income per HEI and HECO - -------------------------------------------------------------------------- consolidated statements of income ---------------------------------
Three months ended Nine months ended September 30, September 30, --------------------------- ------------------------ (in thousands) 1999 1998 1999 1998 - ------------------------------------------------------------------------------------------------------------- Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income).... $ 46,472 $ 51,266 $131,709 $135,525 Deduct: Income taxes on regulated activities........... (13,419) (16,693) (36,208) (42,253) Revenues from nonregulated activities.......... (1,358) (2,316) (3,938) (6,879) Add: Expenses from nonregulated activities.......... 390 211 656 479 -------- ----------- ---------- ------------ Operating income from regulated activities after income taxes (per HECO consolidated statements of income).......................... $ 32,085 $ 32,468 $ 92,219 $ 86,872 ========= =========== =========== ============
26 Item 2. Management's discussion and analysis of financial condition and results - -------------------------------------------------------------------------------- of operations - ------------- The following discussion should be read in conjunction with the consolidated financial statements of HEI and HECO and accompanying notes. RESULTS OF OPERATIONS HEI Consolidated - ----------------
Three months ended September 30, (in thousands, except per --------------------- % Primary reason(s) for share amounts) 1999 1998 change significant change* - ---------------------------------------------------------------------------------------------------------- Revenues................. $392,450 $377,318 4 Increase for the electric utility segment Operating income......... 56,551 62,299 (9) Decreases for the electric utility and "other" segments, partly offset by increase for the savings bank segment Income (loss) from: Continuing operations. $ 21,632 $ 27,779 (22) Lower operating income and AFUDC and higher preferred securities distributions, partly offset by lower preferred stock dividends and income taxes Discontinued - (8,693) NM Discontinued operations of real operations........... estate subsidiary, partly offset by insurance settlement in the ------------------------ third quarter of 1998 Net income......... $ 21,632 $ 19,086 13 ======================== Basic earnings per common share: Continuing operations. $ 0.67 $ 0.87 (23) See explanation for "Income (loss) from continuing operations" Discontinued - (0.27) NM See explanation for "Income operations........... (loss) from discontinued ------------------------ operations" $ 0.67 $ 0.60 12 ======================== Weighted-average number of common shares outstanding............. 32,203 32,010 1 Issuances under the 1987 Stock Option and Incentive Plan and other plans
27
Nine months ended September 30, (in thousands, except per ------------------------ % Primary reason(s) for share amounts) 1999 1998 change significant change* - ------------------------------------------------------------------------------------------------- Revenues................. $1,114,385 $1,112,841 - Increase for the electric utility segment Operating income......... 169,293 172,874 (2) Decreases for the electric utility and "other" segments, partly offset by increase for the savings bank segment Income (loss) from: Continuing operations. $ 65,142 $ 73,519 (11) Lower operating income and AFUDC and higher preferred securities distributions and interest expense, partly offset by lower preferred stock dividends and income taxes Discontinued operations. - (9,817) NM Discontinued operations of real estate subsidiary, partly offset by insurance settlement -------------------------- in 1998 Net income........... $ 65,142 $ 63,702 2 ========================== Basic earnings per common share: Continuing operations. $ 2.02 $ 2.30 (12) See explanation for "Income (loss) from continuing operations" Discontinued - (0.31) NM See explanation for "Income operations........... (loss) from discontinued operations" -------------------------- $ 2.02 $ 1.99 2 ========================== Weighted-average number of common shares 1 Issuances under the 1987 Stock outstanding............. 32,180 31,992 Option and Incentive Plan and other plans
* Also see segment discussions which follow. NM Not meaningful. 28 Following is a general discussion of the results of operations by business segment. Electric utility - ----------------
Three months ended (in thousands, September 30, except per ------------------------------ % Primary reason(s) for significant barrel amounts) 1999 1998 change change - ------------------------------------------------------------------------------------------------------------ Revenues............. $277,283 $259,684 7 Higher fuel prices, the effects of which are passed on to customers ($13 million), 0.6% higher KWH sales ($3 million) and higher rates at MECO ($3 million) Expenses Fuel oil............ 58,942 48,554 21 Higher fuel oil prices, partly offset by lower KWH's generated Purchased power..... 71,952 69,148 4 Higher KWHs purchased and fuel prices Other............... 99,917 90,716 10 Higher other operation, maintenance and depreciation and amortization expenses Operating income..... 46,472 51,266 (9) Higher KWH sales and rates at MECO, more than offset by higher other operation, maintenance and depreciation and amortization expenses Net income for common stock...... 20,315 24,976 (19) Lower operating income and AFUDC and higher preferred securities distributions, partly offset by lower income taxes Kilowatthour sales (millions)........ 2,338 2,323 1 Fuel oil price per barrel.............. $ 21.69 $ 17.79 22
29
Nine months ended (in thousands, September 30, except per --------------------------------- % Primary reason(s) for significant barrel amounts) 1999 1998 change change - ------------------------------------------------------------------------------------------------------------ Revenues............. $767,346 $762,494 1 1.4% higher KWH sales ($10 million) and higher rates at MECO ($8 million), partly offset by lower fuel prices, the effects of which are passed on to customers ($8 million), and lower revenues related to integrated resource planning Expenses Fuel oil............ 151,046 149,734 1 Higher KWHs generated, partly offset by lower fuel oil prices Purchased power..... 199,581 204,822 (3) Lower KWHs purchased, capacity charges and fuel prices Other............... 285,010 272,413 5 Higher maintenance and depreciation and amortization expenses, partly offset by lower other operation expenses Operating income..... 131,709 135,525 (3) Higher KWH sales and rates at MECO and lower other operation expenses, more than offset by higher maintenance and depreciation and amortization expenses Net income for common stock...... 56,620 62,927 (10) Lower operating income and AFUDC and higher preferred securities distributions, partly offset by lower income taxes Kilowatthour sales (millions)........ 6,692 6,601 1 Fuel oil price per barrel.............. $18.86 $19.77 (5)
Kilowatthour (KWH) sales in the third quarter and first nine months of 1999 increased 0.6% and 1.4%, respectively, from the same periods in 1998, partly due to an increase in the number of customers. Although KWH sales were higher, electric utility net income decreased 19% during the third quarter of 1999, primarily due to a 37% increase in maintenance expenses (including a larger scope of generating unit overhaul work and more chemical cleanings and equipment part replacements), a 9% increase in depreciation and amortization expense and a 62% decrease in AFUDC. For the first nine months of 1999, electric utility net income decreased by 10% due primarily to a 30% increase in maintenance expenses, a 9% increase in depreciation and amortization expense and a 63% decrease in AFUDC. Depreciation increased due to additions to plant in 1998. AFUDC decreased due to the nonaccrual of AFUDC with respect to HELCO's Keahole project beginning in December 1998 and a lower construction in progress base on which AFUDC is calculated. Partly offsetting the higher other expenses 30 for the first nine months of 1999 was a 4% decrease in other operation expenses, primarily due to lower employee benefits expense. Competition The electric utility industry is becoming increasingly competitive. IPPs are well established in Hawaii and continue to actively pursue new projects. Customer self-generation, with or without cogeneration, has made inroads in Hawaii and is a continuing competitive factor. Competition in the generation sector in Hawaii is moderated, however, by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities. HECO has been able to compete successfully by offering customers economic alternatives that, among other things, employ energy efficient electrotechnologies such as the heat pump water heater. Legislation has been introduced in Congress that would restructure the electric utility industry with a view toward increasing competition by, for example, allowing customers to choose their generation supplier. Some of the bills would exempt Alaska and Hawaii. Also, the proposed "Comprehensive Electricity Competition Act," submitted to Congress in May 1999, includes a provision that would permit states to "opt out" of the proposed retail competition deadline of not later than January 1, 2003. On December 30, 1996, the PUC instituted a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. See note (3) in HECO's "Notes to Consolidated Financial Statements." In their statement of position, HECO and its subsidiaries proposed to achieve some of the benefits of competition through proposals for (1) competitive bidding for new generation, (2) performance-based ratemaking (which would include an index-based price cap, an earnings sharing mechanism and a benchmark incentive plan) and (3) innovative pricing provisions (including rate restructuring, expanded time-of-use rates, customer migration rates such as standby charges, flexible pricing to encourage economic development and to compete with customer generation options, new service options and two-part rates incorporating real-time pricing). HECO and its subsidiaries suggest in their statement of position that these proposals be implemented through PUC approval of applications submitted in a series of separate proceedings to be initiated by HECO in 1999 and 2000. In May 1999, the PUC approved HECO's standard form contract for customer retention that allows HECO to provide a rate option for customers who would otherwise reduce their energy use from HECO's system by using energy from a nonutility generator. Based on HECO's current rates, the standard form contract provides a 2.77% discount on base energy rates for "Large Power" customers and an 11.27% discount on base energy rates for general service demand customers. In June 1999, the PUC suspended a similar request by HELCO pending further internal PUC review and required HELCO to respond to the statements of the Consumer Advocate and various protestants in that docket (which HELCO completed on July 8, 1999). PUC regulation of electric utility rates The PUC has broad discretion in its regulation of the rates charged by HEI's electric utility subsidiaries and in other matters. Any adverse decision and order (D&O) by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding, could have a material adverse effect on the Company's financial condition and results of operations. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case. Management cannot predict with certainty when D&Os in pending or future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. 31 Recent rate requests HEI's electric utility subsidiaries initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs, the cost of purchased power and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of September 30, 1999, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.4% for HECO (D&O issued on December 11, 1995 and based on a 1995 test year), 11.65% for HELCO (D&O issued on April 2, 1997 and based on a 1996 test year) and 10.94% for MECO (D&O issued on April 6, 1999 and based on a 1999 test year). Hawaii Electric Light Company, Inc. - ----------------------------------- In March 1998, HELCO filed a request to increase rates by 11.5%, or $17.3 million in annual revenues, based on a 1999 test year and a 12.5% ROACE, primarily to recover costs relating to (1) an agreement to buy power from Encogen's 60 MW plant and (2) adding two combustion turbines (CT-4 and CT-5) at HELCO's Keahole power plant. Due to the EAB's denial of HELCO's motion for reconsideration of the EAB's November 25, 1998 decision (see "HELCO power situation--PSD permit" in note (3) to HECO's "Notes to consolidated financial statements") and a delay in purchasing power from Encogen, HELCO's test year 1999 rate increase application was withdrawn in March 1999. In October 1999, HELCO filed a request to increase rates by 9.6%, or $15.5 million in annual revenues, based on a 2000 test year, primarily to recover (1) costs relating to an agreement to buy power from Encogen's planned 60 MW plant and (2) depreciation of and a return on additional investments in plant and equipment since the last rate case, including pre-PSD facilities at the Keahole power plant (see note 3 in HECO's "Notes to consolidated financial statements"). Although HELCO's estimates for the test year justify an increase of $19.2 million, HELCO limited its request to $15.5 million realizing that the PUC often uses other estimates based on later information and other factors. In its application, HELCO requested an ROACE of 13.5% for the 2000 test year. The timing of a future HELCO rate increase request, if any, to recover costs relating to adding CT-4 and CT-5 will depend on future circumstances. Maui Electric Company, Limited - ------------------------------ In January 1998, MECO filed a request to increase rates by 15.3%, or $22.4 million in annual revenues, based on a 1999 test year and a 12.75% ROACE, primarily to recover costs relating to the addition of generating unit M17 in late 1998. In November 1998, MECO revised its requested increase to 11.9%, or $16.4 million in annual revenues, based on a 12.75% ROACE. In December 1998, MECO received an interim D&O from the PUC, effective January 1, 1999, authorizing an 8.5%, or $11.7 million, increase in annual revenues (subject to refund with interest, pending the final outcome of the case), based on a ROACE of 11.12%, which was the ROACE authorized in MECO's prior rate case. In April 1999, MECO received an amended final D&O from the PUC which authorized an 8.2%, or $11.3 million, increase in annual revenues, based on a 1999 test year and a 10.94% ROACE. The amended final D&O required a refund to customers because MECO had previously received under the interim D&O $0.4 million annually in excess of the amount that was finally approved. MECO refunded with interest the excess amounts collected since January 1, 1999, which amounted to approximately $0.1 million. In March 1999, the PUC issued a D&O denying MECO's request to include $0.8 million in its rate base for exhaust flow enhancers, which were provided as part of a settlement for a warranty claim. MECO wrote-off the $0.8 million in the first quarter of 1999. 32 Savings bank - ------------
Three months ended September 30, -------------------------------------- % (in thousands) 1999 1998 change Primary reason(s) for significant change - ---------------------------------------------------------------------------------------------------------------- Revenues......... $102,624 $103,229 (1) Lower other income (including a decrease in service fees) Operating income. 14,919 13,398 11 Higher net interest income, partly offset by an increase in the provision for loan losses, higher office occupancy and equipment expenses and higher compensation and employee benefit expenses Net income....... 8,499 7,904 8 Higher operating income Interest rate spread.......... 3.22% 2.99% 8 34 basis points decrease in the weighted-average rate on interest-bearing liabilities, partly offset by an 11 basis points decrease in the weighted-average yield on interest-earning assets Nine months ended September 30, -------------------------------------- % (in thousands) 1999 1998 change Primary reason(s) for significant change - ---------------------------------------------------------------------------------------------------------------- Revenues......... $304,663 $306,324 (1) Lower interest income as a result of lower weighted-average yields on interest-earning assets, partly offset by higher other income (including a gain on the sale of a building) Operating income. 45,839 42,079 9 Higher net interest income and other income, partly offset by an increase in the provision for loan losses, higher office occupancy and equipment expenses and higher compensation and employee benefit expenses Net income....... 26,081 23,616 10 Higher operating income Interest rate spread.......... 3.17% 3.10% 2 32 basis points decrease in the weighted-average rate on interest-bearing liabilities, partly offset by a 25 basis points decrease in the weighted-average yield on interest-earning assets
33 ASB continued to be affected by Hawaii's weak economy, including the effects of historically higher amounts of delinquencies, and the relatively flat yield curve. The yield curve has started to widen which should favorably affect ASB's net interest income over time. ASB's interest rate spread--the difference between the weighted-average yield on interest-earning assets and the weighted-average rate on interest-bearing liabilities--increased 8% and 2% for the third quarter and first nine months of 1999, respectively, compared to the same periods in 1998. Comparing the third quarter and first nine months of 1999 to the same period in 1998, the weighted- average rate on interest-bearing liabilities decreased more than the weighted- average yield on interest-earning assets decreased. On April 1, 1999, ASB reduced the rates offered on passbook/statement savings accounts by 25 basis points. Deposits traditionally have been the principal source of ASB's funds for use in lending, meeting liquidity requirements and making investments. ASB experienced an outflow of deposits of $386 million ($267 million of which were certificates of deposits, $166 million of which were transferred to retail repurchase agreements) in the first nine months of 1999, partly offset by $79 million of interest credited to accounts. ASB also derives funds from borrowings, payments of interest and principal on outstanding loans receivable and mortgage/asset- backed securities, and other sources. In recent years, advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase have become more significant sources of funds as the demand for deposits decreased due in part to increased competition from money market and mutual funds. Using sources of funds with a higher cost than deposits, such as advances from the FHLB, puts downward pressure on ASB's interest rate spread and net interest income. In the slow Hawaii economy, ASB has experienced an increase in loan loss reserves. During the first nine months of 1999, ASB added $10.8 million to its allowance for loan losses. As of September 30, 1999, ASB's allowance for loan losses was 1.28% of average loans outstanding, up from 1.18% a year ago. The following table presents the changes in the allowance for loan losses for the periods indicated.
