AGREEMENT FOR INCREMENT TWO CAPACITY AND AMENDMENT NO. 6 TO POWER PURCHASE AGREEMENT BETWEEN HAWAIIAN ELECTRIC COMPANY, INC. AND KALAELOA PARTNERS, L.P.

EX-10.4 10 dex104.htm AGREEMENT FOR INCREMENT TWO CAPACITY AND AMENDMENT NO 6 Agreement for Increment Two Capacity and Amendment No 6

HECO Exhibit 10.4

AGREEMENT FOR INCREMENT TWO CAPACITY AND

AMENDMENT NO. 6 TO POWER PURCHASE AGREEMENT

BETWEEN

HAWAIIAN ELECTRIC COMPANY, INC.

AND KALAELOA PARTNERS, L.P.

This Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement (“Increment Two Capacity Agreement”) is made and entered into as of the date of the last execution hereof, as set forth below the respective signature blocks of the parties, by and between HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation (“HECO”), and KALAELOA PARTNERS, L.P., a Delaware limited partnership (“Kalaeloa”).

RECITALS:

A. HECO and Kalaeloa entered into a Power Purchase Agreement, dated as of October 14, 1988, as amended and clarified by (i) Amendment No. 1 to Power Purchase Agreement dated as of June 15, 1989, (ii) Restated and Amended Amendment No. 2 to Power Purchase Agreement dated as of February 9, 1990, (iii) Amendment No. 3 to Power Purchase Agreement dated as of December 10, 1991, (iv) Agreement to Clarify and Interpret dated as of March 31, 1997, (v) Amendment No. 4 to Power Purchase Agreement dated as of October 1, 1999, and (vi) Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement executed concurrently herewith, (as so amended and clarified, the “Power Purchase Agreement”), which provides for, among other things, the sale by Kalaeloa and the purchase by HECO of electric energy and capacity from Kalaeloa’s combined cycle oil-fired cogeneration facility located at Barbers Point, Oahu, Hawaii.

B. HECO and Kalaeloa have executed certain letter agreements clarifying the interpretation and/or application of certain provisions of the Power Purchase Agreement, some of which have been incorporated into and superseded by the Increment One Capacity Agreement (as defined hereinbelow).

C. Kalaeloa has commenced the M Upgrade (as defined hereinbelow), and HECO has consented to the M Upgrade pursuant to the Consent and Agreement dated as of December 31, 2003 by and between HECO and Kalaeloa.

D. Kalaeloa and HECO desire to amend the Power Purchase Agreement to provide for up to an additional twenty megawatts (20,000 KW) in capacity beyond the 189,000 KW capacity confirmed in the Confirmation Agreement Concerning Section 5.2B(2) of the Power Purchase Agreement and Amendment No. 5 to the Power Purchase Agreement referenced in Recital A above (the “Increment One Capacity Agreement”).

E. Kalaeloa has completed an assessment of the potential for trips of the entire Facility and has committed to complete certain improvements, if this Increment Two Capacity Agreement becomes effective, in order to reduce the potential for such trips of the

entire Facility, consisting of (a) certain improvements as described in the letter from Kalaeloa to HECO dated July 29, 2004, a copy of which is attached hereto as Exhibit 1, and (b) certain improvements as described in the letter from Kalaeloa to HECO dated October 8, 2004, a copy of which is attached hereto as Exhibit 2.

AGREEMENTS:

NOW, THEREFORE, in consideration of the premises and mutual agreements and covenants contained in this Increment Two Capacity Agreement and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto agree to provide for Increment Two Capacity as follows:

1.	Definitions.

Regardless of whether or not the Increment Two Capacity In-Service Date has occurred, (i) capitalized terms used in Sections 3 through 5 and 11 through 15 of this Increment Two Capacity Agreement and defined in Section 2 of this Increment Two Capacity Agreement have the respective meaning given them in Section 2, and (ii) capitalized terms used but not defined in this Increment Two Capacity Agreement have the respective meaning given to them in the Power Purchase Agreement.

2.	Regarding Article I of the Power Purchase Agreement.

Effective upon the occurrence of the Increment Two Capacity In-Service Date, Article I of the Power Purchase Agreement is deemed amended by modifying Sections 1.70 and 1.81 to read in their entirety as set forth below, and by adding the definitions set forth below as Sections 1.96 through 1.109:

1.70 Demonstrated Facility Capacity – For purposes of determining the Increment One Capacity, the maximum capacity of 189,000 KW as demonstrated by the data collected and corrected pursuant to the test conducted on April 21, 2004 through April 23, 2004 under the protocol attached as Exhibit 2 to the Increment One Capacity Agreement. For purposes of determining the Increment Two Capacity, the maximum capacity of the Facility as demonstrated by the data collected and corrected pursuant to the Acceptance Test.

1.81 New Capacity – The Increment One Capacity plus the Increment Two Capacity.

* * *

1.96 Acceptance Test – The acceptance test conducted according to the test protocol stated in the Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Post M Upgrade Case for up to 209 MW for Two CTs, a copy of which is attached to the Increment Two Capacity Agreement as Exhibit 3.

1.97 Full Plant Trip – The Unplanned Removal From Service of the Facility’s two combustion turbine generators in circumstances in which the Facility had, at any

point during the sixty (60) minutes preceding the Unplanned Removal From Service of the first of the combustion turbines to be so removed, been operating with a Net Electrical Energy Output above 180,000 KW.

1.98 Full Plant Trip (Category I) – A Full Plant Trip in which not more than twenty-five (25) minutes and no seconds elapse between the Unplanned Removal From Service of the first of the combustion turbines to be so removed during such Full Plant Trip and the Unplanned Removal From Service of the second of the combustion turbines to be so removed.

1.99 Full Plant Trip (Category II) – A Full Plant Trip (other than a Full Plant Trip (Category I)) in which not more than one hundred eighty (180) minutes and no seconds elapse between the Unplanned Removal From Service of the first of the combustion turbines to be so removed during such Full Plant Trip and the Unplanned Removal From Service of the second of the combustion turbines to be so removed.

1.100 Full Upgraded Capacity – The total of Baseline Capacity, Increment One Capacity and Increment Two Capacity.

1.101 Increment Two Capacity – The increment, at 0.85 power factor, of Demonstrated Facility Capacity up to a maximum of 20,000 KW beyond 189,000 KW.

1.102 Increment Two Capacity Agreement – The Agreement for Increment Two Capacity and Amendment No. 6 to the Power Purchase Agreement by and between HECO and Kalaeloa.

1.103 Increment Two Capacity In-Service Date – Provided the conditions precedent to the effectiveness of Section 2 and Sections 6 through 11 of the Increment Two Capacity Agreement as set forth in Section 15 thereof have been satisfied, the latter of (i) the date on which the Facility as modified by the Increment Two Capacity Upgrade satisfies the Acceptance Test and (ii) the Increment Two Rate Inclusion Date.

1.104 Increment Two Capacity Upgrade – The physical modifications to be made to the Facility so that the Facility is able to deliver the Increment Two Capacity under HECO Dispatch.

1.105 Increment Two Rate Inclusion Date – The effective date of an interim or final order (whichever is first) of the Public Utilities Commission in a HECO general rate case using a 2005 calendar year test year that includes in HECO’s base electric rates the additional purchased power costs (including the Capacity Charge for the Increment Two Capacity and the Variable O&M Component of the Energy Charge) incurred by HECO pursuant to the Increment Two Capacity Agreement.

1.106 M Upgrade – The physical modifications to the Facility authorized to be commenced pursuant to the Consent and Agreement dated as of December 31, 2003, by and between HECO and Kalaeloa.

1.107 On-peak EFOR – For each Contract Year, the ratio for the Equivalent Forced Outage Rate for the On-peak Period hours during such Contract Year (expressed as a percent) set forth in Attachment C to this Agreement, as modified by the letter dated October 30, 1997, which represents the time (in hours) during the On-peak Period hours during such Contract Year that the Facility (Baseline Capacity plus New Capacity) is unavailable for service, either totally or partially due to forced outages or deratings (other than Delay Degradation) to the total On-peak Period hours during such Contract Year calculated in accordance with the most current formula defined by NERC GADS (less adjustment for unplanned (forced) derated hours during reserve shutdown).

1.108 Prorated Shutdown Capacity – The greater of the capacity of the Facility with one of its combustion turbines not in service (as determined by the Acceptance Test) or 90,000 KW.

1.109 Unplanned Removal From Service – The unscheduled removal from service, other than for routine scheduled maintenance preapproved by HECO, of a combustion turbine generator at the Facility, but not including any such removal caused by a disturbance or condition occurring on HECO’s grid system during which the Facility could not reasonably have been expected to remain synchronized and continue operation notwithstanding the employment of Good Engineering and Operating Practices.

(1)

For purposes of this Section 1.109, Good Engineering and Operating Practices will not require that the Facility remain synchronized and continue operation through the following fault conditions:

(a)

three phase fault conditions at the Points of Interconnection lasting more than 120 milliseconds,

(b)

two phase fault conditions at the Points of Interconnection lasting more than 120 milliseconds, or

(c)

single phase fault conditions at the Points of Interconnection lasting more than 2.0 seconds.

A fault condition event shall be deemed to have ended when the voltage has recovered to and remains above 0.83 per unit (equivalent to 66.1 kV as measured line-to-ground) at the Points of Interconnection or as close as practicable thereto (which shall be deemed to be HECO’s Kalaeloa 138 kV Substation). Such voltage level shall be determined by the measurement equipment described in Section 4.G of the Increment Two Capacity Agreement. In the case where reliable data is not available from said measurement equipment, such voltage level shall be determined by interpretation or analysis of data collected from other voltage measuring equipment on the HECO grid and/or at the Facility.

(2)

For purposes of this Section 1.109, Good Engineering and Operating Practices do not require that the Facility remain synchronized and continue operation if protection relay devices that are properly set, reviewed and accepted according to Sections 2.1B or 3.2A(5) herein or Section 4.C of the Increment Two Capacity Agreement, or included in Attachment A hereto, and which operate in accordance with such specifications, have automatically removed all or a part of the Facility from service.

(3)

No Unplanned Removal From Service shall be deemed to have occurred if an operator has manually removed one or both combustion turbine generators from service because, in his considered judgment, such condition or disturbance posed an immediate threat of serious damage to an integral part of the Facility despite the fact that none of the Facility’s breakers or protection relay devices automatically removed all or part of the Facility from service, provided that an after-the-fact review of the circumstances verifies that the actions of the operator were consistent with Good Engineering and Operating Practices.

3.	HECO Conditions Precedent.

General Conditions.

