HAWAIIAN ELECTRIC CO INC - Annual Report: 2005 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

For the fiscal year ended December 31, 2005

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 if Registrant Hawaiian Electric Industries, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  x    No  ¨

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  ¨    No  x

Indicate by check mark if Registrant Hawaiian Electric Industries, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  ¨    No  x

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ¨    No  x

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (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 whether Registrant Hawaiian Electric Company, Inc. (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.  x

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer  x  Accelerated filer   ¨  Non-accelerated filer   ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer  ¨  Accelerated filer  ¨  Non-accelerated filer  x

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

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

DOCUMENTS INCORPORATED BY REFERENCE

HECO Consolidated 2005 Financial Statements—Parts I, II, III and IV

HECO Consolidated Selected Financial Data—Part II

Portions of Proxy Statement of Hawaiian Electric Industries, Inc. for the 2006 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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Forward-Looking Statements

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, 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 95% of Hawaii’s population. 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, is the third largest financial institution in the State of Hawaii based on total assets as of December 31, 2005. ASB has subsidiaries involved in the sale and distribution of insurance products and an inactive advertising agency for ASB and its subsidiaries. Former ASB subsidiary, ASB Realty Corporation, which had elected to be taxed as a real estate investment trust, was dissolved in May 2005 (see Note 10 to HEI’s Consolidated Financial Statements under “ASB state franchise tax dispute and settlement”).

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments (in companies based in Hawaii and the U.S. mainland) with a carrying value of $6.9 million as of December 31, 2005.

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

Hycap Management, Inc., 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 and will terminate in 2007.

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 to its former operations and the operations of its former subsidiary.

HEI Investment Corp. (HEIIC), incorporated in May 1984 primarily to make passive investments in corporate securities and other long-term investments, changed its name to HEI Investments, Inc. (HEIII) in January 2000. HEIII is not an “investment company” regulated under the Investment Company Act of 1940. In February 2000, HEIII became a subsidiary of HEIPC. HEIII’s long-term investments currently consist primarily of investments in leveraged leases accounted for in the Company’s continuing operations. In 2005, HEIII sold its approximate 25% interest in a trust that is the owner/lessor of a 60% undivided interest in a coal-fired electric generating plant in Georgia for a pretax gain of $14 million.

For information about the Company’s discontinued international power operations formerly conducted by HEIPC and its subsidiaries, see Note 14 to HEI’s Consolidated Financial Statements.

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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 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. MECO acquired the Lanai City power plant on the island of Lanai in 1988 and all the outstanding common stock of Molokai Electric Company, Limited (currently a division of MECO) in 1989. In 2005, the electric utilities’ revenues and net income from continuing operations amounted to approximately 82% and 57%, respectively, of HEI’s consolidated amounts, compared to approximately 81% and 75% in 2004 and approximately 78% and 67% in 2003, respectively.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population currently estimated at 1,212,000, or approximately 95% of the Hawaii population, 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 HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements.

Sales of electricity

The following table sets forth the number of electric customer accounts as of December 31, 2005, 2004 and 2003 and electric sales revenues by company for each of the years then ended:

Revenues from the sale of electricity in 2005 were from the following types of customers in the proportions shown:

        Kilowatthour (KWH) sales of HECO and its subsidiaries follow a seasonal pattern, but they do not experience the extreme seasonal variation due to extreme weather variations like some electric utilities on the U.S. mainland. KWH sales in Hawaii tend to increase in the warmer summer months, probably as a result of increased demand for air conditioning.

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HECO and its subsidiaries derived approximately 10% of their operating revenues from the sale of electricity to various federal government agencies in each of 2005, 2004 and 2003.

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, mandated 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 was measured relative to the agency’s 1985 energy use. The Energy Policy Act of 2005 further mandated that federal buildings reduce energy consumption by up to 20% in fiscal year 2015 relative to base fiscal year 2003 consumption to the extent that these measures are cost effective. The Act also establishes energy conservation goals at the state level for federally funded programs; stricter conservation measures for a variety of large energy consuming products; tax credits for energy efficient homes, solar energy, fuel cells and microturbine power plants; and includes other energy-related provisions. HECO continues to work with various federal agencies to implement demand-side management programs that will help them achieve their energy reduction objectives. Neither HEI nor HECO management can predict with certainty the impact of federal mandates 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, and for the year ended, December 31, 2005. The capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.