Nine months ended September 30, ------------------------------- (in thousands) 1999 1998 - -------------------------------------------------------------------------------------------- Allowance for loan losses, beginning of period............... $39,779 $29,950 Additions to provisions for losses........................... 10,848 9,473 Allowance for losses on loans returned to Bank of America, FSB......................................................... - (107) Net charge-offs.............................................. (9,980) (2,719) ---------- ---------- Allowance for loan losses, end of period..................... $40,647 $36,597 ========== ==========
Management has been disposing of nonperforming loans at a loss which has resulted in higher charge-offs. In the first nine months of 1999, proceeds from the sales of nonperforming commercial real estate and residential loans were invested in earning assets. In March 1998, ASB formed a wholly owned operating subsidiary, ASB Realty Corporation, which elects to be taxed as a real estate investment trust. This reorganization has reduced ASB's income taxes. For the first nine months of 1999, ASB and subsidiaries' effective income tax rate was 34.3%. Although the State of Hawaii has indicated that it may challenge the tax treatment of this reorganization, ASB believes that its tax position is proper. 34 Other - -----
Three months ended September 30, ----------------------- % (in thousands) 1999 1998 change Primary reason(s) for significant change - ---------------------------------------------------------------------------------------------------------- Revenues..... $12,543 $14,405 (13) Estimated loss on the sale of YB and most of the other assets of HTB ($2 million) Operating loss........ (4,840) (2,365) (105) Lower revenues (see above), higher general and administrative expenses at the holding companies and higher maintenance expense at the HEIPC Group, partly offset by higher investment gains at HEIIC
Nine months ended September 30, ------------------------- % (in thousands) 1999 1998 change Primary reason(s) for significant change - ----------------------------------------------------------------------------------------------------------- Revenues..... $42,376 $44,023 (4) Estimated loss on the sale of YB and most of the other assets of HTB ($2 million) Operating loss........ (8,255) (4,730) (75) Lower revenues (see above), higher general and administrative expenses at the holding companies and higher maintenance expense at the HEIPC Group, partly offset by higher investment gains at HEIIC
The "other" business segment includes results of operations from Hawaiian Tug & Barge Corp. and its subsidiary, Young Brothers, Limited, maritime freight transportation companies; HEI Investment Corp., a company primarily holding investments in leveraged leases; the HEIPC Group, companies formed to pursue independent power and integrated energy services projects in Asia and the Pacific; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI District Cooling, Inc., a company formed to develop, build, own, operate and/or maintain central chilled water, cooling system facilities, and other energy related products and services; ProVision Technologies, Inc., a company formed to sell, install, operate and maintain on- site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim; Hawaiian Electric Industries Capital Trust I, HEI Preferred Funding, LP and Hycap Management, Inc., companies formed primarily for the purpose of effecting the issuance of 8.36% Trust Originated Preferred Securities; HEI and HEI Diversified, Inc., holding companies; and eliminations of intercompany transactions. Freight transportation The freight transportation subsidiaries recorded an operating loss of $0.7 million and operating income of $1.5 million in the third quarter and first nine months of 1999, respectively, compared with operating income of $1.0 million and $3.2 million in the same periods of 1998. The decreases were primarily due to the estimated $2 million loss on the sale of YB and most of the other assets of HTB. See note (9) in 35 HEI's "Notes to consolidated financial statements" for a discussion of the sale of YB and certain assets of HTB. Independent power and integrated energy services HEIPC was formed in 1995 and its subsidiaries have been and will be formed from time to time to pursue independent power and integrated energy services projects in Asia and the Pacific. The HEIPC Group recorded operating losses of $1.4 million and $3.5 million in the third quarter and first nine months of 1999, respectively, compared with $1.0 million and $2.6 million in the same periods of 1998. The increase in operating losses was due in part to a mechanical failure of a unit at Tanguisson, Guam (described below). In September 1996, HEI Power Corp. Guam (HPG), entered into an energy conversion agreement for approximately 20 years with the Guam Power Authority (GPA), pursuant to which HPG has repaired and is operating and maintaining two oil- fired 25-MW (net) units at Tanguisson, Guam. In November 1996, HPG assumed operational control of the Tanguisson facility. HPG's total cost to repair the two units was $15 million. In the second quarter of 1999, a mechanical failure of one of the units resulted in additional expenses for HPG, which accounts for part of the variance in operating losses for the quarter and year-to-date. The unit was returned to service in September 1999. HPG may be able to recover some or all of the negative financial impacts resulting from the mechanical failure from various parties, including an insurance carrier. The GPA project site is contaminated with oil from spills occurring prior to HPG's assuming operational control. HPG has agreed to manage the operation and maintenance of GPA's waste oil recovery system at the project site consistent with GPA's oil recovery plan as approved by the U.S. Environmental Protection Agency. GPA has agreed to indemnify and hold HPG harmless from any pre-existing environmental liability. In September 1998, HEIPC (through a wholly owned, indirect subsidiary) acquired an effective 60% interest in a joint venture, Baotou Tianjiao Power Co., Ltd., formed to design, construct, own, operate and manage a 200 MW coal-fired power plant to be located inside BaoSteel's complex in Inner Mongolia, People's Republic of China. See note (7), "China project," in HEI's "Notes to consolidated financial statements." In December 1998, HEIPC (through a wholly owned, indirect subsidiary) invested $7.6 million to acquire convertible cumulative nonparticipating 8% preferred shares in CEPALCO, an electric distribution company in the Philippines. In September 1999, the HEIPC subsidiary acquired 5% of CEPALCO common stock for approximately $2.1 million. The acquisitions are strategic moves which put the HEIPC Group in a position to participate in the eventual privatization of the National Power Corporation and growth in the electric distribution business in the Philippines. The HEIPC Group is actively pursuing other projects in Asia and the Pacific that are subject to approval by the HEIPC and HEI Boards of Directors. The success of any project undertaken by the HEIPC Group will be dependent on many factors, including the economic, political, monetary, technological, regulatory and logistical circumstances surrounding each project and the location of the project. Due to political or regulatory actions or other circumstances, projects may be delayed or even prohibited. There is no assurance that any project undertaken by the HEIPC Group will be successfully completed or that the HEIPC Group's investment in any such project will not be lost, in whole or in part. Discontinued operations See note (8) in HEI's "Notes to consolidated financial statements." Accounting for the effects of certain types of regulation - --------------------------------------------------------- In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company's financial statements reflect assets and costs of HECO and its subsidiaries and YB based on current cost-based rate-making regulations. Management believes HECO and its subsidiaries' and YB's operations currently satisfy the SFAS No. 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect 36 on the Company's results of operations, financial position or liquidity may result. As of September 30, 1999, HEI's and HECO's consolidated regulatory assets amounted to $115 million and $113 million, respectively. Contingencies - ------------- See note (7) in HEI's "Notes to consolidated financial statements" and note (3) in HECO's "Notes to consolidated financial statements" for discussions of contingencies. Year 2000 issue - --------------- The following discussion includes numerous forward-looking statements. The following discussion includes forward looking statements related, but not limited, to the costs of remediation, the effect of such costs on HEI's and HECO's financial condition and liquidity, anticipated dates of completion of remediation work, future performance of remediated systems, third party remediation, contingency plans and risks, and most reasonably likely worst case scenarios. Also, see "Forward-looking information" on page v. HEI consolidated The Company is aware of the Year 2000 date issues associated with the practice of encoding only the last two digits of four digit years in computer equipment, software and devices with embedded technology. Year 2000 date issues, if not properly addressed, may result in computer errors that could cause a disruption of business operations. Further, the Company could be adversely impacted by Year 2000 date issues if suppliers, customers and other related businesses do not address the issues successfully. HEI and subsidiary management have developed Year 2000 programs and have teams in place. All significant computer-based systems have been included in the inventory and assessment process. Priority has been given to systems that are considered mission or business critical. HEI and each business unit have appointed a Year 2000 project manager who provides periodic reporting to their respective senior management and board of directors. Both the electric utility and the savings bank segments are subject to external oversight by their respective regulators. Although substantial effort is being devoted to the Year 2000 issue, no absolute assurance can be given that the Company will successfully avoid all problems that may arise. Further, no absolute assurance can be given that the Year 2000 problems of other entities will not have a material adverse impact on the Company's systems or results of operations. Costs. Management believes that the cost to remediate its systems to become - ------ Year 2000 ready have not and will not have a material adverse effect on the Company's financial condition or liquidity. The total cost of initiatives undertaken primarily for Year 2000 remediation is estimated at $10.9 million, of which approximately $9.9 million has been incurred through September 30, 1999. The cost to remediate systems and the target dates provided below represent management's best estimates at this time. These estimates are based on information provided by various work units within the Company and external parties such as vendors and business partners. Numerous assumptions have been made regarding future dates, including the continued availability of internal and external resources, third party remediation plans and the successful testing of mission critical systems. Electric utility State of readiness. HECO and its subsidiaries identified information technology - ------------------- (IT) and non-IT systems which required Year 2000 remediation work and prioritized these systems by importance, business risk and Year 2000 exposure, allocating resources accordingly. Remediation work for each of the systems included an assessment phase, a renovation and validation phase and an implementation phase. All work related to mission-critical electric generation and distribution systems was completed by September 30, 1999. All other remediation work is 99% complete and expected to be finished in November 1999. In December 1998, HECO and its subsidiaries replaced the majority of their business-critical information systems with an integrated application suite that is Year 2000 ready. The installation of an integrated application suite has both simplified and lowered the cost of Year 2000 IT remediation efforts. 