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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

OR

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x  No ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨  No x

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Proxy Statement of Hawaiian Electric Industries, Inc. for the 2005 Annual Meeting of Shareholders to be filed—Part III

This combined Form 10-K represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. Neither registrant makes any representations as to the information relating to the other registrant.

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GLOSSARY OF TERMS

Defined below are certain terms used in this report:

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GLOSSARY OF TERMS (continued)

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GLOSSARY OF TERMS (continued)

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GLOSSARY OF TERMS (continued)

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Cautionary Statements and Risk Factors that May Affect Future Results

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance (including future revenues, expenses, earnings or losses or growth rates), ongoing business strategies or prospects and possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those in forward-looking statements and from historical results include, but are not limited to, the following:

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I

HEI

HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in the electric utility, banking and other businesses operating primarily in the State of Hawaii. HEI’s predecessor, HECO, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result of a 1983 corporate reorganization, HECO became an HEI subsidiary and common shareholders of HECO became common shareholders of HEI.

HECO and its operating subsidiaries, Maui Electric Company, Limited (MECO) and Hawaii Electric Light Company, Inc. (HELCO), are regulated electric public utilities providing the only electric public utility service on the islands of Oahu, Maui, Lanai, Molokai and Hawaii, which islands collectively include approximately 93% of Hawaii’s electric public utility market. HECO also owns all the common securities of HECO Capital Trust III (Delaware statutory trust), which was formed to effect the issuance of $50 million of cumulative quarterly income preferred securities in 2004, for the benefit of HECO, MECO and HELCO. In December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects.

Besides HECO and its subsidiaries, HEI also owns directly or indirectly the following subsidiaries: HEI Diversified, Inc. (HEIDI) (a holding company) and its subsidiary, ASB, and the subsidiaries of ASB; Pacific Energy Conservation Services, Inc. (PECS); HEI Properties, Inc. (HEIPI); Hycap Management, Inc. (in dissolution); Hawaiian Electric Industries Capital Trusts II and III (formed in 1997 to be available for trust securities financings); The Old Oahu Tug Service, Inc. (TOOTS); and HEI Power Corp. (HEIPC) and its subsidiaries (discontinued operations).

ASB, acquired in 1988, was the third largest financial institution in the State of Hawaii based on total assets and had 66 branches as of December 31, 2004. ASB has subsidiaries involved in the sale and distribution of insurance products and an inactive advertising agency for ASB and its subsidiaries and a subsidiary, ASB Realty Corporation, which elected to be taxed as a real estate investment trust (see Note 10 to HEI’s Consolidated Financial Statements under “ASB state franchise tax dispute and settlement”).

HEIDI was also the parent company of HEIDI Real Estate Corp., which was formed in February 1998. In September 1999, HEIDI Real Estate Corp.’s name was changed to HEIPI, and HEIDI transferred ownership of HEIPI to HEI. At December 31, 2004, HEIPI’s venture capital investments had a carrying value of $1.5 million.

PECS was formed in 1994 and currently is a contract services company providing limited support services in Hawaii.

ProVision Technologies, Inc., formed in October 1998 to sell, install, operate and maintain on-site power generation equipment and auxiliary appliances in Hawaii and the Pacific Rim, was sold in July 2003. HEI Leasing, Inc. was formed in February 2000 to own passive investments and real estate subject to leases, but was never active and was dissolved in October 2003. Hycap Management, Inc., including its former subsidiary HEI Preferred Funding, LP (a limited partnership in which Hycap Management, Inc. was the sole general partner), and Hawaiian Electric Industries Capital Trust I (a Delaware statutory trust in which HEI owned all the common securities) were formed to effect the issuance of $100 million of 8.36% HEI-obligated trust preferred securities in 1997, which securities were redeemed in April 2004. Hawaiian Electric Industries Capital Trust I and HEI Preferred Funding, LP were dissolved and terminated in 2004, and Hycap Management, Inc. began dissolution in 2004 for a period of three years and then will terminate. HEI District Cooling, Inc. was formed in August 1998 to develop, build, own, lease, operate and/or maintain, either directly or indirectly, central chilled water cooling system facilities, and other energy related products and services for commercial and residential buildings, but was dissolved in October 2003.

In November 1999, Hawaiian Tug & Barge Corp. (HTB) sold substantially all of its operating assets and the stock of YB for a nominal gain, changed its name to TOOTS and ceased maritime freight transportation operations. TOOTS currently administers certain employee and retiree-related benefits programs and monitors matters related its former operations and the operations of its former subsidiary.

For information about the Company’s discontinued operations, see Note 14 to HEI’s Consolidated Financial Statements.

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For financial information about the Company’s industry segments, see Note 2 to HEI’s Consolidated Financial Statements.

For additional information about the Company, see HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements.

The Company’s website address is www.hei.com. The information on the Company’s website is not incorporated by reference in this annual report on Form 10-K unless specifically incorporated herein by reference. HEI and HECO currently make available free of charge through this website, www.hei.com, their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC.

Electric utility

HECO and subsidiaries and service areas

HECO, MECO and HELCO are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Maui, Lanai and Molokai; and Hawaii, respectively. HECO was incorporated under the laws of the Kingdom of Hawaii (now State of Hawaii) in 1891. HECO acquired MECO in 1968 and HELCO in 1970. In 2004, the electric utilities’ revenues and net income from continuing operations amounted to approximately 81% and 75%, respectively, of HEI’s consolidated amounts, compared to approximately 78% and 67% in 2003 and approximately 76% and 76% in 2002, respectively.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population currently estimated at 1,202,000, or approximately 95% of the population of the State of Hawaii, and comprise a service area of 5,766 square miles. The principal communities served include Honolulu (on Oahu), Wailuku and Kahului (on Maui) and Hilo and Kona (on Hawaii). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural operations.

The state has granted HECO, MECO and HELCO nonexclusive franchises, which authorize the utilities to construct, operate and maintain facilities over and under public streets and sidewalks. HECO’s franchise covers the City & County of Honolulu, MECO’s franchises cover the County of Maui and the County of Kalawao, and HELCO’s franchise covers the County of Hawaii. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.

For additional information about HECO, see HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements and HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements.

Sales of electricity

HECO, MECO and HELCO provide the only electric public utility service on the islands they serve. The following table sets forth the number of electric customer accounts as of December 31, 2004, 2003 and 2002 and electric sales revenues by company for each of the years then ended:

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Revenues from the sale of electricity in 2004 were from the following types of customers in the proportions shown:

KWH sales of HECO and its subsidiaries follow a seasonal pattern, but they do not experience the extreme seasonal variation like some electric utilities on the mainland. The seasonal variation in sales is largely the result of corresponding mild variations in weather. Sales tend to increase in the warmer summer months, probably as a result of increased demand for air conditioning and refrigeration. However, the weather in Hawaii is generally temperate, and Hawaii does not experience the wide range of fluctuations in temperature and humidity seen in the hot summers and cold winters in some parts of the mainland.

HECO and its subsidiaries derived approximately 10%, 10% and 9% of their operating revenues from the sale of electricity to various federal government agencies in 2004, 2003 and 2002, respectively.

