<PAGE>
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report: April 30, 1996
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<TABLE>
<CAPTION>
Exact Name of Registrant Commission I.R.S. Employer
as Specified in Its Charter File Number Identification No.
- --------------------------- ----------- ------------------
<S> <C> <C>
Hawaiian Electric Industries, Inc. 1-8503 99-0208097
Hawaiian Electric Company, Inc. 1-4955 99-0040500
</TABLE>
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State of Hawaii
----------------------------------------------
(State or other jurisdiction of incorporation)
900 Richards Street, Honolulu, Hawaii 96813
----------------------------------------------------------------
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code:
(808) 543-5662 - Hawaiian Electric Industries, Inc.
(808) 543-7771 - Hawaiian Electric Company, Inc.
None
--------------------------------------------------------------
(Former name or former address, if changed since last report.)
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<PAGE>
ITEM 5. OTHER EVENTS
On April 30, 1996, a preliminary official statement was prepared and circulated
in connection with a proposed offering by the Department of Budget and Finance
of the State of Hawaii of Special Purpose Revenue Bonds for the benefit of
Hawaiian Electric Company, Inc. ("HECO") and its subsidiaries, Maui Electric
Company, Limited ("MECO") and Hawaii Electric Light Company, Inc. ("HELCO") (the
"Subsidiaries" and, collectively with HECO, the "Companies"). The following is
certain of the information contained in the preliminary official statement
concerning the company.
<PAGE>
SELECTED CONSOLIDATED FINANCIAL INFORMATION OF
HAWAIIAN ELECTRIC COMPANY, INC. AND SUBSIDIARIES
(DOLLARS IN THOUSANDS, EXCEPT PER BARREL AMOUNTS)
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
----------------------------------------------- -----------------
1991 1992 1993 1994 1995 1995 1996
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues...... $739,636 $776,929 $874,010 $907,308 $981,990 $231,176 $245,944
-------- -------- -------- -------- -------- -------- --------
Fuel Oil................ 275,806 225,611 213,285 186,717 207,001 48,477 53,622
Purchased Power......... 106,660 172,761 258,723 271,636 276,364 63,853 67,807
Other Operating
Expenses............... 281,243 301,518 323,917 361,643 395,903 95,640 99,820
-------- -------- -------- -------- -------- -------- --------
Total Operating
Expenses............... 663,709 699,890 795,925 819,996 879,268 207,970 221,249
-------- -------- -------- -------- -------- -------- --------
Operating Income........ $ 75,927 $ 77,039 $ 78,085 $ 87,312 $102,722 $ 23,206 $ 24,695
======== ======== ======== ======== ======== ======== ========
Allowance for Equity
Funds Used During
Construction........... $ 3,998 $ 6,781 $ 6,973 $ 9,064 $ 10,202 $ 2,367 $ 2,651
Income Before Interest
and Other Charges (1).. $ 80,438 $ 86,779 $ 89,641 $102,105 $119,047 $ 26,810 $ 29,197
Allowance for Borrowed
Funds Used During
Construction........... $ 1,307 $ 2,095 $ 3,869 $ 4,043 $ 5,112 $ 1,167 $ 1,350
Income Before Preferred
Stock Dividends of
HECO (2)............... $ 46,210 $ 53,678 $ 56,126 $ 65,961 $ 77,023 $ 16,839 $ 18,512
Ratio of Earnings to
Fixed Charges (3)...... 2.82 3.03 3.25 3.47 3.46 3.27 3.32
Average Fuel Oil Cost
Per Barrel............. $ 22.79 $ 19.69 $ 21.09 $ 18.92 $ 20.47 $ 19.82 $ 22.50
Kilowatthour Sales
(Millions)............. 8,090(4) 8,332 8,325 8,593 8,806 2,051 2,109
</TABLE>
- --------
(1) Income Before Interest and Other Charges includes Operating Income plus the
Allowance for Equity Funds Used During Construction and nonoperating
income.
(2) Income Before Preferred Stock Dividends of HECO includes Income Before
Interest and Other Charges, less interest (excluding Allowance for Borrowed
Funds Used During Construction), amortization of net bond premium and
expense and preferred stock dividends of the Subsidiaries.