37 Numerous Year 2000 tests of both in-house and purchased software have been conducted. HECO and its subsidiaries identified third parties with whom they have significant business relationships and contacted these vendors and service providers to determine their Year 2000 readiness. Significant third parties include fuel suppliers, IPPs, financial institutions and large customers. Over 99% of the vendors contacted have responded regarding their compliance. HECO and MECO formed Power Partners Year 2000 groups to provide a forum to share information among the utilities, their IPPs and fuel suppliers. HECO and MECO also contracted with two of their major vendors of power plant equipment for their services in assessing, remediating and testing their installed control systems. HECO, HELCO and MECO have completed remediation and testing of all generating units on Oahu, Hawaii, Maui, Molokai and Lanai. All IPPs have done the same. Following national guidelines, HECO, HELCO, MECO and several IPPs successfully conducted Year 2000 readiness drills in September 1999. Costs. HECO management believes that the cost to remediate its systems to become - ------ Year 2000 ready have not and will not have a material adverse effect on HECO's consolidated financial condition or liquidity. The total cost of initiatives undertaken primarily for Year 2000 remediation is estimated at $4.3 million, of which $3.5 million has been incurred through September 30, 1999. Risks. The Year 2000 remediation effort addresses two distinct areas of risk-- - ------ (1) electric systems, which deliver power to customers, and (2) business systems, which handle data processing. Importantly, with respect to the electric systems, neither the generation nor distribution systems are fully dependent on automated control systems. HECO and its subsidiaries have the capability to manually control the generation and dispatching of power and have some degree of diversity and redundancy in their systems. There are never 100% guarantees of service reliability. HECO believes, however, the most reasonably likely worst case scenario would be brief, localized power outages and billing, payment, collection and/or reporting errors or delays. Contingency plans. Contingency plans in the event of a Year 2000 problem are - ------------------ being finalized for HECO and its subsidiaries. Approximately 400 employees will be on site on December 31, 1999 to January 1, 2000, and on other critical dates in 2000 as deemed necessary. Other measures to mitigate risk include increased fuel inventories, suspension of fuel transfers between locations, additional units on-line and backup communications systems. Savings Bank State of readiness. ASB and its subsidiaries follow guidelines provided by the - ------------------- Office of Thrift Supervision (OTS), which require ASB to first renovate its mission critical systems. ASB, in its assessment, identified IT and non-IT mission critical systems requiring Year 2000 remediation work. IT systems include outsourced and in-house mainframe systems and applications, licensed vendor applications, ATMs, desktop applications and high speed check sorting. ASB has prioritized these systems by importance, business risk, and Year 2000 exposure, allocating resources accordingly. The OTS guidelines use a five-phase approach to Year 2000 issues --an Awareness Phase, Assessment Phase, Renovation Phase, Validation Phase and Implementation Phase. By July 1999, ASB successfully completed the five-phase project of its mission critical systems. Re-testing may be warranted due to system upgrades and regulatory requirements. ASB and its subsidiaries identified third parties with whom they have significant relationships including software-hardware systems providers, large customers and a service bureau. ASB has implemented a Customer Impact Program that monitors the activities of its large business and deposit customers. ASB continues to monitor its service and supply vendors for Year 2000 compliance. ASB initially reported a total of 426 vendors. Since then that number has been adjusted to reflect consolidation and/or expansion of departments reporting multiple use of the same vendors. To date ASB has identified 368 of 398 vendors who are Year 2000 ready or in the process of becoming ready by January 1, 2000. The remaining 30 vendors have been replaced or discontinued. Costs. The total cost of initiatives undertaken by ASB primarily for Year 2000 - ------ remediation is estimated at $5.9 million, of which approximately $5.8 million has been incurred through September 30, 1999. 38 Risks. The Year 2000 remediation effort addresses various areas of risk, - ------ primarily ASB's business systems, including in-house applications, vendor applications, service bureau applications and electronic banking. ASB believes that the most reasonably likely worst case scenario would be localized disruption of customer services. ASB believes off-line processing at all branch sites is feasible for up to five working days. Contingency plans. ASB's overall contingency plan provides the broad steps that - ------------------ ASB could take if entire systems or partial systems were lost. In 1998, ASB developed comprehensive and detailed contingency plans for mission critical systems. ASB has used these contingency plans as models to develop similar detailed plans for other departments. ASB's contingency plans include activating off-line or manual procedures, implementing stand-in programs, activating the disaster recovery plan and relocating certain operations to the recovery site. In addition to the broader Year 2000 contingency plan, ASB has developed specialized contingency plans to address the New Year 2000 event weekend. Management will be in position to make critical decisions based on information gathered at a dedicated Command Center. Recovery equipment will be pre- positioned to best advantage. Furthermore, service agreements are in place to assure skilled and technical vendors and service providers are on-site and/or dedicated to ASB's recovery plans. Critical employees will be on-site or on standby to lead recovery teams. Bank personnel will be available and assigned to needed tasks. Bank management at the Command Center will coordinate all Year 2000 weekend activities. Accounting changes - ------------------ See note (6) and note (5) in HEI's and HECO's respective "Notes to consolidated financial statements." FINANCIAL CONDITION Liquidity and capital resources - ------------------------------- The Company and consolidated HECO each believes that its ability to generate cash, both internally from operations and externally from debt and equity issues, is adequate to maintain sufficient liquidity to fund their respective construction programs and investments and to satisfy debt and other cash requirements in the foreseeable future. The consolidated capital structure of HEI was as follows:
(in millions) September 30, 1999 December 31, 1998 - ----------------------------------------------------------------------------------------------------- Short-term borrowings................... $ 165 7% $ 223 10% Long-term debt.......................... 979 44 900 40 HEI- and HECO-obligated preferred securities of trust subsidiaries..... 200 9 200 9 Preferred stock of electric utility subsidiaries........................... 34 2 81 4 Minority interests...................... 3 - 4 - Common stock equity..................... 836 38 827 37 ------------ ------------ ------------ ------------ $2,217 100% $2,235 100% ============ ============ ============ ============
ASB's deposit liabilities, securities sold under agreements to repurchase, advances from the FHLB and retail repurchase agreements are not included in the table above. For the first nine months of 1999, net cash provided by operating activities of HEI consolidated was $180 million. Net cash used in investing activities was $328 million, largely due to ASB's purchase of mortgage/asset-backed securities and origination of loans, net of repayments, and HECO's consolidated capital expenditures. Net cash used by financing activities was $55 million as a result of several factors, including net decreases in deposit liabilities, securities sold under agreements to repurchase and short-term borrowings, the redemption of certain series of the electric utilities subsidiaries' preferred 39 stock and the payment of common stock dividends and trust preferred securities distributions, partly offset by net increases in advances from FHLB, retail repurchase agreements and long-term debt. Total HEI consolidated financing requirements for 1999 through 2003, including net capital expenditures (which exclude the AFUDC and capital expenditures funded by third-party cash contributions in aid of construction), long-term debt retirements (excluding repayments of advances from FHLB of Seattle and securities sold under agreements to repurchase) and preferred stock retirements, are estimated to total $1.2 billion. Of this amount, approximately $0.8 billion is for net capital expenditures (mostly relating to the electric utilities' net capital expenditures described below). HEI's consolidated internal sources, after the payment of HEI dividends, are expected to provide approximately 68% of the consolidated financing requirements, with debt and equity financing providing the remaining requirements. Additional debt and equity financing may be required to fund activities not included in the 1999-2003 forecast, such as the development of additional independent power projects by the HEIPC Group in Asia and the Pacific, or to fund changes in requirements, such as increases in the amount of or an acceleration of capital expenditures of the electric utilities. On March 2, 1999, HEI filed a registration statement with the SEC to register $300 million of Medium-Term Notes, Series C (Series C Notes). On May 5, 1999, HEI sold $100 million of its Series C Notes, with $200 million of Series C Notes remaining available for issuance from time to time. The $100 million of Series C Notes sold have a fixed interest rate of 6.51% with a maturity date of May 5, 2014. At the option of the holder, HEI may be required to repay the notes on May 5, 2006 at a repayment price equal to 98.1% of the principal amount to be repaid. Following is a discussion of the liquidity and capital resources of HEI's largest segments. Electric utility HECO's consolidated capital structure was as follows:
(in millions) September 30, 1999 December 31, 1998 - ------------------------------------------------------------------------------------------------------ Short-term borrowings from nonaffiliates and affiliate........ $ 103 6% $ 139 8% Long-term debt...................... 645 38 622 36 HECO-obligated preferred securities of trust subsidiaries.............. 100 6 100 6 Preferred stock..................... 34 2 81 5 Common stock equity................. 803 48 787 45 -------------- ------------- -------------- ------------ $1,685 100% $1,729 100% ============== ============= ============== ============
Operating activities provided $145 million in net cash during the first nine months of 1999. Investing activities used net cash of $60 million, primarily for capital expenditures. Financing activities used net cash of $114 million, including $47 million for the payment of common and preferred dividends and preferred securities distributions, $47 million for preferred stock redemptions and $36 million for the net repayment of short-term borrowings, partially offset by a $23 million net increase in long-term debt. In August 1999, the Department of Budget and Finance of the State of Hawaii issued and sold an aggregate of $61.4 million in refunding special purpose revenue bonds on behalf of HECO, MECO and HELCO. The proceeds of the sale (exclusive of accrued interest) were used to provide a portion of the funds required for the refunding prior to stated maturity of the 7.2% Series 1984 Revenue Bonds ($11.4 million) and the 7-5/8% Series 1988 Revenue Bonds ($50 million). The electric utilities' consolidated financing requirements for 1999 through 2003, including net capital expenditures, long-term debt retirements, preferred stock redemptions and sinking fund requirements, are currently estimated to total $666 million. HECO's consolidated internal sources, after the payment of common stock and preferred stock dividends, are expected to provide approximately 91% of the consolidated financing requirements, with debt financing providing the remaining requirements. As of 40 September 30, 1999, approximately $17.4 million of proceeds from previous sales by the Department of Budget and Finance of the State of Hawaii of special purpose revenue bonds issued for the benefit of HECO, MECO and HELCO remain undrawn. Also as of September 30, 1999, an additional $100 million of revenue bonds were authorized for issuance for the benefit of HECO and HELCO prior to the end of 2003. It is anticipated that the Department of Budget and Finance of the State of Hawaii will issue and sell, in November 1999, $35 million aggregate principal amount of special purpose revenue bonds on behalf of HECO and $20 million aggregate principal amount of refunding special purpose revenue bonds on behalf of HECO, MECO and HELCO. The proceeds (exclusive of accrued interest) from the sale of refunding revenue bonds, if issued, will be used to provide a portion of the funds required to refund the 7.35% Series 1990A Revenue Bonds ($20 million) prior to stated maturity. The PUC must approve issuances of long- term securities by HECO, HELCO and MECO. Capital expenditures include the costs of projects which are required to meet expected load growth, to improve reliability and to replace and upgrade existing equipment. Net capital expenditures for the five-year period 1999 through 2003 are currently estimated to total $595 million. Approximately 74% of forecast gross capital expenditures, which includes the allowance for funds used during construction and capital expenditures funded by third-party contributions in aid of construction, is for transmission and distribution projects, with the remaining 26% primarily for generation projects. For 1999, electric utility net capital expenditures are estimated to be $119 million. Gross capital expenditures are estimated to be $138 million, comprised of approximately $108 million for transmission and distribution projects, $24 million for generation projects and $6 million for general plant projects. Drawdowns of proceeds from previous and future sales of tax-exempt special purpose revenue bonds and the generation of funds from internal sources are expected to provide the cash needed for the net capital expenditures. Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power, the availability of generating sites and transmission and distribution corridors, the ability to obtain adequate and timely rate increases, escalation in construction costs, demand-side management programs and requirements of environmental and other regulatory and permitting authorities. Savings bank
September December 31, % (in millions) 30, 1999 1998 change - ----------------------------------------------------------------------------------------------- Total assets.............................. $5,753 $5,692 1% Mortgage/asset-backed securities.......... 1,943 1,791 8 Loans receivable, net..................... 3,216 3,143 2 Deposit liabilities....................... 3,559 3,866 (8) Securities sold under agreements to 427 515 (17) repurchase............................... Advances from Federal Home Loan Bank...... 1,082 806 34