Generating reliability and reserve margin

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. HECO, HELCO and MECO have isolated electrical systems that are not interconnected to each other or to any other electrical grid and thus, each maintain a higher level of reserve generation than is typically carried by interconnected mainland U.S. 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 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, HECO is below preferred levels of reserve margin and has made several public calls for energy conservation when reserves were especially narrow. See “Integrated resource planning, requirements for additional generating capacity and adequacy of supply” in HEI’s MD&A.

Integrated resource planning and requirements for additional generating capacity

The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs), which may be approved, rejected or modified by the PUC. 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. The PUC adopted a “framework,” which established the process and guidelines for developing IRPs and directed that each plan cover a 20-year planning horizon with a five-year program implementation schedule and that the planning cycle will be repeated every three years.

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs. The PUC has approved IRP cost recovery provisions for HECO, MECO and HELCO, pursuant to which the utilities have recovered the costs for approved DSM programs (including DSM program lost margins and shareholder incentives), and IRP costs incurred by the utilities and approved by the PUC, either through a surcharge or through their base rates.

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See “Other regulatory matters—Demand-side management programs—agreements with the Consumer Advocate” in HEI’s MD&A, which includes a discussion of the electric utilities’ residential and commercial and industrial load management programs and of the agreements between the utilities and the Consumer Advocate concerning caps on the recovery of lost margins and shareholders incentives.

Incremental IRP costs are deferred until approved for recovery, at which time they are amortized to expense. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2005 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 decision and order (D&O) approving recovery of the costs. HECO completed recovery of its 2004 incremental IRP costs in August 2005 and MECO is scheduled to complete recovery of its 2004 costs in June 2006. In HECO’s 2005 test year rate case, the parties to the rate case reached a settlement agreement to include $0.6 million for IRP costs in base rates. The PUC issued its interim D&O in HECO’s rate case granting an increase effective September 28, 2005, at which time HECO’s IRP costs will be recovered through base rates, and the separate surcharge for recovery is discontinued, pending the PUC’s final D&O. The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred during the 1995-2004 period, and the PUC’s decision is pending on this matter. As of December 31, 2005, 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 $18 million. HECO and MECO expect to begin recovering their incremental 2005 IRP costs incurred through September 28, 2005 and December 31, 2005, respectively, subject to refund with interest, following the filing of actual 2005 costs (which is expected to occur in late March or early April 2006).

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’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. 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.

In September 2003, the PUC opened a docket to commence HECO’s third IRP (IRP-3). 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 were requested in HECO’s rate increase application, which was filed in November 2004. The energy efficiency DSM programs were bifurcated from the rate case into a separate Energy Efficiency Docket, which is still pending. 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 (see “Certain factors that may affect future results and financial condition-Consolidated-Competition-Distributed generation proceeding” in HEI’s MD&A). Also on the supply-side, HECO and Kalaeloa Partners, L.P. (Kalaeloa) executed amendments to the Kalaeloa PPA, under which Kalaeloa now provides

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28 megawatts (MW) of additional firm capacity (see FIN 46R discussion in Note 1 to HECO’s Consolidated Financial Statements).

HECO’s gross peak demand was 1,250 MW in 2002, 1,284 MW in 2003 and 1,327 MW in 2004. The gross peak demand of 1,327 MW in 2004 was 20 MW higher than the projected peak for 2004. Although the gross peak demand in 2005 decreased to 1,273 MW, demand for electricity on Oahu is projected to increase. In October 2004, November 2005 and January 2006, HECO issued a public request that its customers voluntarily conserve energy as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in November 2005 and January 2006, HECO remotely turned off water heaters of a number of residential customers who participate in its Energy Scout load-control program.

For a discussion of HECO’s 2005 and 2006 Adequacy of supply letters, see “Integrated resource planning, requirements for additional generating capacity and adequacy of supply” in HEI’s MD&A.

On October 28, 2005, HECO filed its IRP-3, which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation. IRP-3 included a potential wind energy project above HECO’s Kahe power plant. However, HECO currently is reviewing other potential sites, such as Kahuku, due to the Mayor of Honolulu’s opposition to the Kahe project site.

In June 2005, HECO filed with the PUC an application for approval of funds to build a new nominal 100 MW simple cycle combustion turbine generating unit at Campbell Industrial Park on Oahu, the site of three other existing power plants, each owned and operated by an IPP (AES Hawaii, Inc., Kalaeloa and HPower). Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, operating mainly between the weekday peak electricity demand periods or during times when other generating units are not available. The air permit application for the unit, filed in October 2003 and currently under review by the Department of Health of the State of Hawaii (DOH), requests approval to burn naphtha or diesel and specifies that the unit will have the ability to convert to using biofuels, such as ethanol, when they are commercially available. On December 15, 2005, HECO signed a contract with Siemens for the right to purchase up to two combustion turbine units. The contract allows the Company to terminate the contract at a specified payment amount if necessary combustion turbine (CT) project approvals are not obtained.