Formerly one of HECO’s larger customers, the Naval Base at Barbers Point, Oahu, closed in 1999 with redevelopment of the base to occur through 2020. Considering (1) that the base closure necessitated relocation of essential flight operations and support personnel to another base on Oahu and (2) the Naval Air Station Barbers Point Community Redevelopment Plan will increase development of the area, HECO continues to expect that the closure is likely to result in an overall increase in demand for electricity over time.

In 1995, HECO and the U.S. General Services Administration (GSA) entered into a Basic Ordering Agreement (GSA-BOA) under which HECO would arrange for the financing and installation of energy conservation projects at federal facilities in Hawaii. In 1996, HECO signed an umbrella Basic Ordering Agreement with the Department of Defense (DOD-BOA) and in 2001, a new DOD-BOA was signed. Under these and other agreements, HECO has completed energy conservation and other projects for federal agencies over the years.

Executive Order 13123, adopted in 1994, mandates that each federal agency develop and implement a program to reduce energy consumption by 35% by the year 2010 to the extent that these measures are cost effective. The 35% reduction will be measured relative to the agency’s 1985 energy use. HECO continues to work with various federal agencies to implement demand-side management (DSM) programs that will help them achieve their energy reduction objectives. Neither HEI nor HECO management can predict with certainty the impact of Executive Order 13123 on HEI’s or HECO’s future financial condition, results of operations or liquidity.

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Selected consolidated electric utility operating statistics

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Generation statistics

The following table contains certain generation statistics as of December 31, 2004 and for the year ended December 31, 2004. The capability available for operation at any given time may be more or less than the generating capability shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.

Generating reliability

HECO, HELCO and MECO have isolated electrical systems that are not interconnected to each other or to any other electrical grid. HECO serves the island of Oahu and HELCO serves the island of Hawaii. MECO has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai.

Because each island system cannot rely upon backup generation from neighboring utilities, HECO, HELCO and MECO each maintain a higher level of reserve generation than is typically carried by interconnected mainland utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak electric demands, to provide for scheduled maintenance of generating units (including the units operated by independent power producers (IPPs) relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system. Although the planning for, and installation of, adequate levels of reserve generation have contributed to the achievement of generally high levels of system reliability, service interruptions do occur from time to time as a result of unforeseen circumstances. For example, HECO implemented load shedding and temporarily shut off power to a significant number of customers on one occasion in 2002, due to unplanned generating unit outages. Load shedding is a predetermined plan that prevents overloading and possible major damage to generating units and potentially a much larger power outage.

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Prior to two new generating units becoming operational at its Keahole power plant in 2004, HELCO’s management was concerned about the possibility of power interruptions as a result of the operating status of various IPPs supplying power to it and the condition and performance of aging generators on the HELCO system. (See discussion in Note 11 to HECO’s Consolidated Financial Statements). A significant number of HELCO’s customers experienced rolling blackouts on two occasions in 2002 due to unplanned generating unit outages.

Integrated resource planning and requirements for additional generating capacity

As a result of a proceeding initiated in 1990, the Public Utilities Commission of the State of Hawaii (PUC) issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs). The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. In its 1992 order, the PUC adopted a “framework,” which established both the process and the guidelines for developing IRPs. The PUC’s framework directs that each plan cover a 20-year planning horizon with a five-year program implementation schedule and states that the planning cycle will be repeated every three years. Under the framework, the PUC may approve, reject or require modifications of the utilities’ IRPs.

The framework also states that utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of planning and implementing DSM programs. Under appropriate circumstances, the utilities have been allowed in the past to recover lost margins resulting from DSM programs and earn shareholder incentives. The PUC has approved IRP cost recovery provisions for HECO, MECO and HELCO. Pursuant to the cost recovery provisions, the electric utilities have been allowed to recover through a surcharge the costs for approved DSM programs (including DSM program lost margins and shareholder incentives), and other incremental IRP costs incurred by the utilities and approved by the PUC, to the extent the costs are not included in their base rates.

In October 2001, HECO and the Consumer Advocate finalized agreements, which were approved by the PUC in November 2001, under which HECO’s energy efficiency programs (three commercial and industrial DSM programs and two residential DSM programs) would be continued until a decision is reached in HECO’s next rate case (filed in November 2004). Under the agreements, HECO will cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current authorized return on rate base. HECO also agreed it will not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. Consistent with the HECO agreements, in October 2001, MECO and HELCO reached agreements with the Consumer Advocate and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, allowed MECO and HELCO to continue temporarily their respective four existing energy efficiency DSM programs. See “Other regulatory matters—Demand-side management programs—agreements with the Consumer Advocate” in HEI’s MD&A, which also includes a discussion of HECO’s residential and commercial and industrial load management programs.

In August 2000, pursuant to a stipulation filed by the electric utilities and the parties in the IRP cost proceedings, the PUC issued an order allowing the electric utilities to begin recovering the 1995 through 1999 incremental IRP costs, subject to refund with interest, pending the PUC’s final decision and order (D&O) approving recovery of each respective year’s incremental IRP costs. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2003 IRP costs, such that the electric utilities can begin recovering incremental IRP costs in the month after the filing of the actual costs incurred for the year, subject to refund with interest, pending the PUC’s final D&O approving recovery of the costs. The Consumer Advocate has objected to the recovery of $2.9 million (before interest) of the $11.0 million of incremental IRP costs incurred during the 1995-2003 period, and the PUC’s decision is pending on this matter.

The electric utilities have completed the recovery of their respective 1995 through 2002 incremental IRP costs through a surcharge on customer bills, subject to refund with interest. In addition, HECO completed the recovery of its 2003 incremental IRP costs in June 2004, subject to refund with interest. MECO is scheduled to complete the recovery of its 2003 incremental IRP costs by May 2005. As of December 31, 2004, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $17 million. HECO and MECO expect to begin recovering their incremental

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2004 IRP costs, subject to refund with interest pending a final D&O, following the filing of actual 2004 costs (which is expected to occur in late March or early April 2005).

In early 2001, the PUC issued its final D&O in the HELCO 2000 test year rate case, in which the PUC concluded that it is appropriate for HELCO to recover its IRP costs through base rates (and included an estimated amount for such costs in HELCO’s test year revenue requirements) and to discontinue recovery of incremental IRP costs through the separate surcharge. HELCO recovered its incremental IRP costs incurred in 2000, which were incurred prior to the final D&O in its rate case, through its surcharge. HELCO’s IRP costs incurred for 2001 and future years are recovered through HELCO’s base rates. HELCO will continue to recover its DSM program costs, lost margins and shareholder incentives approved by the PUC in a separate surcharge.

The utilities have characterized their proposed IRPs as planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed, in which the PUC further reviews the details of the proposed programs and the utilities’ proposals for the recovery of DSM program expenditures, lost margins and shareholder incentives.

HECO’s IRP. HECO filed its second IRP with the PUC in January 1998 and updated the status of its DSM and Supply Side Action Plans in July 1999. In January 2001, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding and the PUC approved the stipulation, closed the docket and ordered HECO to submit its IRP annual evaluation report and program implementation schedule by October 2002 (subsequently extended to December 2002) and its next (third) IRP by October 2005, as stipulated. The PUC also ordered HECO to immediately notify it in writing if HECO requires additional generation prior to the 2009 time frame.