As of September 30, 1999, ASB was the third largest financial institution in the state based on total assets of $5.8 billion and deposits of $3.6 billion. For the first nine months of 1999, net cash provided by ASB's operating activities was $48 million. Net cash used in ASB's investing activities was $256 million, due largely to the purchase of mortgage/asset-backed securities and origination of loans, net of repayments. Net cash provided by financing activities was $33 million largely due to a net increase of $277 million in FHLB advances and a net increase of $168 million in retail repurchase agreements, partly offset by a net decrease of $306 million in deposit liabilities (includes $166 million of State of Hawaii certificate of deposits transferred to retail repurchase agreements), a net decrease of $89 million in securities sold under agreements to repurchase and $16 million in common and preferred stock dividends. 41 Minimum liquidity levels are currently governed by the regulations adopted by the OTS. ASB was in compliance with OTS liquidity requirements as of September 30, 1999. ASB believes that 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. As of September 30, 1999, ASB was in compliance with the OTS minimum capital requirements (noted in parentheses) with a tangible capital ratio of 5.6% (1.5%), a core capital ratio of 5.6% (3.0%) and a risk-based capital ratio of 11.2% (8.0%). 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 September 30, 1999, ASB was "well-capitalized" (ratio requirements noted in parentheses) with a leverage ratio of 5.6% (5.0%), a Tier-1 risk-based ratio of 10.3% (6.0%) and a total risk-based ratio of 11.2% (10.0%). On December 1, 1998, the OTS adopted Thrift Bulletin 13a (TB 13a), which became effective on December 1, 1998. In addition to other guidance, TB 13a provides detailed guidelines for implementing revisions of the CAMELS rating system, published by the Federal Financial Institutions Examination Council. The publication announced revised interagency policies that, among other things, established the Sensitivity to Market Risk component rating (the "S" rating). TB 13a provides quantitative guidelines for an initial assessment of an institution's level of interest rate risk. Examiners have broad discretion in implementing those guidelines. TB 13a also provides guidelines concerning the factors examiners consider in assessing the quality of an institution's risk management systems and procedures. Based on the calculation of ASB's interest rate risk rating under these new guidelines, management is developing and beginning to implement an action plan to improve ASB's interest rate risk position. The plan may include additional capital contributions from HEIDI. Significant interstate banking legislation has been enacted at both the federal and state levels. Under the federal Riegle-Neal Interstate Banking and Branching Efficiency Act of 1994, a bank holding company may acquire control of a bank in any state, subject to certain restrictions. Under state law, effective June 1, 1997, a bank chartered under state law may merge with an out-of-state bank and convert all branches of both banks into branches of a single bank, subject to certain restrictions. Although the federal and state laws apply only to banks, such legislation may nonetheless affect the competitive balance among banks, thrifts and other financial institutions and the level of competition among financial institutions doing business in Hawaii. For a discussion of the unfavorable disparity in the Financing Corporation assessment rates that ASB and other thrifts have paid in relation to the rates that most commercial banks have paid, see note (4) in HEI's "Notes to Consolidated Financial Statements." By law, the Financing Corporation's assessment rate on deposits insured by the Bank Insurance Fund must be one-fifth the rate on deposits insured by the Savings Association Insurance Fund until the insurance funds are merged or until January 1, 2000, whichever occurs first, at which time the FICO interest obligation for both banks and thrifts should thereafter be identical, at a currently estimated rate of 2.4 cents per $100 of deposits. On November 4, 1999, Congress passed the Gramm-Leach-Bliley Act (the Act). According to press reports, President Clinton is expected to sign the Act. The Act repeals the Depression Era Glass-Steagall Act so that banks, insurance companies and investment firms can compete directly against each other, thereby allowing "one-stop shopping" for an array of financial services. Although the Act does further restrict the ability of a savings and loan holding company to own both a savings association and nonfinancial subsidiaries, the savings and loan holding company relationship among HEI, HEIDI and ASB is "grandfathered" under the Act so that HEI and its subsidiaries will be able to continue to engage in their current activities. It is too early to assess the net effect of the Act on ASB's competitive position. On the one hand, the availability of "one-stop-shopping" for financial services might increase competitive pressures on ASB. On the other hand, the restriction on the ability to combine savings associations and nonfinancial subsidiaries under one holding company may decrease competitive pressure by reducing the incentive to create new thrifts. 42 In addition to its effects upon competition, the Act might result in increased costs for ASB. For example, the Act imposes on financial institutions an obligation to protect the security and confidentiality of its customers' nonpublic personal information, and directs, among others, the FDIC and the OTS to establish "appropriate standards" to protect such information and the use thereof. Although ASB currently has in place a policy concerning customer privacy, it cannot be known at this time whether the rules eventually adopted by the regulatory authorities might impose additional compliance costs on ASB. Item 3. Quantitative and qualitative disclosures about market risk - ------------------------------------------------------------------ The Company's results are impacted by ASB's ability to manage interest rate risk. For quantitative and qualitative information about the Company's market risks, see pages 39 to 41 of HEI's 1998 Annual Report to Stockholders. U.S. Treasury yields at September 30, 1999 and December 31, 1998 were as follows:
September 30, 1999 December 31, 1998 ------------------ ----------------- 3 month 4.85 4.46 1 year 5.18 4.52 5 year 5.76 4.54 10 year 5.88 4.65 30 year 6.05 5.09
Interest rates (as measured by U.S. Treasury yields) have increased between 39 and 123 basis points from December 31, 1998 to September 30, 1999 and had a negative effect on the market value of ASB's interest-sensitive net earning assets. On the positive side, in the nine months ended September 30, 1999, ASB's interest-sensitive net earning assets have grown. Overall, management believes there was an immaterial, favorable change between those dates in the Company's quantitative disclosures of its interest-sensitive assets, liabilities and off- balance sheet items. 43 PART II - OTHER INFORMATION - -------------------------------------------------------------------------------- Item 1. Legal proceedings - ------------------------- There are no significant developments in pending legal proceedings except as set forth in HECO's "Notes to consolidated financial statements," and management's discussion and analysis of financial condition and results of operations. Item 5. Other information - -------------------------- A. EPA notice of violation and civil administrative complaints On September 30, 1999, HECO received civil administrative complaints from the EPA for alleged violations of Resource Conservation and Recovery Act hazardous waste regulations at the Waiau and Kahe power plants. Penalties associated with each alleged violation/count were identified in the complaints. The combined penalty for both facilities amounted to approximately $153,000. HECO is working with the EPA on a settlement of the matter. B. DOH notice of violation for Kahe sludge drying bed By letter dated September 30, 1999, HECO received a notice of violation from the DOH for alleged disposal of hazardous waste at the sludge drying bed at the Kahe power plant. Previously, in March 1999, HECO had voluntarily notified the DOH upon discovering unexplained high levels of selenium in the sludge drying bed. HECO initiated an investigation to characterize the site and to determine the source of the contamination, and submitted a draft corrective action plan to the DOH in April 1999. The source of the high levels of selenium remains unknown. The notice of violation identifies revisions DOH would like to see in the corrective action plan. HECO has 30 days to submit a revised plan to the DOH for review. Once the plan is approved, HECO has 60 days from that date to implement and complete cleanup of the sludge drying bed. Although no monetary penalty is imposed in the notice of violation, HECO will incur cleanup costs of approximately $100,000. C. HECO power outage On April 9, 1991, HECO experienced a power outage that affected all customers on the island of Oahu. The PUC initiated an investigation of the April 9, 1991 outage, which was consolidated with a pending investigation of an outage that occurred in 1988. Power Technologies, Inc. (PTI), an independent consultant hired by HECO with the approval of the PUC, investigated the 1991 outage. HECO implemented certain of PTI's recommendations and provided the PUC with summaries of its progress on those recommendations. In July 1999, the PUC issued its D&O and ordered that (1) PTI's report on the investigation, including its findings, conclusions and recommendations, be accepted and approved, (2) HECO continue to provide annual status reports on the final implementation of PTI's recommendations and (3) the investigation be closed. The PUC also concluded that no penalty was justified based on the facts and circumstances of the case. In October 1999, the PUC clarified its order indicating that by approving and accepting PTI's report, the PUC has not approved or disapproved HECO's determinations as to whether or how to implement the specific recommendations of the report. D. Ratio of earnings to fixed charges The following tables set forth the ratio of earnings to fixed charges for HEI and its subsidiaries for the periods indicated: 44 Ratio of earnings to fixed charges excluding interest on ASB deposits
Nine months Years ended December 31, ended ----------------------------------------------------------------------------------- September 30, 1999 1998 1997 1996 1995 1994 - -------------------- ------------- ------------- ------------ ------------ ------------- 1.78 1.85 1.89 1.93 2.02 2.31 ==================== ============= ============= ============ ============ =============
Ratio of earnings to fixed charges including interest on ASB deposits
Nine months Years ended December 31, ended ----------------------------------------------------------------------------------- September 30, 1999 1998 1997 1996 1995 1994 - -------------------- ------------- ------------- ------------ ------------ ------------- 1.46 1.47 1.58 1.56 1.60 1.73 ==================== ============= ============= ============ ============ =============
For purposes of calculating the ratio of earnings to fixed charges, "earnings" represent the sum of (i) pretax income from continuing operations (excluding undistributed net income or net loss from less than fifty-percent-owned persons) and (ii) fixed charges (as hereinafter defined, but excluding capitalized interest). "Fixed charges" are calculated both excluding and including interest on ASB's deposits during the applicable periods and represent the sum of (i) interest, whether capitalized or expensed, but excluding interest on nonrecourse debt from leveraged leases which is not included in interest expense in HEI's consolidated statements of income, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the interest factor in rental expense, (iv) the preferred stock dividend requirements of HEI's subsidiaries, increased to an amount representing the pretax earnings required to cover such dividend requirements and (v) the preferred securities distribution requirements of trust subsidiaries. The following table sets forth the ratio of earnings to fixed charges for HECO and its subsidiaries for the periods indicated: Ratio of earnings to fixed charges
Nine months Years ended December 31, ended ----------------------------------------------------------------------------------- September 30, 1999 1998 1997 1996 1995 1994 - -------------------- ------------- ------------- ------------ ------------ ------------- 3.07 3.33 3.26 3.58 3.46 3.47 ==================== ============= ============= ============ ============ =============
For purposes of calculating the ratio of earnings to fixed charges, "earnings" represent the sum of (i) pretax income before preferred stock dividends of HECO and (ii) fixed charges (as hereinafter defined, but excluding the allowance for borrowed funds used during construction). "Fixed charges" represent the sum of (i) interest, whether capitalized or expensed, incurred by HECO and its subsidiaries, (ii) amortization of debt expense and discount or premium related to any indebtedness, whether capitalized or expensed, (iii) the interest factor in rental expense, (iv) the preferred stock dividend requirements of HELCO and MECO, increased to an amount representing the pretax earnings required to cover such dividend requirements and (v) the preferred securities distribution requirements of the trust subsidiaries. 45 Item 6. Exhibits and reports on Form 8-K - ----------------------------------------- (a) Exhibits HECO Hawaiian Electric Company, Inc. and subsidiaries Exhibit 10 Second Amended and Restated Power Purchase Agreement between Hilo Coast Power Company and HELCO dated October 4, 1999 HEI Hawaiian Electric Industries, Inc. and subsidiaries Exhibit 12.1 Computation of ratio of earnings to fixed charges, nine months ended September 30, 1999 and 1998 HECO Hawaiian Electric Company, Inc. and subsidiaries Exhibit 12.2 Computation of ratio of earnings to fixed charges, nine months ended September 30, 1999 and 1998 HEI Hawaiian Electric Industries, Inc. and subsidiaries Exhibit 27.1 Financial Data Schedule September 30, 1999 and nine months ended September 30, 1999 HECO Hawaiian Electric Company, Inc. and subsidiaries Exhibit 27.2 Financial Data Schedule September 30, 1999 and nine months ended September 30, 1999 (b) Reports on Form 8-K Subsequent to June 30, 1999, HEI and/or HECO filed Current Reports, Forms 8-K, with the SEC as follows:
Dated Registrant/s Items reported - ----------------------------------------------------------------------------------------------------------- August 3, 1999 HEI/HECO Item 5: Financial information of HECO and its subsidiaries for the second quarter and six months ended June 30, 1999 and other updated information August 4, 1999 HEI Item 5: HEI's August 4, 1999 news release: Hawaiian Electric Industries, Inc. Selling Maritime Freight Transportation Operations October 28, 1999 HEI/HECO Item 5: Financial information of HECO and its subsidiaries for the third quarter and nine months ended September 30, 1999 and other updated information
46 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/ Robert F. Mougeot By /s/ Paul Oyer ---------------------- -------------- Robert F. Mougeot Paul A. Oyer Financial Vice President and Financial Vice President and Chief Financial Officer Treasurer (Principal Financial Officer of HEI) (Principal Financial Officer of HECO) Date: November 10, 1999 Date: November 10, 1999 47 EX-10 2 SECOND AMENDED AND RESTATED POWER PURCHASE HECO Exhibit 10 --------------- SECOND AMENDED AND RESTATED POWER PURCHASE AGREEMENT ---------------------------------------------------- This Second Amended and Restated Power Purchase Agreement ("the Contract") is made and entered into on October 4, 1999 by and between HILO COAST POWER COMPANY, a Division of Brewer Environmental Industries, LLC (hereinafter referred to as "HCPC") and HAWAII ELECTRIC LIGHT COMPANY, INC. (hereinafter referred to as "HELCO"). W I T N E S S E T H T H A T: - - - - - - - - - - - - - - WHEREAS, HELCO is and has been an operating electric public utility on the Island of Hawaii in the State of Hawaii and is subject to the Hawaii Public Utilities Laws (Chapter 269 of the Hawaii Revised Statutes) and the rules and regulations of the Hawaii Public Utilities Commission (hereinafter referred to as the "PUC"); and WHEREAS, HELCO and Pepeekeo Sugar Company ("Pepeekeo") entered into that certain Purchase Power Agreement dated July 1, 1971 (hereinafter referred to as "the Initial Agreement"); and WHEREAS, Pepeekeo assigned all of its right, title and interest in and to the Initial Agreement to HCPC, subject to the terms, conditions and provisions thereof, pursuant to that certain Assignment of Power Purchase Agreement Contract made September 1, 1971 (hereinafter referred to as the "Assignment"); and WHEREAS, HELCO and HCPC agreed to amend and restate the Initial Agreement as heretofore amended and/or modified in its entirety as of May 31, 1988, for a term through December 31, 2002; and WHEREAS, HCPC currently provides electric power and energy to HELCO pursuant to an Amended and Restated Power Purchase Agreement entered into on March 24, 1995 and approved by the PUC in Decision and Order No. 14207, filed on September 6, 1995, in Docket No. 95-0075 (the "Prior Contract"); and WHEREAS, prior to July 9, 1997, the Prior Contract was between HELCO and Hilo Coast Processing Company, a Hawaii agricultural cooperative association. As of that date, the rights and obligations under the Prior Contract were assumed by HCPC and Hilo Coast Processing Company was dissolved. HCPC has the same management as the dissolved Hilo Coast Processing Company, but is now part of a larger organization, Brewer Environmental Industries, LLC, a subsidiary of C. Brewer and Company, Limited; and WHEREAS, the term of the Prior Contract is due to expire on December 31, 1999; and WHEREAS, for a period beyond December 31, 1999 HELCO needs the 22 megawatts of capacity during its peak hours of operation in order to adequately meet its system load and reserve criteria; and WHEREAS, HCPC and HELCO have been negotiating over the terms of the continued supply of power and energy from HCPC beyond the term of the Prior Contract; and WHEREAS, in Order No. 17050, filed on June 24, 1999, in Docket No. 97-0102, the PUC ordered that HELCO and HCPC continue to negotiate, consistent with the conclusions in the Order; and WHEREAS, HELCO needs power and capacity from HCPC almost exclusively during its system peak hours but under the Prior Contract 2 was obligated to purchase a minimum of four (4) megawatts of power at all times during 48 weeks of each year; and WHEREAS, HCPC is willing to extend the term of the agreement under which it will provide power and energy to HELCO at the price for capacity and energy currently in force under the Prior Contract and to remove the 4 mW minimum purchase obligation in consideration of other modifications to its obligations and rights; and WHEREAS, upon approval of this Contract by the PUC, all outstanding matters in Docket No. 97-0102 will be settled; NOW, THEREFORE, in consideration of the mutual promises and obligations set forth herein, the sufficiency of which is hereby mutually acknowledged, the parties hereto agree as follows: I. Definitions. ----------- A. HELCO Dispatch. The term "HELCO dispatch" as used herein means -------------- HELCO's absolute and sole right, through supervisory equipment and otherwise, to control electrical energy generated by HCPC pursuant to this Contract up to such capacity as may be agreed from time to time. HELCO may purchase, install, and own Automatic Generator Control equipment at HCPC in order to allow HELCO to dispatch the megawatt level of electrical energy from HCPC as required to optimize economic and reliable operation of HELCO's electrical system. Var control will continue to be through HCPC's control operator. HCPC shall cooperate with HELCO in the installation of such equipment. Upon termination of the Contract, HELCO shall remove such equipment within thirty (30) days of the termination. B. Contract Year. The term "contract year" means a year ------------- 3 during the term hereof beginning at 0001 hours on January 1 and ending at 0001 hours on January 1 of the following year. C. [deleted] D. [deleted] E. PUC. PUC means the Hawaii Public Utilities Commission. --- F. PUC Approval. PUC Approval means the PUC order or orders described in ------------ Section XVIII. G. Good Engineering and Operating Practices. The practices, methods and ---------------------------------------- acts engaged in or approved by a significant portion of the electric utility industry for similarly situated U.S. facilities that at a particular time, in the exercise of reasonable judgment in light of the facts known or that reasonably should be known at the time a decision is made, would be expected to accomplish the desired result in a manner consistent with law, regulation, reliability, safety, environmental protection, economy and expedition. With respect to the power plant, Good Engineering and Operating Practices include but are not limited to taking reasonable steps to ensure that: 1. Adequate materials, resources and supplies, including fuel, are available to meet the power plant's needs under normal conditions and reasonably anticipated abnormal conditions. 2. Sufficient operating personnel are available and are adequately experienced and trained to operate the power plant properly, efficiently and within manufacturer's guidelines and specifications and are capable of responding to emergency conditions. 3. Preventive, routine and non-routine maintenance 4 and repairs are performed on a basis that ensures reliable long-term and safe operation, and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment, tools, and procedures. 4. Appropriate monitoring and testing is done to ensure equipment is functioning as designed and to provide assurance that equipment will function properly under both normal and emergency conditions. 5. Equipment is operated in a safe manner and in a manner safe to workers, the general public and the environment and with regard to defined limitations such as steam pressure, temperature, and moisture content, chemical content and quality of make-up water, operating voltage, current, frequency, rotational speed, polarity, synchronization, control system limits, etc. H. Ramp-up Period. The Ramp-up Period is a reasonable period --------------- beginning at the time the HCPC unit is initially synchronized to the HELCO system and ending at the time it reaches its minimum dispatch capability of 18 MW (but not earlier than the beginning of the related On-peak Period). II. HCPC's Obligation to Supply Capacity. ------------------------------------ A. Capacity Guarantee. HCPC shall furnish HELCO 22,000 kw of capacity ------------------ and 13,600 kvar of reactive under HELCO dispatch during the entire term hereof except for the "annual overhaul period" set forth in Section II.B. below. The reactive shall be in proportion to power in the range of 0.85 lagging to 1.0 unity power factor and shall be dispatched by HELCO so that HCPC keeps its turbine generator 5 output, at HELCO's direction, within the limits of plus or minus 5% of 13.8 kv. B. Plant Shutdown Period. HCPC shall have the right to shut its --------------------- turbine generator down and shall have no obligation to furnish HELCO the capacity described in II.A hereof during four consecutive weeks each contract year (the "annual overhaul period"). HCPC's annual overhaul period for the year 2000 shall be taken in the first quarter of 2000 as mutually agreeable to HCPC and HELCO. HCPC's annual overhaul period for subsequent years shall be scheduled for September each year, provided, however, that HELCO may request such annual overhaul period to be moved up earlier in the year, in which case HCPC shall make all reasonable efforts to comply with such request. In the event HELCO gives HCPC notice of termination under Section XIV hereof prior to HCPC taking its annual overhaul period for the year of termination, HCPC shall be permitted to either take its annual overhaul period in December of the year of termination or request that its annual overhaul period for the year of termination be rescheduled, which request shall not be unreasonably denied by HELCO. C. Capacity Charge. As compensation for maintaining the 22,000 kw of --------------- capacity under HELCO dispatch during the time periods as described herein, HELCO will pay HCPC a capacity charge, payable in twelve equal monthly installments within ten (10) days after the last day of each calendar month, equal to $5,082,000 ($231/kw-yr) per contract year. HELCO shall not be obligated to pay any additional capacity charge for any additional capacity supplied by HCPC, either at HELCO's request or at HCPC's request. A failure by HCPC to provide 6 the required capacity to HELCO shall result in the reduction in the capacity charge due to HCPC from HELCO in accordance with Section IX.B.1. of this Contract. HELCO shall not have any obligation to pay capacity charges to HCPC (i) for periods in excess of 24 consecutive hours in which HCPC is unable to fulfill its obligations under Section II.A. of this Contract without fault as set forth in Section VIII, or (ii) for periods in which HCPC does not fulfill its obligations under Section II.A. of this Contract due to HCPC's "total default", as such term is defined in Section XV.B. of this Contract. D. Conditions Related to Capacity Guarantee. ---------------------------------------- 1. The capacity obligation amounts in Section II.A. are based on the assumption that such amounts are permissible under HCPC's applicable permits and any conditions thereunder. Upon HELCO's request, HCPC shall provide verification of such assumption. Should the assumption be incorrect, HELCO reserves the right to require that HCPC use its best effort to cure any discrepancies in a timely manner and/or to adjust such capacity obligation, and the corresponding capacity charge, in order to comply with such permits and conditions. 2. [deleted] 3. [deleted] III. Sale and Purchase of Energy. --------------------------- A. Purchase of Energy 1. Priority Periods (a) "On-peak Period" is defined as the 14 consecutive hours falling within a 16-hour window (0600-2200 hours) during which HCPC is scheduled to be dispatched under this Contract. 7 (b) "Priority Period" is defined as a 70 hour period within a calendar week, consisting of 5 On-peak Periods during 5 consecutive days (usually Monday through Friday, subject to change and adjusted for partial calendar weeks at the beginning or end of this Contract), as determined by HELCO pursuant to subsection (d) herein. (c) During a Priority Period, HELCO may dispatch HCPC up to 22,000 kW, provided however, that HELCO shall use its reasonable best efforts, taking into account Good Engineering and Operating Practices with respect to operation and maintenance of HELCO's utility system, to dispatch HCPC at a minimum average load level of 18,000 kW. During each contract year, HELCO's "Minimum Purchase Obligation" shall be 60,480,000 kWh (18,000 kW x 5 days x 14 hours x 48 weeks) during the Priority Periods. The Minimum Purchase Obligation shall be reduced by the kilowatthours not made available by HCPC during the Priority Periods, and as otherwise limited by transmission system constraints. Consideration of HELCO's utility system operation and maintenance shall include, but not be limited to, transmission system issues such as planned and unplanned line outages, ampacity limitations, and voltage constraints. (d) As to any calendar week, HELCO shall provide HCPC with advance notice of the days and hours that will constitute the Priority Period for that week. Advance notice will be provided before the first working day of the prior calendar week. In the event such advance notice is not received by HCPC at least eight (8) days prior to the start of the Priority Period, HELCO shall 8 reimburse HCPC for any actual, documented incremental costs incurred by HCPC to the extent directly attributable to the timing of the notice. (e) If, due to HELCO's scheduling of the Priority Periods, HCPC incurs incremental labor costs (including incremental labor benefit costs) for its necessary operations personnel which are mandated by its applicable collective bargaining agreement or applicable laws, HELCO shall reimburse HCPC for such actual, documented incremental labor costs. (f) HCPC shall have available for dispatch at least 18,000 kW at the start of each fourteen (14) hour On-peak Period. HELCO's purchases of energy during the Ramp-up Period prior to the start of the fourteen (14) hour On-peak Period shall not be counted as part of HELCO's Minimum Purchase Obligation. 