Generation statistics

The following table contains certain generation statistics as of December 31, 20022003 and for the year ended December 31, 2002.2003. 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.

In 2002, a 1,500 KW hydroelectric unit owned by HELCO was damaged and HELCO is presently exploring options to rebuild or replace the unit.

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.

HELCO’s management is concerned about the possibility of power interruptions as a result of the current operating status of various IPPs supplying power to it and the condition and performance of aging generators on the

HELCO system that were intended to be operated less frequently once CT-4 and CT-5 were installed.installed at HELCO’s Keahole power plant. (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, subject towhich were approved by the PUC approval,in November 2001, under which HECO’s three commercial and industrial DSM programs and two residential DSM programs would be continued until HECO’s next rate case, which, under the agreements, HECO committed to file using a 2003 or 2004 test year and following the PUC’s rules for determining the test year. In August 2003, HECO and the Consumer Advocate agreed, and the PUC approved, a delay in the filing of HECO’s next rate case, with the result that the rate case would be filed using a 2005 test year. 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, HELCOMECO and MECOHELCO 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” at page 955 in HECO’s MD&A. All of the electric utilities’ existing DSM programs are energy efficiency programs designed to reduce the consumption of electricity.

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. The Consumer Advocate has objected to the recovery of $1.9 million (before interest) of the $8.5 million of incremental IRP costs incurred during the 1995-1998 and 2001 period, and the PUC’s decision is pending on this matter. The Consumer Advocate has not yet filed its position on the recovery of the $1.5 million of integrated resource planning costs the electric utilities incurred from 1999 through 2000. Procedural schedules for the IRP cost proceedings have been established with respect to the 1999-20032000-2003 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 $2.5 million (before interest) of the $10.3 million of incremental IRP costs incurred during the 1995-2002 period, and the PUC’s decision is pending on this matter.

The electric utilities have completed the recovery of their respective 1995 through 20002001 incremental IRP costs through a surcharge on customer bills, subject to refund with interest.

In addition, HECO completed the recovery of its 20012002 incremental IRP costs in June 2002,May 2003, subject to refund with interest. MECO is scheduled to complete the recovery of its 20012002 incremental IRP costs by August 2003.May 2004. As of December 31, 2002,2003, the amount of revenues the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $16$17 million. HECO

and MECO expect to begin recovering their incremental 20022003 IRP costs, subject to refund with interest pending a final D&O, following the filing of actual 20022003 costs (which is expected to occur in late March or early April 2003)2004).

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’ sHELCO’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 IRPIRP..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 nextthird 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. AThe updated second IRP also includes plans to add a second 107 MW simple-cycle combustion turbine is scheduled to be added in 2015, and in 2016, a conversion unit 105 MW steam turbine is scheduled to be added 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 where they are an 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 load management programs scheduled for implementation in 2004 (i.e., a DispatchableResidential Direct Load Control Program and a Commercial and Industrial Load Program and a Residential Direct Load Control Program). HECO plans to filefiled applications with the PUC requesting approval of these two load management programs in June and December 2003, respectively.

In September 2003, the PUC opened a docket to commence HECO’s third IRP, which HECO expects to file by March 2005 and expects will require multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP) and central station generation. Given the second quarter of 2003.lead times needed for permitting and regulatory approvals, in October 2003, HECO submitted a covered source permit application with the DOH for a 107 MW simple cycle combustion turbine in Campbell Industrial Park. The application specifies that the unit would use diesel fuel oil or naphtha, with the ability to convert to a bio-fuel, like ethanol or bio-diesel, when it becomes commercially practicable.

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. MECO plans to work withIn February 2004, the parties to the proceeding and attempt to reachfiled a stipulation for PUC approval to expedite the proceeding, close the docket, and establish a schedule for MECO’s next IRP annual evaluation report and program implementation schedule and its next IRP. The stipulation provided that MECO would submit IRP evaluation reports and program implementation schedules by April 2004 and April 2005 and its next (third) IRP by October 2006. The PUC’s decision on the stipulation is pending.

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 receive 20 MW of wind energy in 2004)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 the seconda 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 earlySeptember 2006 (assuming receipt in early 2004 of the necessary air permit, for which an application was submitted in December 2001).

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. MECO does not plan to proceed with a new energy efficiency DSM program at this time, and MECO is in the process of evaluating the load management DSM programs, and will determine at a later date the need for and timing of filing load management DSM program applications.

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. HELCO plans to work withIn January 2004, the parties to the proceeding and, similar to HECO’s IRP, attempt to reachfiled a stipulation for PUC approval to expedite the proceeding closeand in February 2004 the PUC approved the stipulation, closed the docket and establish a schedule for HELCO’s nextordered HELCO to submit its IRP annual evaluation report and program implementation scheduleby the end of March 2004 and its next 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.

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, have been delayed.delayed, but are now expected to be fully operational by December 31, 2004. (See “HELCO power situation” in Note 11 ofto 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 now purchaseshas been purchasing 22 MW of firm capacity from HCPC’s coal-fired facility under a newrestated and amended PPA, as a resultthe term of the delays in adding new generation.which runs through 2004, but automatically extends for one-year periods thereafter, unless terminated prior to an extension period by either party. HELCO also has deferred the retirements of some of its older generating units. IfAfter CT-4 and CT-5 are installed, this would extendHELCO’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 third phase of its DTCC unit or othernext firm capacity additions until sometime after 2012.

addition is the 2017 timeframe. The timing of the need for additional new generation may change, however, based on factors such as the availability of permitting for the Keahole installations, 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 HCPC. (See the discussion of HELCO power purchase agreements in “Nonutility generation.”)

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.

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) and land use permits from the Hawaii Board of Land and Natural Resources (BLNR). 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 and HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements), the Company has two other significant capital projects currently in progress. In 2003, construction commenced on a $37 million project for an underground fuel pipeline that will transport fuel from an oil refinery at Campbell Industrial Park to HECO’s Waiau power plant. This project is scheduled for completion in late 2004. Also in 2003, planning continued 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.

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) and 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 are in discussions regarding a possible refinancing of the facility by AES Hawaii, and concerningreached agreement on the terms upon which HECO would be willing to consent to thea proposed refinancing. A letterUnder the agreement, which was contingent on obtaining certain PUC approvals and completion of intent has been signed, but by its terms it is non-binding and the parties are proceeding to negotiate definitive documents. The arrangements addressed in the letter of intent contemplate thatrefinancing, HECO will receivereceived consideration for its consent, primarily in the form of a PPA amendment that willreduces the cost of firm capacity supplied to HECO pursuant to the PPA, retroactive to June 1, 2003. The benefit ratepayers. If definitive documents acceptableof the firm capacity cost reduction, totaling approximately $2.9 million annually for the remaining term of the PPA, is being passed on to both parties are negotiated, they will beratepayers through a reduction in rates. AES Hawaii also has granted HECO an option, subject to severalcertain conditions, includingto 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 approval ofissued a D&O approving the PPA amendment and completionthe establishment of a rate adjustment (lowering rates) on short notice, and, on July 9, 2003, the PUC issued a D&O clarifying its July 1, 2003 D&O. On July 31, 2003, the proposed refinancing.refinancing was completed and capacity payments were reduced, retroactive to June 1, 2003.

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.

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.

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 24%25% of HECO’s total net generating and firm purchased capacity on the island of Oahu as of December 31, 2002.2003. The PUC also has approved and allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs.

MECO and HELCO power purchase agreements.PPAs.As of December 31, 2002,2003, MECO and HELCO had PPAs for 16 MW (includes 4 MW of system protection) and 88109 MW of currently available firm capacity, respectively.

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. In March 1998, an HC&S unit failed and HC&S lost 10 MW of generating capacity. HC&S replaced the unit and put it into operation in the second quarter of 2000. HC&S, however, has had some difficulties in meeting its contractual obligations to MECO infor the years 2000 2001 and 2002through 2003 due to operational constraints that led to several claims of force majeure by HC&S. The constraints have been primarily due to an extended drought condition on Maui that impacts HC&S’&S’s irrigation pumping load for its sugar cane operations. There has also been a higher than normal reduction in energy produced due to other equipment outages. With the completion of some maintenance activities and the easing of drought conditions, HC&S returned to full contract capacity of 16 MW in late October 2002. On January 23, 2001, MECO rescinded a December 27, 1999 PPA termination notice that it had sent to HC&S and agreed with HC&S that neither party would issue to the other a notice of termination prior to the end of 2002. On June 14, 2002, MECO and HC&S agreed that neither party will give written notice of termination under the terms of the PPA, such that the PPA terminates prior to December 31, 2007. As a result, 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’years prior written notice by either party.

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 has been in decline since the middle of 2002 and PGV was ablereduced to produce only about 6 MW of firm capacity infrom April 2002 compared to the 30 MW the company contracted to provide to HELCO.March 2003. The loss of generation has beenwas 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 itsPGV’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 reachedPGV’s capacity levels ofis currently between 2025 to 2528 MW. PGV is in the process of obtainingobtained a permit from the DOH for the new injection well.well in March 2003. Without the new injection well, PGV is currently producingwas able to produce only about 10 to 11 MW due to the high brinemoisture content comingof the steam from the new source well. PGV is assessing whether to drill another source well or to install new generation equipment geareddesigned to utilize the excess brine.lower quality steam. While PGV indicates it is seekingevaluating its options to enable it to restore its 30 MW commitment to HELCO as soon as possible, HELCO cannot predict when PGV will reachbe 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 ending March 31, 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, will be assessed against PGV in 2004. Constellation Energy, parent company of PGV, has solicited preliminary indications of interest from potential bidders in order to explore the possibility of putting PGV up for sale. HELCO is not aware if and when a sale will be completed.

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 after two years, whereby HELCO purchases 22 MW of firm capacity from HCPC’s coal-fired facility. The PPA extends for one-year periods thereafter, unless terminated prior to an extension period. The PPA was amended on November 5, 1999.1999, which extended the November 30, 1999 deadline for obtaining PUC approval of the PPA. The PUC approved the PPA, as amended, on December 7, 1999.

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 facility is designed to sell sufficient steam to be a QF. 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., which is a Florida-based energy company and parent company of Tampa Electric Company, a regulated electric utility. TECO Energy Inc. 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 hashad been limited to 55-57 MW in early 2003. Hamakua Partners has requested maintenance outages to correct the problems and returned to providing 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. Jones has tentatively scheduledstated that the outages forbankruptcy filing will have no impact on Hamakua Partners’ ability to meet its contractual commitments. Jones has been attempting to sell its interest in Hamakua Partners under the supervision of the bankruptcy court. An auction among the qualified bidders was held on February 23, 2004 and the court held a hearing on February 24, 2004. By Order dated March 2, 2004, the court approved a motion to sell substantially all of the assets of Jones to United States Power Fund L. P. (USPF) and April 2003.directed the appropriate parties to implement the sale. HELCO will be working with Jones and USPF to evaluate the terms and conditions of the sale and any implications of the sale on the PPA with Hamakua Partners.

HELCO purchases energy on an as-available basis from a number of nonutility generators. The largest include an 11 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 and 2003, but final agreement has not been reached on variouscertain technical and interconnection cost issues. Throughout 2002, the PUC has been kept informed through submittal of status of negotiations letters.

On August 17, 1999, HELCO entered into a PPA with Kahua Power Partners LLC (KPP) for the purchase of as-available energy from KPP’s proposed 10 MW windfarm. The PPA was amended by Amendment No. 1 dated April 4, 2000. The PUC approved the PPA, as amended, on June 1, 2001. KPP hasdid not, begun construction ofhowever, construct its windfarm. GE Wind Energy completed the acquisition of certain assets of Enron Wind Corporation in May 2002, including the proposed KPP project. On October 7, 2003, GE Wind Energy andassigned the KPP PPA to Hawi Renewable Development, Inc. (HRD) have since indicated they are in discussions. On December 9, 2003, HELCO terminated the KPP PPA pursuant to sellHRD’s notice that it does not plan to develop that wind farm, and its request that the windfarm project to HRD.PPA be terminated.

On January 8, 2001, HELCO entered into a PPA with 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. Due to transmission line limitations, the output of HRD would behave been limited to 3 MW if the KPP windfarm iswere connected to the electric grid through the same 34.5 kVkilovolt (kV) line.

On December 30, 2003, HELCO and HRD are in negotiations forHawi Renewable Development, LLC (HRD LLC) entered into a new PPA under which HRD LLC would sell energy from an expanded windfarmwind farm (approximately 10.6 MW) at HRD’s 5 MW wind farm site (which can accommodate the proposed windfarm site, ifexpanded wind farm). Since the KPP projectwind farm would not be built, it is cancelled.anticipated that the output of the 10.6 MW wind farm would not be limited by another wind farm on the 34.5 kV line (although the output of the 10.6 MW wind farm may be limited on occasion due to other factors). PUC approval of the PPA is pending.

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.

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 HECO’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 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 Tesoro Hawaii Corp. dba BHP Petroleum Americas Refining Inc. (Tesoro)(BHP). TheseSubsequently, 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. HECO is currently negotiating with its fuel suppliers for new long-term LSFO supply agreements to replace those expiring at the end of 2004.

HECO, MECO and HELCO executed joint fuel supply contracts with Chevron and TesoroBHP (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 permits the electric utilities to include fuel costs incurred under these contracts in their respective ECA clauses. The electric utilities pay market-related prices for diesel and MSFO supplied under these agreements. HECO, HELCO and MECO are currently negotiating with its fuel suppliers for new long-term contracts for the supply of diesel and MSFO to replace those expiring at the end of 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, 2003.

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 2003, 2002 2001 and 2000:2001:

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 2002,2003, over 99% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 73%75% of MECO’s and 32%29% 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. 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. Thus the annual prices paid by the utilities for LSFO, MSFO and diesel averaged approximately 25%, 13% and 21%, respectively, above the average price for that grade of fuel in 2002. Even though the average price per barrel was lower in 2002 than 2001, the prices of LSFO, MSFO and diesel trended higher during 2002 from the level prevailing at the end of 2001. The utilities’ price for MSFO averaged approximately 3% above the average price in 2001, while the2002 price for LSFO and diesel averaged approximately 7% and 16%, respectively, below the average price in 2001, while the price for MSFO averaged approximately 3% above the average price in 2001.

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 new double-hull bulk petroleum barge at freight rates approximately the same as prevailed under predecessor transportation contracts with HITI. The new 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. 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, PGV and HCPC 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 77%78% of the net energy generated and purchased by HECO and its subsidiaries in 20032004 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, however, maintains an inventory of fuel oil in excess of one month’s supply. HELCO and MECO 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.

Transmission systems

HECO has 138 kilovolt (kv)kV transmission and 46 kvkV subtransmission lines. HELCO has 69 kvkV transmission and 34.5 kvkV subtransmission lines. MECO has 69 kvkV transmission and 23 kvkV subtransmission lines on Maui and 34.5 kvkV transmission lines on Molokai. Lanai has no transmission lines and uses 12 kvkV 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,kV, 69 kvkV or 138 kvkV 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 (1,057(1,027 MW); Waiau, adjacent to Pearl Harbor (499(481 MW); and Honolulu (113(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 kvkV transmission lines (of which approximately 8 miles are underground) and approximately 570 miles of overhead and underground 46 kvkV 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) for its revised East Oahu Transmission Project. See “Oahudiscussion in Note 11 to HECO’s Consolidated Financial Statements.

In March 2004, approximately 40,000 of HECO’s customers in the Honolulu//East Oahu area, including Waikiki, lost power for forty-five minutes to one and one-half hours. The areas affected are served by the Pukele substation. One of the two transmission system”lines serving the Pukele substation was out for scheduled maintenance when the second