The generating unit application also requests approval to build an additional 138 kilovolt (kV) transmission line approximately two miles long, within and adjacent to Campbell Industrial Park, to more reliably transmit power from the new and existing generating units to the Oahu electric grid. Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $137 million. As of December 31, 2005 accumulated project costs for planning, engineering, permitting and AFUDC amounted to $2.7 million. HECO has prepared a draft Environmental Impact Statement (EIS) for the proposed project. Notice of the availability of the draft EIS was published on February 8, 2006 and the public comment period ends on March 25, 2006.

In a related application filed with the PUC in June 2005, HECO requested approval for an approximately $11.5 million package of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. These measures include a base electric rate discount for those who live near the proposed generation site, additional air-quality monitoring stations, a fish monitoring program and the use of recycled instead of potable water in Kahe power plant’s operations.

In July 2005, the Consumer Advocate filed Preliminary Statements of Position on HECO’s Campbell Industrial Park generating unit and transmission line additions application and community benefits application. Also in July 2005, HECO filed memoranda in response opposing the Consumer Advocate’s recommendations to suspend the two applications, suspend the start of the procedural schedule for both applications until after the filing of the IRP-3 (which was filed on October 28, 2005), and consolidate the applications.

In September 2005, the PUC suspended HECO’s Campbell Industrial Park generating unit and transmission line additions application to allow more time to review the application. Also in September 2005, the PUC ordered HECO and the Consumer Advocate to submit a stipulated prehearing order for the community benefits application. In January 2006, the PUC granted an environmental group’s motion to intervene and a neighboring business entity’s motion to participate in the generating unit and transmission line application, and ordered HECO, the Consumer Advocate and the other parties (the environmental group and the business entity) to submit a stipulated prehearing order by March 13, 2006.

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In addition to the 100 MW simple-cycle combustion turbine anticipated to be added in 2009, IRP-3 also includes plans to build a 180 MW coal unit in 2022. However, the report notes there is flexibility to allow HECO to modify its plan in response to changing market conditions and to also consider alternative generation technologies should they 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 (2006-2025).

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000. In April 2004 and 2005, MECO filed with the PUC its IRP evaluation reports, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

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 (currently planned to be added in 2011), 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). 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 December 2005, Maalaea Unit 13, a 12.34 MW diesel generator suffered an equipment failure. The unit is not expected to be available for service until approximately June 2007. MECO’s Maui system should have sufficient installed capacity to meet the forecasted loads, except that the Maui system may not have sufficient capacity at times in the event of an unexpected outage of its largest unit, until Maalaea Unit 13 returns to service. MECO intends to implement appropriate mitigation measures to overcome insufficient reserve capacity situations.

MECO’s third IRP is scheduled to be filed with the PUC in October 2006.

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

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 CTs at its Keahole power plant site and proceeding in parallel with a PPA with Hamakua Energy Partners, L.P. (HEP, formerly Encogen Hawaii, L.P.) for a 60 MW (net) dual-train combined-cycle (DTCC) facility.

The HEP 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” and “HELCO power situation” in Note 11 to HECO’s Consolidated Financial Statements. HELCO has deferred the retirements of some of its older generating units. Subject to obtaining zoning approval and obtaining all other necessary permits and approvals, HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009 or earlier. 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) and HEP.

HELCO’s third IRP is scheduled to be filed with the PUC by December 31, 2006.

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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 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 abandonment. 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.

Significant capital projects include HELCO’s Keahole power plant expansion project, including ST-7, HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements), MECO’s Maalaea and Waena power plant expansion projects, and HECO’s $25 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 has also requested approval from the PUC to install a new generating unit in Campbell Industrial Park (an approximately 100 MW combustion turbine scheduled for commercial operation in 2009) and a two mile long 138 kV overhead transmission line to provide additional transmission capacity for the new generating unit as well as for existing units at Campbell Industrial Park. See preceding discussion in “Integrated resource planning and requirements for additional generating capacity.”

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, 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 utilizes a “clean coal” technology and 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. In 2003, HECO consented to AES Hawaii’s proposed refinancing and received consideration for its consent, primarily in the form of a PPA amendment that reduced the cost of firm capacity retroactive to June 1, 2003, which benefit is being passed on to ratepayers through a reduction in rates. AES Hawaii also 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.