2. Emergency Periods (a) All periods of delivery of energy outside of the Priority Periods, except for any Ramp-up Periods, shall be considered "Emergency Periods." HELCO shall use its reasonable best efforts to notify HCPC of the need for emergency energy, and HCPC shall use its reasonable best efforts to provide HELCO with emergency energy at the time it is required. (b) During any Emergency Period, HELCO may dispatch HCPC up to 22,000 kW, provided however, that HELCO shall use its reasonable best efforts, taking into account Good Engineering and Operating Practices with respect to operation and maintenance of HELCO's utility system, to dispatch HCPC at a minimum average load 9 level of 18,000 kW. Consideration of HELCO's utility system operation and maintenance shall include but not be limited to transmission system issues such as planned and unplanned line outages, ampacity limitations, and voltage constraints. (c) If the Emergency Period has a gap in time prior to or following an On-peak Period, HELCO shall reimburse HCPC for additional diesel fuel costs, if any, to restart its generating unit. (d) If an Emergency Period occurs during the two (2) days of the calendar week which are not included in a Priority Period, HELCO shall use its reasonable best efforts to dispatch HCPC for at least eight (8) consecutive hours. (e) HELCO shall reimburse HCPC for its actual, documented labor costs (including incremental labor benefit costs) for its necessary operations personnel during any Emergency Period, in the amounts mandated by its applicable collective bargaining agreement. HELCO will not be required to pay HCPC's labor and incremental labor benefits costs for the first two (2) hours in each of the first two (2) instances of provision of emergency power per contract year. 3. Incremental Costs. In the event HELCO is obligated to reimburse HCPC for certain incremental costs pursuant to Section III.A.1(d) or (e) or Section III.A.2(e), HELCO shall have the right to verify such incremental costs by obtaining from HCPC, subject to appropriate confidentiality arrangements, the relevant provisions of HCPC's applicable collective bargaining agreement. 10 B. Determination of Energy Rates. ----------------------------- 1. The rate for energy shall consist of on-peak and off-peak rates equal to: (a) the base on-peak and off-peak rates specified in Section III.B.4 of this Contract (the "base rates") plus two-thirds of the difference between the base on-peak or off-peak rates and 100% of HELCO's on-peak and off- peak avoided cost, respectively, if HELCO's on-peak or off-peak avoided cost is greater than the respective base on-peak or off-peak rate, or (b) the base on-peak or off-peak rates, if such base rates are greater than HELCO's respective on-peak or off-peak avoided cost at the time the energy is delivered. The calculation of the on-peak energy payment rate is illustrated in Exhibit B to this Contract. 2. For the purpose of determining the on-peak and off-peak energy payment rates, HELCO's on-peak hours shall be those between the hours of 0700 hours and 2100 hours each day and the off-peak hours shall be those between the hours of 2100 hours on one day and 0700 hours on the following day. 3. "HELCO's avoided cost" means HELCO's respective on-peak and off- peak avoided costs for energy in cents per kilowatt hour as shown by HELCO's most recent avoided cost filing with the PUC. 4. The base on-peak and off-peak rates shall be HELCO's avoided cost for the first quarter of 1995, specifically, $0.0541/kwh on-peak and $0.0451/kwh off-peak. 5. (deleted] 11 6. [deleted] C. Application of Rates. -------------------- 1. The on-peak rate shall apply to all energy provided by HCPC during the Priority Periods. 2. The on-peak rate shall apply to all energy provided by HCPC during Emergency Periods. 3. The off-peak rate shall apply to all energy provided by HCPC during other than the Priority Periods and Emergency Periods. D. Payments. Charges for all energy delivered hereunder shall be -------- payable monthly within ten (10) days after the last day of each calendar month. IV. [deleted] V. 69 kv Substation and Transmission Line. -------------------------------------- A. Existing Facilities. ------------------- Pursuant to the Initial Agreement, HELCO constructed and equipped a 69/13.8 kv substation, transmission line and other necessary apparatus for the purpose of making HCPC capacity available to the HELCO system. With regard thereto, HELCO charged HCPC $77,238 annually for a 20-year period, paid in equal monthly installments from September 15, 1974 to September 14, 1994. The interconnection facilities include the following: 1. 69 kv and 13.8 kv equipment at the HELCO Pepeekeo Switching Station; 2. Two 13.8 kv overhead polelines; 12 3. Two 13.8 kv underground circuits; 4. 13.8 kv breakers and switchgear equipment at the HCPC power plant; 5. 13.8 kv revenue meters and metering support facilities at the HCPC power plant; and 6. Communication and current transformer circuit between the Pepeekeo Switching Station and the HCPC power plant. The point of interconnection is the jumper cables between the HELCO 13.8 kv overhead lines and HCPC's 13.8 kv underground conductors. HELCO will continue to own, operate and maintain at its expense items #1, #2, and the revenue meters in item #5. HCPC will continue to own, operate and maintain at its expense items #3, #4, the metering support facilities in item #5, and #6. B. [deleted] VI. Metering. -------- All electric energy to be delivered hereunder shall be what is commonly called 3-phase 60 hertz alternating current and shall be delivered and metered at an electromotive force of 13.8 kv, a plus or minus 5% variation being allowable, at HCPC's 13.8 kv bus. All revenue-metering equipment shall be owned and operated by HELCO in a metering compartment provided by HCPC and meeting all PUC standards at the 13.8 kv bus. Metering shall be accomplished by an individual system measuring energy from HCPC. HELCO shall, at least once each contract year during the term hereof, test and adjust, in the presence of HCPC's representative, all revenue-metering equipment in conformity with the current standards followed by HELCO pursuant to the latest 13 PUC order or rule relating to the testing and adjustment of revenue-metering equipment. If said equipment is found inaccurate by more than 2%, then adjustment in the billings for such inaccuracy shall be made within 30 days by one party to the other as the case may be. Any inaccuracy so discovered shall be conclusively presumed to have existed for half the period between the last inspection and the inspection in which the inaccuracy was discovered. VII. Purchase of Power by HCPC. ------------------------- Sales of electrical energy to HCPC by HELCO shall be governed by applicable rate schedules and rules and regulations at the time of such sales as specified in HELCO's tariff filed with the PUC, and not by this Contract. VIII. Interruption of Service. ----------------------- If HCPC shall be wholly or partially prevented from delivering the electrical energy contracted for herein, or if the service thereof shall be interrupted, or if HELCO shall be prevented from receiving, using and applying the same, by reason of or through strikes, riot, fire, flood, invasion, insurrection, lava flow or volcanic activity, tidal wave, civil commotion, accident, the order of any court or civil authority, any act of God or the public enemy, or any other similar or dissimilar cause reasonably beyond its exclusive control and not attributable to its neglect, then and in any such event, HCPC shall not be obligated to deliver said electrical energy hereunder during such period and shall not be liable for any damage or loss resulting from such interruption or suspension, and HELCO shall not be obligated or liable to take or pay for any such energy during 14 such period. In the event of a strike of its own employees which would interfere with the delivery of energy hereunder, HCPC will utilize its best efforts to operate the HCPC power plant facilities, including the use of supervisory labor. In any case, however, so long as HCPC is able to fulfill its obligations under this Contract, HELCO will continue to pay the capacity charge set forth in Section II.C. hereinabove. In the event HELCO is able to fulfill its obligations under this Contract but HCPC is unable to do so, HCPC shall continue to pay the charge set forth in Section V hereinabove. In the event of either party being unable to fulfill its obligations under this Contract without fault as aforesaid, for periods not in excess of 24 consecutive hours, then, and in such case, there will be no adjustment of the charge set forth in Section V or the capacity charge. In any of such event or events, the party or parties suffering such interruption or suspension shall be prompt and diligent in removing the cause thereof. In order to minimize the possibility of interruption, HCPC agrees to keep reasonable fuel reserves and a reasonable inventory of spare parts on hand at all times. IX. Performance Standards and Sanctions. ----------------------------------- A. Minimum Performance Standards. ----------------------------- 1. HCPC acknowledges and agrees that the HCPC unit is expected to meet the following minimum standards for satisfactory day-to-day performance during each contract year:(i) a "Priority Period Availability" (as defined in subsection IX.A.2, and excluding the four-week annual maintenance period and other downtime due to a catastrophic equipment failure) of 95 percent or better; (ii) not more 15 than 6 unit trips per year; and (iii) a forced outage rate of 5 percent or less. 2. The "Priority Period Availability" of the HCPC unit (in percent) is to be computed by adding the average megawatts available from the HCPC unit during each Priority Period hour during the contract year, multiplying the total by 100, and dividing by 73,920 (22 MW x 14 hr/day x 5 days/wk x 48 weeks). 3. "Catastrophic equipment failure" means a sudden, unexpected failure of a major piece of equipment which (i) substantially reduces or eliminates the capability of the HCPC Unit to produce power, (ii) is beyond the reasonable control of HCPC and could not have been prevented by the exercise of due diligence by HCPC and, (iii) despite the exercise of all reasonable efforts, requires more than 60 days to repair. 4. "Unit trip" means the sudden and immediate removal of the HCPC unit from service as a result of an immediate mechanical/electrical/hydraulic control system trip or operator initiated trip/shutdown which requires HELCO to take immediate steps to place an unscheduled generator on line to make up for the loss of output of the HCPC unit; provided, however, that a unit trip shall not include: (i) any such removal which occurs within 48 hours of the time at which the HCPC unit is restarted following an outage; (ii) trips caused or initiated by HELCO; or (iii) trips occurring during periods when HCPC has continued to furnish capacity to HELCO at the request of HELCO's Production Manager or his designated representative after HCPC has notified HELCO that the HCPC unit is likely to trip. 16 5. The forced outage rate of the HCPC unit during a contract year is to be computed by totaling the average megawatts unavailable for service due to forced outages or deratings on an hourly basis, multiplying the total by 100, and dividing by 192,720. B. Sanctions. --------- 1. The capacity charge is to be made on the basis of the full Priority Period Availability of 22,000 kw. For any full Priority Period hour in which the full 22,000 kw is not available, the capacity charge will be reduced by $0.0609/kW. 2. For each contract year in which the Priority Period Availability of the HCPC unit is less than 95 percent, HCPC will pay to HELCO $5000 for each full percentage point of the shortfall unless the shortfall is due to a catastrophic equipment failure. 3. For each unit trip in excess of 6 per contract year, HCPC shall pay $5000 to HELCO. 4. HELCO shall have the right to set off any payment due from HCPC under this Section against any payments due to HCPC. C. Deletion of Capacity Charge. --------------------------- 1. If the performance of the HCPC unit fails to meet any of the following minimum criteria for any reason other than a catastrophic equipment failure, the capacity charge shall be deleted until, with respect to criterion (v) or (vi), HCPC demonstrates to HELCO's reasonable satisfaction that it has cured the defect or deficiencies causing the unit trips, and until, with respect to criterion (i), (ii) or (iii), HCPC operates the unit at or above the 17 minimum criterion or criteria for one full year: (i) Priority Period Availability of no less than 75 percent for any one contract year; (ii) Priority Period Availability of no less than 80 percent for two out of any three consecutive contract years; (iii) Forced outage rate no greater than 15 percent for any one contract year; (iv) Forced outage rate no greater than 10 percent for two out of any three consecutive contract years; (v) Unit trips no greater than 18 for any one contract year; or (vi) Unit trips no greater than 12 for any two out of three consecutive contract years. 2. Any period during which the HCPC unit does not meet or exceed the minimum criteria set forth in Section IX.C.l. shall be termed a "deficiency period." 3. Notwithstanding the provisions of Section IX.C.l.