(3) In computing the Ratio of Earnings to Fixed Charges, earnings represent
Income Before Preferred Stock Dividends of HECO (excluding the Allowance
for Borrowed Funds Used During Construction) plus federal and state income
taxes and fixed charges. Fixed charges consist of interest on all
indebtedness (without reduction for the Allowance for Borrowed Funds Used
During Construction) plus amortization of net bond premium and expense,
pre-tax preferred stock dividend requirements of MECO and HELCO, and the
estimated interest component of rentals.
(4) Excludes the effect of a change in the method of estimating unbilled
kilowatthour sales and revenues.
<PAGE>
CERTAIN FACTORS AFFECTING HISTORICAL FINANCIAL RESULTS
Year to year changes in operating revenues have resulted primarily from
changes in kilowatthour sales, changes in fuel oil prices and general rate
increases approved by the Hawaii Public Utilities Commission (the "PUC").
Following is a summary of changes in the principal factors contributing to
changes in operating revenues for the five-year period ending December 31,
1995.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1991 1992 1993 1994 1995
---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C>
Kilowatthour Sales Growth (Decline) (%)......... 1.5* 3.0* (0.1) 3.2 2.5
Increase/(Decrease) in Average Fuel Oil Cost Per
Barrel (%)..................................... (8.2) (13.6) 7.1 (10.3) 8.2
Approximate Change in Operating Revenues due to
General Rate Increases ($ in millions)......... 33.2 77.2 78.7 34.6 39.6
</TABLE>
- --------
* Excludes the effect of a change in the method of estimating unbilled
kilowatthour sales and revenues.
The rate schedules of the Companies each contain an energy cost adjustment
clause whereby the charges for electric energy vary automatically with changes
in the weighted average price paid for fuel oil and certain components of
purchased energy costs and the relative amounts of company-generated energy and
purchased energy. Under these clauses, the cost increases or savings due to
changes in fuel oil prices and certain components of purchased energy costs are
automatically passed through to customers.
Changes in fuel oil expenses for the Companies have resulted primarily from
changes in kilowatthour sales, fuel oil prices and the level of power
generation. Fuel oil is purchased under contracts at prices tied to market
prices for petroleum products as reported in Singapore, Los Angeles and the
U.S. Pacific Northwest. Increases in purchased power in recent years have
significantly affected the levels of power generation by HECO. At December 31,
1995, HECO and its subsidiaries had power purchase agreements for 469 megawatts
("MW") of firm capacity, representing 22% of their total generating
capabilities and purchased power firm capacities. HECO's three major power
purchase agreements represent 406 MW of this total, with 180 MW of this
capacity having commenced operations in May 1991 under an agreement with
Kalaeloa Partners, L.P. and another 180 MW having commenced operations in
September 1992 under an agreement with AES Barbers Point, Inc. At December 31,
1995, HELCO had two power purchase agreements for a total of 47 MW of firm
capacity, and MECO had one power purchase agreement for 16 MW of firm capacity,
representing 23% and 7% of their respective total generating capabilities and
purchased power firm capacities.
In general, payments under the power purchase agreements for 469 MW of firm
capacity are based upon available capacity and energy. Payments for capacity
generally are not required if the contracted capacity is not available, and
payments are reduced, under certain conditions, if available capacity drops
below contracted levels. In general, the payment rates for capacity have been
predetermined for the terms of the agreements. The energy payment will vary
over the terms of the agreements and changes in the fuel component of the
energy charges may be passed on to customers through energy cost adjustment
clauses. The Companies do not operate or participate in the operation of any of
the facilities that provide power under these agreements. Title to the
facilities does not pass to the Companies upon expiration of the agreements,
and the agreements do not contain bargain purchase options with respect to the
facilities.
<PAGE>
CONSOLIDATED CAPITALIZATION
The following table summarizes HECO's consolidated capitalization as of March
31, 1996 (and as adjusted).