In October 1988, HECO entered into an agreement with Kalaeloa, a limited partnership whose sole general partner was an indirect, wholly-owned subsidiary of ASEA Brown Boveri, Inc. (ABB), which through affiliates, contracted to design, build, operate and maintain the facility. The ownership of Kalaeloa was subsequently restructured. 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 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, and is designed to sell sufficient steam to be a QF. On October 12, 2004, HECO and Kalaeloa executed two amendments to the PPA: 1) Confirmation Agreement Concerning Section 5.2B(2) Of PPA And Amendment No. 5 To PPA (Amendment No. 5), and 2) Agreement For Increment Two Capacity And Amendment No. 6 To PPA (Amendment No. 6). Amendment No. 5 confirms that Kalaeloa’s facility is able to deliver 189 MW of capacity and sets the capacity payment rate for capacity above 180 MW at $112 per kilowatt per year. 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. Amendment Nos. 5 and 6 became

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effective on September 28, 2005, when HECO received an interim D&O allowing the recovery of the costs of the additional 29 MW (subsequently revised to 28 MW) of additional capacity (see FIN 46R discussion in Note 1 to HECO’s Consolidated Financial Statements). Kalaeloa currently supplies HECO with 208 MW of firm capacity.

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 (HPower). The HPower facility currently supplies HECO with 46 MW of firm capacity. Under the amendment, 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.

The PUC has allowed rate recovery for the firm capacity and purchased energy costs related to HECO’s three major PPAs that provide a total of 434 MW of firm capacity, representing 26% of HECO’s total net generating and firm purchased capacity on Oahu as of December 31, 2005. The PUC also has allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs.

HELCO and MECO PPAs. As of December 31, 2005, HELCO and MECO had PPAs for 90 MW and 16 MW (includes 4 MW of system protection) of currently available firm capacity, which PPAs have been approved by the PUC.

HELCO has a 35-year PPA with PGV for 30 MW of firm capacity from its geothermal steam facility expiring on December 31, 2027. Since April 2002, PGV’s output has been reduced. In 2005, PGV generally exported to HELCO between 25 MW and 30 MW. If PGV does not provide the contracted 30 MW of capacity, the PPA provides for annual availability sanctions, which amounted to $0.7 million, $0.2 million, $0.1 million, and $0.1 million for 2002, 2003, 2004 and 2005, respectively. In 2005, PGV re-drilled an existing well, and drilled for a new production and a new injection well. As a result, PGV can export 30 MW to HELCO with all of its wells and converters in service. PGV has indicated its intent to pursue improvements to the plant to increase its capacity by 8 MW, and to pursue negotiations with HELCO for a new or amended PPA.

On October 4, 1999, HELCO entered into a PPA with Hilo Coast Power Company (HCPC) effective January 1, 2000 through December 31, 2004, whereby HELCO purchased 22 MW of firm capacity from HCPC’s coal-fired facility. HELCO terminated the PPA as of January 1, 2005.

In October 1997, HELCO entered into an agreement with Encogen, which has been succeeded by HEP. 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. In 2000, HEP began providing HELCO with firm capacity. In June 2001, HEP demonstrated 60 MW of output from the facility. Subsequently, the output deteriorated due to technical problems, but returned to providing 60 MW in 2003.

HELCO purchases energy on an as-available basis from a number of nonutility generators. Wailuku River Hydroelectric L.P., the owner of a 12.1 MW run-of-the-river hydroelectric facility, has an existing contract to provide HELCO with as-available power through May 2023.

Apollo Energy Corporation (Apollo), the owner of a 7 MW 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). HELCO and Apollo reached agreement on a PPA on October 13, 2004. The PPA enables Apollo to repower its existing facility, and install an additional 13.5 MW of capacity, for a total windfarm capacity of 20.5 MW. The PUC approved the PPA on March 10, 2005. On September 7, 2005, Apollo informed HELCO that its wind turbine supplier will not be able to supply any wind turbines to the project in 2005 or 2006, and any delivery in 2007 is not yet known. Apollo is claiming an event of force majeure under the PPA, since the PPA requires that Apollo’s windfarm meet an in-service date which is two years following the date of receipt of a non-appealable PUC approval order. HELCO is seeking information from Apollo regarding its claim of force majeure.