(v) and (vi), the capacity charge shall not be deleted solely on the basis of excessive unit trips during such period following a deficiency period (not to exceed five (5) days) as HCPC is taking appropriate and timely corrective action acceptable to HELCO to cure any defects or deficiencies causing the unit trips. HCPC shall not be deemed to be taking appropriate and timely corrective action unless (i) it provides written notice to HELCO of the defects or deficiencies causing the unit trips, the corrective action it proposes to take, and an appropriate schedule for completing such corrective action within 18 two (2) days after the end of a deficiency period, and (ii) it complies with such schedule. Such written notice shall not be valid unless it is provided within seven (7) days after the end of a deficiency period. X. Privity. ------- Any other term, covenant or provision herein contained to the contrary notwithstanding, this Contract is not intended and shall not be construed in any manner so as to benefit any third party; nor is it intended nor shall it be construed in a manner such as to place HCPC in privity with any parties who might have a contract to purchase electric energy from HELCO; nor is it intended nor shall it be construed in any manner so as to impose a duty upon HCPC to supply electric energy to the public or any portion of the public or to any private person or parties not a party to this Contract, or to supply electric energy to any particular locality or district in the County of Hawaii. XI. Assignment. ---------- This Contract shall not be assigned by either party without the prior written consent of the other party; provided that HELCO may assign its interest in this Contract, upon written notice to HCPC, to the Trustee under HELCO's First Mortgage and Deed of Trust dated May 1, 1941, as it has been and may be amended from time to time; which consent shall not be unreasonably withheld. XII. Arbitration. ----------- A. Enforcement of Contract. In the event any controversy or dispute ----------------------- arises with respect to this Contract or any of the terms or 19 conditions hereof other than any dispute arising under Section XV, or with respect to any alleged breach hereof, such controversy or dispute, and all issues with respect to any obligation or duty to continue performance under this Contract pending resolution of such controversy or dispute, shall be submitted to and settled by arbitration in accordance with the laws of the State of Hawaii (which are currently codified in Chapter 658 of the Hawaii Revised Statutes) and the Commercial Rules of the American Arbitration Association and the parties shall be bound by the award of such arbitration. B. Attorneys' Fees. In the event of any breach of any covenant or --------------- condition of this Contract, or any dispute or controversy with respect hereto, the prevailing party shall be entitled to recover from the other party all expenses and costs, including reasonable attorneys' fees, incurred in the enforcement of this Contract. XIII. Training Standards. ------------------ All HCPC employees operating and maintaining the steam generator and all HCPC employees maintaining the turbine generator shall have received training in accordance with good engineering and operating standards and practices. HCPC's operation and maintenance schedules shall be established to provide adequate staffing by qualified personnel at all times. XIV. Term. ---- A. The term of this Contract shall be from January 1, 2000 to and including December 31, 2004, and thereafter shall continue for one-year periods unless either party gives written notice of termination by May 30 of the year of termination. 20 B. HELCO Right to Early Termination: HELCO may choose to terminate -------------------------------- this Contract as of January 1, 2002, 2003 or 2004 by giving HCPC written notice of such termination no later than May 30 of the previous year. In the event of such termination, HELCO shall pay to HCPC an early termination payment in accordance with the following schedule: Termination as of January 1 Early Termination Payment --------------------------- ------------------------- 2002 $1,500,000 2003 $1,000,000 2004 $ 500,000 2005 and later $ 0 HELCO shall pay HCPC the Early Termination Payment amount no later than thirty (30) days after the date HCPC ceases deliveries of capacity and energy to HELCO. C. If HCPC has not already taken its four-week overhaul period that year, HCPC's obligation to provide capacity and energy to HELCO shall cease as of midnight, November 30 of the year of termination without any decrease in the capacity charge payable under Section II.C herein. XV. Termination; Default. -------------------- A. Termination upon HCPC's Total Default. ------------------------------------- 1. Upon the occurrence of a total default by HCPC, HELCO may, at its option, (i) terminate this Contract by delivering written notice of such termination to HCPC, and institute proceedings or resort to such other remedies not in conflict with this Contract as 21 it deems appropriate, or (ii) continue this Contract, in which event HCPC shall pay HELCO's power replacement cost, and institute proceedings or resort to such other remedies not in conflict with this Contract as it deems appropriate. Termination under this Section shall be effective 30 days from the date of HCPC's receipt of written notice of termination and shall not prejudice any other rights or remedies HELCO may have. 2. "Total default" means abandonment of the production of power by failure to maintain continuous service to the extent required by this Contract, when HCPC has the technical capability to maintain such service (including the ability to operate HCPC's unit in a safe manner in accordance with good engineering and operating practices), for three (3) or more consecutive days, the last 24 hours of which shall be after notice to HCPC that it is in total default. 3. "HELCO's power replacement cost" means the cost to HELCO of replacing the capacity and energy that HCPC is obligated to furnish to HELCO pursuant to Sections II.A. and III.A.l. and 2. less the net payments HELCO would have made to HCPC for such capacity and energy. B. HCPC's Failure to Restore Unit. If HCPC shall fail to make all ------------------------------ reasonable efforts to restore the HCPC unit to full or substantially full operating condition following any casualty loss and such failure continues for ten (10) days after written demand therefor by HELCO, HELCO shall have the option to terminate this Contract by giving written notice of such termination to HCPC. Such termination 22 shall be effective 30 days from the date of HCPC's receipt of written notice of termination and shall not prejudice any other rights or remedies HELCO may have. C. HELCO's Right to Possession. In the event there is a total default --------------------------- by HCPC as defined under Section XV, HELCO shall have the right but not any obligation immediately to take possession of the HCPC Power Plant for the remaining term of the Contract and to generate power regardless of whether or not it exercises its default purchase option under Section XVI.A. If at the time of such total default HCPC is under the jurisdiction of the Bankruptcy Court, to the extent any automatic stay may apply, the parties agree that HELCO has cause, within the meaning given that term in Section 362(d) (1) of the Bankruptcy Code, 11 U.S.C. (S) 362(d) (1), to obtain relief from any automatic stay to permit it to exercise its rights under this Section. If HELCO takes possession of the HCPC Power Plant, it must preserve the value and operational integrity of the plant so that the fair market value (less depreciation) of the plant is not negatively impacted. During and as a result of any such possession by HELCO, the risk of damage to or loss of the HCPC Power Plant shall be borne by HELCO to the extent such damage or loss is attributable to HELCO's failure to operate the power plant in accordance with (i) Good Engineering and Operating Practices and (ii) electric public utility standards. In the event HELCO takes possession of the HCPC Power Plant, HCPC shall make available to HELCO all operating manuals and equivalent information relating to the operation of the power plant. XVI. HELCO's Purchase Options. ------------------------ 23 A. Default Purchase Option. ----------------------- 1. In addition to any other rights or remedies HELCO may have, if a total default by HCPC occurs and HELCO gives notice of termination of this Contract to HCPC pursuant to Section XV.A., HELCO, at its option, shall have the right but not any obligation, to purchase the HCPC Power Plant, as defined and identified on Exhibit "A" to this Contract, free and clear of any liens, debts, mortgages or other encumbrances (which right shall be termed HELCO's "default purchase option"). 2. In order to preserve its default purchase option, HELCO shall provide written notice of its preliminary intent to exercise such option to purchase to HCPC within 30 days after HELCO gives notice of termination of this Contract to HCPC as a result of HCPC's total default. 3. Notice of intent to purchase hereunder by HELCO shall be in writing, and shall be given to HCPC within 15 days after agreement between the parties as to the fair market value of the HCPC Power Plant, or after a determination of such fair market value, with the closing of any such purchase contingent upon PUC approval unless waived by HELCO. 4. The purchase price pursuant to HELCO's default purchase option shall be the fair market value of the HCPC Power Plant. 5. If HELCO gives written notice of its preliminary intent to exercise its default purchase option after a total default by HCPC occurs, HELCO shall have the right but not any obligation to 24 immediately take possession of the HCPC Power Plant during any remaining term of this Contract and to generate electrical energy for its electric public utility system. If HELCO takes possession of the HCPC Power Plant, it must preserve the value and operational integrity of the plant so that the fair market value (less depreciation) of the plant is not negatively impacted. During and as a result of any such possession by HELCO, the risk of damage to or loss of the HCPC Power Plant shall be borne by HELCO to the extent such damage or loss is attributable to HELCO's failure to operate the power plant in accordance with (i) Good Engineering and Operating Practices and (ii) electric public utility standards. In the event HELCO takes possession of the HCPC Power Plant, HCPC shall make available to HELCO all operating manuals and equivalent information relating to the operation of the power plant. B. [deleted] C. [deleted] D. Protection of Option to Purchase. HCPC will not directly or -------------------------------- indirectly create, or permit to be created by any action or inaction of HCPC or those claiming through or under HCPC (and will not permit to remain, and will promptly discharge, any of the same so created or permitted) any mortgage, lien or encumbrance with respect to the HCPC Power Plant (other than those existing and disclosed in writing to HELCO by HCPC as of the date of this Contract) that would impair the exercise by HELCO of its option to purchase pursuant to Section XVI.A. of this Contract, without HELCO's prior written consent, which consent shall not be unreasonably withheld. 25 XVII. [deleted] XVIII. PUC Approval. ------------ HELCO shall use its good faith efforts to obtain, as soon as practicable, an order from the PUC ordering that: (i) the Contract is approved; (ii) the energy and capacity charges to be paid by HELCO pursuant to the Contract are reasonable; (iii) HELCO may pass on to its ratepayers, through its energy cost adjustment clause ("ECAC"), the energy payments it will be required to make to HCPC under the Contract, to the extent that such payments are not recovered in HELCO's base rates; (iv) the terms and conditions of the Contract are reasonable; and (v) HELCO may include the energy and capacity payments in its calculation of revenue requirements in future HELCO rate cases. If the PUC order, or an acceptable PUC interim order, is not issued by November 30, 1999 (unless extended by written, signed agreement of the parties), this Contract shall be null and void. If an order is issued on or before November 30, 1999 (unless extended by written, signed agreement of the parties) but is unacceptable, then the party to whom the order is unacceptable shall provide written notice (faxed or hand-delivered to the other party) of the unacceptable terms or conditions by December 15, 1999, in which event the Contract shall be null and void. An acceptable PUC interim order is an order issued by November 30, 1999 that (i) approves (a) the Contract, on an interim basis pending issuance of the PUC's final order, and (b) inclusion in 26 HELCO's ECAC of the energy payments it is required to make to HCPC under the Contract, to the extent that such payments are not recovered in HELCO's base rates, for an interim period extending up to 90 days after the issuance date of the PUC's final order, and (ii) does not contain terms and conditions that are unacceptable to either party. If the final PUC order (i) does not approve the contract, or (ii) contains terms and conditions that are unacceptable to either party, or (iii) conditions approval of the Contract on modifications to the Contract that would have a material adverse impact on a party, or (iv) fails to make any of the findings requested above, or (v) is not issued by March 31, 2000 (unless extended by written, signed agreement of the parties), then either party [provided such party is adversely affected in the case of condition (ii) or (iii)] may terminate the Contract, by written notice faxed or hand-delivered to the other party within 30 days of the filing date of the final PUC order, in which event the Contract shall terminate as of 90 days after the issuance date of the final PUC order. XIX. General Provisions. ------------------ A. Severability. Any portion or provision of this Contract which is ------------ invalid, illegal or unenforceable in any jurisdiction shall, as to that jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability, without affecting in any way the remaining portions or provisions