In December 2002, HECO filed with the PUC its IRP evaluation report, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

On the supply side, HECO’s updated second IRP focused on the planning for the next generating unit addition in the 2009 time frame—a 107 MW simple-cycle combustion turbine. The updated second IRP also includes plans to add a second 107 MW simple-cycle combustion turbine in 2015, and in 2016, a conversion unit 105 MW steam turbine to create a dual-train combined-cycle unit. However, the report notes there is flexibility to allow HECO to defer the need for the second and third generating units should alternative generation technologies advance to the point they are economically and technically feasible substitutes for conventional generation. In addition, pursuant to HECO’s generation asset management program, all existing generating units are currently planned to be operated (future environmental considerations permitting) beyond the 20-year IRP planning period (1998-2017).

On the demand side, in November 2001, the PUC issued two D&Os allowing HECO to temporarily continue its five energy efficiency DSM programs until its next rate case. The five energy efficiency DSM programs are designed to reduce the rate of increase in Oahu’s energy use, defer construction of new generating units, minimize the state’s use of oil, and achieve savings for utility customers who participate in the programs. The energy efficiency DSM programs include incentives for customers to install efficient lighting, refrigeration, water-heating and air-conditioning equipment and industrial motors. HECO’s updated second IRP includes two DSM load management programs (i.e., a Residential Direct Load Control Program and a Commercial and Industrial Direct Load Control Program). HECO filed applications with the PUC requesting approval of these two load management programs in June and December 2003, respectively. In October 2004, the PUC approved HECO’s two programs and implementation of the programs began in early 2005.

In September 2003, the PUC opened a docket to commence HECO’s third IRP, which HECO was ordered by the PUC to file by October 2005. HECO expects its third IRP will propose multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as combined heat and power (CHP)) and central station generation. Given the lead times needed for permitting and regulatory approvals, in October 2003 HECO submitted a covered source permit application with the DOH for a simple cycle combustion turbine sized in the 100 MW range in Campbell Industrial Park on Oahu, which could be added as a peaking unit in the event new central generation was required in 2009, as was indicated in HECO’s second IRP. The application specifies that the unit would use diesel fuel oil or naphtha, with ability to convert to a bio-fuel, like ethanol, when it becomes commercially available. This application was subsequently amended, in part

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to include the possibility that a second simple-cycle combustion turbine may be needed sooner than projected (for example, if energy efficiency and load management DSM, CHP and renewable energy program impacts are not fully realized, or if system demand increases more than projected).

In June 2004, HECO conducted an updated 5-year sales and peak forecast for Oahu that projects increased system peak requirements based on the island’s strengthening economy. Based on this forecast, HECO supplied information to the PUC in its 2005 annual Adequacy of Supply letter. This letter concluded that HECO’s generation capacity for Oahu for the next three years (2005-2007) is sufficiently large to meet all reasonably expected demands for service if HECO is able to acquire the forecast peak reduction benefits of its energy efficiency and load management DSM programs and there is expeditious review and approval of its proposed enhanced energy efficiency DSM programs, and either the CHP program currently pending before the PUC or individual CHP contracts submitted to the PUC.

New larger energy efficiency DSM programs were developed during the on-going IRP process and, pursuant to the DSM stipulation, approval for the enhanced DSM programs has been requested in HECO’s pending rate increase application, which was filed in November 2004 (although HECO also plans to seek approval on a more accelerated basis if possible). On the supply-side, CHP system installations are behind schedule, due to suspension of the CHP program application and individual CHP contract applications pending action in the generic DG docket. Also on the supply-side, HECO and Kalaeloa executed amendments to the Kalaeloa PPA, subject to certain conditions including PUC approval, under which Kalaeloa would provide up to 29 MW of additional firm capacity (see FIN 46R discussion in Note 1 to HECO’s Consolidated Financial Statements).

Demand for electricity on Oahu continues to increase. An all-time peak demand of 1,327 MW (gross) was recorded on October 12, 2004, and was 20 MW higher than the projected peak for 2004 in the June 2004 forecast. On October 13, 2004, HECO issued a public request that its customers voluntarily conserve energy as two units were out for scheduled maintenance and two units were unexpectedly unavailable.

As a result of load growth and other factors, the 2005 Adequacy of Supply letter concludes that there currently is an increased risk to generation reliability, and that generation reserve margins, although substantial, are lower than is considered desirable under the circumstances. Also, the risk of having generation-related customer outages will be higher if the peak reduction impacts of planned DSM programs or CHP installations fall short of achieving their forecast benefits. This situation is expected to continue, if the peak demand continues to grow as forecast, at least until 2009, which is the earliest that HECO expects to be able to install its planned combustion turbine. The letter also indicates that HECO is working on plans to implement a number of potential interim mitigation measures, such as installing portable leased, distributed 1.6 MW generating units at substations or other sites, and initiating a customer demand response program to supplement its load management DSM programs.

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000. A stipulated prehearing order was approved by the PUC in October 2000. The parties filed individual Statements of Position in May 2001. In February 2004, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding and in April 2004 the PUC approved the stipulation, closed the docket, and ordered MECO to submit its IRP annual evaluation reports and program implementation schedules by April 2004 and April 2005 and its next (third) IRP by October 2006, as stipulated.

In April 2004, MECO filed with the PUC its IRP evaluation report, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

MECO’s second IRP identified changes in key forecasts and assumptions since the development of MECO’s initial IRP. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant site in increments from 2000-2005, 100 MW at its new Waena site in increments from 2007-2018, beginning with a 20 MW combustion turbine in 2007, and 10 MW from the acquisition of a wind resource in 2003 (currently, MECO expects to begin purchasing 30 MW of wind energy in 2006, subject to PUC approval). Approximately 4 MW of additional generation through the year 2020 is planned for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installed in 2005, is currently expected to be installed in the third quarter of 2006 (in August 2004 MECO received the necessary air permit, which became effective in September 2004).

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On the demand side, in November 2001 the PUC issued a D&O allowing MECO to continue temporarily its four existing energy efficiency DSM programs, which are similar in design to HECO’s programs. MECO’s IRP included plans for a new energy efficiency DSM program and two new load management DSM programs. While MECO does not plan to proceed with a new energy efficiency DSM program at this time, MECO is planning on filing applications for the two new load management DSM programs by the end of 2005.

HELCO’s IRP. In September 1998, HELCO filed with the PUC its second IRP, which was updated in March 1999 and revised in June 1999. A schedule for the proceeding was approved by the PUC, and the parties to the proceeding completed two rounds of discovery. In January 2004, the parties to the proceeding filed a stipulation for PUC approval to expedite the proceeding and in February 2004 the PUC approved the stipulation, closed the docket and ordered HELCO to submit its IRP annual evaluation report by the end of March 2004 and its next (third) IRP by October 2005, as stipulated. The PUC also ordered HELCO to immediately notify it in writing should circumstances change pertaining to, among other things, HELCO’s supply-side resources and load and sales forecast. The PUC subsequently opened a docket to commence HELCO’s third IRP.

In March 2004, HELCO filed with the PUC its IRP evaluation report, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

The second IRP identified changes in key forecasts and assumptions since the development of HELCO’s initial IRP. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. Due to delays in adding new generation, the near-term additions proposed in HELCO’s second IRP included installing two 20 MW combustion turbines (CTs) at its Keahole power plant site and proceeding in parallel with a power purchase agreement (PPA) with Hamakua Energy Partners, L.P. (Hamakua Partners, formerly Encogen Hawaii, L.P.) for a 60 MW (net) dual-train combined-cycle (DTCC) facility.