On December 30, 2003, HELCO and Hawi Renewable Development, LLC (HRD) entered into a PPA under which HRD would sell energy from an expanded wind farm (approximately 10.6 MW) at HRD’s 5 MW wind farm site. 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. HELCO expects to purchase as-available energy from the HRD wind farm beginning in 2006.

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

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constraints. On June 28, 2005, MECO and HC&S agreed to extend the PPA through December 31, 2011, and from year to year thereafter, subject to termination on or after December 31, 2011 on not less than two years prior written notice by either party. MECO informed the PUC of the PPA extension by letter dated July 27, 2005.

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 PUC approved the PPA on March 18, 2005.

On May 10, 2005, MECO entered into a PPA with Makila Hydro, LLC (Makila) for the purchase of as-available energy from an existing 0.5 MW hydro electric plant, which Makila is refurbishing. The PPA was submitted to the PUC for approval on June 28, 2005.

The PUC has 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.

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 of rates and issues relating to the ECA clause below under “Rates,” and “Certain factors that may affect future results and financial condition–Electric utility–Regulation of electric utility rates” and “Material estimates and critical accounting policies–Electric utility–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 Chinese, Vietnamese 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 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 Products Company (Chevron) and Tesoro Hawaii Corp. (Tesoro) with no material changes in the primary commercial arrangements including volumes and pricing formulas. The PUC approved these contract extensions in December 2004. The PUC 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 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.

In March and April of 2004, HECO, HELCO and MECO executed 10-year extensions of 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 electric utilities pay market-related prices for diesel and MSFO supplied under these agreements.

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. This agreement has been informally extended on a year-by-year basis since a second amendment to the contract is currently being negotiated.

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

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The following table sets forth the average cost of fuel oil used by HECO, MECO and HELCO to generate electricity in the years 2005, 2004 and 2003:

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 2005, 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 36% of HELCO’s fuel consumption. MSFO made up the remainder of the fuel consumption of MECO and HELCO. 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. By the spring of 2005, the prices of LSFO, MSFO and diesel rose above the levels reached at the end of 2004, reflecting demand supported by continued strong economic growth in the U.S. and China, and continued geopolitical uncertainty. Elevated price levels continued into the later part of the year as hurricanes Katrina and Rita seriously damaged U.S. Gulf crude oil and natural gas production facilities and caused a significant, if temporary, loss in regional refinery processing capability. Thus, the average prices paid by the utilities in 2005 for LSFO, MSFO and diesel averaged approximately 30%, 33% and 37%, respectively, above the average price paid for that grade of fuel in 2004. 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.

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. The contracts provide for the employment of a double-hull bulk petroleum barge (since 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 HPower, 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. HEP energy prices vary primarily with HELCO’s diesel costs.

The Company estimates that 79.5% of the net energy generated and purchased by HECO and its subsidiaries in 2006 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 generally maintains an average system fuel inventory level equivalent to 35 days of forward consumption. HELCO and MECO generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and HEP require that they maintain certain minimum fuel inventory levels.

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Transmission systems

HECO has 138 kV transmission and 46 kV sub-transmission lines. HELCO has 69 kV transmission and 34.5 kV transmission and sub-transmission lines. MECO has 69 kV transmission and 23 kV sub-transmission 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 sub-transmission 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 (as of December 31, 2005) located in West Oahu (1,055 MW); Waiau, adjacent to Pearl Harbor (481 MW); and Honolulu (107 MW). HECO also leases nine 1.64 MW generating units that provide a total of 14.8 MW (net) of firm power and are located at two substation sites and at HECO’s Iwilei tank farm. HECO’s non-firm power sources (approximately 28 MW) are located primarily in West Oahu. HECO transmits power to its service areas on Oahu through approximately 220 miles of overhead and underground 138 kV transmission lines (of which approximately 8 miles are underground) and approximately 521 miles of overhead and underground 46 kV sub-transmission lines. See “East Oahu Transmission Project (EOTP)” in Note 11 to HECO’s Consolidated Financial Statements for a further discussion of the transmission system and the EOTP.

HELCO system. HELCO serves the island of Hawaii’s electricity requirements with firm capacity (net) generating units (as of December 31, 2005) located in West Hawaii (77 MW) and East Hawaii (195 MW). HELCO’s non-firm power sources total 24 MW, but are expected to increase in 2006 from additional wind power. 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 (as of December 31, 2005) located on the island of Maui (233 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), which was approved by the PUC in March 2005. 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 86 miles of 23 kV overhead lines.