HECO’s obligation to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the portion of the Capacity Charge corresponding to the Increment Two Capacity, and any and all obligations of HECO that are ancillary to that purchase and that payment, are contingent upon the following in form and substance satisfactory to HECO:

(1) The submission to HECO (or, where satisfactory to HECO, making such available for inspection by HECO) in form and substance reasonably satisfactory to HECO of documents or other evidence demonstrating that the Facility following completion of the Increment Two Capacity Upgrade, if operated and maintained in accordance with Good Engineering and Operating Practices, can be reasonably expected to have a useful life at least equal to the Term; provided that conceptual engineering design drawings and specifications of major equipment components, if available, shall be deemed to constitute such evidence;

(2) The submission to HECO (or, where satisfactory to HECO, making such available for inspection by HECO), in form and substance reasonably satisfactory to HECO, of the following on or before the Increment Two Capacity In-Service Date:

(a) Documents or other evidence that Kalaeloa obtained all required permits, licenses, approvals and other governmental authorizations needed to commence construction of each phase of the Increment Two Capacity Upgrade;

(b) Documents or other evidence that Kalaeloa has obtained all currently required permits, licenses, approvals and other governmental authorizations

needed to operate the Facility following completion of the Increment Two Capacity Upgrade;

(c) Documents or other evidence demonstrating that the Increment Two Capacity Upgrade has been completed in compliance with the terms of this Increment Two Capacity Agreement and with the information submitted pursuant to Section 3A(2) hereof, provided that such documents and evidence may be made available to HECO at the Facility rather than submitted to HECO. Evidence required under this Section shall be submitted or made available by Kalaeloa during or upon the completion of each phase of development (for example, completion of detailed engineering, completion of as-built drawings and receipt of manufacturers’ guarantee performance data). To allow HECO to evaluate the information provided by Kalaeloa, Kalaeloa shall cooperate in such physical inspections of the Facility pursuant to Section 9.1 of the Power Purchase Agreement as may be reasonably required by HECO during and after completion of the Increment Two Capacity Upgrade. In no event shall HECO’s technical review and inspection of the Facility and the Increment Two Capacity Upgrade be deemed to be an endorsement of the design thereof or as any warranty of the safety, durability or reliability of the Facility following completion of the Increment Two Capacity Upgrade nor a waiver of any of HECO’s rights;

(d) Documents or other evidence demonstrating that the improvements described in Exhibit 1 attached hereto (the “Full Plant Trip Reduction Improvements”) have been completed, provided that such documents and evidence may be made available to HECO at the Facility rather than submitted to HECO. To allow HECO to evaluate the information provided by Kalaeloa, Kalaeloa shall cooperate in such physical inspections of the Facility pursuant to Section 9.1 of the Power Purchase Agreement as may be reasonably required by HECO during and after completion of the Full Plant Trip Reduction Improvements. In no event shall HECO’s technical review and inspection of the Facility and the Full Plant Trip Reduction Improvements be deemed to be an endorsement of the design thereof or as any warranty of the safety, durability or reliability of the Facility following completion of the Full Plant Trip Reduction Improvements nor a waiver of any of HECO’s rights;

(e) Evidence of insurance coverages increased if appropriate to cover the full replacement value of the Facility following completion of the Increment Two Capacity Upgrade in the form and types of coverage for insurance policies required under the Power Purchase Agreement; and

(f) Evidence that construction of the Increment Two Capacity Upgrade is complete and that the Acceptance Test described in Section 4E of this Increment Two Capacity Agreement has been satisfactorily accomplished, and a letter from Kalaeloa stating that the Facility as modified by the Increment Two Capacity Upgrade is ready to begin producing electric energy on a commercial basis under the terms and conditions of the Power Purchase Agreement as amended and otherwise modified by this Increment Two Capacity Agreement.

Increment Two Capacity In-Service Date Condition Precedent.

Notwithstanding any other provisions of this Increment Two Capacity Agreement, HECO’s obligations under this Increment Two Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the portion of the Capacity Charge corresponding to the Increment Two Capacity, and any and all obligations of HECO that are ancillary to that purchase and that payment, are all contingent upon (1) the effectiveness of all terms of the Increment One Capacity Agreement and (2) the occurrence of the Increment Two Capacity In-Service Date.

4.	Design, Construction and Testing of Increment Two Capacity Upgrade.

General.

Except as otherwise provided in this Increment Two Capacity Agreement, Kalaeloa or its contractors shall furnish all financial resources, labor, tools, materials, equipment, transportation, supervision and other goods and services necessary to completely design and construct the Increment Two Capacity Upgrade. The design and construction of the Increment Two Capacity Upgrade shall take place using Good Engineering and Operating Practices.

Permits and License.

Kalaeloa shall be responsible for the acquisition of all permits and licenses, and the completion of all environmental review procedures, required for the construction of the Increment Two Capacity Upgrade and operation of the Facility following completion of the Increment Two Capacity Upgrade.

[Reserved.]

Status Reports.

At HECO’s request, Kalaeloa shall provide opportunities for HECO to meet with appropriate personnel of Kalaeloa or its contractors to discuss and assess the status of permitting, environmental review procedures, design, construction and operation of the Increment Two Capacity Upgrade.

Acceptance Testing and Timing.

Immediately following the completion of the Increment Two Capacity Upgrade, HECO and Kalaeloa shall conduct the Acceptance Test. Kalaeloa shall use commercially reasonable efforts to cause the Facility as modified by the Increment Two Capacity Upgrade to satisfy the Acceptance Test no later than one hundred (100) days after the commencement of the next upcoming “C” Inspection for Combustion Turbine No. 2, or such later date as to which Kalaeloa and HECO may agree by a subsequent written agreement. If the Acceptance Test is not satisfactorily completed by said deadline due solely to delay caused by HECO, then said deadline shall be extended for the time necessary to accommodate the delay to the extent caused by HECO. If the Acceptance Test is not satisfactorily completed by said deadline, then each of Kalaeloa and HECO shall have the option to declare this Increment Two Capacity Agreement

null and void, which declaration shall be in writing and shall be delivered to the other party within sixty days after said deadline (as may have been extended pursuant to this paragraph) or such longer time as HECO and Kalaeloa may agree by a subsequent written agreement.

Regarding M Upgrade

(1) Kalaeloa caused to be installed the modifications to the first combustion turbine as part of the M Upgrade during the “C” Inspection that commenced on May 2, 2004. Kalaeloa hereby notifies HECO that said modifications to the first combustion turbine have been completed and accepted by Kalaeloa. Kalaeloa has instructed Alstom Power Inc. to proceed with the modifications to the second combustion turbine to complete the M Upgrade during the next upcoming “C” Inspection for Combustion Turbine No. 2, and Kalaeloa shall notify HECO in writing by July 29, 2005 (or such later date as to which Kalaeloa and HECO may agree by a subsequent written agreement) whether the entire M Upgrade has been completed and accepted by Kalaeloa. If Alstom Power Inc. has not completed and Kalaeloa has not accepted the entire M Upgrade by said deadline, then HECO and Kalaeloa shall each have the option to declare this Increment Two Capacity Agreement null and void, which declaration shall be delivered to the other party within sixty days after said deadline (as may have been extended pursuant to this paragraph) or such longer time as Kalaeloa and HECO may agree by a subsequent written agreement.

(2) In the event Kalaeloa requires HECO to purchase the Facility pursuant to Section 3.3H of the Power Purchase Agreement, the parties agree that the phrase “original equity investment” does not include any expenses related to the M Upgrade. Kalaeloa has delivered to HECO that certain letter dated June 30, 2004, a copy of which is attached hereto as Exhibit 4, setting forth calculations of (i) the purchase price for the Facility for purposes of said Section 3.3H, which calculation does not include any expenses related to the M Upgrade, and (ii) the fair market value of the Facility for purposes of said Section 7.2B(1), similar in format to the letters from Kalaeloa to HECO dated March 31, 2000 and April 4, 1997.

Voltage Monitoring Equipment at Points of Interconnection

Kalaeloa shall reimburse HECO for the cost to purchase and install a model 7100S Power Quality Monitor manufactured by Drantez-BMI (or an equivalent power quality monitor acceptable to the parties) at the Points of Interconnection or as close as practicable thereto (which shall be deemed to be HECO’s Kalaeloa 138 kV Substation) at the 138 kV level to measure the parameters necessary to determine whether a fault condition as described in Section 1.109 of the Power Purchase Agreement has occurred and the magnitude thereof. The cost to be reimbursed by Kalaeloa to HECO for the purchase and installation of such equipment shall not exceed $15,000. Kalaeloa shall pay to HECO $7,500 of this sum within sixty (60) days of the execution of the Increment Two Capacity Agreement with the balance due within thirty (30) days of HECO’s invoice for same following completion of the installation. HECO shall operate and maintain such equipment at its own expense.

5.	Payment for Adjustments to Interconnection Facilities.

Based upon Kalaeloa’s representations below, HECO has determined that no upgrades to the electrical transmission facilities between HECO’s CEIP Substation and the Points of Interconnection are necessary or advisable as a result of the Increment Two Capacity, as further described in the Interconnection Requirement Study For Kalaeloa Partners, L.P.’s Proposed 235 MW (Net) Combined-Cycle Operating Facility Connected to the HECO Transmission System at Kalaeloa dated September 2004. HECO has determined that certain relay settings must be changed, and Kalaeloa shall reimburse HECO for the actual cost thereof within thirty (30) days after completion thereof and presentation by HECO to Kalaeloa of invoices or other documentation demonstrating such actual cost; provided, however, that if the amount to be reimbursed by Kalaeloa to HECO for the cost of the foregoing exceeds $20,000, then Kalaeloa may notify HECO by writing received by HECO within the time stated for payment of the reimbursement that Kalaeloa elects to terminate this Increment Two Capacity Agreement, whereupon HECO shall not be required to accept or pay for the Increment Two Capacity. HECO may, at its option, collect the cost of the foregoing through an offset in the payment of the Monthly Invoice not to exceed the portion of the Capacity Charge corresponding to the New Capacity payable under such Monthly Invoice. The aforesaid Interconnection Requirement Study was performed on the basis of the following representations made by KPLP to HECO: (i) the M Upgrade involves only changes to the Facility’s combustion turbines and no changes to the Facility’s electrical equipment (such as its three generators) and (ii) the Facility’s single-line diagrams and protective relay list will remain the same as those attached to the Power Purchase Agreement. In reliance upon the foregoing representations, HECO has not reviewed the single-line diagram and protective relays of the Facility.

6.	Rates for Purchase.

Subject to the other provisions of the Power Purchase Agreement, HECO shall, from and after the Increment Two Capacity In-Service Date, accept and pay for Net Electrical Energy Output by the Facility and delivered to the Points of Interconnection and make Capacity Payments to Kalaeloa, as set forth in the Power Purchase Agreement as modified by this Section 6. The respective rights and obligations accrued by HECO and Kalaeloa with respect to the payment and receipt of Energy Charges and Capacity Charges for the period prior to the Increment Two Capacity In-Service Date shall continue to be governed by the provisions of the Power Purchase Agreement without giving effect to the amendments and other modifications set forth in this Section 6.

Regarding Section 5.1 of the Power Purchase Agreement.

HECO’s obligation to pay the Energy Charge shall remain as set forth in Section 4A (captioned “Regarding Section 5.1 of the Power Purchase Agreement”) of the Increment One Capacity Agreement.

Regarding Section 5.2A(2) of the Power Purchase Agreement.

Effective upon the Increment Two Capacity In-Service Date, the provisions in Section 5.2A(2) of the Power Purchase Agreement are deleted and of no further force or effect and replaced with the word “[Reserved]”.

Regarding Section 5.2A(3) of the Power Purchase Agreement.

Section 5.2A(3) is amended in its entirety to read as follows:

(3)

Liquidated Damages Due to Failure to Achieve On-peak EFOR Requirements

(a) As a material inducement to HECO’s decision to enter into the Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two In-Service Date, On-peak EFOR will not exceed six percent (6%) during any Contract Year.

(b) Commencing with the first Contract Year after the Increment Two Capacity In-Service Date, HECO shall calculate the On-peak EFOR for each Contract Year. If the On-peak EFOR is two percent (2%) or less, there will be no reduction from the amount incurred by HECO for the Annual New Capacity Charge for such Contract Year. If the aforesaid calculation demonstrates an On-peak EFOR for such Calendar Year in excess of two percent (2%), for each one-tenth of a percentage point that the On-peak EFOR exceeds two percent (2%) up to a maximum of twelve percent (12%) when rounded to the nearest one-tenth of a percent (0.1%), the amounts incurred by HECO for the Annual New Capacity Charge for such Contract Year shall be reduced by the following amounts:


On-peak EFOR		Amount of Reduction
2.1% to 6.0%		$5,000 per 0.1% in excess of 2.0%
6.1% to 12.0%		$10,000 per 0.1% in excess of 6.0%
Greater than 12.0%		No further reduction

7.	Calculation of On-peak EFOR.

Effective upon the Increment Two Capacity In-Service Date, Article XXV of the Power Purchase Agreement is amended by adding new Sections 25.5 through 25.8 as follows:

25.5 When neither of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver Net Electrical Energy Output equal to at least the Full Upgraded Capacity (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating On-peak EFOR. If, when called for by HECO Dispatch during periods when neither of the Facility’s combustion turbines is in reserve shutdown status, Kalaeloa is unable to deliver Net

Electrical Energy Output equal to at least the lesser of the Full Upgraded Capacity or the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to the Full Upgraded Capacity minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating On-peak EFOR.

25.6 On those occasions when one of the Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver Net Electrical Energy Output equal to at least the Prorated Shutdown Capacity (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating On-peak EFOR. If, when called for by HECO Dispatch during periods when one of the Facility’s combustion turbines is in a reserve shutdown status, Kalaeloa is unable to deliver Net Electrical Energy Output equal to at least the lesser of the Prorated Shutdown Capacity or the capacity actually called for by HECO Dispatch, a derate will be assessed equal in magnitude to Prorated Shutdown Capacity, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating On-peak EFOR.

25.7 Under this Agreement, the ratio for On-peak EFOR is to be calculated in accordance with North American Electric Reliability Council (NERC) Generating Availability Data System (GADS) formulas, excluding the applicable seasonal adjustment. As a result, Net Dependable Capacity (“NDC”) and Net Maximum Capacity (“NMC”) are used in calculating Equivalent Planned Derated Hours and Equivalent Unplanned Derated Hours. In all cases, regardless of ambient conditions and degradation (except for Delay Degradation), NDC and NMC will continue to be Full Upgraded Capacity. Deratings that are less than or equal to 2% of the NMC, and/or less than or equal to 30 minutes in duration, will continue to be included as deratings in determining Derated Hours.

25.8 For purposes of calculating On-peak EFOR, the routine maintenance requirements provided in Section 3.2D(7) for any “C” Inspection commenced after the Increment Two In-Service Date shall be thirty-five (35) days per combustion turbine, or such longer time as agreed by HECO in writing prior to commencement of such “C” inspection, instead of fifty (50) days. The time allotted for the steam turbine maintenance portion of the “C” Inspection shall remain unchanged.

8.	Limitation on Certain Reductions in and Deductions from Capacity Payments and on Liquidated Damages.

Effective upon the Increment Two Capacity In-Service Date, Article XXVI of the Power Purchase Agreement is amended in its entirety to read as follows:

ARTICLE XXVI

LIMITATION ON CERTAIN REDUCTIONS IN AND DEDUCTIONS FROM

CAPACITY PAYMENTS AND ON LIQUIDATED DAMAGES

26.1 Any other provision of this Agreement to the contrary notwithstanding, for each Contract Year, the sum of the following items shall not be assessed or accrue to the

extent such sum exceeds the Annual New Capacity Charge for such Contract Year: the reduction in the Capacity Charge corresponding to the New Capacity pursuant to Section 5.2A(3) and the Increment Two Capacity pursuant to Section 5.2A(4), liquidated damages payable under Article XXIV, the deduction from the Capacity Charge for New Capacity pursuant to Section 27.2.5, and liquidated damages payable under Article XXVII; and HECO acknowledges that it shall not seek any further remedies against Kalaeloa related to such failures, except in cases of willful misconduct or in cases in which HECO may have a claim to equitable relief.

26.2 If any amounts owed by Kalaeloa for the reduction in the Capacity Charge corresponding to the New Capacity pursuant to Section 5.2A(3) and the Increment Two Capacity pursuant to Section 5.2A(4), the deduction from the Capacity Charge corresponding to the New Capacity pursuant to Section 27.2.5, liquidated damages payable under Article XXVII or reimbursement of the cost of the Interconnection Addition is not paid when due, HECO shall have the right to set off any payment due against HECO’s payments of subsequent Monthly Invoices as necessary, provided, however, that the maximum amount set off against any one Monthly Invoice shall be limited to the portion of the Capacity Charge corresponding to the New Capacity payable that month.

9.	Reliability Standards and Liquidated Damages.

Effective upon the Increment Two Capacity In-Service Date, the following is added to the Power Purchase Agreement as a new Article XXVII:

ARTICLE XXVII

RELIABILITY STANDARDS AND LIQUIDATED DAMAGES

27.1 Relationship Between Articles VIII, XXIV and XXV of Power Purchase Agreement.

The liquidated damages set forth in Article VIII of this Agreement were agreed to in the context of a Facility able to deliver 180,000 KW capacity pursuant to HECO Dispatch, and the parties agree that such liquidated damages continue to be an appropriate remedy for HECO and liability for Kalaeloa with respect to such capacity. However, in light of the addition to the Facility of the New Capacity, HECO and Kalaeloa agree that, from and after the Increment Two Capacity In-Service Date, an additional remedy for HECO and additional liability for Kalaeloa are appropriate and that the provisions of this Article XXVII shall have effect from and after the Increment Two Capacity In-Service Date. The respective rights and obligations accrued by HECO and Kalaeloa with respect to liquidated damages under Article VIII of this Agreement for the period prior to the Increment Two Capacity In-Service Date shall continue to be governed by the provisions of this Agreement without giving effect to the provisions of this Article XXVII. Article XXIV of this Agreement is intended to address circumstances other than the unavailability of capacity addressed under Articles VIII and XXV, and the respective rights and obligations of HECO and Kalaeloa under said Article

XXIV are separate from and in addition to the respective rights and obligations of HECO and Kalaeloa under said Articles VIII and XXV.

27.2 Full Plant Trips.

27.2.1 As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two Capacity In-Service Date, during any twelve (12) month period, there will be no more than one Full Plant Trip that could have been avoided through the employment of Good Engineering and Operating Practices. Kalaeloa’s failure to comply with the foregoing shall not be considered a default under Section 7.1A; provided, however, that nothing in this sentence shall be interpreted as precluding the inclusion of Full Plant Trips (1) for purposes of calculating the Equivalent Availability Factor and Equivalent Forced Outrage Rate referenced in clause (a) of Section 7.1A(4) and (2) within the Unit Trips referenced in clause (b) of Section 7.1A(4) as and to the extent any such Full Plant Trips also constitute one or more Unit Trips.

27.2.2 For each Full Plant Trip (Category I), Kalaeloa shall pay to HECO as liquidated damages the sum of ONE HUNDRED THOUSAND DOLLARS ($100,000).

27.2.3 For each Full Plant Trip (Category II), Kalaeloa shall pay to HECO as liquidated damages the sum of FIFTY THOUSAND DOLLARS ($50,000).

27.2.4 Kalaeloa shall earn a grace period to be used in determining whether an event is a Full Plant Trip (Category I) or Full Plant Trip (Category II) by providing HECO’s Load Dispatcher, prior to the Unplanned Removal From Service of the first generator to be so removed, with notice that the Facility is likely to experience a Full Plant Trip. In order to qualify as a notice of the type referred to in the preceding sentence, the notice must (a) be made in a direct and two-way communication between Kalaeloa or its operator’s personnel and HECO’s Load Dispatcher through such media as the “hot line” between the Facility’s control room and that of HECO’s Load Dispatcher, (b) clearly and specifically state that there is likely to be an Unplanned Removal From Service of the two combustion turbines at the Facility and (c) be acknowledged by HECO’s Load Dispatcher as conveying the message that there is likely to be an Unplanned Removal From Service of the two combustion turbines at the Facility. If Kalaeloa provides notice which satisfies the requirements set forth in the first two sentences of this Section 27.2.4, the number of minutes that elapse between the receipt of such notice by HECO’s Load Dispatcher and the actual Unplanned Removal From Service of the Facility’s first combustion turbine (the “grace period”) shall, for purposes of determining whether the event in question is to be classified as a Full Plant Trip (Category I) or Full Plant Trip (Category II) for purposes of assessing the liquidated damages set forth in Section 27.2.2 or 27.2.3, be added to the number of minutes that actually elapsed between the Unplanned Removal From Service of the first combustion turbine and the Unplanned Removal From Service of the second combustion turbine.

27.2.5 If three or more Full Plant Trip (Category I) events occur during any twelve (12) month period (regardless of whether or not, by virtue of the grace period provided under Section 27.2.4, such events were treated as Full Plant Trip (Category I) events for purposes of assessing liquidated damages), the occurrence of the third Full Plant Trip (Category I) event within such twelve (12) month period shall result in a twenty-five percent (25%) deduction from the amount payable as Capacity Charge for New Capacity for the period commencing with the date of such third Full Plant Trip (Category I) event until such time as Kalaeloa has adequately addressed, to HECO’s satisfaction in HECO’s sole but non-arbitrary discretion, the circumstances giving rise to the Full Plant Trip problem, as evidenced by HECO’s written notice to Kalaeloa to that effect. If Kalaeloa is not satisfied with the exercise of HECO’s sole discretion in determining whether Kalaeloa has adequately addressed such circumstances or HECO is not reasonably prompt in responding to Kalaeloa, Kalaeloa may, at its own expense, submit the issue of whether or not Kalaeloa has addressed the circumstances giving rise to the Full Plant Trip problem to an independent engineer from the list of qualified engineers maintained pursuant to Section 3.F(6) (the “Section 3.F(6) List”). If Kalaeloa decides to submit such issue to the assessment of an independent engineer, Kalaeloa shall provide HECO with written notice to that effect. If HECO and Kalaeloa do not agree within seven (7) days of the date of HECO’s receipt of the aforesaid notice from Kalaeloa upon the independent engineer from the Section 3.F(6) List to be retained by Kalaeloa for such purpose, Kalaeloa shall designate the independent engineer from the Section 3.F(6) List and the assessment of such independent engineer shall be binding on the parties. If such independent engineer determines that Kalaeloa has adequately addressed the problem, such engineer shall also decide the date upon which Kalaeloa achieved this result so that the parties will know that date from which the aforesaid twenty-five percent (25%) deduction from the portion of the Capacity Charge corresponding to the New Capacity ceased to apply. The provisions of Article XIV shall not apply to the selection of the independent engineer under this Section 27.2.5 or the conduct of the engineering assessment under this Section 27.2.5.

27.2.6 The twenty-five percent (25%) deduction from the portion of the amount payable as Capacity Charge corresponding to the New Capacity pursuant to the provisions of Section 27.2.5 is intended to correlate to the portion of the amount payable as Capacity Charge corresponding to the New Capacity to take into account the unreliability of such New Capacity as evidenced by the occurrence of Full Plant Trip (Category I) events and is not intended to compensate HECO for the Full Plant Trip events themselves. Accordingly, liquidated damages shall still be payable as provided in Sections 27.2.2 through 27.2.4 for all Full Plant Trip (Category I) and/or Full Plant Trip (Category II) events that occur during a period for which there has been a deduction from the Capacity Charge for New Capacity pursuant to Section 27.2.5.

27.3 Payment to HECO.

Payment of liquidated damages to HECO under this Article XXVII is due thirty (30) days after written demand therefor from HECO.

10.

Other Clarifications, Modification and Amendments to the Power Purchase Agreement.

Effective upon the Increment Two Capacity In-Service Date, the following provisions of the Power Purchase Agreement are deemed to be clarified, modified or amended as set forth in this Section 10:

Regarding Section 3.1A of the Power Purchase Agreement.

The words “and Increment Two Capacity” are inserted after the words “Firm Capacity” in the second line of Section 3.1A.

Regarding Sections 23.18 and 23.19 of the Power Purchase Agreement.

Sections 23.18 and 23.19 of the Power Purchase Agreement are amended in their entirety to read as follows:

23.18 Steam Sales Contract Monthly Report

Not more than 30 days following the end of each Calendar Month, Kalaeloa shall provide HECO with a written report setting forth for each one-hour interval during each On-peak Period during such Calendar Month the amount of process steam exported by the Facility pursuant to the Steam Sales Contract and the average (the “On-peak Monthly Steam Average”) export of process steam for all such one-hour intervals during the month (the “Steam Sales Monthly Report”). If any Steam Sales Monthly Report indicates that the On-peak Monthly Steam Average exceeds 110,000 lb/hour that month, then the Steam Sales Monthly Report shall also include an explanation of the reasons for the On-peak Monthly Steam Average exceeding 110,000 lb/hour and a projection for the Calendar Year of the amount of process steam to be exported by the Facility pursuant to the Steam Sales Contract. If any such yearly projection indicates that the On-peak Monthly Steam Average is projected to exceed 110,000 lb/hour in a Month remaining in such Calendar Year, then the Steam Sales Monthly Report shall also include an explanation of the reasons therefor.

23.19 Additional Covenant Concerning Steam Sales Contract

If any Steam Sales Monthly Report indicates that the counterparty to the Steam Sales Contract has increased its take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during any On-peak Period resulting in or contributing to a derating of the Facility’s capability below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation), or that said counterparty is projected to increase its take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during the Calendar Year such that the increased take of steam may result in deratings of the Facility’s capability below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) during On-peak Periods, then Kalaeloa shall promptly take such actions as it determines to be appropriate to eliminate the occurrence of such

deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) and shall report to HECO on its efforts to eliminate the occurrence of such deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation).

In the event the counterparty’s take of process steam from the Facility beyond the equivalent of 110,000 lb/hour during the Calendar Year results in or contributing to deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) during more than thirty (30) On-peak Periods during that Calendar Year, Kalaeloa shall employ all commercially reasonable efforts to eliminate such process steam-related deratings below the Full Upgraded Capacity (as such may be reduced by any Delay Degradation) or to induce such counterparty to limit its take of process steam from the Facility to the equivalent of 110,000 lb/hour during On-peak Periods, provided that Kalaeloa is not required to induce any limitation that would have the effect of causing the Facility to fail to achieve the Minimum Thermal Threshold or remain a Qualifying Facility.

Regarding Attachment G of the Power Purchase Agreement.

Attachment G to the Power Purchase Agreement is deemed replaced in its entirety by Attachment G to this Increment Two Capacity Agreement.

Regarding Attachment R of the Power Purchase Agreement.

Attachment R to the Power Purchase Agreement is deemed replaced in its entirety by Attachment R to this Increment Two Capacity Agreement.

Regarding Attachment W of the Power Purchase Agreement.

Attachment W to the Power Purchase Agreement is deemed replaced in its entirety by Attachment W to this Increment Two Capacity Agreement.

Regarding Attachment D of the Power Purchase Agreement.

No modifications to Attachment D to the Power Purchase Agreement are required as a result of the Increment Two Capacity Upgrade, and said Attachment D remains applicable to the Facility as modified by the Increment Two Capacity Upgrade.

11.

Other Terms Unchanged.

All of the terms and conditions of the Power Purchase Agreement that are not altered, amended or replaced by the provisions of this Increment Two Capacity Agreement shall remain in full force and effect. In the event that a conflict arises between the Power Purchase Agreement and this Increment Two Capacity Agreement, this Increment Two Capacity Agreement shall prevail, but the respective documents shall be interpreted to be in harmony with each other where possible.

12.

Kalaeloa’s Representations, Warranties and Guarantees of Performance With Respect to New Capacity.

A. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents to HECO that once the Increment Two Capacity Upgrade is complete, Kalaeloa expects that the annual average of its export of process steam under the Steam Sales Contract will be equivalent to approximately 110,000 lb/hour and that Kalaeloa has no information indicating that the counterparty to the Steam Sales Contract will increase its annual take of process steam beyond this expected average.

B. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that, from and after the Increment Two Capacity In-Service Date, the Facility will, during each Calendar Year, achieve the Minimum Thermal Threshold, and, as HECO’s sole remedy therefor, except in cases of willful misconduct or cases in which HECO has a claim for equitable relief, Kalaeloa shall pay liquidated damages as set forth in Article XXIV of the Power Purchase Agreement.

C. Without limitation to the effect of Sections 12.A. and 12.B. above, Kalaeloa, as a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, represents, warrants and guarantees to HECO that, from and after the Increment Two In-Service Date, the Facility will have and maintain the capability to produce and deliver the Baseline Capacity and the New Capacity to the extent required by the Power Purchase Agreement, as amended and clarified by the Increment Two Capacity Agreement and the previous amendments and clarifications of the Power Purchase Agreement identified in Recital “A” to the Increment Two Capacity Agreement, to the Metering Point under HECO Dispatch.

D. As a material inducement to HECO’s decision to enter into this Increment Two Capacity Agreement, Kalaeloa reaffirms its representations and warranties given in the Consent and Agreement between the parties dated December 31, 2003 and further represents, warrants and guarantees to HECO that Kalaeloa can complete the Increment Two Capacity Upgrade and implement this Increment Two Capacity Agreement without the necessity for modifications to (i) the back-up fuel supply agreement referred to in Section 3.2G of the Power Purchase Agreement or (ii) any obligations or commitments that HECO may have regarding potable or cooling water. Kalaeloa represents, warrants and guarantees to HECO that, in the event Kalaeloa is unable to obtain fuel from its primary supplier, Kalaeloa shall make a good faith effort to acquire alternative supplies of low sulfur residual fuel oil as primary fuel and diesel oil as start-up and shutdown fuel necessary to operate the Facility before calling upon HECO to fulfill HECO’s obligation to provide fuel to Kalaeloa. Kalaeloa agrees and acknowledges that any obligations or commitments that HECO may have regarding potable or cooling water are limited to supplies of potable water and cooling water in quantities reasonably adequate to permit operation of the Facility in the manner provided for in the Power Purchase Agreement prior to the commencement of the Increment Two Capacity Upgrade.

13.

Regulatory Approval.

A. The parties shall use good faith efforts to obtain, as soon as practicable, a final non-appealable order from the Public Utilities Commission that does not contain terms and

conditions deemed to be unacceptable to HECO, and is in a form deemed to be reasonable by HECO, in its sole, but nonarbitrary, discretion, approving this Increment Two Capacity Agreement and ordering that:

(1) the purchase power costs to be incurred by HECO as a result of this Increment Two Capacity Agreement are reasonable;

(2) HECO’s purchase power arrangements under this Increment Two Capacity Agreement, pursuant to which HECO will purchase Increment Two Capacity from Kalaeloa and may purchase additional energy, are prudent and in the public interest;

(3) the Fuel Component and the Additive Component of the purchased energy costs and related revenue taxes to be incurred by HECO pursuant to this Increment Two Capacity Agreement may be included in HECO’s energy cost adjustment clause to the extent such costs are not included in base rates; and

(4) HECO may include the costs of the Increment Two Capacity and the purchased power incurred by HECO pursuant to this Increment Two Capacity Agreement in its revenue requirements for ratemaking purposes and for the purposes of determining the reasonableness of HECO’s rates.

B. Notwithstanding any other provisions of this Increment Two Capacity Agreement to the contrary, HECO’s obligations under this Increment Two Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment Two Capacity and to pay the Capacity Charge for the Increment Two Capacity, and any and all obligations of HECO which are ancillary to that purchase and that payment, are all contingent upon obtaining the order described in this Section 13. (Such order is referred to hereinbelow as the “PUC Approval Order”.)

C. As used in Section 13.A. above, the term “final non-appealable order from the Public Utilities Commission” means a PUC Approval Order (a) that is considered to be final by HECO, in its sole discretion, because HECO is satisfied that no party to the subject Public Utilities Commission proceeding intends to seek a change in such PUC Approval Order through motion or appeal, or (b) that is not subject to appeal to any Circuit Court of the State of Hawaii or the Supreme Court of the State of Hawaii, because the thirty (30) day period permitted for such an appeal has passed without the filing of notice of such an appeal, or (c) that was affirmed on appeal to any Circuit Court of the State of Hawaii or the Supreme Court, or the Intermediate Appellate Court upon assignment by the Supreme Court, of the State of Hawaii, or was affirmed upon further appeal or appellate process, and that is not subject to further appeal, because the jurisdictional time permitted for such an appeal (and/or further appellate process such as a motion for reconsideration or an application for writ of certiorari) has passed without the filing of notice of such an appeal (or the filing for further appellate process). Promptly after the issuance of a PUC Approval Order, HECO shall provide Kalaeloa with a copy of such PUC Approval Order together with a written statement as to whether the conditions set forth in (i) Section 11A and (ii) clause (a) of this Section 13C have been satisfied.

D. As used in this Increment Two Capacity Agreement, the term “PUC Approval Date” shall be defined as (a) the date of issuance of the PUC Approval Order if HECO provides

the written statement referred to in the last sentence of Section 13C to the effect that the condition referred to in clause (a) of Section 13C of this Increment Two Capacity Agreement has been satisfied or (b) as follows:

(1) If a PUC Approval Order is issued and is not made subject to a motion for reconsideration filed with the Public Utilities Commission or an appeal, the PUC Approval Date shall be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the issuance of the PUC Approval Order.

(2) If the PUC Approval Order became subject to a motion for reconsideration, and the motion for reconsideration is denied or the PUC Approval Order is affirmed after reconsideration, and such order is not made subject to an appeal, the PUC Approval Date shall be deemed to be the date one day after the expiration of the thirty-day period permitted for filing of an appeal following the order denying reconsideration of or affirming the PUC Approval Order.

(3) If the PUC Approval Order, or an order denying reconsideration of the PUC Approval Order or affirming approval of the PUC Approval Order after reconsideration, becomes subject to an appeal, then the PUC Approval Date shall be the date upon which the PUC Approval Order becomes a non-appealable order within the meaning of Section 13.C.

14.

Entire Agreement.

This Increment Two Capacity Agreement and the Power Purchase Agreement, as amended herein, embody the whole agreement and understanding of the parties as to matters described herein and supersede and nullify all prior agreements, arrangements and understandings related to the subject matter of this Increment Two Capacity Agreement; provided, however, that nothing in this Section 14 shall cause the Power Purchase Agreement to be invalid or unenforceable against HECO or Kalaeloa on the basis of regulatory action concerning this Increment Two Capacity Agreement.

15.

Effective Date.

Provided the conditions precedent to the effectiveness of Section 2 and Sections 6 through 11 of this Increment Two Capacity Agreement as set forth in the next sentence of this Section 15 have been satisfied, Section 2 and Sections 6 through 11 hereof shall become effective on the Increment Two Capacity In-Service Date. The conditions precedent referenced in the first sentence of this Section 15 are (a) the occurrence of the PUC Approval Date as defined in Section 13 above, (b) the consent to this Increment Two Capacity Agreement of ING Capital LLC, as Agent for the “Lenders” under the Amended and Restated Loan and Note Purchase Agreement, dated as of December 10, 1991 (the “Lender Approval”), (c) the acceptance of the M Upgrade by Kalaeloa and (d) the satisfactory completion of the Acceptance Test. Kalaeloa shall use good faith efforts to obtain Lender Approval. Should the PUC Approval Date not occur by August 1, 2005, or such later date as to which HECO and Kalaeloa may agree by a subsequent written agreement, or should the Lender Approval not be obtained within a reasonable period (expected to be approximately sixty (60)) days after the full execution of this Increment Two Capacity Agreement and the delivery hereof to the Agent (which Kalaeloa

agrees to cause to be done promptly after full execution by the parties), but in no event later than January 3, 2005, Section 2 and Sections 6 through 11 of this Increment Two Capacity Agreement shall be null and void ab initio, and HECO and Kalaeloa shall be free of all obligations under said Section 2 and Sections 6 through 11 and shall pursue no remedies against one another arising out of or related to said Section 2 and Sections 6 through 11.

16.

Miscellaneous.

A. The failure of either party to enforce at any time any of the provisions of this Increment Two Capacity Agreement, or to require at any time performance by the other party of any of the provisions hereof, shall in no way be construed to be a waiver of such provisions, nor in any way to affect the validity of this Increment Two Capacity Agreement or any part hereof, or the right of such party to enforce every such provision.

B. No modification or waiver of all or any part of this Increment Two Capacity Agreement shall be valid unless it is reduced to writing which expressly states that the parties thereby agree to a waiver or modification as applicable and signed by both parties.

C. This Increment Two Capacity Agreement may be executed in several counterparts and all so executed counterparts shall constitute one agreement, binding on both parties hereto, notwithstanding that both parties may not be signatories to the original or the same counterpart.

D. This Increment Two Capacity Agreement and all documents executed and delivered in connection herewith, and all notices and other communications given pursuant to this Increment Two Capacity Agreement, may be executed and signatures transmitted electronically via the Internet or facsimile.

IN WITNESS WHEREOF, the parties have executed this Increment Two Capacity Agreement by their respective duly-authorized officers as of the date first stated above.


HAWAIIAN ELECTRIC COMPANY, INC.		KALAELOA PARTNERS, L.P.


By	/s/ Thomas C. Simmons	By	PSEG Kalaeloa Inc., Its general partner
	Its Vice President – Power Supply

By	/s/ Thomas L. Joaquin	By	/s/ Royal Daniel
	Its SVP – Operations		Its Vice President

Executed on: October 12, 2004		Executed on: October 12, 2004


EXHIBITS

EXHIBIT 1		Letter dated July 29, 2004, regarding LSFO forwarding pumps

EXHIBIT 2		Letter dated October 8, 2004, regarding ground system and lightening protection

EXHIBIT 3		Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Post M Upgrade Case for up to 209 MW for Two CT/Case for One CT Operation identified as “9/23/04”.

EXHIBIT 4		Letter dated June 30, 2004, setting forth calculations of (i) the purchase price for the Facility for purposes of Section 3.3H and (ii) the fair market value of the Facility for purposes of Section 7.2B(1)


ATTACHMENTS

ATTACHMENT G		(see 10.C.)

ATTACHMENT R		(see 10.D.)

ATTACHMENT W		(see 10.E.)

EXHIBIT 1

July 29, 2004

Hawaiian Electric Company, Inc.

PO Box 2750

Honolulu, Hawaii ###-###-####


Attention:		Ward D. Saunders, P.E.
		Power Purchase Contracts Administrator

Subject:		Plant Reliability Improvements
Ref.		Under Voltage Study Results

Dear Ward,

In accordance with the above referenced study, we will be replacing the variable frequency drives presently installed on all three LSFO forwarding pumps.

The new variable frequency drives with improved fault recovery and disturbance ride through capability are of the Baldor series 15 H or similar type and will be installed during the next upcoming full plant outage which is planned for April of 2005.

Though numerous modifications to the existing drives/pump controls improved the supply voltage disturbance ride through capabilities, it is unclear as to what magnitude and duration can be withstood. However the Facility has survived most of the faults after the implementation of these improvements.

The new drives as proposed have a clearly defined disturbance ride-through capability of the absence of voltage for a duration of up to 2 seconds, thus equipment’s and plant reliability will be further increased. Experience at the Facility has shown that disturbances seldom, if ever, drop the supply voltage to zero volts for a duration of more than 1 second.

Best Regards.

/s/ H.R. Tobler

H.R. Tobler

General Manager

Kalaeloa Partners, L.P.

EXHIBIT 2

October 8, 2004

Hawaiian Electric Company, Inc. (“HECO”)

PO Box 2750

Honolulu, Hawaii ###-###-####


Attention:		Ward D. Saunders, P.E.
		Power Purchase Contracts Administrator

Subject: Action Items for Kalaeloa Facility Grounding System and Lightning Protection

Dear Ward,

Kalaeloa Partners, L.P. (“Kalaeloa”) agrees to complete the following action items and implement the applicable procedure changes:

Grounding System

Replace two defective exothermic weld connections. (completed prior to 8/17/04)

ii.

Modify the plant’s maintenance program to include periodic evaluations of the grounding system and visual checks of all accessible exothermic weld connections. (completed prior to 8/17/04)

iii.

Test and repair as part of regular preventative maintenance.

Electronic Components

Identify critical components essential for the operation of the plant in close proximity to the stacks, which are the most probable target iin case of a lightning strike. (completed prior to 8/17/04)

ii.

Assure adequate spare parts of such components. (in progress, parts inventory expected to be complete by October 2004)

iii.

Provide list of components and planned spare inventory to HECO.

Training

Train operations and maintenance personnel how to respond quickly in case of problems, i.e., learn how to quickly detect defective

components based on symptoms, learn how to replace defective components without unnecessarily and adversely impacting the safe operation of the plant. (Ongoing process).

Study and Implementation

Kalaeloa has completed a study by an independent third party that confirmed that the Facility currently meets the design specifications of the Turnkey Design/Build Contract between Kalaeloa and ABB Energy Services, Inc. dated November 8, 1988 with respect to Section 3.8.1 “Station Grounding” and such has been forwarded to you previously.

Though the above mentioned steps will not guarantee that lightning could never cause trips in the future, complete implementation of such steps will greatly reduce the chance that lightning will cause a trip of both CT’s and increase the likelihood that the plant recovery process from a lightning event should be minimized as compared to the January 2004 lightning event.

Kalaeloa will retain an independent third party consultant to review the current state of the Facility in order to determine whether the 1989 Edition of NFPA 78 (the “1989 NFPA 78”) was used as the design and construction basis of the Facility. A copy of such consultant’s report will be provided to HECO. If it is determined by such third party consultant that the Facility’s design and/or construction did not incorporate the material provisions of the 1989 NFPA 78, then, if Kalaeloa does not, within a reasonable time (as such is determined by such independent third party consultant) take such action to rectify any such matters so that the Facility’s construction meets the material requirements of the 1989 NFPA 78, Kalaeloa agrees that upon the expiration of such reasonable time, the Power Purchase Agreement between us and you is hereby clarified so that an “Unplanned Removal From Service” (as defined in the Increment Two Capacity Agreement) caused by fire which results from lightning strikes to the Facility will constitute a “Full Plant Trip” (as defined in the Increment Two Capacity Agreement) until such time as Kalaeloa is in compliance with such material provisions of the 1989 NFPA 78.

Best Regards,

/s/ H.R. Tobler

H.R. Tobler

General Manager

Kalaeloa Partners, L.P.

EXHIBIT 3

Capacity Evaluation Protocol

Kalaeloa Cogeneration Facility

Post M Upgrade

Case for up to 209 MW for Two CT

Case for One CT Operation

Purpose

The purpose of this evaluation protocol is to set forth a protocol to be used to demonstrate the Facility’s ability following implementation of the M Upgrade to provide additional capacity of up to 209 MW, to the Hawaiian Electric Company, Inc. (“HECO”) system and to identify a new level of capacity when the Facility is operating with one combustion turbine (“CT”) and the steam turbine (“ST”) (as measured by HECO’s revenue meters at the Points of Interconnection and with the output corrected to the below agreed upon evaluation conditions which are being used as a proxy to represent reasonable worst case conditions for Facility operations). The results of this evaluation will be used by HECO and Kalaeloa to support current discussions to increase the Firm Capacity.

Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Power Purchase Agreement dated as of the 14^th day of October 1988 between KALAELOA Partners, L.P. (“Kalaeloa”) and HECO (as heretofore amended and clarified, the “PPA”).

Test Conditions and Parameters

A continuous 48-hour test run of the Facility will be conducted for the case for the full Facility capability, while two shorter 4-hour period runs separate from the 48-hour run will be conducted for the cases of single CT operations (collectively, the “Test”). Any abnormal conditions or equipment failure during any portion of the Test which impact that portion of the Test results shall cause that portion of the Test to end, and in which case the parties after review of the reasons for the Test’s termination shall promptly arrange the scheduling of another Test or portion of a Test by mutual agreement of Kalaeloa and HECO. The 48 hour portion of the Test may be concluded before its 48-hour duration if the determination that enough data has been collected is made jointly by HECO and Kalaeloa. However, each of the two 4-hour one CT operation Test portions should run the entire four hours.

2.	For at least one month prior to the Test, turbine washes shall have continued to be conducted on Friday/Saturday and Saturday/Sunday periods respectively.

The commencement of the Test shall be scheduled such that at the conclusion of the Test, the HRSGs will be in their most fouled state in the cleaning cycle and due for wash according to the then current normal wash cycle. The HRSGs shall not be washed during the 48-hour period just prior to the commencement of the Test.

The Test timing relative to “C” inspection interval should be the same as the test conducted pursuant to the 189 MW protocol with degradation factors from Attachment D applied as necessary to position the performance of each CT as if it is operating at the following time in the “C” inspection life cycle. The Test shall be corrected as if the Test had been conducted just prior to a “C” inspection being due for at least one of the CTs (i.e. approximately 16,000 operating hours have elapsed since the last C inspection). The other CT should be at the mid point (approximately 8,000 operating hours) following its last “C” inspection. Given the historical and future plans for “C” inspection intervals at one per year and an approximately two year interval between “C” inspections for a given CT this scenario should closely approximate the worst case Facility operating regime relative to operational degradation of the two CTs. The four-hour single CT portion of the Test shall be corrected as if the Test had been conducted just prior to a “C” inspection being due for both of the CTs (i.e. approximately 16,000 operating hours have elapsed since the last C inspection). If the Test is conducted at a time when either CT has not accumulated the operating hours to meet the above criteria, a degradation correction to the Test result will be applied as discussed below.

5.	The maximum turbine inlet temperature (“TIT”) setpoint shall be 1854 Deg. F. Actual TIT may vary by no more than a couple degrees from the setpoint due to normal control system variations.

6.	The maximum steam injection to fuel ratio (lbs of steam/lb of fuel) shall not exceed 1.5 lbs unless a greater amount is needed to meet the air quality permit requirements of the Facility. Operating conditions shall meet the requirements of all applicable permits.

Steam export to Tesoro during the Test shall beat least 110,000 lb/hr or the value thereof necessary for the Facility to achieve PURPA Qualifying Facility requirements, whichever is greater. If the steam export is less than 110,000 lb/hr, an appropriate downward correction will be applied pursuant to the Evaluation of Test Results section of this document.

The power factor during the Test shall be as close as possible to 0.85 at full load for at least 30 to 60 minutes, if HECO Dispatch can accommodate such, to ensure the Facility is able to operate with the increased load at the contractual minimum power factor required by the PPA. The power factor during the Test may range anywhere within the specifications of Section 2.1D of the PPA.

9.	The Facility shall operate at normal and representative operating conditions under control of HECO Dispatch consistent with the terms and conditions of the PPA.

Operation during any portion of the Test outside of these conditions shall entitle Kalaeloa to repeat such portion of the Test.

10.

Kalaeloa shall perform the Test in full compliance with all of its current operating permits, including the Covered Source Permit. Where no continuous emission monitoring is required by permit to document compliance, Kalaeloa shall, during the Test, demonstrate to HECO’s satisfaction that the Facility is continuously capable of complying with its Covered Source Permit at all output levels between 65MW and the capacity capability demonstrated by the Test.

11.

Kalaeloa provided written documentation to HECO’s satisfaction that all Facility modifications made subsequent to the initial design and construction of the Facility are in compliance with applicable environmental laws and regulations, and permits so that the Facility can operate under HECO Dispatch with all modifications subsequent to its original design and construction, and the continuous operation of the Facility for future periods at the capacity level for two CT operation and once CT operation demonstrated in the Test will not be limited or restricted in any way as a result of a condition contained in any permit.

12.

HECO’s evaluation of the capability level demonstrated by two CT operation and one CT operation within this Test shall be based on the minimum average capacity level that the Facility is able to sustain over each One Clock Hour Average (as defined below), as recorded by the revenue meters after the adjustment by any correction factor as discussed herein, in which the Facility is being dispatched at full load during the Test and in which the Facility adheres to all operational parameters set forth herein. Capacity data shall only be valid once the Facility is stable at full load. Stable full load is defined by operation at full firing temperature and inlet guide vanes at 0 +/- 0.3, and that these conditions exist for at least one hour prior to the measurement hour in order to allow the Facility’s steam cycle to reach equilibrium. Operation at this mode shall be continuous at the discretion of HECO’s Load Dispatcher. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections of the results to the Test results.

13.	Kalaeloa shall provide a certificate of calibration for all instrumentation pertinent to the operational parameters listed herein.

14.	Kalaeloa shall provide written confirmation that no abnormal events occurred during the Test with the various Facility equipment and that the operating modes were within a range of that can be sustained on a continuous mode of operation under HECO Dispatch.

General Information

1.	The Facility shall be operated by ALSTOM personnel.

HECO’s Load Dispatcher shall allow operation of the Facility at full load as much as practical consistent within dispatch requirements of the HECO system. This can include dispatch of the Facility at the Net Electrical Energy Output as low as 65,000 KW. Testing can be interrupted or terminated at any time by any party should such be necessary to protect the safety of personnel, equipment or system stability but shall be re-commenced once such situation is rectified.

HECO may, at its discretion, dispatch observers to the Facility to monitor testing as HECO deems necessary. HECO’s observers shall not interfere with operations, nor shall they direct/supervise ALSTOM’s operators in any manner. However, should they find issues that may compromise the quality of the testing or data, such issues shall be discussed with ALSTOM management and Kalaeloa.

4.	Following are contact people for each organization. Additional contact information for the Facility will be provided upon request:

•

Contact person for HECO is Ward Saunders – Contract Administrator

•

Contact person for Kalaeloa is Ruedi Tobler – General Manager

•

Contact person for ALSTOM is Mike Rossio – Operations Manager

5.	Data shall be collected using installed Facility instrumentation, except as listed under “Evaluation of Test Results” item # 1.

Test Set Up

First test run for the full Facility case shall start on a Wednesday at 13:00 and shall end on the first Friday thereafter at 13:00. Each of the one CT operation portion of the Test run shall start on a Saturday at 13:00 and end 4-hours later. In general the second 4-hour run would be on the following Saturday or a subsequent Saturday as soon as the HECO system can accommodate such portion of the Test.

2.	Additional testing, if necessary, shall be conducted if agreed to by HECO and Kalaeloa.

Normal and routine turbine, compressor and HRSG washing schedules shall be followed between the time this Test procedure is agreed and conclusion of Testing and in no case shall normal washing of the turbines, compressors and HRSG’s actually occur more frequently than weekly with the exception of daily on line compressor washes.

4.	Normal full load operating conditions of the Facility as follows:

•

evaporative coolers in service

•

stack heat exchangers in service

•

fuel: LSFO (specification sheet attached)

•

variable inlet guide vane (“VIGV”) setting: zero

•

TIT setpoint: 1854F

•

steam injection: minimum steam-to-fuel ratio 1.3, maximum 1.5 or greater if needed to maintain emissions within permit limits.

•

process steam total: as needed by Tesoro

•

Power Factor: as dispatched by HECO between 0.85 lagging to 1.0

5.	Data shall be collected by the Facility’s data acquisition system.

KALAELOA Procedure

1.	Start at 12:00 on day of that portion of the Test by taking the Facility to full load if consistent with load dispatch requirements. For the one CT Test, the CT being tested shall be synchronized, the steam turbine shall be synchronized and the other CT shall not be synchronized.

2.	Check to see that performance computer is not locked up, and verify that fuel data are updated.

3.	Take Facility off Energy Management System (“EMS”) with concurrence of HECO’s Load Dispatcher and set at baseload conditions: TIT = 1854 °F, max., VIGV at 0°, additive at normal rate, process steam as needed by Tesoro.

4.	Allow Facility to stabilize at the above conditions until 13:00 at which time print out the following Praut diagrams:


• P02		• P25
• P06		• P26
• P04		• P27
• P09		• P37
• P12		• Bar 16
• P20

5.	If conditions appear stable about 13:00, call HECO’s Load Dispatcher and declare that Testing is under way. Make entry in log book.

6.	One hour after start of Test, print out the same data sheets as listed above. Also, around that time, take a fuel sample from LSFO forwarding system.

Test will run 48 hours from that point for the case of full Facility capability or 4-hours for the portion of the Test which tests capability without the second CT synchronized. If HECO needs the Facility back on EMS, do so and make a note in the log. Continue to respond to HECO’s load needs as per normal operating practices.

8.	If operating conditions change such that Facility load drops below full load in dual CT mode or in single CT mode, make an entry in the log book indicating time that such reduction started, reason for reduction, and print out any PRAUT data that may help

provide information on this type of condition. When the Facility is restored to full load, make the appropriate entry in the log book.

9.	Hourly, check that RADARS is continuing with data collections.

10.	Log time whenever fuel tanks are switched. Take a fuel sample at LSFO forwarding about 1 hour after the tanks are switched.

Evaluation of Test Results

1.	HECO shall poll its revenue meters (KW and KVAR) and make results available to Kalaeloa soon after the Test (but within 3 working days in any event).

The minimum full load One Clock Hour Average shall establish the uncorrected capacity of the Facility. The One Clock Hour Average is defined as the four consecutive 15 minute periods beginning with the reading for the 15 minute period that ends at 15 minutes past the hour. These values are used to mitigate any short-term variations and to correspond to hourly average Facility supplemental data used for corrections to the capacity measured during the Test.

The lowest full load One Clock Hour Average of each of the three turbines in that hour shall be corrected to the following parameters as applicable in accordance with the correction factors determined from the charts to be provided to HECO which include the ASHRAE design conditions determined at 0.4% annual percentile for Barbers Point NAS (now Kalaeloa National Weather Service site) (the “ASHRAE Design Conditions”):


Variable	-	Corrected to:
Compressor Inlet Temperature		77F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb, for CT correction with evaporative coolers in service

Ambient Temperature		86F. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb for ST correction

Ambient Humidity	-	64%. Based on ASHRAE Design Conditions of 76F wet bulb, 86F coincident dry bulb

Ambient Pressure	-	14.8 psia. Average barometric pressure for August 15 to September 15 at 13:00 (from Kalaeloa’s operational data)

Power Factor		0.85 lagging



Export Steam				Up to110,000 lbs/hr (or value necessary for Facility to achieve PURPA requirements). No correction above 110,000 lbs/hr

If the actual temperature and humidity conditions exceed the ASHRAE Design Conditions, no corrections will be made to the KW output of any of the three turbines. The 0.4% annual percentile ASHRAE Design Conditions represent a ceiling for reasonably anticipated worst-case conditions.

The Test results for the two portions of the Test relating to each CT will need to be corrected per PPA Attachment D to correct to the approximate time prescribed for the Test of each CT relative to the need for a “C” inspection pursuant to Test Conditions and Parameters, Item 4, if that portion of the Test does not occur when prescribed by such Item 4. A determination of which CT result is corrected to 8,000 operating hours vs 16,000 operating hours is made after performing the calculation for both combinations of CTs (i.e. CT1 for 8,000 and CT2 for 16,000 vs CT1 for 16,000 and CT2 for 8,000). The combination of operating hour correction pairs to be applied is the average of the two cases, however, if any of the combinations requires that a correction be applied where the degradation is calculated to a CT for an operating hour level that has already occurred in the present C inspection interval, no correction is applied for that CT for purposes of the specific combination calculation. An example of the calculations is attached.

The corrected capacity for the full Facility shall be rounded to the nearest MW output with decimal values of 0.50 and higher being round up to the next integer MW value and decimal values of 0.49 or less being rounded down to the next integer MW value and shall be the capability level demonstrated for the full Facility case by the Test.

To determine the capability of the Facility without one CT in operation, the lowest capability test result level of the two test runs will be used for the test result. The corrected capacity shall be the value in MW truncated to the integer level.

In order to facilitate evaluation of the Test results and the influence of the Facility modifications, the following shall be provided:

Correction curves for CT:

1.)

Compressor Inlet Temperature

2.)

Power Factor

3.)

Ambient Humidity

Correction curves for ST:

1.)

Ambient Temperature and Ambient Humidity

2.)

Ambient Pressure

3.)

Power Factor

4.)

HP steam export

5.)

IP steam export

6.)

LP steam export

The following data shall be collected by Kalaeloa during the Test to be used for correcting the measured capacity from the Test results to the herein defined reasonable worst-case conditions:

•

date (with day of week shown separately)

•

date of last “C” inspection for each CT

•

date each HRSG last cleaned

•

time (13:00)

•

Ambient Temperature

•

Ambient Humidity

•

Ambient Pressure

•

evaporative cooler on?

•

dispatched at full load?

•

TIT

•

steam to fuel ratio, each CT

•

steam export to Tesoro

•

CT1 MW

•

CT2 MW

•

total facility MW

•

fuel flow, each CT

•

steam turbine MW

•

steam turbine exhaust pressure.

•

steam turbine throttle pressure

•

steam turbine throttle temperature

•

CT1 stack exhaust temperature

•

CT2 stack exhaust temperature

•

fuel analysis (including fuel bound nitrogen)

•

VIGV data

•

listing of all CT washes, compressor washes (on-line and off-line), boiler washes within 45 days of the start of the test.

•

list the Equivalent Operating Hours (EOH) of each CT since the last “C” inspection and the EOH of the ST since the last major inspection.

Example 1

Assumptions

1.	CT Unit No. 1 M Upgrade commences operation on June 1^st, 2004.

2.	CT Unit No. 2 M Upgrade commences operation on December 31^st, 2004.

3.	All three portions of the Test are completed by January 30, 2005 and on January 30, 2005 the log book reveals that:

(i)

5,830 operating hours have elapsed on CT Unit No. 1; and

(ii)

720 operating hours have elapsed on CT Unit No. 2.

4.	All operating conditions and ASHRAE Design Conditions corrections have been applied to Preliminary Results.

The lower border of the lower right curve on Figure 3 of Attachment D to the PPA (the “Output Degradation Curve”) will be used to measure output degradation of the CTs. Since the data source for the equation for the Output Degradation Curve is not available at the present time and it is presumed that the equation will not be available at the time of the Test, the parties will visually and by means of a ruler, extract the Output Degradation Curve changes in a reasonable manner and it is agreed that the extracted values from the Output Degradation Curve which are used in the example below are not to be deemed to be official readings from the Output Degradation Curve but rather reasonably approximated values for purposes of illustration in the example below.

6.	ST degradation is assumed to be negligible based on the estimated potential of the HRSG to produce steam. Thus, HRSG steam output would not be expected to substantially change throughout the C inspection cycle.

Preliminary Results

7.	The Test’s 48 hour portion demonstrates the lowest full load One Clock Hour Average for the Facility is 210,000 KW and during the same hour the One Clock Hour Average for CT Unit No. 1 is 79,040 KW and the One Clock Hour Average for CT Unit No. 2 is 80,960 KW.

8.	The Test’s 4 hour portion for CT Unit No. 1 demonstrates the lowest full load One Clock Hour Average for CT Unit No. 1 and the ST is 102,870 KW of which the One Clock Hour Average for the same hour is 78,870 KW for CT Unit No. 1 and 24,000 KW for the ST.

9.	The Test’s 4 hour portion for CT Unit No. 2 demonstrates the lowest full load One Clock Hour Average for CT Unit No. 2 and the ST is 105,130 KW of which the One Clock Hour Average for the same hour is 81,130 KW for CT Unit No. 2 and 24,000 KW for the ST.

Degradation Correction for the 48 Hour Portion of the Test

10.

(a) Correction of the 48 hour test portion requires correcting the One Clock Hour Average (which occurred during the lowest full load One Clock Hour Average for the Facility) for each of CT Unit No. 1 and CT Unit No. 2 to allow for degradation as contemplated by the Output Degradation Curve. Two cases will be calculated and the

result averaged. In the first case, CT Unit No. 1 will be degraded to 8,000 hours and CT Unit No. 2 will be degraded to 16,000 hours. In the second case, CT Unit No. 1 will be degraded to 16,000 hours and CT Unit No. 2 will be degraded to 8,000 hours. The cases will then be averaged.

Case One

(b) For CT Unit No. 1 the degradation shall be 0.47% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 1 had been tested at the 8,000 operating hour mark (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 1^st, 2004) which is the state at which CT No. 1 should be deemed to be halfway through its “C” inspection life cycle. Thus, 0.47% was determined by calculating the degradation which the Output Degradation Curve predicts would occur for the 2,170 operating hours from hour 5,930 until hour 8,000. Therefore, the CT Unit No. 1 reading (during the Facility’s lowest full load One Clock Hour Average) of 79,040 KW is multiplied by (100% - 0.47%) which equals 78,669 KW for CT Unit No. 1.

(c) For CT Unit No. 2 the degradation shall be 2.74% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 2 had been tested at the 16,000 operating hour mark (CT Unit No. 2 has already degraded during its 720 hours of operation since December 31^st, 2004) which is the state at which CT No. 2 should be deemed to be at the end of its “C” inspection life cycle. Thus, 2.74% was determined by calculating the degradation which would occur for the 15,280 operating hours from hour 720 until hour 16,000. Therefore, the CT Unit No. 2 reading (during the Facility’s lowest full load One Clock Hour Average) of 80,960 KW is multiplied by (100% - 2.74%) which equals 78,742 KW for CT Unit No. 2.

(d) Correction to the 48 hour portion shall be 210,000 – ((79,040 - 78,669) + (80,960 - 78,742)) = 207,411 which represents the lowest full load One Clock Hour Average of the Facility less the Output Degradation Curve degradation calculated in (b) and (c) above for the CTs.

Case Two

(e) For CT Unit No. 1 the degradation shall be 1.28% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 1 had been tested at the 16,000 operating hour mark (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 1^st, 2004) which is the state at which CT No. 1 should be deemed to be at the end of its “C” inspection life cycle. Thus, 1.28% was determined by calculating the degradation which the Output Degradation Curve predicts would occur for the 10,170 operating hours from hour 5,930 until hour 16,000. Therefore, the CT Unit No. 1 reading (during the Facility’s lowest full load One Clock Hour Average) of 79,040 KW is multiplied by (100% - 1.28%) which equals 78,028 KW for CT Unit No. 1.

(f) For CT Unit No. 2 the degradation shall be 1.93% which represents the additional degradation which the Output Degradation Curve predicts would occur if CT Unit No. 2 had been tested at the 8,000 operating hour mark (CT Unit No. 2 has already degraded during its 720 hours of operation since December 31^st, 2004) which is the state at which

CT No. 2 should be deemed to be halfway through its “C” inspection life cycle. Thus, 1.93% was determined by calculating the degradation which would occur for the 7,280 operating hours from hour 720 until hour 8,000. Therefore, the CT Unit No. 2 reading (during the Facility’s lowest full load One Clock Hour Average) of 80,960 KW is multiplied by (100% - 1.93%) which equals 79,397 KW for CT Unit No. 2.

(g) Correction to the 48 hour portion shall be 210,000 – ((79,040 - 78,028) + (80,960 – 79,397)) = 207,425 which represents the lowest full load One Clock Hour Average of the Facility less the Output Degradation Curve degradation calculated in (e) and (f) above for the CTs.

(h) Finally, the average of 207,411 KW and 207,425 KW is taken yielding 207,418 KW.

Degradation Corrections for 4 Hour Portion of the Test Relating to CT Unit No. 1

11.

Correction to CT Unit No. 1 shall be 1.28% which represents the additional degradation which the Output Degradation Curve predicts would occur for the 10,170 operating hour from hour 5,830 until operating hour 16,000 (CT Unit No. 1 has already degraded during its 5,830 hours of operation since June 2004) which is the state at which CT No. 1 should be deemed to be halfway through its “C” inspection life cycle. Thus, 1.28% was determined by calculating the degradation which would occur from operating hour 5,830 until hour 16,000. Therefore, the CT Unit No. 1 lowest full load One Clock Hour Average of 78,870 KW is multiplied by (100% - 1.28%) which equals 77,860 KW for CT Unit No. 1. 101,860 KW is the result of the 4 hour portion of the Test for CT Unit No. 1 (77,860 KW for CT Unit No. 1 plus the ST of 24,000 KW).

Degradation Correction for 4 Hour Portion of the Test Relating to CT Unit No. 2

12.

Correction to CT Unit No. 2 shall be 2.74% which represents the additional degradation which the Output Degradation Curve predicts would occur from operating hour 720 until operating hour 16,000 (CT Unit No. 2 has already degraded during its 720 operating hours of operation since its “C” inspection) which is the state at which CT No. 2 should be deemed to be at the end of its “C” inspection life cycle. Thus, 2.74% was determined by calculating the degradation which would occur for the 15,280 operating hours from operating hour 720 until operating hour 16,000. Therefore, the CT Unit No. 2 lowest full load One Clock Hour Average of 81,130 KW is multiplied by (100% - 2.74%) which equals 78,907 KW for CT Unit No. 2. 102,907 KW is the result of the 4 hour portion of the Test for CT Unit No. 2 (78,907 KW for CT Unit No. 2 plus the ST of 24,000 KW).

Test Results

13.	Full Facility capability is 207,000 KW (which represents 207,418 KW rounded to 207,000 KW).

14.	Partial Facility capability is 101,000 KW which is the lower of the capabilities of 101,860 KW and 102,907 KW as such result is truncated in accordance with the protocol.

Increment Two Capacity Agreement Results

15.	Demonstrated Facility Capacity is 207,000 KW.

16.	Increment Two Capacity is set at 18,000 KW which represents the first 18,000 KW beyond the Baseline Capacity of 180,000 KW plus the Increment One Capacity of 9,000 KW.

17.	New Capacity is 27,000 KW which is the Increment One Capacity of 9,000 KW plus the Increment Two Capacity of 18,000 KW.

18.	Prorated Shutdown Capacity is set at 101,000 KW which is the highest of 90,000 KW and 101,000 KW.

EXHIBIT 4

30-Jun-04

Mr. Ward D. Sauders, P.E.

Purchased Power Contract Administrator

Hawaiian Electric Company, Inc.

P.O. Box 2750

Honolulu, HI ###-###-####

Subject: Calculation of Value of the Facility

Dear Ward,

At your request, we have prepared the calculation of the value of the Facility as specified under PPA Sections 3.3 (H) and 7.2 B (1). These calculations include the outstanding principal on the project debt as of June 30, 2004. Since we make quarterly debt service payments, this debt value will be the same until September 30, 2004. Please see the enclosed.

Sincerely,

Kalaeloa Partners, L.P.


By:		PSEG Kalaeloa Inc.
		Its General Partner

By		/s/ Royal Daniel
		Royal Daniel
		Its Vice President

(Enclosures)

Kalaeloa Partners, L.P.

Calculation of PPA 3.3 (H) Value as of 6/30/04


PPA Section 3.3(H) Loss of QF Status

	Outstanding Debt (1)		$	154,198,500
+	Obligations under steam sales contract			—
+	Obligations under site lease			—
+	Turnkey Design/Build Contract			—
+	Operating, maintenance and Repair Contract			—
+	Fuel Supply Contract			—
+	Kalaeloa original equity investment less distributions (2)			—

		Total	$	154,198,500


Footnotes:
	(1)	Outstanding Debt:

		Bank loan current balance after quarterly payment on 6/30/04	$	36,579,750
		Institutional loan current balance after quarterly payment on 6/30/04		117,618,750

		Total (As of 6/30/04)	$	154,198,500


(2) Kalaeloa partners investments and distributions

	Investment		Distribution
1989 Investment	$	1,016,433
1989 Distribution			$	1,612,566
1991 Investment		14,361,064
1992 Distribution				8,711,952
1993 Distribution				5,039,345
1994 Distribution				6,462,618
1995 Distribution				4,566,365
1996 Distribution				—
1997 Distribution				15,188,983
1998 Distribution				9,354,933
1999 Distribution				3,633,000
2000 Distribution				6,168,857
2001 Distribution				10,229,529
2002 Distribution				1,854,003
2003 Distribution				5,832,546
2004 Distribution				1,191,214

	$	15,377,497	$	79,845,911

Investment less Distribution not less than zero. Kalealoa will not include the PSEG purchase price of $54.4 million as an original investment.

Kalaeloa Partners, L.P.

Calculation of PPA 7.2 B (1) Value as of 6/30/04

PPA Section 7.2 B (1), Amendment 3- HECO’s assumption of Kalaeloa’s Interest upon default


	Outstanding Debt (1)		$	154,198,500
+	Other obligations			—
+	Fair market value (FMV) of Facility (2)			110,000,000
-	Stated amount per Amendment			(30,000,000	)
-	$8.5 million x (A/B) (3)			(5,890,729	)

	Total		$	228,307,771

Footnotes
	(1)	See footnote1, previous page

	(2)	Hypothetical fair market value based on recent market price indication rounded to the nearest $10,000,000 (actual fair market value would be based on average of 3 appraisals)

	(3)	A is outstanding principal	$	154,198,500
		B is initial principal	$	222,500,000
		A/B is:		0.6930
		$8,500,000 x 0.6930	$	5,890,729

ATTACHMENT G

General Plant Description

The KALAELOA Combined Cycle Facility will be constructed in two phases as follows:

Phase 1, consisting of a simple cycle facility with one combustion turbine Type GT11N to generate electricity for, “peaking” service; and

Phase 2, the Combined Cycle Facility with one additional combustion turbine Type GT11N and one steam turbine to generate steam for sale to Tesoro Hawaii, Corp. (Tesoro) (formerly HIRI) and electricity for HECO dispatch.

The Combined Cycle Cogeneration Facility will be located on the island of Oahu in the Campbell Industrial Park. The proposed site is located approximately twenty (20) miles west of Honolulu. A legal description of the site is provided in Attachment F. The Facility will consist of state of the art components, systems, and redundancy to allow the plant to meet the availability guarantees contained in the PPA. All plant equipment will be designed to provide a plant life of at least thirty (30) years.

The Facility will consist of two ABB type GT11N gas turbine generators with a nominal rating each of 74,600 kilowatts (76°F, 14.69 PSIA). Both of these combustion turbines are equipped with the NM upgrade package and now have a nominal rating of 86,000 kilowatts (76 deg F, 14.69 PSIA). The gas turbine exhaust flow will pass through two dual pressure heat recovery steam generators (HRSG) with each HRSG generating approximately 260,000 Lb/Hr of 905°F/1108 PSIA superheated steam and 97,000 Lb/Hr of 322°F/90 PSIA saturated steam at design conditions. LSFO will be the primary fuel for the gas turbines with No. 2 distillate fuel oil serving as the back-up fuel.

The 1108 PSIA steam will pass from the HRSG high pressure drum and enter a 51,900 kilowatt extraction condensing steam turbine (with Tesoro design steam requirements) generator. Steam will be extracted from the steam turbine, desuperheated, and sent to Tesoro under conditions specified in the Steam Purchase Agreement contained in Attachment N.

During the operation of Phase 1, water injection will be used for NOx control. Steam will be used for gas turbine NOx control during Phase 2. Steam from the extraction/condensing turbine will exhaust into a condenser operating at 2.66 inches HGA. The condenser will be cooled by water from a salt water well system. Condensate collected in the condenser hot well will be pumped via condensate pumps thru two stages of feedwater heating to the deaerator. The unit will be equipped with steam jet air ejectors. After exiting the deaerator, two HP feed pumps will supply feedwater to the HP sections of the HRSGs. Two LP feed pumps will supply the feedwater to the LP sections of the HRSG’s.

The source of makeup water for the plant steam cycle will be city potable or city reverse osmosis recycled water. Once that water is demineralized it will be discharged into a demineralized water storage tank. The demineralized water will serve as the markup for the auxiliary boiler and the cogeneration plant steam cycle. The makeup water will enter the steam cycle after the No. 2 low pressure heater. Demineralized boiler feedwater will be returned from the refinery and enter the steam cycle at this location also.

The Phase 1 fuel will be a gaseous fuel supplied by HIRI. The LSFO primary fuel for the Combined Cycle Facility and No. 2 distillate Phase 2 backup fuel oil will be provided by Tesoro. A vanadium inhibitor will be added to the LSFO at the Facility.

The cogeneration facility will be configured and instrumented to control and measure discharges/emissions in accordance with applicable environmental permits.

Attachment R

Explanation of Quick

Load Pick-up Curves

The starting point for the curve shown in HTGK 100 336 is two CTs plus the ST in operation at 115 MW (45 MW for each CT and 25 MW for ST at design conditions of 76°F). At time 0, we will have a frequency drop from 60 Hz to 59.5 Hz. The gas turbines would then pick up to 20% of their full load to reach point (1) after approximately 6 seconds. The setting value for power output of the gas turbines has then to be set to full load with the high gradient. The gas turbine will be loaded accordingly at 9.5 MW/min beginning in second 7. The steam turbine will also increase load with a certain time spent between rising of gas turbine load and steam turbine load, due to the inertia of piping and boiler. At point (2) the gas turbines have reached full load, the remaining load increase will then only come from the steam turbine.

The starting point for the curve shown in HTGK 400 337 is one CT plus ST in operation at 65 MW (45 MW for CT and 20 MW for ST at design conditions of 76°F). At time 0 we will have a frequency drop from 60 Hz to 59.5 Hz. The gas turbine would then pick up 20% of its full load to reach point (1) after approximately 6 seconds. The setting value for power output of the gas turbine I has then to be set to full load with the high gradient. At the same time the gas turbine II has to be quick-started according to HTCT 70 907/a “Quick Start.” We will then reach point (2). From (2) to (3) the load increase comes only from the load increase of the steam turbine. At (4) the gas turbine is synchronized and loaded at 9.5 MW/min. At (5) the bypass of HRSG II is starting to close. The pressure gradient of both boilers is controlled by the bypass to a maximum gradient of 4 bar/min. From (5) to (6) the load increase comes from gas turbine II and the steam turbine. After (6) the load increase is only given by the steam turbine.

General Comments on Load Pick-ups

If the temperature controller is not at the maximum inlet temperature, the speed controller of the gas turbine reacts according to a statism of 4%, every time a frequency drop

occurs. If the CT load is higher than ~ 83% (maximum inlet temperature reached), the gas turbine will no longer react to a frequency drop, as was the case with the speed controller in operation, but only with a gradient of approximately 3.4 - 9.5 MW/min, depending on which figure is set. The steam turbine would react according to the steam production.

Y-2

ATTACHMENT W

Capacity Charge Calculation

(Unavailability Adjustment)

This computation is provided as an illustration of how to compute a Capacity Charge adjustment pursuant to Section 5.2A(4) for a hypothetical partial unavailability of the Facility.

Example I – Unavailability in excess of 10MW for 30 days or more


Assumptions:		Baseline Capacity = 180MW
		Capacity Charge for Baseline Capacity = $164.35/KW-yr
		($164.35 is the value effective 12/19/91 per PPA, Restated and Amended Amendment 2, Section 3.)
		New Capacity = 29MW
		Capacity Charge for New Capacity = $112.00/KW-yr
		Capacity deficiency = 38 MW
		Duration of capacity deficiency = 42 days; 0 hours; 0 minutes
		Period of capacity deficiency = April 20 (00:00) – May 31(24:00)

Impact on Capacity Charge:

Month of April means payment due in April for Energy received by HECO in March and Capacity to be received by HECO in April.

Month of April – no impact (capacity paid in advance)

Month of May – no impact (capacity paid in advance)

Month of June – normal payment =

[

180,000 KW

164.35 / Kwyr

] + [

29,000 KW

112.00 / Kwyr

]

12mo/ yr

= $2,735,916.67


adjustment to payment	=	[	9,000	x	42.00	x	164.35	] + [	29,000	x	42.00	x	112.00	]
adjustment to payment	=	[	9,000	x	365	x	164.35	] + [	29,000	x	365	x	112.00	]

= $543,946.03 reduction

NOTE:

If deficiency for the same period had been 209 MW, adjustment to the Month of June would be $2,735,916.67 and the balance ($1,041,897.03 in this case) would be deducted from Month of July Capacity Charge payment due to Kalaeloa.

Example II – Unavailability of 10MW or less for more than 120 days


Assumptions:		Capacity deficiency = 10 MW
		Duration of capacity deficiency = 121 days; 0 hours; 0 minutes
		Period of capacity deficiency = April 20 – August 18

Impact on Capacity Charge:

Months of April to September – no impact (capacity paid in advance)

Month of October – normal payment =

[

180,000 KW

164.35 / Kwyr

] + [

29,000 KW

112.00 / Kwyr

]

12mo/ yr

= $2,783,316.67

adjustment to payment

[

10,000

121.00

112.00

]

365

= $371,287.67 reduction