<TABLE>
<CAPTION>
ACTUAL AS ADJUSTED (2)
------------------------------ ------------------------------
(% OF TOTAL (% OF TOTAL
(IN THOUSANDS) CAPITALIZATION) (IN THOUSANDS) CAPITALIZATION)
-------------- --------------- ------------- ---------------
<S> <C> <C> <C> <C>
Short-Term Debt
(including borrowings
from parent)........... $ 157,010 10.7 $ 82,010 5.6
Long-Term Debt
(including $43 million
due within one
year)(1)............... 517,243 35.3 592,243 40.4
Preferred Stock with
Mandatory Redemption
Requirements (including
sinking fund
requirements due within
one year).............. 39,350 2.7 39,350 2.7
Preferred Stock without
Mandatory Redemption
Requirements........... 48,293 3.3 48,293 3.3
Common Stock Equity..... 703,407 48.0 703,407 48.0
---------- ----- ---------- -----
Total Capitalization.. $1,465,303 100.0 $1,465,303 100.0
========== ===== ========== =====
</TABLE>
- --------
(1) The Department of Budget and Finance of the State of Hawaii (the
"Department") was authorized by the Hawaii Legislature in 1994 (the "1994
Legislative Authorization") to issue up to $170 million of Special Purpose
Revenue Bonds and to loan the proceeds to HECO and the Subsidiaries prior
to December 31, 1997. The $75 million of Bonds offered hereby are the first
Bonds issued pursuant to the 1994 Legislative Authorization. Long-Term Debt
will increase from time to time as the proceeds from the sale of the Bonds,
together with undrawn proceeds as of March 31, 1996 of approximately $.9
million from previously-issued revenue bonds, are drawn down.
(2) Includes adjustments to reflect $75 million in estimated drawdowns expected
to be made by June 30, 1996 from the proceeds of the Bonds offered hereby.
CAPITAL EXPENDITURE PROGRAMS AND FINANCING REQUIREMENTS
CAPITAL EXPENDITURE PROGRAMS
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. Capital expenditures requiring the use of cash totaled
approximately $184.7 million in 1995, of which $104.0 million was attributable
to HECO, $35.4 million to HELCO and $45.3 million to MECO. Approximately 68% of
the total 1995 capital expenditures was for transmission and distribution
projects and approximately 32% was for generation and general plant projects.
Cash contributions in aid of construction received in 1995 totaled $10.4
million.
The Companies' current consolidated forecast of capital expenditures,
excluding the allowance for funds used during construction ("AFUDC") and
capital expenditures funded by third-party contributions in aid of
construction, for the five-year period 1996 through 2000, is approximately $747
million. Approximately 62% of forecast gross capital expenditures, including
AFUDC and third-party contributions in aid of construction, is for transmission
and distribution projects, with the remaining 38% primarily for generation
projects. Capital expenditures for 1996, net of cash contributions in aid of
construction and excluding AFUDC, are estimated to be $154 million, and gross
capital expenditures are estimated to be $189 million, of which approximately
58% is for transmission and distribution projects. An estimated $55 million is
planned for new generation projects.
<PAGE>
Capital expenditure estimates and the timing of construction projects are
reviewed periodically by management and may change significantly as a result of
many considerations, including changes in economic conditions, changes in
forecasts of kilowatthour 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 relief, escalations
in construction costs, demand side management programs and requirements of
environmental and other regulatory and permitting authorities.
FINANCING REQUIREMENTS
Total HECO consolidated requirements for funds in the years 1996 through
2000, including net capital expenditures, debt retirements (exclusive of
reductions in levels of short-term borrowings) and sinking fund requirements,
are currently estimated to total $829 million. HECO's consolidated internal
sources, after payment of common stock and preferred stock dividends, are
currently expected to provide approximately $559 million of the $829 million in
total requirements, with additional borrowings (including proceeds from the
Bonds offered hereby) providing approximately $179 million and equity financing
providing the remaining requirements. The 1994 Legislative Authorization
authorizes the Department to issue up to $170 million of Special Purpose
Revenue Bonds, including the Bonds offered hereby, and to loan the proceeds to
the Companies prior to December 31, 1997. The PUC must approve issuances of
long-term debt and equity for HECO, MECO and HELCO.
RECENT DEVELOPMENTS AND PUC PROCEEDINGS
RATE AND OTHER PROCEEDINGS BEFORE THE PUC
The Companies are subject to the regulatory jurisdiction of the PUC with
respect to rates and other matters. The PUC has broad discretion in its
regulation of the rates charged by the Companies and any adverse decision by
the PUC concerning the level or method of determination of utility rates, the
authorized returns on equity or other matters, or any undue delay in rendering
a decision in a rate or other proceeding, could have a material adverse effect
on the financial condition and results of operations of the Companies. Upon a
showing of probable entitlement, the PUC is required to issue an interim
decision 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), but there is no
limitation on the time within which the PUC must render a final decision.
Interim rate increases are subject to refund with interest, pending the final
outcome of the case.
The rate schedules of each of the Companies contain an energy cost adjustment
clause whereby the charges for electric energy vary automatically with changes
in the weighted average price for fuel oil and certain components of purchased
energy costs, and the relative amounts of company-generated energy and
purchased energy. Under Hawaii law and practices, specific and separate PUC
approval is not required for each rate change pursuant to an automatic rate
adjustment clause previously approved by the PUC. However, rate increases,
other than pursuant to such automatic adjustment clauses, and changes in the
provisions of the automatic adjustment clauses, require the prior approval of
the PUC after public and contested case hearings.
The Companies currently have several cases pending before the PUC including,
but not limited to, requests for approval of construction projects, requests by
MECO and HELCO for increases in electric rates, investigations of HECO and
HELCO power outages and reliability, and ongoing dockets relating to the PUC's
requirement that each of the Companies develop and implement integrated
resource plans. Management cannot predict when decisions in pending or future
cases will be rendered or what the final outcomes will be, including the amount
of any interim or final rate increase that may be granted.
<PAGE>
RECENT RATE REQUESTS AND RESULTS
The Companies have requested 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.
HECO. In July 1993, HECO filed a request to increase rates based on a 1994
test year. HECO requested an 8.6% increase (as revised) over rates in effect at
the time of the revision, or $53.8 million in annual revenues, based on a
12.75% return on average common equity ("ROACE"). In December 1994, HECO
received a final decision and order authorizing an increase of 6.5%, or $40.5
million in annual revenues, effective January 1, 1995 and based on a 12.15%
ROACE. The final decision and order, together with the decision in a separate
proceeding involving postretirement benefits other than pensions, resulted in
an increase of $50.5 million in annual revenues.
In December 1993, HECO filed a request to increase rates based on a 1995 test
year. HECO requested an increase of 4.1% (as revised), or $28.2 million in
annual revenues, based on a 13.25% ROACE. In December 1995, HECO received a
final decision and order authorizing an increase of 1.3%, or $9.1 million in
annual revenues, based on an 11.4% ROACE. The decision and order required a
refund to customers because HECO had previously received four interim increases
totaling $18.9 million on an annualized basis, or $9.8 million more than the
amount that was finally approved. The reduced rate relief resulted primarily
from the lower ROACE used by the PUC in the final decision and order largely
because of decreases in interest rates subsequent to the first interim
increase, which was effective January 1, 1995 and was based on a 12.6% ROACE.
The refund amount of $10.2 million (representing amounts received under interim
rates in excess of final approved rates, with interest thereon), of which $10
million was accrued in December 1995, is being returned to customers in the
first half of 1996.
MECO. In November 1991, MECO filed a request to increase rates. In January
1993, MECO revised its requested increase to 10%, or $11.4 million in annual
revenue, based on a 13.0% ROACE and a 1993 test year. In August 1994, MECO
received a final decision and order authorizing an increase of 7.0%, or
$8.1 million in annual revenues, based on a 12.75% ROACE. The final decision
and order, together with the decision in the separate proceeding involving
postretirement benefits other than pensions, resulted in $10 million of annual
rate relief.
In February 1995, MECO filed a request to increase rates based on a 1996 test
year. MECO's final requested increase was 3.8%, or $5.0 million in annual
revenues, based on an 11.5% ROACE. In January 1996, MECO received an interim
decision and order authorizing an increase of 2.8%, or $3.7 million in annual
revenues, based on an 11.5% ROACE, effective February 1, 1996. In February
1996, MECO filed a notice of intent with the PUC to seek increased rates, based
on a 1997 test year.
HELCO. In November 1993, HELCO filed a request to increase rates by 13.4%, or
$15.8 million in annual revenues, based on a 1994 test year and a 12.4% ROACE
(which was later increased to 13.1%). In February 1995, HELCO received a final
decision and order authorizing an increase of 11.8%, or $13.7 million in annual
revenues, based on a 12.6% ROACE. The final decision and order, together with
the decision in the separate proceeding involving postretirement benefits other
than pensions, resulted in $15.5 million of annual rate relief.
In March 1995, HELCO filed a request to increase rates based on a 1996 test
year. In February 1996, HELCO revised its requested increase to 6.2%, or $8.9
million in annual revenues, based on a 12.5% ROACE. In March 1996, HELCO
received an interim decision and order authorizing an increase of 4.8%, or $6.8
million in annual revenues, based on an 11.65% ROACE, effective March 4, 1996.
HELCO is considering filing a request to increase rates, based on a 1997 test
year.
<PAGE>
ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Companies provide various postretirement benefits other than pensions to
eligible employees upon their retirement, including health and life insurance
benefits. Health benefits are provided with contributions by retirees toward
costs based on their years of service and retirement date. Employees are
eligible for these benefits if, upon retirement, they participate in one of the
Companies' defined benefit pension plans. The Companies began funding some of
these benefits in December 1994.
In February 1992, the PUC opened a generic docket to determine whether
Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," should be adopted
for rate-making purposes. Effective January 1, 1993, the Company adopted the
provisions of SFAS No. 106. In November 1994, the PUC issued a decision and
order authorizing recovery of the full cost of postretirement benefits other
than pensions effective January 1, 1995. The Companies were required to fund
the recovered SFAS No. 106 costs. The regulatory asset established from January
1, 1993 through December 31, 1994 for postretirement benefits other than
pensions is being amortized ratably over 18 years beginning in 1995 for rate-
making and financial reporting purposes. In December 1995, the PUC issued a
decision and order in a HECO rate case proceeding which did not provide revenue
to cover HECO's costs relating to postretirement executive life insurance and
the Companies wrote-off the regulatory asset relating to such costs, resulting
in a 1995 after-tax charge of $1.1 million.
The transition obligation (the accumulated postretirement benefit obligation
at January 1, 1993 of approximately $125.3 million) is being amortized ratably
over 20 years beginning in 1993.
PROPERTY DAMAGE RESERVE
In March 1995, the PUC opened a generic docket to investigate whether the
public utilities in the State of Hawaii should be allowed to establish property
damage reserves to cover the cost of damage to their facilities and equipment
caused by catastrophic disasters. The Companies' overhead transmission and
distribution systems are susceptible to wind and earthquake damage, and their
underground systems are susceptible to earthquake and flood damage. The
overhead and underground transmission and distribution systems (with the
exception of substation buildings and contents) have a replacement value
roughly estimated at approximately $2 billion and are uninsured because the
amount of transmission and distribution system insurance available is limited
and the premiums are extremely high. Hearings in this docket are scheduled for
September 1996.
HELCO POWER SITUATION
In 1991, HELCO identified the need for additional generation beginning in
1994 to provide for forecasted 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. In the same year, the PUC issued an order calling for an
investigation of the reliability of HELCO's system following service
interruptions and rolling blackouts instituted on the island of Hawaii. HELCO
added firm capacity to its system in August 1992 (a 20-MW HELCO-owned unit) and
in June 1993 (pursuant to a power purchase agreement for 25 MW of firm
capacity). HELCO also proceeded with plans to install at its Keahole power
plant site two 20-MW combustion turbines ("CT-4" and "CT-5"), followed by an
18-MW heat steam recovery generator ("ST-7"), at which time these units would
be converted to a 56-MW (net) combined-cycle unit. In January 1994, the PUC
approved expenditures for CT-4, which HELCO had planned to install in late
1994, and in September 1995, the PUC conditionally approved expenditures for
CT-5 and ST-7.
Despite HELCO's best efforts to install the necessary additional generation,
the schedule for the installation of HELCO's phased combined-cycle unit at
HELCO's Keahole power plant site was revised due to delays in obtaining
approval of the air quality Prevention of Significant Deterioration/Covered
Source Permit ("PSD") and the Conservation District Use Permit amendment
("CDUP") for the Keahole power plant site.
<PAGE>
In late 1995, a contested case hearing with respect to the CDUP was conducted
and the hearing officer recommended denial of the CDUP application. On April
22, 1996, the Hawaii Board of Land and Natural Resources ("BLNR") issued a
written order in which it stated that it had voted 3 in favor and 2 against a
motion to accept the hearing officer's recommendation and stating that HELCO's
CDUP application was denied. The order stated that the BLNR does not intend to
deliberate further or vote again on the matter. HELCO's position is that denial
of the CDUP application requires the favorable vote of at least 4 members of
the BLNR, that the BLNR's order of April 22, 1996 thus does not operate to deny
the application and that the failure of the BLNR to take effective action
results in HELCO being entitled to its CDUP by operation of law. HELCO
currently intends to vindicate its position through judicial review of the
BLNR's order or other appropriate proceedings. These proceedings may delay, if
not prevent, installation of HELCO's project at the 15-acre Keahole site.
The Hawaii Department of Health ("DOH") forwarded HELCO's PSD permit to the
Environmental Protection Agency ("EPA") for its approval. In a November 1995
letter to the DOH, the EPA declined to sign HELCO's PSD permit. HELCO requested
that the EPA reconsider this decision and the EPA agreed to reconsider based on
additional information supplied by HELCO. In a second letter dated February 6,
1996, the EPA set forth information to be considered by HELCO, and HELCO
responded to the EPA's positions by letter dated March 8, 1996. By letter dated
April 8, the EPA restated its determinations and indicated that further
documentation is required from HELCO in order for the EPA to consider HELCO's
positions. Information exchange and discussions with the EPA and the DOH are
ongoing. If the EPA does not sign a permit forwarded by the DOH, this would
delay, if not prevent, HELCO's project.
Two independent power producers ("IPPs"), Kawaihae Cogeneration Partners
("KCP") and Enserch Development Corporation ("Enserch"), filed separate
complaints against HELCO with the PUC, alleging that they are entitled to power
purchase contracts to provide HELCO with additional capacity which, under
HELCO's current estimates of generating capacity requirements, would be in
place of HELCO's planned 56-MW combined-cycle unit at Keahole. In July 1995,
the PUC issued a decision and order in the docket involving KCP. In the order,
the PUC stated its position on various issues affecting HELCO's avoided cost
calculations (several of which were contrary to HELCO's recommendations). In
September 1995, HELCO provided proposals to the two IPPs, and further
negotiations were undertaken. Status reports on the negotiations with the two
IPPs were filed with the PUC at the end of September and October 1995.
In September 1995, the PUC allowed HELCO to continue to pursue construction
of and commit expenditures for the second combustion turbine and the steam
recovery generator for its planned combined-cycle unit, stating 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." In view of permitting delays and the need for power, the PUC also
ordered HELCO to continue negotiating with the IPPs and directed that the
facility to be built should be the one that can be most expeditiously put into
service at "allowable cost."
On January 26, 1996, the PUC ordered that the KCP docket be reopened and that
HELCO and KCP continue in good faith to negotiate a power purchase agreement,
file a list of unresolved issues requiring PUC guidance and meet with the PUC
on March 27, 1996. Status reports were filed during March and the meeting was
held as scheduled. On March 20, 1996, the PUC ordered that HELCO and Enserch
file status reports with the PUC and, if requested by either party on or before
April 15, 1996, hold a hearing on April 25, 1996. Status reports were filed by
Enserch and HELCO during April and the hearing was held as scheduled.
Additional written submissions may be made to the PUC by the parties in the
Enserch docket by May 21, 1996. The PUC may provide guidance to the IPPs and
HELCO concerning certain issues as their negotiations continue.
If HELCO's negotiations with the IPPs result in a power purchase agreement
and/or if HELCO's combined-cycle unit is not installed, HELCO may be required
to write off a portion of the costs incurred in
<PAGE>
its efforts to put into service its combined-cycle unit ($44.7 million as of
March 31, 1996) if such costs ultimately are not recoverable from customers or
others. The $44.7 million includes approximately $26.7 million for equipment
purchases, approximately $9.4 million for planning, engineering, permitting,
site development and other costs and approximately $8.6 million as an allowance
for funds used during construction. Management cannot determine at this time
whether the negotiations with the IPPs will result in a power purchase
agreement, or whether HELCO's combined cycle unit will be installed, or the
amount of incurred costs, if any, that may not be recoverable from customers or
others.
In June 1995, HELCO filed with the PUC its generation resource contingency
plan detailing alternatives and mitigation measures to address possible further
delays in obtaining the permits necessary to construct its combined-cycle unit.
HELCO has arranged for additional firm capacity to be provided by its existing
firm power producers, obtained contracts shifting loads to off-peak hours,
begun implementing in January 1996 its energy-efficiency demand-side management
programs based on interim PUC approval and deferred generation unit
retirements. These measures have helped HELCO maintain its reserve margin and
reduce the risk of capacity shortages. HELCO is also proposing installation of
up to 6 MW of dispersed diesel generation units that could provide power by
late 1996. In January 1996, the PUC opened a generic docket relating to HELCO's
contingency plan. Pursuant to the PUC order, HELCO submitted updated
information to the PUC on March 18, 1996.
<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)
/s/ Curtis Y. Harada /s/ Paul Oyer
- ---------------------------------- -------------------------------------
Curtis Y. Harada Paul A. Oyer
Controller of HEI Financial Vice President,
(Principal Accounting Officer of HEI) Treasurer and Director of HECO
(Principal Financial Officer of HECO)
Date: April 30, 1996 Date: April 30, 1996