hereof in such jurisdiction or, to the extent permitted by law, rendering that or any other portion or provision thereof invalid, illegal or 27 unenforceable in any other jurisdiction. B. Section Headings. The Section headings included in this Contract ---------------- are for the convenience of the parties only and shall not affect the construction or interpretation of this Contract. Schedules and Exhibits referred to in this Contract are an integral part of this Contract. C. Notices. All notices given pursuant to this Contract shall be in ------- writing and be personally delivered or mailed with postage prepaid, by registered or certified mail, return receipt requested to the address set forth below or such other address as a party may from time to time specify in writing to the other party. If so mailed and also sent by telegram or facsimile machine, the notice will conclusively be deemed to have been received on the business day next occurring 24 hours after the latest to occur of such mailing and telegraphic communication; otherwise, no notice shall be deemed given until it actually arrives at the address in question. The addresses to which notice are initially to be sent are as follows: 28 If to HELCO to: President Hawaii Electric Light Company, Inc. P.O. Box 1027 Hilo, Hawaii 96721 Telecopier No.: (808) 969-0100 With a copy to: Director, Power Purchase Division Hawaiian Electric Company, Inc. P.O. Box 2750 Honolulu, Hawaii 96840 Telecopier No.: (808) 543-4377 If to HCPC to: President Hilo Coast Power Company, a Division of Brewer Environmental Industries,LLC P.O. Box 4190 Hilo, Hawaii 96720 Telecopier No.: (808) 933-7772 With a copy to: President C. Brewer and Company, Limited P.O. Box 1826 Papaikou, Hawaii 96781 Telecopier No.: (808) 969-8151 D. Entire Agreement. This Contract (including Exhibits "A" and "B" ---------------- hereto) constitutes the entire agreement of the parties with respect to the subject matter hereof and supersedes all prior written or oral and all contemporaneous oral agreements, understandings and negotiations between the parties with respect to the subject matter hereof. E. Governing Law. This Contract is governed by and is to be construed ------------- and interpreted in accordance with the laws of the State of Hawaii, without giving effect to the conflict of law principles thereof. 29 F. Modifications, Amendments or Waivers. Except as otherwise provided ------------------------------------ herein, provisions of this Contract may be modified, amended or waived only by a written document specifically identifying this Contract and signed by a duly authorized executive officer of a party. G. Interpretation. Because the terms of this Contract have been -------------- negotiated at arm's length among sophisticated parties represented by experienced counsel and with all parties having had the opportunity to request and bargain for provisions in their respective interests, the parties agree that any dispute as to the construction of this Contract shall be resolved by interpreting its terms according to their ordinary and every day meaning, and not for or against any party by virtue of its role in negotiating or drafting this Contract and that the rule of "interpretation against the draftsman" shall not apply. H. Good Faith Efforts. For purposes of any provision in this Contract ------------------ which requires any party to obtain certain approvals or comply with certain conditions, including, but not limited to, any approvals and conditions under Section XVIII hereof, such party shall use its good faith efforts to obtain such approvals or comply with such conditions in a timely manner, and the other party shall not act so as to prevent or hinder such efforts. Furthermore, with regard to Section XVIII hereof, HCPC shall cooperate with HELCO's efforts in obtaining a satisfactory PUC order. I. Cooperation between the Parties. Both HCPC and HELCO shall ------------------------------- cooperate with the other party in connection with this Contract 30 and except for pursuing or enforcing its legal rights shall refrain from taking any action or making any statements or representations which may undermine the business activities or reputation of the other party. 31 IN WITNESS WHEREOF, the undersigned have caused these presents to be executed as of the day and year first above written. HAWAII ELECTRIC LIGHT COMPANY, INC. By: /s/ Edward Y. Hirata -------------------------------- Its Vice President --------------------------- By: /s/ Molly M. Egged ------------------------------- Its Secretary ---------------------------- 32 HILO COAST POWER COMPANY, a Division of Brewer Environmental Industries, LLC, a Hawaii Limited Liability Company By Brewer Environmental Industries Holdings, Inc. By: /s/ Kent T. Lucien -------------------------------- Its: Vice President --------------------------- 33 EXHIBIT A HCPC POWER PLANT OWNERSHIP TRANSFER ----------------------------------- 1. Transfer ownership of the power generating plant, associated equipment, and structures to include, but not be limited to the following: A. Powerhouse (boiler and turbine generator) B. Bagasse storage and handling buildings C. Coal storage area D. Fuel storage area E. Circulating water wells and pipeline F. Circulating water outfalls G. Fresh water well located off-site H. Land that Items A-G above are situated on as shown on the attached map. (Location of Item G is not shown.) 2. Obtain easements and rights-of-way to include but not be limited to the following: A. 13.8 KV generator feeder from the power plant to the HELCO substation B. Service roads C. Service water line from the fresh water well D. Power supply line for the fresh water well pump 3. Sever interconnections with plantation facilities, for the following items: A. 2.4 KV distribution system B. Domestic utilities (water, sanitary sewer, power, etc.) C. Service utilities (air, steam, etc.) 4. HCPC should obtain all government approvals and proper subdivision of the affected property prior to transfer of ownership. (Note: Coal storage area is situated on a parcel zoned for residential use.) 5. Equipment included in paragraph 1 above is described in greater detail on the attached page A3. A-1 EXHIBIT A HCPC POWER PLANT OWNERSHIP TRANSFER ----------------------------------- A map of the land that items 1A-G are situated on. A-2 HCPC POWER PLANT OWNERSHIP TRANSFER LIST OF EQUIPMENT Number of Units Description - ------- ----------- 5 Air Compressors, Instrument Air Dryer, Air Tank and Miscellaneous Tanks 4 Demineralize Chemical Treatment Pumps, Fuel Oil Heating, Pumping and Storage and Condensate Tanks Misc Piping, Superstructure, Support Steel and Bridge Crane 8 Minor Component Group Consisting of Rotary Seal Valves, Pressure Control Valves, Fiberglass Tank, Kittrell Silencer Check Valves and L.D. Fan Coupling 4 Conveying and Storage Equipment for Bagasse and Boiler Ash 4 Control Instrumentation System and Accessories 4 Motors for Fans and Boiler Feed Pumps and Auxiliaries 3 480 V and 2,400 V Load Centers and 13.8 KV Switchgear 1 Concrete Substructure and Foundations for Boiler and Turbogenerator 9 20 Mega-Watt DeLaval Turbo-Generator/Condenser, Vacuum Pump, Spare Parts and Cooling Water Heat Exchanger 1 330,000 lb./hr. 1,250 psig. 825 degree F.T.T. Babcock and Wilcox Boiler and Spare Parts 5 Boiler Feed Pumps and Drive Turbine, Generator and Feedwater Heater 1 Fuel Storage Structure 1 Foundations 1 Fuel Reclaimers 9 Fuel Conveyors, Bagasse Plows and Trash Conveyor and Drives 1 Electrical System 3 Salt Water Wells Nos. 1, 2 and 3 1 Fresh Water Well System (off-site) with 6-inch Water Line to Power Plant A-3 EXHIBIT B Calculation of Energy Payment Rate Assumptions: - ----------- HELCO on-peak base ("floor") rate (Prior Contract): $0.0437 HCPC on-peak energy payment rate (Prior Contract): HELCO avoided cost HCPC on-peak base ("floor") rate (this Contract): $0.0541 (rounded to $0.054 for illustration purposes) HCPC on-peak energy payment rate (this Contract): formula reflecting two-thirds of the increase/decrease between quarterly avoided cost figures HELCO on-peak filed avoided energy cost payment rates: First year 1st quarter $0.054 2d quarter $0.057 3d quarter $0.060 PUC approval 4th quarter $0.063 Second year 1st quarter $0.057 2d quarter $0.051 3d quarter $0.053 4th quarter $0.057 HCPC on-peak energy payment rates: - --------------------------------- First year 1st quarter $0.054 2d quarter $0.057 3d quarter $0.060 PUC approval $0.058 (1) 4th quarter $0.060 Second year 1st quarter $0.056 2d quarter $0.054 (2) 3d quarter $0.054 (3) 4th quarter $0.056 (4) (l) Immediate adjustment upon PUC approval, to reflect sharing formula (2) Due to floor (3) Effect of III.B: energy payment rate will not be increased even though HELCO's avoided cost increases, where HELCO's avoided cost for both the current and prior quarter are less than or equal to the floor (4) Effect of III.B: where HELCO's avoided cost increases and the current quarter's avoided cost is above the floor but the prior quarter's avoided cost is below the floor. HCPC's energy payment is increased but only to the extent of two-thirds the difference between the floor and the current quarter's avoided cost. B-1 EX-12.1 3 HEI AND SUBSIDIARIES COMPUTATION OF RATIO HEI Exhibit 12.1 ---------------- Hawaiian Electric Industries, Inc. and subsidiaries COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (unaudited)
Nine months ended Nine months ended September 30, September 30, ------------------------------- ------------------------------- (dollars in thousands) 1999 (1) 1999 (2) 1998 (1) 1998 (2) - ---------------------------------------------------------------------------------------------------------- Fixed charges Total interest charges (3)............. $115,616 $208,055 $108,333 $216,610 Interest component of rentals.......... 3,315 3,315 2,648 2,648 Pretax preferred stock dividend requirements of subsidiaries.......... 2,626 2,626 7,172 7,172 Preferred securities distributions of trust subsidiaries................... 12,016 12,016 9,289 9,289 ------------- ------------- ------------- ------------- Total fixed charges.................... $133,573 $226,012 $127,442 $235,719 ============= ============= ============= ============= Earnings Pretax income from continuing operations............................ $106,322 $106,322 $119,659 $119,659 Fixed charges, as shown................ 133,573 226,012 127,442 235,719 Interest capitalized................... (2,171) (2,171) (5,145) (5,145) Earnings available for fixed charges... $237,724 $330,163 $241,956 $350,233 ============= ============= ============= ============= Ratio of earnings to fixed charges..... 1.78 1.46 1.90 1.49 ============= ============= ============= =============
(1) Excluding interest on ASB deposits. (2) Including interest on ASB deposits. (3) Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI's consolidated statements of income. EX-12.2 4 HECO AND SUBSIDIARIES COMPUTATION OF RATIO HECO Exhibit 12.2 ----------------- Hawaiian Electric Company, Inc. and subsidiaries COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (unaudited)
Nine months ended September 30, -------------------------------- (dollars in thousands) 1999 1998 - --------------------------------------------------------------------------------------------- Fixed charges Total interest charges.................................... $ 36,756 $ 36,784 Interest component of rentals............................. 574 552 Pretax preferred stock dividend requirements of subsidiaries............................................. 1,120 3,062 Preferred securities distributions of trust subsidiaries.. 5,746 3,019 --------------- --------------- Total fixed charges....................................... $ 44,196 $ 43,417 =============== =============== Earnings Income before preferred stock dividends of HECO........... $ 57,528 $ 65,519 Income taxes (see note below)............................. 36,120 42,213 Fixed charges, as shown................................... 44,196 43,417 AFUDC for borrowed funds.................................. (1,955) (5,145) --------------- --------------- Earnings available for fixed charges...................... $135,889 $146,004 =============== =============== Ratio of earnings to fixed charges........................ 3.07 3.36 =============== =============== Note: Income taxes is comprised of the following: Income tax expense relating to operating income from regulated activities.................................. $36,208 $42,253 Income tax benefit relating to loss from nonregulated activities............................... (88) (40) --------------- --------------- $36,120 $42,213 =============== ===============
EX-27.1 5 HEI FINANCIAL DATA SCHEDULE 9/30/99
5 This schedule contains summary financial information extracted from Hawaiian Electric Industries, Inc. and subsidiaries' consolidated balance sheet as of September 30, 1999 and consolidated statement of income for the nine months ended September 30, 1999 and is qualified in its entirety by reference to such financial statements. 0000354707 Hawaiian Electric Industries, Inc. 1,000 9-MOS DEC-31-1999 JAN-01-1999 SEP-30-1999 209,430 2,070,881 155,306 0 0 0 3,237,540 1,147,935 8,241,648 0 978,676 100,000 134,293 665,275 170,518 8,241,648 0 1,114,385 0 945,092 8,483 0 54,488 106,322 41,180 65,142 0 0 0 65,142 2.02 2.02
EX-27.2 6 HECO FINANCIAL DATA SCHEDULE 9/30/99
UT This schedule contains summary financial information extracted from Hawaiian Electric Company, Inc. and subsidiaries' consolidated balance sheet as of September 30, 1999 and consolidated statement of income and cash flows for the nine months ended September 30, 1999 and is qualified in its entirety by reference to such financial statements. 0000046207 Hawaiian Electric Company, Inc. 1,000 9-MOS DEC-31-1999 JAN-01-1999 SEP-30-1999 PER-BOOK 1,940,038 0 192,496 14,387 145,429 2,292,350 85,387 295,468 421,840 802,695 100,000 34,293 645,176 0 0 103,111 0 0 0 0 607,075 2,292,350 763,408 36,208 634,981 671,189 92,219 6,572 98,791 41,263 57,528 908 56,620 40,616 40,621 144,964 0 0
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