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 “Electric utility–Results of operations–Most recent rate requests,” “Certain factors that may affect future results and financial condition–Electric utility–Regulation of electric utility rates” and “Material estimates and critical accounting policies–Electric utility–Electric utility revenues” in HEI’s MD&A.

Public Utilities Commission of the State of Hawaii

Carlito P. Caliboso (an attorney previously in private practice) continues to serve as Chairman of the PUC (term expiring June 30, 2010). Also serving as commissioners are Janet E. Kawelo (whose term expires June 30, 2006 and who previously served as the Deputy Director for the State Department of Land and Natural Resources) and Wayne H. Kimura (whose term expires June 30, 2008 and who previously served as State Comptroller with the State Department of Accounting and General Services).

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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.

Competition

See “Certain factors that may affect future results and financial condition–Consolidated–Competition–Electric utility” 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.

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 a policy of prudent avoidance, 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 “Electric utility–Results of operations–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, Item 1A. Risk Factors, 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, AES Hawaii, 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 claims that it has liability for the incident and responded to the demand asserting its defenses. In addition, HECO has insurance coverage (over a deductible amount).

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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, 2005, ASB was the third largest financial institution in the State of Hawaii based on total assets of $6.8 billion and deposits of $4.6 billion. In 2005, ASB’s revenues and net income from continuing operations amounted to approximately 18% and 51%, respectively, of HEI’s consolidated amounts, compared to approximately 19% and 38% in 2004 and approximately 21% and 48% in 2003, 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 to insure that ASB would have a capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 31, 2005, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28.3 million. ASB is subject to OTS regulations on dividends and other distributions applicable to financial institutions and ASB must receive a letter of non-objection from the OTS 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 earning assets (loans receivable and investment and mortgage-related securities) and the interest expense incurred on costing 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 affecting ASB’s operating results include fee income, provision for loan losses, gains or losses on sales of securities available-for-sale, and noninterest expenses.

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 2005 as ASB has been undergoing a transformation, involving four major lines of business, to become a full-service community bank serving both consumer and commercial business customers. The transformation project will require continued investment in people and technology. ASB’s ongoing challenge is to increase revenues faster than expenses.

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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 (except for common equity, which is calculated using the average month-end balances).

In 2005, the average loans receivables increased by $289.5 million, or 9.3%, over 2004 average loans receivable due to the continued strength in the Hawaii economy and real estate market. The average residential mortgage portfolio for 2005 grew by $139.8 million, or 5.6%, over the 2004 average residential mortgage portfolio. Average commercial real estate loans, net of undisbursed loan funds, increased $51.1 million, or 24.2%, over 2004 primarily due to commercial construction real estate loans originated in 2005 of $39.8 million. ASB’s average commercial portfolio increased by $65.6 million, or 23.1%, during 2005 primarily due to higher commercial loan originations. The average consumer loan portfolio increased $22.5 million, or 10.3%, from 2004. ASB’s average deposit balances increased by $339.7 million, or 8.3%, during 2005, enabling ASB to replace other borrowings and to help fund loan growth.

In 2004, the low interest rate environment and continued strength in the Hawaii real estate market also resulted in an increase in average loans receivables. The average residential mortgage portfolio for 2004 grew by $37.7 million, or 1.5%, over the 2003 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 commercial 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 deposits increased during the year as ASB continued to attract deposits. Average other borrowings also decreased during 2004 as the increase in average deposits enabled ASB to repay some of its higher costing other borrowings.

Asset/liability management

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

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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 earning assets and costing liabilities for the years ended December 31, 2005, 2004 and 2003.

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.

Noninterest income

In addition to net interest income, ASB has various sources of noninterest income, including fee income from credit and debit cards and fee income from deposit liabilities and other financial products and services. Noninterest income totaled approximately $56.9 million in 2005, $57.2 million in 2004 and $58.5 million in 2003. Noninterest income for 2005 was relatively stable when compared to 2004. The decrease in noninterest income for 2004 was due to net gains on sales of securities totaling $4.1 million in 2003 compared to a net loss of $0.1 million in 2004, partially offset by higher fee income in 2004.

Lending activities

General. Loans and mortgage-related securities of $6.2 billion represented 90.3% of total assets as of December 31, 2005, compared to $6.2 billion, or 91.3%, and $5.8 billion, or 88.8%, as of December 31, 2004 and 2003, respectively. ASB’s loan portfolio consists primarily of conventional residential mortgage loans.

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The following table sets forth the composition of ASB’s loan and mortgage-related securities portfolio as of the dates indicated: