<PAGE>
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.
<TABLE>
<CAPTION>
<S> <C>
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)
=========================================================================================================
</TABLE>
<PAGE>
Hawaiian Electric Industries, Inc. and subsidiaries
Hawaiian Electric Company, Inc. and subsidiaries
Form 10-Q--Quarter ended September 30, 1999
INDEX
<TABLE>
<CAPTION>
<S> <C> <C>
Page No.
Glossary of terms.......................................................... ii
Forward-looking information................................................ v
</TABLE>
PART I. FINANCIAL INFORMATION
<TABLE>
<CAPTION>
Item 1. Financial statements
<S> <C> <C>
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
</TABLE>
PART II. OTHER INFORMATION
<TABLE>
<CAPTION>
<S> <C> <C>
Item 1. Legal proceedings........................................... 44
Item 5. Other information........................................... 44
Item 6. Exhibits and reports on Form 8-K............................ 46
Signatures................................................................ 47
</TABLE>
i
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
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
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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.
</TABLE>
1
<PAGE>
<TABLE>
<CAPTION>
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
<S> <C> <C> <C> <C>
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
========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
2
<PAGE>
<TABLE>
<CAPTION>
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
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
3
<PAGE>
<TABLE>
<CAPTION>
Hawaiian Electric Industries, Inc. and subsidiaries
Consolidated statements of cash flows (unaudited)
Nine months ended
September 30,
----------------------------------
(in thousands) 1999 1998
- ------------------------------------------------------------------------------------- ----------------------------------
<S> <C> <C>
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.
</TABLE>
4
<PAGE>
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
<PAGE>
(2) Segment financial information
- ----------------------------------
Segment financial information was as follows:
<TABLE>
<CAPTION>
Electric Savings Holding Elimi-
($ in thousands) utility bank Other companies nations Total
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
===================================================================
</TABLE>
* Income before income taxes and discontinued operations.
Revenues attributed to foreign countries for the periods identified above were
not significant.
6
<PAGE>
(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
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
------------------------------ --------------------------
(in thousands) 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
American Savings Bank, F.S.B. and subsidiaries
Balance sheet data
<TABLE>
<CAPTION>
(in thousands) September 30, 1999 December 31, 1998
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
================== ====================
</TABLE>
7
<PAGE>
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:
<TABLE>
<CAPTION>
Nine months ended
September 30,
------------------------------------------
(in thousands) 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
================== ==================
</TABLE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
Three months Nine months ended
ended September 30, September 30,
(in thousands) 1998 1998
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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)
================== =====================
</TABLE>
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
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
Hawaiian Electric Company, Inc. and subsidiaries
Consolidated balance sheets (unaudited)
September 30, December 31,
(in thousands, except par value) 1999 1998
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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.
</TABLE>
12
<PAGE>
<TABLE>
<CAPTION>
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
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
============== ==============
</TABLE>
Hawaiian Electric Company, Inc. and subsidiaries
Consolidated statements of retained earnings (unaudited)
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
--------------------------------- ---------------------------------
(in thousands) 1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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.
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
Hawaiian Electric Company, Inc. and subsidiaries
Consolidated statements of cash flows (unaudited)
Nine months ended
September 30,
--------------------------------------------
(in thousands) 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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.
</TABLE>
14
<PAGE>
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:
<TABLE>
<CAPTION>
Nine months ended
September 30,
-----------------------------------------
(in thousands) 1999 1998
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Interest................................................................... $28,786 $26,249
================== ==================
Income taxes............................................................... $17,352 $22,277
================== ==================
</TABLE>
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
<PAGE>
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
<PAGE>
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
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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
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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
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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
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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
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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
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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
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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
<PAGE>
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:
<TABLE>
<CAPTION>
Balance sheet data
HELCO MECO
--------------------------------- --------------------------------
September 30, December 31, September 30, December 31,
(in thousands) 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
=============== ============= ============= =============
</TABLE>
25
<PAGE>
<TABLE>
<CAPTION>
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
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
---------------------------------
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
--------------------------- ------------------------
(in thousands) 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
========= =========== =========== ============
</TABLE>
26
<PAGE>
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
- ----------------
<TABLE>
<CAPTION>
Three months ended
September 30,
(in thousands, except per --------------------- % Primary reason(s) for
share amounts) 1999 1998 change significant change*
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
27
<PAGE>
<TABLE>
<CAPTION>
Nine months ended
September 30,
(in thousands, except per ------------------------ % Primary reason(s) for
share amounts) 1999 1998 change significant change*
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
* Also see segment discussions which follow.
NM Not meaningful.
28
<PAGE>
Following is a general discussion of the results of operations by business
segment.
Electric utility
- ----------------
<TABLE>
<CAPTION>
Three months ended
(in thousands, September 30,
except per ------------------------------ % Primary reason(s) for significant
barrel amounts) 1999 1998 change change
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
</TABLE>
29
<PAGE>
<TABLE>
<CAPTION>
Nine months ended
(in thousands, September 30,
except per --------------------------------- % Primary reason(s) for significant
barrel amounts) 1999 1998 change change
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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)
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
Savings bank
- ------------
<TABLE>
<CAPTION>
Three months ended
September 30,
-------------------------------------- %
(in thousands) 1999 1998 change Primary reason(s) for significant change
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
</TABLE>
33
<PAGE>
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.
<TABLE>
<CAPTION>
Nine months ended
September 30,
-------------------------------
(in thousands) 1999 1998
- --------------------------------------------------------------------------------------------
<S> <C> <C>
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
========== ==========
</TABLE>
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
<PAGE>
Other
- -----
<TABLE>
<CAPTION>
Three months ended
September 30,
----------------------- %
(in thousands) 1999 1998 change Primary reason(s) for significant change
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
Nine months ended
September 30,
------------------------- %
(in thousands) 1999 1998 change Primary reason(s) for significant change
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
(in millions) September 30, 1999 December 31, 1998
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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%
============ ============ ============ ============
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
(in millions) September 30, 1999 December 31, 1998
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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%
============== ============= ============== ============
</TABLE>
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
<PAGE>
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
<TABLE>
<CAPTION>
September December 31, %
(in millions) 30, 1999 1998 change
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
September 30, 1999 December 31, 1998
------------------ -----------------
<S> <C> <C>
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
</TABLE>
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
<PAGE>
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
<PAGE>
Ratio of earnings to fixed charges excluding interest on ASB deposits
<TABLE>
<CAPTION>
Nine months Years ended December 31,
ended -----------------------------------------------------------------------------------
September 30, 1999 1998 1997 1996 1995 1994
- -------------------- ------------- ------------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
1.78 1.85 1.89 1.93 2.02 2.31
==================== ============= ============= ============ ============ =============
</TABLE>
Ratio of earnings to fixed charges including interest on ASB deposits
<TABLE>
<CAPTION>
Nine months Years ended December 31,
ended -----------------------------------------------------------------------------------
September 30, 1999 1998 1997 1996 1995 1994
- -------------------- ------------- ------------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
1.46 1.47 1.58 1.56 1.60 1.73
==================== ============= ============= ============ ============ =============
</TABLE>
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
<TABLE>
<CAPTION>
Nine months Years ended December 31,
ended -----------------------------------------------------------------------------------
September 30, 1999 1998 1997 1996 1995 1994
- -------------------- ------------- ------------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
3.07 3.33 3.26 3.58 3.46 3.47
==================== ============= ============= ============ ============ =============
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
Dated Registrant/s Items reported
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
</TABLE>
46
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
(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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
EXHIBIT A
HCPC POWER PLANT OWNERSHIP TRANSFER
-----------------------------------
A map of the land that items 1A-G are situated on.
A-2
<PAGE>
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
<PAGE>
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
<PAGE>
HEI Exhibit 12.1
----------------
Hawaiian Electric Industries, Inc. and subsidiaries
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(unaudited)
<TABLE>
<CAPTION>
Nine months ended Nine months ended
September 30, September 30,
------------------------------- -------------------------------
(dollars in thousands) 1999 (1) 1999 (2) 1998 (1) 1998 (2)
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
============= ============= ============= =============
</TABLE>
(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.
<PAGE>
HECO Exhibit 12.2
-----------------
Hawaiian Electric Company, Inc. and subsidiaries
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(unaudited)
<TABLE>
<CAPTION>
Nine months ended
September 30,
--------------------------------
(dollars in thousands) 1999 1998
- ---------------------------------------------------------------------------------------------
<S> <C> <C>
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
=============== ===============
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
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.
</LEGEND>
<CIK> 0000354707
<NAME> Hawaiian Electric Industries, Inc.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 209,430
<SECURITIES> 2,070,881
<RECEIVABLES> 155,306
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 3,237,540
<DEPRECIATION> 1,147,935
<TOTAL-ASSETS> 8,241,648
<CURRENT-LIABILITIES> 0
<BONDS> 978,676
100,000
134,293
<COMMON> 665,275
<OTHER-SE> 170,518
<TOTAL-LIABILITY-AND-EQUITY> 8,241,648
<SALES> 0
<TOTAL-REVENUES> 1,114,385
<CGS> 0
<TOTAL-COSTS> 945,092
<OTHER-EXPENSES> 8,483
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 54,488
<INCOME-PRETAX> 106,322
<INCOME-TAX> 41,180
<INCOME-CONTINUING> 65,142
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 65,142
<EPS-BASIC> 2.02
<EPS-DILUTED> 2.02
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
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.
</LEGEND>
<CIK> 0000046207
<NAME> Hawaiian Electric Company, Inc.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,940,038
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 192,496
<TOTAL-DEFERRED-CHARGES> 14,387
<OTHER-ASSETS> 145,429
<TOTAL-ASSETS> 2,292,350
<COMMON> 85,387
<CAPITAL-SURPLUS-PAID-IN> 295,468
<RETAINED-EARNINGS> 421,840
<TOTAL-COMMON-STOCKHOLDERS-EQ> 802,695
100,000
34,293
<LONG-TERM-DEBT-NET> 645,176
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 103,111
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 607,075
<TOT-CAPITALIZATION-AND-LIAB> 2,292,350
<GROSS-OPERATING-REVENUE> 763,408
<INCOME-TAX-EXPENSE> 36,208
<OTHER-OPERATING-EXPENSES> 634,981
<TOTAL-OPERATING-EXPENSES> 671,189
<OPERATING-INCOME-LOSS> 92,219
<OTHER-INCOME-NET> 6,572
<INCOME-BEFORE-INTEREST-EXPEN> 98,791
<TOTAL-INTEREST-EXPENSE> 41,263
<NET-INCOME> 57,528
908
<EARNINGS-AVAILABLE-FOR-COMM> 56,620
<COMMON-STOCK-DIVIDENDS> 40,616
<TOTAL-INTEREST-ON-BONDS> 40,621
<CASH-FLOW-OPERATIONS> 144,964
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