The Hamakua Partners PPA was approved in 1999 and its DTCC facility was completed in December 2000. (See the discussion of HELCO power purchase agreements in “Nonutility generation.”) The two Keahole CTs, CT-4 and CT-5, which were the first two phases of a planned 56 MW (net) DTCC unit, were put into limited commercial operation in May 2004 and June 2004, respectively. (See “HELCO power situation” in Note 11 to HECO’s Consolidated Financial Statements.) A PPA with Hilo Coast Power Company (HCPC) for 18 MW of firm capacity terminated at the end of 1999, but as a result of the delays in adding new generation, HELCO had been purchasing 22 MW of firm capacity from HCPC’s coal-fired facility under a restated and amended PPA, which was terminated as of January 1, 2005. HELCO also has deferred the retirements of some of its older generating units. HELCO’s current plans are to install a 16 MW steam turbine, ST-7, in 2009 or earlier pending approval of land use re-classification, zoning approval and obtaining all the necessary permits and approvals to complete the DTCC unit. After the installation of ST-7, the target date for the next firm capacity addition is the 2017 timeframe. The timing of the need for additional new generation may change, however, based on factors such as the condition of the units whose retirements have been deferred, and the status of the nonutility generators providing firm capacity, including Puna Geothermal Venture (PGV). (See the discussion of HELCO power purchase agreements in “Nonutility generation” below.)

On the demand side, in December 2001 the PUC issued a D&O allowing HELCO to continue temporarily its four existing energy efficiency DSM programs, which are similar in design to HECO’s programs.

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New capital projects

The capital projects of the electric utilities may be subject to various approval and permitting processes, including obtaining PUC approval of the project, air permits from the Department of Health of the State of Hawaii (DOH) and/or the U.S. Environmental Protection Agency (EPA), land use permits from the Hawaii Board of Land and Natural Resources (BLNR) and land use entitlements from the applicable county. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits could result in project delays, increased project costs and/or project abandonments. Extensive project delays and significantly increased project costs could result in a portion of the project costs being excluded from rates. If a project is abandoned, the project costs are generally written-off to expense, unless the PUC determines that all or part of the costs may be deferred for later recovery in rates.

In addition to HELCO’s Keahole power plant expansion project, HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements), and MECO’s Maalaea power plant expansion project (see preceding discussion in “Integrated resource planning and requirements for additional generating capacity” section under the sub-heading “MECO’s IRP”), the Company has two other significant capital projects. In December 2004, construction was completed on a $40 million project for an underground fuel pipeline that transports fuel from HECO’s tank farm at Campbell Industrial Park to HECO’s Waiau power plant. Also in 2004, construction commenced on HECO’s $23 million project to construct a New Dispatch Center which will house a modernized Energy Management System, and which will be integrated with new Outage Management and Customer Information systems. The New Dispatch Center project is expected to be completed in 2007, with the Energy Management System operational in 2006.

HECO also plans to request approval from the PUC to build a generating unit (an approximately 100 MW combustion turbine planned to be added in 2009) and a 138 kV overhead transmission line (approximately two miles long, generally paralleling an existing overhead line through the industrial area between the AES and Campbell Industrial Park substations, to provide additional transmission capacity for the new generating unit as well as for existing units at Campbell Industrial Park).

Nonutility generation

The Company has supported state and federal energy policies which encourage the development of alternate energy sources that reduce the use of fuel oil. The Company’s alternate energy sources range from wind, geothermal and hydroelectric power, to energy produced by the burning of bagasse (sugarcane waste), municipal waste and coal.

HECO PPAs. HECO currently has three major PPAs. In March 1988, HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended in August 1989, provides that, for a period of 30 years beginning September 1992, HECO will purchase 180 MW of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant, which became operational in September 1992, utilizes a “clean coal” technology. The facility is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). See discussion of a lawsuit against The AES Corporation, AES Hawaii, HECO and HEI in Note 11 to HECO’s Consolidated Financial Statements. Under the amended PPA, AES Hawaii must obtain certain consents from HECO prior to entering into any arrangement to refinance the facility. In the second quarter of 2003, HECO and AES Hawaii reached agreement on the terms upon which HECO would consent to a proposed refinancing. Under the agreement, which was contingent on obtaining certain PUC approvals and completion of the refinancing, HECO received consideration for its consent, primarily in the form of a PPA amendment that reduced the cost of firm capacity supplied to HECO pursuant to the PPA, retroactive to June 1, 2003. The benefit of the firm capacity cost reduction, totaling approximately $2.9 million annually for the remaining term of the PPA, is being passed on to ratepayers through a reduction in rates. AES Hawaii also has granted HECO an option, subject to certain conditions, to acquire an interest in portions of the AES Hawaii facility site that are not needed for the existing plant operations, and which potentially could be used for the development of another coal-fired facility. On July 1, 2003, the PUC issued a D&O approving the PPA amendment and a rate adjustment (lowering rates) on short notice. On July 31, 2003, the proposed refinancing was completed and capacity payments were reduced, retroactive to June 1, 2003.

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In October 1988, HECO entered into an agreement with Kalaeloa Partners, L.P. (Kalaeloa), a limited partnership whose sole general partner was an indirect, wholly-owned subsidiary of ASEA Brown Boveri, Inc. (ABB), which has guaranteed certain of Kalaeloa’s obligations and, through affiliates, contracted to design, build, operate and maintain the facility. The agreement with Kalaeloa, as amended, provides that HECO will purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. The Kalaeloa facility, which was completed in the second quarter of 1991, is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that utilizes waste heat from the combustion turbines. The facility is designed to sell sufficient steam to be a QF. As of February 28, 1997, the ownership of Kalaeloa was restructured so that 1% was owned by the ABB subsidiary as the general partner and 99% was owned by Kalaeloa Investment Partners (KIP) as the limited partner. KIP is a limited partnership comprised of PSEG Hawaiian Management, Inc. and PSEG Hawaiian Investment, Inc. (nonregulated affiliates of Public Service Enterprise Group Incorporated) and Harbert Power Corporation. Subsequently, HECO consented to, and the PUC approved of, the transfer of the general partner partnership interest from the ABB subsidiary to an entity affiliated with the owners of KIP. During the second quarter of 2003, Kalaeloa approached HECO with plans to upgrade the combustion turbines (the M upgrade) by installing new parts designed to improve their efficiency and output. The upgraded combustion turbines would allow Kalaeloa to increase the capacity of the facility by approximately 20 MW. Under the agreement, Kalaeloa may not make any modifications to the facility that would either increase or decrease the generating capacity of the facility without the prior approval of HECO, except as required by law or regulation. The agreement also provides that HECO shall not be obligated to approve a change in facility capacity if such change would adversely impact HECO system reliability or result in an increased cost of power to HECO from the facility. On December 31, 2003, HECO and Kalaeloa entered into a Consent and Agreement (Consent) in which HECO consented to the M upgrade. The Consent provides that neither the M upgrade nor HECO’s consent to the M upgrade shall obligate HECO to accept additional energy made available as a result of the M upgrade, or to enter into negotiations to accept any change in the firm capacity of the facility, and shall not affect the rights of the parties under the section of the agreement related to an increase in firm capacity.

The PPA with Kalaeloa provides that if Kalaeloa’s facility is able to demonstrate, under certain conditions, that it is able to deliver capacity above the 180 MW of firm capacity (up to a maximum of 189 MW), the firm capacity under the PPA shall be increased to the level that was demonstrated. Under the PPA, the additional capacity above 180 MW shall be paid at $112 per kilowatt per year (as compared to the payment rate of $164.35 per kilowatt per year for capacity up to and including 180 MW). On October 12, 2004, HECO and Kalaeloa executed two amendments to the PPA: 1) Confirmation Agreement Concerning Section 5.2B(2) Of Power Purchase Agreement And Amendment No. 5 To Power Purchase Agreement (Amendment No. 5), and 2) Agreement For Increment Two Capacity And Amendment No. 6 To Power Purchase Agreement Between HECO And Kalaeloa (Amendment No. 6). Amendment No. 5 confirms Kalaeloa’s demonstration, through a test conducted in 2004, that its facility is able to deliver 189 MW of capacity from the existing facility, and sets the capacity payment rate for capacity above 180 MW at $112 per kilowatt per year. Amendment No. 5 also clarifies, modifies, or amends certain provisions of the PPA. Amendment No. 6 provides for the purchase of up to 20 MW of additional capacity, beyond the 189 MW capacity confirmed in Amendment No. 5, at $112 per kilowatt per year. The amount of capacity which HECO will purchase, up to the additional 20 MW, will be demonstrated through a test conducted in 2005. Amendment Nos. 5 and 6 were submitted to the PUC for approval on November 5, 2004. The approval by the PUC and inclusion of the associated purchased power expenses in HECO rates are needed for the amendments to be effective (see FIN 46R discussion in Note 1 to HECO’s Consolidated Financial Statements).

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (H-POWER). The H-POWER facility began to provide firm energy in 1990 and currently supplies HECO with 46 MW of firm capacity. The firm capacity amendment provides that HECO will purchase firm capacity until mid-2015.

HECO purchases energy on an as-available basis from two nonutility generators, which are diesel-fired qualifying cogeneration facilities at the two oil refineries (10 MW and 18 MW) on Oahu. HECO previously purchased energy on an as-available basis from an approximately 3 MW combustion turbine fired by methane gas from a landfill. In March 2002, the combustion turbine suffered a major failure. In July 2002, the owner of the facility requested that HECO terminate the PPA and HECO agreed.

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The PUC has approved and allowed rate recovery for the firm capacity and purchased energy costs related to HECO’s three major PPAs that provide a total of 406 MW of firm capacity, representing 25% of HECO’s total net generating and firm purchased capacity on the island of Oahu as of December 31, 2004. The PUC also has approved and allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs.

HELCO and MECO PPAs. As of December 31, 2004, HELCO and MECO had PPAs for 108 MW and 16 MW (includes 4 MW of system protection) of currently available firm capacity, respectively, but HELCO’s PPA with HCPC for 22 MW was terminated as of January 1, 2005 (see below).

HELCO has a 35-year PPA with Puna Geothermal Venture (PGV) for 30 MW of firm capacity from its geothermal steam facility expiring on December 31, 2027. PGV’s output was reduced to 6 MW from April 2002 to March 2003. The loss of generation was attributed to blockage of a source well due to a failed liner 5,000 feet below the Earth’s surface and decreasing steam quality emanating from one of PGV’s source wells. PGV completed drilling an additional source well in February 2003, and converted the blocked source well into an injection well in early March 2003. The new injection well was tested and PGV’s capacity is currently between 25 to 28 MW. PGV obtained a permit from the DOH for the new injection well in March 2003. Without the new injection well, PGV was able to produce only about 10 to 11 MW due to the high moisture content of the steam from the new source well. PGV is assessing whether to drill another source well or to install new generation equipment designed to utilize the lower quality steam. While PGV indicates it is evaluating its options to enable it to restore its 30 MW commitment to HELCO as soon as possible, HELCO cannot predict when PGV will be able to meet its contractual commitment. HELCO’s PPA with PGV provides for annual availability sanctions against PGV if PGV does not provide up to the contracted 30 MW of capacity. In the first quarter of 2003, HELCO recorded $0.7 million lower purchased power expense from PGV for availability sanctions for not meeting contracted capacity for 2002. In addition, since PGV had not yet restored its 30 MW commitment to HELCO by December 31, 2003, availability sanctions for 2003, of approximately $0.2 million, were assessed against PGV in 2004. Sanctions for 2004, estimated at approximately $0.1 million, will be assessed against PGV in 2005. On June 3, 2004, HELCO was informed that ORNI 8 LLC, a wholly owned affiliate of Ormat Nevada Inc., acquired PGV through the acquisition of the PGV partner entities from Constellation Power, Inc. The transaction did not require HELCO’s consent or PUC approval. PGV has indicated its intent to pursue improvements to the plant to increase its capacity, and to pursue negotiations with HELCO for a new or amended PPA.

On October 4, 1999, HELCO entered into a PPA with HCPC effective January 1, 2000 through December 31, 2004, subject to early termination by HELCO, whereby HELCO purchases 22 MW of firm capacity from HCPC’s coal-fired facility. On May 27, 2004, HELCO provided notice to HCPC to terminate the PPA as of January 1, 2005, and the PPA with HCPC was terminated as of January 1, 2005.

In October 1997, HELCO entered into an agreement with Encogen, a limited partnership whose general partners at the time were wholly-owned special-purpose subsidiaries of Enserch and Jones Capital Corporation. Enserch Corporation and J.A. Jones, Inc. (Jones), the parent companies of Enserch and Jones Capital Corporation, respectively, guaranteed certain of Encogen’s obligations. The agreement provides that HELCO will purchase up to 60 MW (net) of firm capacity for a period of 30 years. The DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines. The PUC approved the agreement on July 14, 1999. On November 8, 1999, HELCO entered into a PPA Novation with Encogen and Hamakua Partners, which recognizes the transfer of the obligations of Encogen under the PPA to Hamakua Partners. Hamakua Partners was formed as a result of the sale of the general partner and limited partner partnership interests of Enserch to entities affiliated with TECO Energy Inc. (TECO), which is a Florida-based energy company and parent company of Tampa Electric Company, a regulated electric utility. TECO has replaced the guarantee of Enserch Corporation of certain of Hamakua Partners’ obligations.

On August 12, 2000, Hamakua Partners began providing HELCO with firm capacity from the first phase of a two-phase construction completion schedule. On December 31, 2000, Hamakua Partners began providing firm capacity from the entire facility, following completion of the second phase of construction. In June 2001, Hamakua Partners demonstrated 60 MW of output from the facility. Subsequently, the output deteriorated due to technical problems in the steam turbine. Hamakua Partners has since resolved its nozzle plugging problems, but due to high nitrogen oxide emissions and high steam turbine vibration problems, the output had been limited to 55-57 MW in early 2003. Hamakua Partners requested maintenance outages to correct the problems and returned to providing

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HELCO with 60 MW later in 2003. In September 2003, Jones filed for reorganization in bankruptcy in North Carolina. Jones is the parent company of the managing general partner and a limited partner of Hamakua Partners, and is one of the two co-guarantors of the Hamakua Partners project. In June 2004, under a court approved motion, substantially all of the assets of Jones including its interest in Hamakua Partners was sold to Black River Energy, an affiliate of United States Power Fund L. P. (USPF). In July 2004, the remaining 50% ownership in Hamakua Partners was sold by TECO to an affiliate of Black River Energy. As a result of both sales, USPF is now the sole owner of the Hamakua facility.

HELCO purchases energy on an as-available basis from a number of nonutility generators. The largest include a 12.1 MW run-of-the-river hydroelectric facility and a 7 MW wind facility. Wailuku River Hydroelectric L.P., the owner of the hydroelectric facility, has an existing contract to provide HELCO with as-available power through May 2023. Apollo Energy Corporation (Apollo), the owner of the wind facility, has an existing contract to provide HELCO with as-available windpower through June 29, 2002 (and extending thereafter until terminated by HELCO or Apollo). Apollo filed a petition for hearing with the PUC on April 28, 2000, alleging that it had unsuccessfully attempted to negotiate a new power purchase agreement with HELCO. Apollo had offered to repower its existing 7 MW facility by the end of 2000 and to install additional wind turbines, up to a total allowed capacity of 15 MW, by the end of 2001. The parties agreed to limit to four issues the matters being presented to the PUC for guidance: whether Apollo is entitled to capacity payments; whether Apollo is entitled to a minimum purchase rate; whether certain performance standards should apply; and whether HELCO’s proposed dispute resolution provision should apply. A hearing on these issues was held on October 3 to 5, 2000. On May 30, 2001, the PUC issued a D&O in which it ordered HELCO and Apollo to continue to negotiate a PPA, consistent with the terms of the D&O, and to submit by August 13, 2001 either a finalized PPA or status reports informing the PUC of matters preventing finalization of a PPA. HELCO and Apollo were unable to agree to a PPA by August 13, 2001, and each submitted a status report. The parties continued to negotiate in 2002, 2003 and 2004, and reached agreement on a PPA on October 13, 2004. The PPA enables Apollo to repower its existing 7 MW facility, and install an additional 13.5 MW of capacity, for a total windfarm capacity of 20.5 MW. The PPA was submitted to the PUC for approval on November 26, 2004.

On January 8, 2001, HELCO entered into a PPA with Hawi Renewable Development, Inc. (HRD) for the purchase of as-available energy from HRD’s proposed 5 MW windfarm. An amendment to the PPA was completed on April 30, 2002. The PPA, as amended, was approved by the PUC on January 14, 2003.

On December 30, 2003, HELCO and Hawi Renewable Development, LLC (HRD LLC) entered into a PPA under which HRD LLC would sell energy from an expanded wind farm (approximately 10.6 MW) at HRD’s 5 MW wind farm site (which can accommodate the expanded wind farm). It is anticipated that the output of the 10.6 MW wind farm may be limited on occasion. The PUC approved the PPA on May 14, 2004.

MECO has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of oil or coal. HC&S has had some difficulties in meeting its contractual obligations to MECO over the years through 2003 due to operational constraints. The PPA remains in force and effect through December 31, 2007, and from year to year thereafter, subject to termination on or after December 31, 2007 on not less than two years prior written notice by either party.

Beginning in 2006, MECO expects to purchase as-available energy from Kaheawa Wind Power, LLC (KWP) under a PPA between MECO and KWP dated December 3, 2004. KWP plans to install a 30 MW windfarm at Ukumehame, Maui. The PPA was submitted to the PUC for approval on December 16, 2004.

The PUC has approved and allowed rate recovery for the firm capacity and purchased energy costs for MECO’s and HELCO’s approved firm capacity and as-available energy PPAs.

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Fuel oil usage and supply

The rate schedules of the Company’s electric utility subsidiaries include energy cost adjustment (ECA) clauses under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. See discussion below under “Rates,” and “Regulation of electric utility rates” and “Electric utility revenues” in HEI’s MD&A.

HECO’s steam power plants burn LSFO. HECO’s combustion turbine peaking units burn No. 2 diesel fuel (diesel). MECO’s and HELCO’s steam power plants burn medium sulfur fuel oil (MSFO) and their combustion turbine and diesel engine generating units burn diesel. The LSFO supplied to HECO is primarily derived from Indonesian and other Far East crude oils processed in Hawaii refineries. The MSFO supplied to MECO and HELCO is derived from U.S. domestic crude oil and various foreign crude oil grades processed in Hawaii refineries.

In December 1997, HECO executed contracts for the purchase of LSFO and the use of certain fuel distribution facilities with Chevron Products Company (Chevron) and BHP Petroleum Americas Refining Inc. (BHP). Subsequently, Tesoro Hawaii Corp. (Tesoro) acquired BHP and assumed all rights and obligations under the contract between HECO and BHP. The Chevron and BHP (now Tesoro) fuel supply and facilities operations contracts have a term of seven years commencing January 1, 1998. The PUC approved the contracts and permits the inclusion of costs incurred under these contracts in HECO’s ECA clauses. HECO pays market-related prices for fuel supplies purchased under these agreements.

In March and April of 2004, HECO executed 10-year extensions of the existing contracts, commencing January 1, 2005, for the purchase of LSFO with Chevron and Tesoro with no material changes in the primary commercial arrangements including volumes and pricing formulas. The PUC approved these contract extensions in December 2004. In December 2004, HECO executed long-term contracts with Chevron for the continued use of certain Chevron fuel distribution facilities and for the operation and maintenance of certain HECO fuel distribution facilities.

HECO, MECO and HELCO executed joint fuel supply contracts with Chevron and BHP (now Tesoro) for the purchase of diesel and MSFO supplies and for the use of certain petroleum distribution facilities for a period of seven years commencing January 1, 1998. The PUC approved these contracts and the electric utilities pay market-related prices for diesel and MSFO supplied under these agreements.

In March and April of 2004, HECO, HELCO and MECO executed 10-year extensions of the existing contracts, commencing January 1, 2005, for the purchase of diesel and MSFO with Chevron and Tesoro, including the use of certain petroleum storage and distribution facilities, with no material changes in the primary commercial arrangements including volumes and pricing formulas. The PUC approved these contract extensions in December 2004.

The diesel supplies acquired by the Lanai Division of MECO are purchased under a contract with a local petroleum wholesaler, Lanai Oil Co., Inc. On March 1, 2000, the PUC approved an amended contract with a term extending through December 31, 2001, and further extending through December 31, 2003 unless terminated as of the end of 2001. This agreement has been extended through December 31, 2005.

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 11 to HECO’s Consolidated Financial Statements.

The following table sets forth the average cost of fuel oil used by HECO, MECO and HELCO to generate electricity in the years 2004, 2003 and 2002:

The average per-unit cost of fuel oil consumed to generate electricity for HECO, MECO and HELCO reflects a different volume mix of fuel types and grades. In 2004, over 98% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 76% of MECO’s and 34% of HELCO’s fuel consumption. MSFO made up the remainder of the fuel consumption of MECO and HELCO.

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In general, MSFO is the least costly fuel, diesel is the most expensive fuel and the price of LSFO falls between the two on a per-barrel basis. During 2004, the prices of LSFO, MSFO and diesel rose above the levels reached at the end of 2003 reflecting stronger demand for petroleum products world wide, particularly in the U.S. and China, tight U.S. crude oil and petroleum product inventories and continued geopolitical uncertainty. Thus the annual prices paid by the electric utilities for LSFO, MSFO and diesel averaged approximately 15%, 14% and 38%, respectively, above the average price for that grade of fuel in 2003. Though prices in 2004 continued the upward trend when compared to the year earlier, the rate of increase lessened somewhat from the previous annual increase. During 2003, the prices of LSFO, MSFO and diesel remained at or above the high levels reached at the end of 2002 reflecting geopolitical uncertainty with the invasion of Iraq and tight U.S. crude oil and petroleum inventories.

In December 2000, HELCO and MECO executed contracts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) for the shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. These contracts were the result of a competitive bidding process and provide for the employment of a double-hull bulk petroleum barge at freight rates approximately the same as prevailed under predecessor transportation contracts with HITI. The double-hull barge entered utility service in March 2002. The contracts are for an initial term of 5 years with options for three additional 5-year extensions. On December 10, 2001, the PUC approved these contracts and issued a final order that permits HELCO and MECO to include the fuel transportation and related costs incurred under the provisions of these agreements in their respective ECA clauses.

HITI never takes title to the fuel oil or diesel fuel, but does have custody and control while the fuel is in transit from Oahu. If there were an oil spill in transit, HITI is contractually obligated to indemnify HELCO and/or MECO. HITI has liability insurance coverage for oil spill related damage of $1 billion. State law provides a cap of $700 million on liability for releases of heavy fuel oil transported interisland by tank barge. In the event of a release, HELCO and/or MECO may be responsible for any clean-up and/or fines that HITI or its insurance carrier does not cover.

The prices that HECO, MECO and HELCO pay for purchased energy from nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation indicator. The energy prices for Kalaeloa, which purchases LSFO from Tesoro, vary primarily with world LSFO prices. The H-POWER, HC&S and PGV energy prices are based on the electric utilities’ respective PUC-filed short-run avoided energy cost rates (which vary with their respective composite fuel costs), subject to minimum floor rates specified in their approved PPAs. The Hamakua Partners energy prices vary primarily with HELCO’s diesel costs.

The Company estimates that 79% of the net energy generated and purchased by HECO and its subsidiaries in 2005 will be generated from the burning of oil. Increases in fuel oil prices are passed on to customers through the electric utility subsidiaries’ ECA clauses. Failure by the Company’s oil suppliers to provide fuel pursuant to the supply contracts and/or substantial increases in fuel prices could adversely affect consolidated HECO’s and the Company’s financial condition, results of operations and/or liquidity. HECO’s policy, however, is to maintain an inventory of fuel oil equivalent to a 35 day supply. HELCO’s and MECO’s policies are to maintain approximately a one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and Hamakua Partners require that they maintain certain minimum fuel inventory levels.

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Transmission systems

HECO has 138 kV transmission and 46 kV subtransmission lines. HELCO has 69 kV transmission and 34.5 kV transmission and subtransmission lines. MECO has 69 kV transmission and 23 kV subtransmission lines on Maui and 34.5 kV transmission lines on Molokai. Lanai has no transmission lines and uses 12 kV lines to distribute electricity. The electric utilities’ overhead and underground transmission and subtransmission lines, as well as their distribution lines, are uninsured because the amount of insurance available is limited and the premiums are extremely high.

Lines are added when needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. By state law, the PUC generally must determine whether new 46 kV, 69 kV or 138 kV lines can be constructed overhead or must be placed underground. The process of acquiring permits and regulatory approvals for new lines can be contentious, time consuming (leading to project delays) and costly.

HECO system. HECO serves Oahu’s electricity requirements with firm capacity (net) generating units located in West Oahu (1,027 MW); Waiau, adjacent to Pearl Harbor (481 MW); and Honolulu (107 MW). HECO’s nonfirm power sources (approximately 28 MW) are located primarily in West Oahu. HECO transmits power to its service areas on Oahu through approximately 219 miles of overhead and underground 138 kV transmission lines (of which approximately 8 miles are underground) and approximately 523 miles of overhead and underground 46 kV subtransmission lines.

HECO’s power sources are located primarily in West Oahu, but the bulk of HECO’s system load is in the Honolulu/East Oahu area. Accordingly, HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a part underground/part overhead 138 kilovolt (kV) transmission line from the Kamoku substation to the Pukele substation in order to close the gap between the Southern and Northern corridors and provide a third 138 kV transmission line to the Pukele substation. Construction of the proposed transmission line in its originally proposed location required the BLNR to approve a CDUP for the overhead portion of the line that would have been in conservation district lands. Several community and environmental groups opposed the project, particularly the overhead portion of the line and, in June 2002, the BLNR denied HECO’s request for a CDUP.

HECO continues to believe that the proposed project (the East Oahu Transmission Project) is needed to improve the reliability of the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, and to address future potential line overloads under certain contingencies. In 2003, HECO completed its evaluation of alternative ways to accomplish the project (including using 46 kV transmission lines). As part of its evaluation, HECO conducted a community-based process to obtain public views of the alternatives. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $55 million, which amount includes $23 million of costs already incurred) for its revised East Oahu Transmission Project. See discussion in Note 11 to HECO’s Consolidated Financial Statements.

HELCO system. HELCO serves the island of Hawaii’s electricity requirements with firm capacity (net) generating units located in West Hawaii (77 MW) and East Hawaii (212 MW). HELCO’s nonfirm power sources total 24 MW, but are expected to increase by 24 MW in 2006. HELCO transmits power to its service area on the island of Hawaii through approximately 468 miles of 69 kV overhead lines and approximately 173 miles of 34.5 kV overhead lines.

MECO system. MECO serves its electricity requirements with firm capacity (net) generating units located on the island of Maui (245 MW), Molokai (12 MW) and Lanai (10 MW). Beginning in 2006, MECO expects to purchase 30 MW of as-available energy, under a PPA between MECO and Kaheawa Wind Power, LLC (KWP) dated December 3, 2004. The PPA was submitted to the PUC for approval on December 16, 2004. MECO transmits power to its service area through approximately 143 miles of 69 kV overhead lines, approximately 15 miles of 34.5 kV overhead lines, and approximately 85 miles of 23 kV overhead lines.

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Rates

HECO, MECO and HELCO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation and other matters—Electric utility regulation.”

All rate schedules of HECO and its subsidiaries contain ECA clauses as described previously. Under current law and practices, specific and separate PUC approval is not required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. Rate increases, other than pursuant to such automatic adjustment clauses, require the prior approval of the PUC after public and contested case hearings. PURPA requires the PUC to periodically review the ECA clauses of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change.

See “Regulation of electric utility rates,” “Most recent rate requests” and “Electric utility revenues” in HEI’s MD&A.

Public Utilities Commission of the State of Hawaii

After serving 14 months on the PUC, Carlito P. Caliboso (an attorney previously in private practice) was reappointed to the PUC, confirmed by the state senate for a six year term expiring June 30, 2010, and continues to serve as Chairman of the PUC. Also serving as commissioners are Janet E. Kawelo (term expiring June 30, 2006, who previously served as the Deputy Director for the State Department of Land and Natural Resources) and Wayne H. Kimura (term expiring June 30, 2008, who previously served as State Comptroller with the State Department of Accounting and General Services).

John E. Cole was appointed Executive Director of the Division of Consumer Advocacy effective May 17, 2004. Prior to becoming the Executive Director, Mr. Cole was a member of the Governor of the State of Hawaii’s Policy Team, which serves as advisor to the Governor on state-wide policy matters. Mr. Cole is an attorney.

Most recent rate requests

See “Most recent rate requests” in HEI’s MD&A.

Competition

In December 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 “Competition” in HEI’s MD&A.

Electric and magnetic fields

Research on potential adverse health effects from exposure to electric and magnetic fields (EMF) continues. To date, no definite relationship between EMF and health risks has been clearly demonstrated. In 1996, the National Academy of Sciences examined more than 500 studies and stated that “the current body of evidence does not show that exposure to EMFs presents a human-health hazard.” An extensive study released in 1997 by the National Cancer Institute and the Children’s Cancer Group found no evidence of increased risk for childhood leukemia from EMF. In 1999, the National Institute of Environmental Health Sciences (NIEHS) Director’s Report concluded that while EMF could not be found to be “entirely safe,” the evidence of a health risk was “weak” and did not warrant “aggressive” regulatory actions. In 2002, the NIEHS further stated that for ”most health outcomes,” there is “no evidence that EMF exposures have adverse effects,” and also that there “is some evidence from epidemiology studies that exposure to power-frequency EMF is associated with an increased risk for childhood leukemia.” In the same brochure, the NIEHS further concluded that this association is “difficult to interpret in the absence of reproducible laboratory evidence or a scientific explanation that links magnetic fields with childhood leukemia.”

While EMF has not been established as a cause of any health condition by any national or international agency, EMF remains the subject of ongoing studies and evaluations. EMF has been classified as a possible human carcinogen by more than one public health organization. In 2004, the U.K. National Radiological Protection Board (NRPB) published a report that supported a precautionary approach and recommended adoption of guidelines for limiting exposure to EMF. In the U.S., there are no federal standards limiting occupational or residential exposure to 60-Hz EMF.

The implications of the foregoing reports have not yet been determined. However, these reports may raise the profile of the EMF issue for electric utilities.

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HECO and its subsidiaries are monitoring the research and continue to participate in utility industry funded studies on EMF and, where technically feasible and economically reasonable, continue to pursue reducing EMFs, in the design and installation of new transmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on HECO, HELCO and MECO in the future.

Legislation

See “Legislation and regulation” in HEI’s MD&A.

Commitments and contingencies

See “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HEI’s MD&A and Note 11 to HECO’s Consolidated Financial Statements for a discussion of important commitments and contingencies, including (but not limited to) HELCO’s Keahole power situation; HECO’s East Oahu Transmission Project; the lawsuit against The AES Corporation, HECO and HEI; and the Honolulu Harbor environmental investigation.

City and County sewer line. On July 22, 2004, a contractor (hired by HECO for a utility line extension project to support the expansion of the City and County of Honolulu’s wastewater treatment plant) accidentally drilled into a force main sewer line owned by the City and County. The City and County made a formal demand that HECO provide full compensation for damages to the force main sewer line. Management believes HECO has defenses against any assertions that it has liability for the incident as well as insurance coverage (over a deductible amount). Accordingly, HECO responded to the demand asserting its defenses against liability. HECO has increased its general liability reserves to provide for clean-up costs in the event it is found to have responsibility for such costs.

Bank—American Savings Bank, F.S.B.

General

ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2004, ASB was the third largest financial institution in the State of Hawaii based on total assets of $6.8 billion and deposits of $4.3 billion. In 2004, ASB’s revenues and net income from continuing operations amounted to approximately 19% and 38%, respectively, of HEI’s consolidated amounts, compared to approximately 21% and 48% in 2003 and approximately 24% and 48% in 2002, respectively.

At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the Office of Thrift Supervision’s (OTS) predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital was limited to a maximum aggregate amount of approximately $65.1 million. At December 31, 2004, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28.3 million because of additional capital contributions of $36.8 million by HEI to ASB since the acquisition, exclusive of capital contributions made in connection with ASB’s 1997 acquisition of most of the Hawaii operations of Bank of America, FSB (including the $75 million capital contribution made by HEIDI in December 2004 after ASB redeemed $75 million of preferred stock that had been issued to HEIDI in connection with the 1997 acquisition). ASB is subject to OTS regulations on dividends and other distributions applicable to financial institutions regulated by the OTS and ASB must receive a letter of non-objection before it can declare and pay a dividend to HEI.

ASB’s earnings depend primarily on its net interest income—the difference between the interest income earned on interest-earning assets (loans receivable and investment and mortgage-related securities) and the interest expense incurred on interest-bearing liabilities (deposit liabilities and borrowings, including advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase). Other factors primarily affecting ASB’s operating results include gains or losses on sales of securities available-for-sale, fee income, provision for loan losses, changes in the value of mortgage servicing rights and expenses from operations.

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For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 4 to HEI’s Consolidated Financial Statements.

The following table sets forth selected data for ASB for the years indicated:

ASB’s tangible efficiency ratio – the cost of earning $1 of revenue – remained flat at 61% from 2003 to 2004. The tangible efficiency ratio rose from 58% for 2002 to 61% for 2003 as net interest income decreased due to margin compression and general and administrative expenses grew due to costs to transform ASB to a full-service community bank. The transformation project will require continued investment in people and technology. ASB’s ongoing challenge is to manage expenses in order to keep increasing costs and increasing revenues in balance.

Consolidated average balance sheet

The following table sets forth average balances of ASB’s major balance sheet categories for the years indicated. Average balances have been calculated using the daily average balances.

In 2004, the low interest rate environment and continued strength in the Hawaii real estate market resulted in an increase in average loans receivables. The average residential mortgage portfolio as of year-end 2004 grew by $37.7 million or 1.5% over the 2003 year-end average residential mortgage portfolio. Average commercial real estate loans, net of undisbursed loan funds, increased $12.4 million or 6.2% over 2003 primarily due to commercial construction real estate loans originated in 2004 of $85.8 million. ASB’s average business portfolio increased by $11.0 million or 4.0% during 2004 as ASB’s transformation to a full-service community bank continued. The average consumer loan portfolio decreased $8.2 million or 3.6% from 2003 as low interest rates and improving real estate values resulted in higher mortgage refinancing and high consumer loan payoffs. Average savings deposits increased during the year as ASB continued to attract core deposits. Average term certificate balances decreased in 2004 as ASB did not aggressively pursue term certificates. Average other borrowings also

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decreased during 2004 as the increase in average savings deposits enabled ASB to repay some of its maturing, higher costing other borrowings. In 2003, the low interest rate environment and continued strength in the Hawaii real estate market drove record loan production and an increase in average loans receivables. The average residential mortgage portfolio as of year-end 2003 grew by $194 million, or 8.5%, over 2002 year-end. ASB increased its average business portfolio by $52 million, or 23.5%, during 2003. The increase in savings deposits and the decrease in term certificates were due to ASB’s efforts in attracting low-costing core deposits and ASB not aggressively pursuing term certificates.

Asset/liability management

See HEI’s “Quantitative and Qualitative Disclosures about Market Risk.”

Interest income and interest expense

See “Results of operations—Bank” in HEI’s MD&A for a table of average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid for certain categories of interest-earning assets and interest-bearing liabilities for the years ended December 31, 2004, 2003 and 2002.

The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average portfolio balance) and (2) changes in volume (change in average portfolio balance multiplied by prior period rate). Any remaining change is allocated to the above two categories on a pro rata basis.