Document:

Confirmation Agreement Concerning Section 5.2B 2

 HECO Exhibit 10.3 
  

CONFIRMATION AGREEMENT 
 CONCERNING SECTION
5.2B(2) OF POWER PURCHASE AGREEMENT AND 
 AMENDMENT NO. 5 TO POWER PURCHASE AGREEMENT 
  
 This Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase
Agreement and Amendment No. 5 to Power Purchase Agreement (“Increment One 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, and (v) Amendment No. 4 to Power Purchase Agreement dated as of October 1, 1999 (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. 
  
 C. Section 5.2B(2) of the Power Purchase Agreement reads as follows: 
  
 In the event that a performance test consistent with Good Engineering and Operating Practices and reasonably satisfactory to both parties
conducted immediately prior to any “C” inspection after the In-Service Date of the Facility demonstrates that the Facility is able to continuously deliver more than 180,000 KW of Firm Capacity, Section 1.22, Section 3.3C(1) of this
Agreement, and Attachment D to this Agreement may at Kalaeloa’s option be revised to reflect the capacity established by such test as the maximum capacity the Facility is capable of delivering under HECO dispatch (but not more than 189,000 KW).
The maximum capacity thus established shall thereupon become the Firm Capacity under this Agreement. The Capacity Charge rate applicable to the Firm Capacity in excess of 180,000 KW shall be $112 per KW per year (“Excess Capacity Charge
Rate”). 
  
 D. HECO and Kalaeloa have disagreed over the
timing and protocol of the performance test referred to in said Section 5.2B(2). 
  

 E. Kalaeloa has made or will make certain capital investments at the Facility to allow the Facility to
meet its intended design capability, which investments include modifications to the exhaust gas diffuser, added heat exchange surface, boiler wash capability (including associated water treatment system) and combustion turbine evaporative cooling
(collectively, the “Investments to Meet Intended Design Capability”). 
  
 F. Notwithstanding the parties’ disagreement regarding the timing and protocol of the performance test referred to in said Section 5.2B(2), Kalaeloa has been making available to HECO energy in excess of 180,000
KWH per hour and HECO has from time to time dispatched such additional energy pursuant to Sections 3.1B and 3.2D(4) of the Power Purchase Agreement. 
  
 G. HECO has decided that it is beneficial to itself and its customers, and Kalaeloa has decided that it is beneficial to itself and its owners, for
Kalaeloa to provide and HECO to accept an increase in Firm Capacity of nine (9) megawatts pursuant to said Section 5.2B(2) of the Power Purchase Agreement and this Increment One Capacity Agreement, subject to approval of this Increment One Capacity
Agreement by the Public Utilities Commission. 
  
 H. In light of
the facts set forth in Recitals F and G above, HECO and Kalaeloa have collected certain data as set forth in the letter dated April 21, 2004 attached hereto as Exhibit 1 and have agreed on the protocol for the performance evaluation regarding the
increase in Firm Capacity as set forth in the Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Case for up to 189 MW, a copy of which is attached hereto as Exhibit 2. 
  
 I. The data collected pursuant to tests conducted on April 21, 2004 through April 23, 2004 under such protocol having
demonstrated that the Facility is able to deliver the capacity of 189,000 KW under HECO Dispatch, HECO and Kalaeloa desire to settle all disputed issues arising out of said Section 5.2B(2) of the Power Purchase Agreement, to confirm the increase in
Firm Capacity provided for in said Section 5.2B(2), to establish an in-service date for such increased capacity contingent upon certain approvals from the Public Utilities Commission, and to otherwise amend certain provisions of the Power Purchase
Agreement in light of certain recent changes in circumstance. 
  
 J. An additional complication for administration of the Power Purchase Agreement has arisen out of the action of the U.S. Bureau of Labor Statistics to cease publication of the Producer Price Index for magnesium ingots, which had been used
by the parties to calculate the “Additive Component” of the Energy Charge under the Power Purchase Agreement, and the failure to date of HECO and Kalaeloa to agree upon an alternate method of calculating the “Additive Component.”

  
 NOW, THEREFORE, in consideration of the premises and mutual
agreements and covenants contained in this Increment One Capacity Agreement and for other good and valuable consideration (including, but not limited to, the avoidance of the expense and uncertainty of formal dispute resolution under the Power
Purchase Agreement), the receipt and adequacy of which are hereby acknowledged, the parties hereby settle, with effect as set forth herein, their disputes over Section 5.2B(2) of the Power Purchase Agreement and the method of 

  

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calculating the Additive Component of the Energy Charge, confirm the increase in Firm Capacity provided for in said Section 5.2B(2), and otherwise agree as
follows: 
  

	1.	Definitions. 

  
 Regardless of whether or not the Increment One Capacity In-Service Date has occurred, (i) capitalized terms used in Sections 3 and 9 through 14 of this
Increment One Capacity Agreement and defined in Section 2 of this Increment One Capacity Agreement have the respective meaning given them in Section 2 and (ii) capitalized terms used but not defined in this Increment One 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 One Capacity In-Service Date, Article I of the Power Purchase Agreement is deemed amended by modifying
Sections 1.6 and 1.22 to read in their entirety as set forth below, and by adding the definitions set forth below as Sections 1.58 through 1.95: 
  
 1.6 Capacity Charge – The amount to be paid by HECO to Kalaeloa pursuant to Section 5.2 of this Agreement based on Baseline Capacity
plus the New Capacity available to the HECO system from the Facility. 
  
 1.22 Firm Capacity – The sum of the following: Baseline Capacity plus the Increment One Capacity. 
  
 * * * 
  
 1.58 Additive Component Credit – The difference between the amount, as determined on the basis of the Pre-Transition Date Formula, of
the Additive Component of the Energy Charge incurred by HECO for Calendar Year 2003 and the amount actually paid by HECO as the Additive Component of the Energy Charge incurred for Calendar Year 2003, as set forth in Section 3.B. of the Increment
One Capacity Agreement. 
  
 1.59 Additive
Component Offset – The difference between (i) the amount of the Additive Component of the Energy Charge that would have been incurred by HECO for the Pre-Transition Date Period had the Post-Transition Date Formula been in effect for such Period
and (ii) the amount actually paid by HECO, as determined on the basis of the Pre-Transition Date Formula, as the Additive Component of the Energy Charge incurred for the Pre-Transition Date Period. The Additive Component Offset is to be set off
against the Additive Component Credit for purposes of determining the Transition Date, as set forth in Section 3.C.4 of the Increment One Capacity Agreement. 
  

1.60 Annual New Capacity Charge – For each Contract Year, the Capacity Charge incurred by HECO for the New Capacity during such
Contract Year pursuant to Section 5.2A(1). 
  

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 1.61 August 2003 PPI Final Value – 98.6, which is the last monthly final value for
the Producer Price Index for magnesium ingots published by the U.S. Bureau of Labor Statistics. 
  
 1.62 Base Additive GNPIPD – The value of GNPIPD on January 1, 2004 as determined by the Final value of GNPIPD for the fourth quarter
of 2003 published by the U.S. Bureau of Economic Analysis and which shall be the denominator in the fraction to be used in the Post-Transition Date Formula. For purposes of calculating the Additive Component Offset for Calendar Year 2004 pursuant to
Section 3.C.4 of the Increment One Capacity Agreement, the Base Additive GNPIPD value shall be 106.243. 
  
 1.63 Baseline Capacity – 180,000 KW at 0.85 power factor. 
  
 1.64 Calendar Year – The period from and including January 1 through and including the next following
December 31. 
  
 1.65 Capacity For Which Capacity
Charges Are Being Incurred – The total capacity for which a Capacity Charge is payable under Section 5.2A(1) without giving effect to any reductions in or deductions from the Capacity Charge pursuant to any other provisions of this Agreement.
 
  
 1.66 Consumer Advocate is defined in
Section 23.20. 
  
 1.67 Current Additive GNPIPD
– For Calendar Year 2004 and for each Calendar Year thereafter, the value of GNPIPD on January 1 of the Calendar Year in question as determined by the Final value of GNPIPD for the fourth quarter of the previous Calendar Year published by the
U.S. Bureau of Economic Analysis, which shall be the numerator in the fraction to be used in the Post-Transition Date Formula for the Calendar Year in question. For purposes of calculating the Additive Component Offset for Calendar Year 2004
pursuant to Section 3.C.4 of the Increment One Capacity Agreement, the Current Additive GNPIPD shall be 106.243. 
  
 1.68 December 2002 PPI Final Value – 134.3, which is the monthly final value for the Producer Price Index for magnesium ingots
published by the U.S. Bureau of Labor Statistics. 
  
 1.69 Delay Degradation – Any degradation in Facility performance occurring under the conditions set forth in Section 3.2D(9) (captioned “Degradation Exemption”) of the Power Purchase Agreement, for the period Kalaeloa is
entitled to such “Degradation Exemption.” 
  
 1.70 Demonstrated Facility Capacity – The maximum capacity of 189,000 KW, as demonstrated by the data collected and corrected pursuant to the tests conducted on April 21, 2004 through April 23, 2004 under the protocol attached as
Exhibit 2 to the Increment One Capacity Agreement. 
  
 1.71 FIN No. 46R is defined in Section 23.20. 
  

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 1.72 Final – The value first published by the U.S. Bureau of Economic Analysis as
“final” (as opposed to “advance” or “preliminary”) for GNPIPD for the quarter in question, such “final” value usually being published the third month after the close of such quarter. Subsequent revisions
(sometimes referred to as “revised estimates”) by the U.S. Bureau of Economics Analysis to the value first published as “final” shall not constitute the “Final” value for purposes of making adjustments tied to changes
in GNPIPD under this Agreement except to the extent that the provisions of Section 3.C.5 and/or paragraph c of Section 8.I of the Increment One Capacity Agreement, by requiring that GNPIPD values used to make adjustments tied to GNPIPD be selected
from the same U.S. Bureau of Economic Analysis publication, permit the value of the Base Additive GNPIPD and/or the value of the 1987 Final GNPIPD, respectively, to be updated. 
  
 1.73 Incentive Energy – For each Contract Year from and after the Increment One Capacity In-Service
Date, the Net Electrical Energy Output accepted by HECO in excess of HECO’s minimum energy purchase obligation for such Contract Year as set forth in Section 5.1D. 
  
 1.74 Increment One Capacity – The first 9,000 KW at 0.85 power factor of Demonstrated Facility Capacity
beyond the Baseline Capacity. 
  
 1.75 Increment
One Capacity Agreement – The Confirmation Agreement Concerning Section 5.2B(2) of the Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement by and between HECO and Kalaeloa. 
  
 1.76 Increment One Capacity In-Service Date – The
Increment One Rate Inclusion Date, provided that the conditions precedent to the effectiveness of Sections 2 and 4 through 9 of the Increment One Capacity Agreement as set forth in Section 13 of the Increment One Capacity Agreement have been
satisfied. 
  
 1.77 Increment One 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 One Capacity and the Variable O&M Component of the Energy Charge) incurred by HECO pursuant to the Increment One Capacity Agreement. 
  
 1.78 Information is defined in Section 23.20. 
  
 1.79 January 2003 Final PPI Value – 101.3, which is the
monthly final value for the Producer Price Index for magnesium ingots published by the U.S. Bureau of Labor Statistics. 
  
 1.80 Minimum Thermal Threshold – For any Calendar Year, shall be an Operating Thermal Threshold of twelve percent (12%), provided,
however, that in the event that HECO determines, in its sole discretion, that the Power Purchase Agreement is likely to be deemed to be an arrangement containing a lease within the scope of Financial Accounting Standards Board (“FASB”)
Statement No. 13, Accounting for Leases, by 

  

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reason of the Minimum Thermal Threshold being 12%, then the Minimum Thermal Threshold shall upon written notice by HECO to Kalaeloa be increased to an
Operating Thermal Threshold of fifteen percent (15%) for the next Calendar Year and subsequent years. 
  
 1.81 New Capacity – The Increment One Capacity. 
  
 1.82 Ninety is defined in Section 25.2. 
  
 1.83 On-peak Monthly Steam Average is defined in Section 23.18. 
  
 1.84 On-peak Period – The fourteen (14) hour period
from and including 7:00 a.m. through and including 8:59 p.m. each day. 
  
 1.85 One Hundred Eighty-Nine is defined in Section 25.1. 
  
 1.86 Operating Thermal Threshold – The ratio, for the Calendar Year in question, of the Facility’s useful thermal output for
such Calendar Year divided by the sum of (i) the useful electrical output for such Calendar Year plus (ii) the useful thermal output for such Calendar Year. This ratio is to be expressed as a percentage. 
  
 1.87 Post-Transition Date Formula – The formula used to
adjust the value of the Additive Component to be used in the calculation of the Energy Charge incurred on or after the Transition Date as further described in Section 5.1A. 
  
 1.88 Post-Transition Date Period – The period from and after the Transition Date until the end of the
Term. 
  
 1.89 PPI Dispute – The dispute
between Kalaeloa and HECO over the calculation of the “Additive Component” of the Energy Charge in light of the action of the U.S. Bureau of Labor Statistics to cease publication of the Producer Price Index for magnesium ingots.

  
 1.90 Pre-Transition Date Formula – The
formula used to adjust the value of the Additive Component to be used in the calculation of the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period as further described in Section 5.1A. 
  
 1.91 Pre-Transition Date Period – The period from and
including January 1, 2004 through the day prior to the Transition Date. 
  
 1.92 Recipient is defined in Section 23.20. 
  
 1.93 SOX 404 is defined in Section 23.20. 
  
 1.94 Transition Date – The first day of the calendar month following the calendar month for which the balance of the Additive
Component Credit is reduced to zero or less by subtraction therefrom of the Additive Component Offset, as set forth in 

  

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Section 3.C.4 of the Increment One Capacity Agreement. 
  
 1.95 Variable O&M Component is defined in Section 5.1E. 
  

	3.	Additive Component. 

  
 A. Regarding Calculation of “Additive Component” Under Section 5.1 of the Power Purchase Agreement. 
  
 The definition of the “Additive Component” set forth towards the
end of Section 5.1A of the Power Purchase Agreement shall apply only to the Additive Component of the Energy Charge incurred prior to January 1, 2003. With respect to subsequent periods, the aforesaid definition of the “Additive Component”
is supplemented as follows: 
  
 The “Additive
Component” of the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period shall be: 
  
 0.144 cents/KWH multiplied by 0.88704028 (which product accounts for the change in the Producer Price Index for magnesium ingots from 114.2 in January of
1988 to 101.3 in January of 2003). 
  
 The “Additive
Component” of the Energy Charge incurred on or after the Transition Date shall be: 
  
 0.144 cents/KWH multiplied by 1.019702277 (which product is being used as a proxy for the change in the Producer Price Index for magnesium ingots from 114.2 in January of 1988 to the month during which the Transition
Date occurs, for which 116.45 shall be used as the value for such month because it represents the midpoint of the August 2003 PPI Final Value and the December 2002 PPI Final Value, which midpoint is the compromise value for the month during which
the Transition Date occurs agreed to by Kalaeloa and HECO) multiplied by the quotient of the Current Additive GNPIPD divided by the Base Additive GNPIPD. 
  
 B. Regarding Credit for Payment of Additive Component of the Energy Charge Incurred for Calendar Year 2003. 
  
 HECO paid Kalaeloa for the “Additive Component” of the Energy
Charge incurred for Calendar Year 2003 on the basis of 0.144 cents/KWH multiplied by 1.17600701, which is the quotient of 114.2 (which represents the January 1988 final value of the Producer Price Index for magnesium ingots) and 134.3 (which
represents the preliminary value published by the U.S. Bureau of Labor Statistics for the Producer Price Index for magnesium ingots for the month of January 2003). Recalculating the “Additive Component” incurred for Calendar Year 2003 on
the basis of the Pre-Transition Date Formula (which uses the January 2003 Final PPI Value in lieu of the aforesaid preliminary value) results in a difference of $555,530.42 to HECO’s credit. As part of the settlement of the PPI Dispute, this
amount (without interest) will 

  

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be credited to HECO pursuant to the mechanism set forth in Section 3.C.4 of this Increment One Capacity Agreement. 
  
 C. Regarding Payment of “Additive Component.” 
  
 1. Periods Prior to January 1, 2003. Kalaeloa and HECO agree that the
calculation of the “Additive Component” of the Energy Charge incurred for all periods prior to January 1, 2003 was properly done if performed pursuant to the only formula provided for in the Power Purchase Agreement prior to the execution
of the Increment One Capacity Agreement, and that any claim for adjustment to the Additive Component incurred for any such period(s) shall be resolved solely in accordance with Section 6.3 of the Power Purchase Agreement. Both Kalaeloa and HECO
hereby waive all claims (other than claims under said Section 6.3) each may have against the other arising out of the calculation and payment of the “Additive Component” for the Energy Charge incurred for all periods prior to January 1,
2003. 
  
 2. Calendar Year 2003 and the Pre-Transition Date
Period. For the Energy Charge incurred for Calendar Year 2003 and for the Pre-Transition Date Period, HECO shall pay, pursuant to Section 6.2 of the Power Purchase Agreement, the Additive Component of the Energy Charge on the basis of the
Pre-Transition Date Formula. 
  
 3. Post-Transition Date
Period. For the Energy Charge incurred on or after the Transition Date, HECO shall pay, pursuant to Section 6.2 of the Power Purchase Agreement, the Additive Component of the Energy Charge on the basis of the Post-Transition Date Formula.

  
 4. Additive Component Credit and Additive Component
Offset. The Additive Component Credit and the Additive Component Offset will be used to determine the Transition Date as provided in this Section 3.C.4. For each month of the Pre-Transition Date Period, a calculation will be made of the Additive
Component of the Energy Charge that would have been incurred by HECO for such month had the Post-Transition Date Formula been in effect for such month. The difference between this amount and the amount actually paid by HECO pursuant to Section 3.C.2
above as the Additive Component of the Energy Charge incurred for such month shall constitute the Additive Component Offset for such month. Each monthly Additive Component Offset shall be subtracted from the then remaining balance of the Additive
Component Credit until the balance of the Additive Component Credit is zero or less. The first day of the calendar month following the month for which the balance of the Additive Component Credit is reduced to zero or less shall be the Transition
Date. Any portion of the Additive Component Offset for the last month of the Pre-Transition Date Period which remains unused once the balance of the Additive Component Credit is reduced to zero or less as aforesaid shall be extinguished and HECO
shall make no payment to Kalaeloa on account of such unused portion. 
  
 5. Miscellaneous. Although the provisions of Section 8.I of this Increment One Capacity Agreement do not strictly apply to the Base Additive GNPIPD and the Current Additive GNPIPD used in the Post-Transition Date Formula due to such
Formula’s use of the Final value of GNPIPD for the fourth quarter of 2003 rather than the Final value for the fourth quarter of 1987 used in the GNPIPD adjustment factor referenced in the aforesaid Section 8.I, the parties agree that, in
selecting GNPIPD values to use in applying the Post- Transition Date 

  

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Formula and in determining which invoices are to be recalculated and which are not following the release of updated GNPIPD values, they will follow the same
procedures as are set forth for the GNPIPD adjustment factor in paragraphs c and d of Section 8.I of this Increment One Capacity Agreement. 
  
 D. Full and Final Settlement of PPI Dispute. 
  
 Provided that the condition precedent set forth in the following paragraph of this Section 3.D is satisfied, this Increment One Capacity Agreement
constitutes full and final settlement of the respective claims of HECO and Kalaeloa arising out of the PPI Dispute. Subject only to the satisfaction of such condition precedent, and immediately upon the occurrence of such satisfaction, Sections 3.A,
3.B and 3.C shall come into effect and thereupon both HECO and Kalaeloa shall be deemed to have released the other from all claims arising out of the PPI Dispute. 
  
 The condition precedent referenced in the preceding paragraph of this Section 3.D is the first to occur of either of the
following: (i) the satisfaction of the conditions precedent to the effectiveness of Sections 2 and 4 through 9 of this Increment One Capacity Agreement, as set forth in Section 13 of this Increment One Capacity Agreement; or (ii) the occurrence of
both (aa) Lender Approval by the Lender Approval Deadline pursuant to Section 13 of this Increment One Capacity Agreement and (bb) the issuance, by the PUC Approval Deadline (as defined in said Section 13), of a “final non-appealable order from
the Public Utilities Commission” (as defined in Section 11.C of the Increment One Capacity Agreement) that either (yyy) declares that the change in the calculation of the Additive Component of the Energy Charge in Section 5.1 of the Power
Purchase Agreement pursuant to the settlement of the PPI Dispute set forth in this Section 3 of the Increment One Capacity Agreement (the “Additive Calculation Settlement”) does not require Public Utilities Commission approval or (zzz)
approves the Additive Calculation Settlement. If the foregoing condition precedent has not been satisfied within the respective time periods provided in the preceding sentence, Sections 3.A, 3.B and 3.C shall be null and void ab initio unless
otherwise agreed in writing by the parties. 
  
 E. No
Prejudice. 
  
 The parties acknowledge that, with regard to
the claims arising out of the PPI Dispute, this Section 3 of the Increment One Capacity Agreement was an attempt to settle a dispute. Therefore, this Increment One Capacity Agreement, and any negotiations, communications or procedures leading up to
this Increment One Capacity Agreement shall not in any way be deemed to waive, limit, or prejudice positions previously taken, or that may be taken in the future, by either HECO or Kalaeloa with respect to the PPI Dispute or be admissible in any
dispute resolution proceedings arising out of the PPI Dispute if Sections 3.A, 3.B and 3.C of this Increment One Capacity Agreement never become effective. 
  

	4.	Rates for Purchase. 

  
 Subject to the other provisions of the Power Purchase Agreement and to the provisions of Section 3 above, HECO shall, from and after the Increment One
Capacity In-Service Date, accept and pay for electrical energy generated by the Facility and delivered to HECO, and make 

  

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Capacity Payments to Kalaeloa when such capacity is available, all as set forth in the Power Purchase Agreement as modified by this Section 4. The respective
rights and obligations accrued by HECO and Kalaeloa with respect to the payment and receipt of the Energy Charge and Capacity Charges for the period prior to the Increment One 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 4. 
  
 A. Regarding Section 5.1 of the Power Purchase Agreement. 
  

Effective upon the Increment One Capacity In-Service Date, a new Section 5.1E is hereby added to the Power Purchase Agreement to read as follows:

  
 E. Incentive Energy 
  
 Notwithstanding any provisions of Section 5.1A to the
contrary, for each Contract Year (or part thereof) from and after the Increment One Capacity In-Service Date, the formula for calculating the Energy Charge set forth in Section 5.1A shall apply only to such Net Electrical Energy Output as is
necessary to satisfy HECO’s minimum energy purchase obligation for such Contract Year (or part thereof) as set forth in Section 5.1D, and the Energy Charge relating to Incentive Energy shall be computed by the following formula: 
  
 Energy Charge = (Fuel Component x (LSFO Actual/LSFO base))

  
 + (Variable O&M Component x (GNPIPD
(current)/GNIPID (base)) 
  
 + Additive Component

  
 In the above formula, the terms defined in
Section 5.1A shall have the same meanings assigned thereto in Section 5.1A (except that the term “Additive Component” shall have the meaning set forth therein as supplemented by Section 3.A of the Increment One Capacity Agreement once said
Section 3.A becomes effective) and the term “Variable O&M Component” shall mean: 
  
 0.48 cents/KWH for intervals during which the Facility is dispatched at less than 180,000 KW; and 
  
 0.144 cents/KWH for intervals during which the Facility is
dispatched at 180,000 KW or above. 
  
 Notwithstanding any other provisions of this Agreement to the contrary, HECO shall not accrue any Accumulated Excess Purchases under Section 5.1D in respect of Incentive Energy. 
  

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 B. Regarding Section 5.2 of the Power Purchase Agreement. 
  
 Effective upon the Increment One Capacity In-Service Date, Section 5.2 of the
Power Purchase Agreement is amended as follows: 
  
 1. Section
5.2A is amended in its entirety to read as follows: 
  
 A. Capacity Charge 
  
 (1) Capacity
Charge for Baseline Capacity and New Capacity 
  
 The Capacity Charge to be paid by HECO to Kalaeloa from and after the Increment One Capacity In-Service Date and thereafter during the remaining Term for Baseline Capacity shall be fixed at a rate of $167.51 per kilowatt year for each
kilowatt of Baseline Capacity, as adjusted pursuant to Section 5.2C and 5.2D below, and at a fixed rate of $112.00 per kilowatt year for each kilowatt of New Capacity. 
  
 (2) Reduction in Capacity Charge for New Capacity Due to Excessive Steam Sales 
  
 Kalaeloa acknowledges that: (a) HECO agreed to conduct the
performance evaluation demonstrating the Firm Capacity on the assumption that the Facility export of process steam under the Steam Sales Contract will be equivalent to approximately 80,000 lb/hour (with an appropriate downward correction if the
Facility was exporting less than 80,000 lb/hour at the time of the evaluation), because Kalaeloa has represented to HECO that that has been approximately the Facility’s average export of process steam in recent years; (b) the Steam Sales
Contract assumes that the Facility will export at least the equivalent of approximately 121,000 lb/hour of process steam; and (c) the ability of the Facility to continuously deliver more than 185,000 KW of electrical energy while simultaneously
exporting the equivalent of approximately 121,000 lb/hour of process steam has not been demonstrated. 
  
 Accordingly, from the Capacity Charge to be paid for New Capacity the following amounts shall be deducted if, during any one hour of an
On-peak Period, (i) the Facility is exporting more than the equivalent of 80,000 lb/hour of process steam, (ii) HECO is dispatching (or has properly ordered dispatch of, whether verbally or electronically) the Facility at more than 180,000 KW of
electrical energy and (iii) the Facility is unable to continuously deliver for the full duration of the HECO Dispatch the lesser of (aa) the Baseline Capacity plus the New Capacity and (bb) the amount of Net Electrical Energy Output HECO sought to
dispatch. (The difference between (x) the Baseline Capacity plus the New Capacity minus (y) the average amount of Net Electrical Energy Output delivered during a one-hour period, or 4,000 KW, whichever is less, is 

  

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referred to herein as the “Capacity Gap.”) The reduction shall be $0.306849 for each kilowatt multiplied by the number of kilowatts in the largest
Capacity Gap that occurs during each On-peak Period of the Contract Year, up to a maximum reduction of $1,228 per On-peak Period or $448,000 in the aggregate in any Contract Year. 
  
 (3) [RESERVED] 
  
 (4) Further Reduction From Capacity Charge 
  
 If any portion of the Capacity For Which Capacity Charges Are Being Incurred in excess of ten (10) MW is unavailable continuously for
thirty (30) days or more other than for routine scheduled maintenance preapproved by HECO, a reduction in the Capacity Charge shall be made for the total period during which such capacity is unavailable in accordance with Attachment W (Example I).
If any portion of Capacity For Which Capacity Charges Are Being Incurred of ten (10) MW or less is unavailable continuously for more than one hundred twenty (120) days, a reduction in the Capacity Charge shall be made for the total period during
which such capacity is not available in accordance with Attachment W (Example II). For purposes of calculating the foregoing reduction in the Capacity Charge, unavailable capacity shall be counted first against New Capacity up to the amount of New
Capacity, and then against Baseline Capacity up to the amount of Baseline Capacity. Once reductions in the Capacity Charge are being effectuated pursuant to this Section 5.2A(4), no other reductions in the Capacity Charge for New Capacity shall be
made pursuant to Sections 5.2A(2) and (3). 
  
 (5) Payment and Reduction 
  
 The
Capacity Charge is payable in advance monthly installments. In the event that a reduction in the Capacity Charge is required by the foregoing provisions, the amount shall be deducted from the amount of the Monthly Invoice next due to Kalaeloa. If,
at end of Term, there remains an amount that has not been deducted from the amounts due under Monthly Invoices, Kalaeloa shall promptly pay to HECO such undeducted amounts. 
  
 2. Sections 5.2B(1) and (2) are deleted in their entirety. 
  

	5.	Operating Thermal Threshold and Liquidated Damages. 

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

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 ARTICLE XXIV – OPERATING THERMAL THRESHOLD AND 
 LIQUIDATED DAMAGES 
  
 24.1 The Facility shall for each Calendar Year beginning with the Calendar Year in which the Increment One Capacity In-Service Date occurs
achieve an Operating Thermal Threshold greater than or equal to the Minimum Thermal Threshold. Within thirty (30) days after the end of each Calendar Year, Kalaeloa shall provide HECO with a written report documenting the Operating Thermal Threshold
actually achieved by Kalaeloa during such Calendar Year and a copy of the annual notice filed by Kalaeloa pursuant to 18 CFR Part 292 demonstrating that the Facility is a Qualifying Facility. 
  
 24.2 If the Facility fails to achieve the Minimum Thermal
Threshold in any Calendar Year, Kalaeloa shall pay, as HECO’s sole and exclusive remedy for such failure, except in cases of willful misconduct or cases in which HECO may have a claim to equitable relief, liquidated damages to HECO as follows:
if such failure occurs during (i) the Calendar Year that commences with the Increment One Capacity In-Service Date, Kalaeloa shall pay liquidated damages to HECO in an amount equal to fifty percent (50%) of the Annual New Capacity Charge for such
Calendar Year; (ii) a Calendar Year immediately following a Calendar Year during which Kalaeloa achieved the Minimum Thermal Threshold, Kalaeloa shall pay liquidated damages to HECO in an amount equal to fifty percent (50%) of the Annual New
Capacity Charge; and (iii) a Calendar Year immediately following a Calendar Year during which Kalaeloa also failed to achieve the Minimum Thermal Threshold, Kalaeloa shall pay liquidated damages to HECO in an amount equal to one hundred percent
(100%) of the Annual New Capacity Charge. For purposes of this Section 24.2, the Annual New Capacity Charge that forms the basis for the liquidated damages of 50% or 100% to be assessed shall be the Annual New Capacity Charge computed without regard
to any payment imposed by this Section 24.2 and any other deductions or reductions that may apply, for the Calendar Year during which such failure occurred. 
  
 24.3 Payment of liquidated damages to HECO under this Article XXIV is due thirty (30) days after written demand therefor from HECO.

  
 24.4 The respective rights and obligation of
HECO and Kalaeloa under this Article XXIV are intended to address new circumstances that have arisen since the initial execution of this Agreement. Accordingly, payments of liquidated damages as a consequence of this Article XXIV are in addition to
the liquidated damages provided for under Article VIII of this Agreement and are not subject to the limitations of said Article VIII. 
  

	6.	Calculation of Equivalent Availability Factor and Equivalent Forced Outage Rate. 

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

 13 

 ARTICLE XXV 
 CALCULATION OF EQUIVALENT AVAILABILITY 
 FACTOR AND EQUIVALENT FORCED OUTAGE RATE 
  
 25.1 When neither of the Facility’s combustion turbines
is in a reserve shutdown status, the Facility must be able to deliver at least 189,000 KW of Net Electrical Energy Output (or such other Net Electrical Energy Output as is associated with the capacity as may result from Delay Degradation) (“One
Hundred Eighty-Nine”), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate. 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 the lesser of One Hundred Eighty-Nine or the Net Electrical Energy Output as is associated with the capacity actually called for by HECO
Dispatch, a derate will be assessed equal in magnitude to One Hundred Eighty-Nine, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate.

  
 25.2 On those occasions when one of the
Facility’s combustion turbines is in a reserve shutdown status, the Facility must be able to deliver at least 90,000 KW of Net Electrical Energy Output (or such other Net Electrical Energy Output as is associated with the capacity as may result
from Delay Degradation) (“Ninety”), when called for by HECO Dispatch, in order to avoid a derating for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate. 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 the lesser of Ninety or the Net Electrical Energy Output as is associated with the capacity actually called for by HECO
Dispatch, a derate will be assessed equal in magnitude to Ninety, minus the revenue meter reading (both expressed in terms of kilowatts), for purposes of calculating Equivalent Availability Factor and Equivalent Forced Outage Rate. 
  
 25.3 Under this Agreement, the ratios for both Equivalent
Availability Factor and Equivalent Forced Outage Rate are 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 the Delay Degradation) in arriving at One Hundred Eighty-Nine or Ninety, as appropriate), NDC and NMC will continue to be One Hundred Eighty-Nine. 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. 
  
 25.4 The foregoing provisions of this Article XXV are intended to integrate into this Agreement the clarification and interpretation of
this Agreement evidenced in the Agreement to Clarify and Interpret dated March 31, 1997, by and between Kalaeloa 

  

 14 

 
and HECO, and the aforesaid Agreement to Clarify and Interpret is superseded by this Article XXV and of no further force or effect. 
  

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

  
 Effective upon the Increment One Capacity In-Service Date, the following is
added to the Power Purchase Agreement as a new Article XXVI: 
  
 ARTICLE XXVI 
 LIMITATION ON CERTAIN REDUCTIONS IN AND DEDUCTIONS 
 FROM NEW 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 Capacity Charge for New Capacity pursuant to Section 5.2A(2) and liquidated remedy payable under Article XXIV. HECO
acknowledges that it shall not seek any further remedies against Kalaeloa related to such failures, except in cases of willful misconduct or cases in which HECO may have a claim to equitable relief. 
  
 26.2 If any amounts owed by Kalaeloa for the reduction in
Capacity Charge for New Capacity pursuant to Section 5.2A(2) or liquidated damages payable under Article XXIV are 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 Capacity Charge for New Capacity payable that month. 
  

	8.	Other Clarifications, Modifications and Amendments to the Power Purchase Agreement. 

  
 Effective upon the Increment One 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 8: 
  
 A. Regarding Section 1.57 of the Power Purchase Agreement 
  
 For purposes of applying the “Unit Trips” definition to incidents occurring after the execution of the Increment One Capacity Agreement, the
requirement of prior HECO “consultation with Kalaeloa” shall, without limitation, be satisfied by any communication either from the Kalaeloa plant operator to the HECO load dispatcher or vice versa with respect to the trip/shutdown in
question regardless of whether or not the communication in question takes place before or after such trip/shutdown event. Such communication (i) need not be made by two-way medium and (ii) shall include any “hot line”, telephone or radio
communication. The point of the clarification set forth in this paragraph is that in a trip/shutdown event, it is impracticable to interpret the term “consultation” to require an exchange of views between Kalaeloa and HECO as a condition
to HECO action, and that such impracticality should not relieve Kalaeloa of the 

  

 15 

 
consequences, as set forth elsewhere in the Power Purchase Agreement, of including the trip/shutdown event in question within the definition of “Unit
Trips.” 
  
 The requirement that HECO “take immediate
steps to place an unscheduled generator on-line” shall not operate to exclude from the “Unit Trips” definition a trip/shutdown event if, at the time of the trip/shutdown in question, all generators comprising HECO’s resource
system that are available to operate are operating and HECO would have taken immediate steps to place another generator on-line had another generator been available. 
  
 An “unscheduled generator” is determined immediately prior to the instant of commencement of the trip/shutdown
event and means, in the case of a steam generator, a generator that had not been scheduled by HECO to be on-line for at least another three hours after the time a trip/shutdown event commenced, and in the case of a non-steam generator such as a
combustion turbine or internal combustion engine, a generator that had not been scheduled by HECO to be on-line at least another thirty minutes after the time a trip/shutdown event commenced. 
  
 The exclusion from the definition of “Unit Trips” of
trips/shutdowns “caused by events outside of the Facility” shall not operate to preclude from the “Unit Trips” definition trips/shutdowns caused by events occurring outside the Facility through which a facility like the Facility
should reasonably be expected, as a result of employing Good Engineering and Operating Practices, to remain synchronized and continue operation without the occurrence of a trip/shutdown event. 
  
 B. Regarding Section 3.3H of the Power Purchase Agreement. 

 
 In the event Kalaeloa requires HECO to purchase the Facility pursuant to
Section 3.3H, the parties agree that the phrase “original equity investment” does not include the Investments to Meet Intended Design Capability. 
  
 C. Regarding Section 6.1 of the Power Purchase Agreement. 
  

The first full paragraph of Section 6.1 is amended in its entirety to read: 
  
 By the fifth (5th) working day (i.e. excluding Saturdays, Sundays and legal holidays of either the federal
government or the Hawaii state government) of each Calendar Month, HECO shall provide Kalaeloa with the appropriate data in writing or electronically for Kalaeloa to compute the Energy Charge in the preceding Calendar Month as determined in
accordance with this Agreement. 
  
 The remainder of Section 6.1
is unchanged. 
  
 D. Regarding Section 7.2B(1) of the Power
Purchase Agreement. 
  
 In the event HECO exercises its right
to purchase the Facility pursuant to Section 7.2B(1) of the Power Purchase Agreement, the parties agree that the fair market value of the 

  

 16 

 
Facility shall be determined as if the Investments to Meet Intended Design Capability had not been made. 
  
 E. Regarding Section 23.15 of the Power Purchase Agreement.

  
 Section 23.15 of the Power Purchase Agreement is amended by
adding the following new Subsection 23.15.C: 
  
 C. Discontinuation of Index. 
  
 Should an index referred to herein, including but not limited to GNPIPD, be discontinued during the Term, HECO and Kalaeloa agree to select a new index that is most similar to the discontinued index in content and concept and to make a
proper transition thereto consistent with the intent hereof. 
  
 F. Regarding Article XXIII of the Power Purchase Agreement. 
  
 Article XXIII of the Power Purchase Agreement is amended by adding the following as new Sections 23.18 through 23.20: 
  
 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 80,000 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 80,000 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 80,000 lb/hour in any 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 80,000 lb/hour during any On-peak Period resulting in or contributing to a derating
of the Facility’s capability below the Firm Capacity (as 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 80,000 lb/hour during the
Calendar Year such that the increased take of steam may result in deratings of the Facility’s capability below 

  

 17 

 
the Firm Capacity (as 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 Firm Capacity (as may be reduced by any Delay Degradation) and shall report to HECO on its efforts to eliminate the occurrence of such deratings below the Firm Capacity (as may be
reduced by any Delay Degradation). 
  
 In the
event the counterparty’s take of process steam from the Facility beyond the equivalent of 80,000 lb/hour during the Calendar Year results in or contributing to deratings below the Firm Capacity (as 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 Firm Capacity (as 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 80,000 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 be a Qualifying Facility. 
  
 23.20 Financial Compliance 
  
 Kalaeloa shall provide or cause to be provided to HECO on a timely basis, as reasonably determined by HECO, all information, including but
not limited to information that may be obtained in any audit referred to below (the “Information”), reasonably requested by HECO for purposes of permitting HECO and HEI to comply with the requirements of (a) Interpretation No. 46 (revised
December 2003) of the FASB, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN No. 46R”), (b) Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX 404”) and (c) all clarifications, interpretations
and revisions of and regulations implementing FIN No. 46R and SOX 404 issued by the FASB, Securities and Exchange Commission, the Public Company Accounting Oversight Board, Emerging Issues Tax Force or other governing agency. In addition, if
required by HECO in order to meet its compliance obligations, Kalaeloa shall allow HECO or its independent auditor to audit, to the extent as is reasonably required, Kalaeloa’s financial records, including its system of internal controls over
financial reporting; provided that HECO shall be responsible for all costs associated with the foregoing, including but not limited to Kalaeloa’s reasonable internal costs. HECO shall limit access to such Information to persons involved with
such compliance matters and restrict persons involved in HECO’s monitoring, dispatch or scheduling of Kalaeloa and/or the Facility, or the administration of the Power Purchase Agreement, from having access to such Information, and persons
reviewing such Information shall not participate in negotiations of amendments, modifications or clarifications of the Power Purchase Agreement (unless such participation is approved, in writing in advance, by Kalaeloa). 
  

 18 

 HECO shall, and shall cause HEI to, maintain the confidentiality of the Information as
provided in this Section 23.20. HECO may share the Information on a confidential basis with HEI and the independent auditors and attorneys for HECO and HEI. (HECO, HEI and their respective independent auditors and attorneys are collectively referred
to in this Section 23.20 as “Recipient.”) If either of HEI or HECO, in the exercise of their respective reasonable judgments, concludes that consolidation or financial reporting with respect to Kalaeloa and/or this Power Purchase Agreement
is necessary, HEI and HECO each shall have the right to disclose such of the Information as HEI or HECO, as applicable, reasonably determines is necessary to satisfy applicable disclosure and reporting or other requirements and give Kalaeloa prompt
written notice thereof (in advance to the extent practicable under the circumstances). If HEI or HECO disclose Information pursuant to the preceding sentence, HEI and HECO shall, without limitation to the generality of the preceding sentence, have
the right to disclose Information to the Public Utilities Commission and the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii (“Consumer Advocate”) in connection with the Public
Utilities Commission’s rate-making activities for HECO and other HEI affiliated entities, provided that, if the scope or content of the Information to be disclosed to the Public Utilities Commission exceeds or is more detailed than that
disclosed pursuant to the preceding sentence, such Information will not be disclosed until the Public Utilities Commission first issues a protective order to protect the confidentiality of such Information. Neither HECO nor HEI shall use the
Information for any purpose other than as permitted under this Section 23.20. 
  
 In circumstances other than those addressed in the immediately preceding paragraph, if any Recipient becomes legally compelled under applicable law or by legal process (e.g., deposition, interrogatory, request for
documents, subpoena, civil investigative demand or similar process) to disclose all or a portion of the Information, such Recipient shall undertake reasonable efforts to provide Kalaeloa with prompt notice of such legal requirement prior to
disclosure so that Kalaeloa may seek a protective order or other appropriate remedy and/or waive compliance with the terms of this Section 23.20. If such protective order or other remedy is not obtained, or if Kalaeloa waives compliance with the
provisions at this Section 23.20, Recipient shall furnish only that portion of the Information which it is legally required to so furnish and to use reasonable efforts to obtain assurance that confidential treatment will be accorded to any disclosed
material. 
  
 The obligation of nondisclosure and
restricted use imposed on each Recipient under this Section 23.20 shall not extend to any portion(s) of the Information which (a) was known to such Recipient prior to receipt, or (b) without the fault of such Recipient is available or becomes
available to the general public, or (c) is received by such Recipient from a third party not bound by an obligation or duty of confidentiality. 
  

 19 

 G. Regarding Attachment A of the Power Purchase Agreement. 
  
 Attachment A to the Power Purchase Agreement is deemed replaced in its
entirety by Attachment A to this Increment One Capacity Agreement. 
  
 H. 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 One Capacity Agreement.  
  
 I. Regarding the GNPIPD adjustment factor. 
  
 Where the Power Purchase Agreement provides for adjustment of dollar values in accordance with the GNPIPD adjustment factor,
including the dollar values for the Non-Fuel Component of the Energy Charge and the dollar value for the minimum energy purchase shortfall calculations, the GNPIPD adjustment factor shall be calculated as follows: 
  
 a. The GNPIPD adjustment factor shall be calculated by dividing the previous
year’s fourth quarter Final GNPIPD value by the fourth quarter 1987 Final GNPIPD value. 
  
 b. In calculating the GNPIPD adjustment factor, the previous year’s fourth quarter Final GNPIPD value and the fourth quarter 1987 Final GNPIPD value shall be numbers published by U.S. Bureau of Economic Analysis
(“BEA”). 
  
 c. In calculating the GNPIPD adjustment
factor, both the previous year’s fourth quarter Final GNPIPD value and the fourth quarter 1987 Final GNPIPD value shall be selected from the same BEA publication release to ensure that the numbers were determined using consistent BEA approved
methodologies for both GNPIPD values. HECO and Kalaeloa recognize that the BEA routinely reviews and, as it deems appropriate, updates past GNPIPD quarterly values. Such reviews and updates may cause the fourth quarter 1987 Final GNPIPD value to
change during the term of the Power Purchase Agreement. Such reviews and updates will not cause a recalculation of invoices issued prior to the release of the updated GNPIPD values. 
  
 d. The BEA typically publishes the previous year’s fourth quarter Final GNPIPD value about three months following the
previous year end. Invoices of capacity and energy delivered in each month of the current year shall utilize the published previous year’s fourth quarter Final GNPIPD value. The invoices for capacity and energy delivered in the current year
that are issued prior to the BEA publishing of the previous year’s fourth quarter Final GNPIPD value (typically involving the January and February capacity and energy deliveries) will be calculated using the GNPIPD adjustment factor used during
the previous year, and then recalculated following BEA publishing of the previous year’s fourth quarter Final GNPIPD value. 
  

 20 

 J. Regarding Attachments D and R of the Power Purchase Agreement. 
  
 No modifications to Attachments D and R to the Power Purchase Agreement are
required as a result of this Increment One Capacity Agreement, and said Attachments D and R remain applicable to the Facility after the Increment One Capacity In-Service Date. 
  

	9.	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 One Capacity
Agreement shall remain in full force and effect. In the event that a conflict arises between the Power Purchase Agreement and this Increment One Capacity Agreement, this Increment One Capacity Agreement shall prevail, but the respective documents
shall be interpreted to be in harmony with each other where possible. 
  

	10.	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 One Capacity Agreement, Kalaeloa represents to HECO that, during recent years, the annual average (measured on a Calendar Year basis) of its export of process steam under the Steam Sales Contract has been equivalent to approximately 80,000
1b/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 average. 
  
 B. As a material inducement to HECO’s decision to enter into this Increment One Capacity Agreement, Kalaeloa
represents, warrants and guarantees to HECO that, from and after the Increment One 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 in cases in which HECO may have a claim to equitable relief, Kalaeloa shall pay liquidated damages as set forth in Article XXIV of the Power Purchase Agreement. 
  
 C. As a material inducement to HECO’s decision to enter into this
Increment One Capacity Agreement, Kalaeloa represents, warrants and guarantees to HECO that the Investments to Meet Intended Design Capability and the construction and operation thereof, (1) have been performed with all required permits, licenses,
approvals and other governmental authorizations needed to construct said improvements and operate the Facility with said improvements, (2) have not been and shall not be included in the meaning of the phrase “original equity investment”
for purposes of calculating the purchase price as described in Section 3.3H of the Power Purchase Agreement, (3) have not been and shall not be included in calculating the fair market value of the Facility for purposes of Section 7.2B(1) of the
Power Purchase Agreement, (4) have been accepted as part of the Facility by the operator under the Operating, Maintenance and Repair Agreement, and (5) do not interfere with, limit or detract from the representations, warranties and guarantees made
by Kalaeloa in the Power Purchase Agreement. Upon request by HECO, Kalaeloa shall provide or make available to HECO at the Facility documents or other evidence demonstrating that Kalaeloa has met the foregoing representations, warrantees and
guarantees. Kalaeloa has delivered to HECO that certain letter dated 

  

 21 

 
June 30, 2004, a copy of which is attached hereto as Exhibit 3, setting forth calculations of (i) the purchase price for the Facility for purposes of said
Section 3.3H 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, which calculations demonstrate that the Investments to
Meet Intended Design Capability are not included in calculating either the purchase price for the Facility for purposes of said Section 3.3H or the fair market value of the Facility for purposes of said Section 7.2B(1). 
  

	11.	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 One Capacity Agreement and ordering that: 
  
 (1) the purchase power costs to be incurred by HECO as a result of this
Increment One Capacity Agreement are reasonable; 
  
 (2)
HECO’s purchase power arrangements under this Increment One Capacity Agreement, pursuant to which HECO will purchase Increment One 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 One 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 One Capacity and the
purchased power incurred by HECO pursuant to this Increment One 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 One Capacity
Agreement to the contrary, HECO’s obligations under this Increment One Capacity Agreement to purchase power delivered by Kalaeloa by virtue of the Increment One Capacity and to pay the Capacity Charge for the Increment One 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 11. (Such order is referred to hereinbelow as the “PUC Approval Order”.) 
  
 C. As used in Section 11.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 

  

 22 

 
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 11C have been satisfied. 
  
 D. As used in this Increment One Capacity Agreement, the term “PUC Approval Date” shall be defined as the date of
issuance of the PUC Approval Order if HECO provides the written statement referred to in the last sentence of Section 11C to the effect that the condition referred to in clause (a) of Section 11C of this Increment One Capacity Agreement has been
satisfied or in the absence of such a written statement: 
  
 (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 11C.  
  

	12.	Entire Agreement. 

  
 This Increment One 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 One Capacity Agreement; provided, however, that nothing in this Section 12 shall cause the
Power Purchase Agreement to be invalid or unenforceable against HECO or Kalaeloa on the basis of regulatory action concerning this Increment One Capacity Agreement. 
  

	13.	Effective Date. 

  
 Sections 3.A, 3.B and 3.C of this Increment One Capacity Agreement shall become effective as provided in Section 3.D. Provided the conditions precedent to
the effectiveness of Sections 2 and 4 through 9 of this Increment One Capacity Agreement as set forth in the next 

  

 23 

 
sentence of this Section 13 have been satisfied, Sections 2 and 4 through 9 hereof shall become effective on the Increment One Capacity In-Service Date. The
conditions precedent referenced in the first sentence of this Section 13 are (a) the occurrence of the PUC Approval Date as defined in Section 11D above and (b) the consent to this Increment One Capacity Agreement by 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”). 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 HECO and Kalaeloa may agree to by a subsequent written agreement (the “PUC Approval Deadline”), or should the Lender Approval not be obtained within a reasonable period (expected to
approximately sixty (60) days) after the full execution of this Increment One Capacity Agreement and the delivery hereof to the Agent (which Kalaeloa agrees to cause to be done promptly after full execution by both parties), but in no event later
than January 3, 2005 or such later date as HECO and Kalaeloa may agree to by a subsequent written agreement (the “Lender Approval Deadline”), Sections 2 and 4 through 9 of this Increment One Capacity Agreement shall be null and void ab
initio, and HECO and Kalaeloa shall be free of all obligations under said Sections 2 and 4 through 9 and shall pursue no remedies against one another arising out of or related to said Sections 2 and 4 through 9. 
  

	14.	Settlement of Section 5.2B(2) Dispute. 

  
 Provided that the conditions precedent set forth in the following paragraph of this Section 14 are satisfied, this Increment One Capacity Agreement shall
constitute full and final settlement of the respective claims of HECO and Kalaeloa under Section 5.2B(2) of the Power Purchase Agreement. Subject only to the satisfaction of such conditions precedent, effective upon the PUC Approval Date, (a) all
rights and obligations of HECO and Kalaeloa with respect to the Increment One Capacity and the obligation to make available and pay for same are integrated into and governed solely by this Increment One Capacity Agreement and (b) both HECO and
Kalaeloa shall be deemed to have released the other from all further obligations under said Section 5.2B(2) and to have terminated their respective rights thereunder to the extent not incorporated into this Increment One Capacity Agreement.

  
 The conditions precedent referenced in the preceding paragraph
of this Section 14 are the following: (i) Lender Approval pursuant to Section 13 of this Increment One Capacity Agreement within the time period provided in or otherwise permitted under said Section 13; and (ii) occurrence of the PUC Approval Date
by Augustc 1, 2005, or such later date as HECO and Kalaeloa may agree to by a subsequent written agreement. If the foregoing conditions precedent have not been satisfied within the respective time periods provided in or otherwise permitted under the
preceding sentence, the settlement of the respective claims of HECO and Kalaeloa under Section 5.2B(2) of the Power Purchase Agreement as set forth in this Increment One Capacity Agreement shall be null and void ab initio, and HECO and Kalaeloa
shall be free to pursue their remedies against one another arising out of their respective claims under Section 5.2B(2) of the Power Purchase Agreement. 
  
 The parties acknowledge that, with regard to the claims under Section 5.2B(2) of the Power Purchase Agreement, this Increment One Capacity Agreement and
the demonstration in connection therewith were an attempt to settle a dispute. Therefore, this Increment One Capacity Agreement, HECO’s participation in said demonstration, and any negotiations, communications 

  

 24 

 
or procedures leading up to this Increment One Capacity Agreement shall not in any way be deemed to waive, limit, or prejudice positions previously taken, or
that may be taken in the future, by either HECO or Kalaeloa with respect to Section 5.2B(2) of the Power Purchase Agreement or be admissible in any dispute resolution proceedings arising out of Section 5.2B(2) of the Power Purchase Agreement if
Sections 2 and 4 through 9 never become effective. 
  

	15.	Miscellaneous. 

  
 A. The failure of either party to enforce at any time any of the provisions of this Increment One 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 One 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 One 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 One 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 One Capacity Agreement and all documents executed and
delivered in connection herewith, and all notices and other communications given pursuant to this Increment One Capacity Agreement, may be executed and signatures transmitted electronically via the Internet or facsimile. 
  
 IN WITNESS WHEREOF, the parties have executed this Increment One 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 Vice President – Power Supply
	 	 	 	 Its General Partner

					
	 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

  

 25 

 EXHIBITS 
  

			
		
	EXHIBIT 1	  	Letter dated April 21, 2004 (see Recital H)
		
	EXHIBIT 2	  	Capacity Evaluation Protocol Kalaeloa Cogeneration Facility Case for up to 189 MW identified as “(9/20/04)” (see Recital H)
		
	EXHIBIT 3	  	Letter dated June 30, 2004 from Kalaeloa to HECO re calculations of the purchase price for the Facility for purposes of said Section 3.3H or the fair market value of the Facility for purposes
of said Section 7.2B(1) (see 10C)

  
 ATTACHMENTS 
  
 ATTACHMENT A (see 8G) 
  
 ATTACHMENT W (see 8H) 
  

 HECO Exhibit 10.3 
  

[ Hawaiian Electric Company, Inc. Letterhead ] 
  
 EXHIBIT 1 
  
 April 21, 2004 
  
 VIA FACSMILIE TRANSMISSION (682-4996) AND U.S. MAIL 
  
 Mr. Ruedi Tobler 
 General Manager 
 Kalaeloa Partners,
L.P. 
 91-111 Kalaeloa Boulevard 
 Kapolei, Hawaii 96707

  
 Dear Ruedi: 
  

			
	 Subject:
	  	KPLP Performance Test for Potential 9 MW Increase
	 	  	in Capacity Capability Prior to a C Inspection

  
 As follow-up to our discussion the
past few weeks on the above subject, Hawaiian Electric Company, Inc. (HECO) would like to reaffirm that we are facilitating the Kalaeloa Partners, L.P. (KPLP) efforts to demonstrate the capabilities of its Facility prior to a “C”
inspection, based on our understanding that the only purpose of the demonstration is to support on-going discussions regarding the potential for an agreement (subject to PUC approval) to increase KPLP’s firm capacity. KPLP plans to collect
various plant parameter data, and HECO plans to collect certain revenue meter data, which would be shared in the on-going discussions. There has been no final agreement on a comprehensive performance test protocol, but it is hoped that the data
collected under well documented operating modes and conditions can form the basis for a performance test if a firm capacity agreement, which could include a test protocol, results from the on-going discussions. HECO’s willingness to participate
in the demonstration is premised on the understanding that its participation (and KPLP’s participation, for that matter) will in no way be deemed to waive, limit, or prejudice positions previously taken, or that may be taken in the future, by
either HECO or KPLP with respect to Section 5.2B(2) of the PPA, as amended. In other words, the participation of HECO and KPLP in the demonstration will be considered statements or conduct made in compromise negotiations, and will not be admissible
in any arbitration or other legal proceedings regarding or arising out of Section 5.2B(2). 
  
 If you have any questions, please let me know. 
  

	
	 Sincerely

	
	 /s/ Ward D. Saunders

	 Ward D. Saunders

	 Power Purchase Contracts Administrator

  
 cc via email: 
 Tom Simmons 
 Dan Ching 
 Stephanie Gonsalves 
  

 EXHIBIT 2 
  

Capacity Evaluation Protocol 
 Kalaeloa Cogeneration Facility 
 Case for up to 189 MW 
  
 Purpose 
  
 The purpose of this evaluation protocol is to set forth a protocol to be used to demonstrate the Facility’s ability to provide additional capacity, up to 189 MW, to
the Hawaiian Electric Company, Inc. (“HECO”) system (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 14th day of October 1988 between KALAELOA Partners, L.P.
(“Kalaeloa”) and Hawaiian Electric Company, Inc. (as heretofore amended and clarified, the “PPA”). 
  
 No change in the Firm Capacity level from the current 180 MW recognized by HECO will be made by reason of the parties’ agreement upon this protocol. 
  
 Test Conditions and Parameters 
  

	1.	A continuous 48 hour test run of the Facility will be conducted (the “Test”). Any abnormal conditions or equipment failure during the Test which impact the Test results
shall cause the Test to end, and in which case the parties after review of the reasons for the Test termination shall arrange the scheduling of another Test by mutual agreement of Kalaeloa and HECO. A 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. 

  

	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. 

 

	3.	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. 

  

 1 

	4.	The Test shall be conducted just prior to a “C” inspection being due for at least one of the combustion turbines. The other combustion turbine should be at the mid point
(approximately at least one year) 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 combustion turbine this scenario should closely approximate the worst case Facility operating regime relative to operational degradation of the two combustion turbines. 

  

	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 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. 

  

	7.	Steam export to Tesoro during the Test shall be at least 80,000 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 80,000 lb/hr, a downward correction will be applied pursuant to the Evaluation of Test Results section of this document. 

  

	8.	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 the
Test outside of these conditions shall entitle Kalaeloa to a new 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.	 Either prior to the Test or as part of the analysis in the evaluation period following the Test, Kalaeloa shall provide 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 operation of the Facility under HECO Dispatch for future periods at the capability level 

  

 2 

	 	 
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 under 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. 

  

	2.	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. 

  

	3.	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 

  

 3 

	 	•	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 
  

	1.	First test run shall start on Wednesday, April 21, 2004 at 13:00 and shall end on Friday, April 23, 2004 at 13:00. 

  

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

  

	3.	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 Test by taking the Facility to full load if consistent with load dispatch requirements. 

  

	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 

	4.	Allow Facility to stabilize at the above conditions until 1:00 p.m. at which time print out the following Praut diagrams: 

  

	 	•	P02 

  

	 	•	P06 

  

	 	•	P04 

  

	 	•	P09 

  

	 	•	P12 

  

	 	•	P20 

  

	 	•	P25 

  

	 	•	P26 

  

	 	•	P27 

  

	 	•	P37 

  

	 	•	Bar 16 

  

	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. 

  

	7.	Test will run 48 hours from that point. 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, 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 (and in any event within 3 working days). 

  

	2.	The full load minimum One Clock Hour Average during each of the 48 hours of the test 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. 

  

	3.	 For the one clock hour used for analysis, the One Clock Hour Average KW output of each of the three turbines shall be corrected to the following parameters as

  

 5 

	 	 
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 GT 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 to 80,000 lbs/hr (or value necessary for Facility to achieve PURPA requirements). No correction if above 80,000 lb/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 ASHRAE Design Conditions represent a ceiling for reasonably anticipated worst-case conditions.

  
 The corrected capacity 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 by the Test. 
  
 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 

  

 6 

	 	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 

  

	 	•	total steam export to Tesoro 

  

	 	•	CT1 MW 

  

	 	•	CT2 MW 

  

	 	•	total plant 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. 

  

 7 

  
 HECO Exhibit 10.3 

 
 EXHIBIT 3 
  
 30-Jun-04 
  
 Mr. Ward D. Sauders, P.E. 
 Purchased Power
Contract Administrator 
 Hawaiian Electric Company, Inc. 
 P.O.
Box 2750 
 Honolulu, HI 96840-0001 
  
 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	 

  

 

 
  

 

 
  

 

 
  

 

 
  

  
 HECO Exhibit 10.3 

 
 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 = 9MW
	 	 	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	  	x	  	164.35 / KWyr	  	]	  	+	  	[	  	9,000 KW	  	x	  	112.00 / KWyr	  	 ]

	 	  	  	  	12mo / yr	  	  	  	  	  	  	12mo / yr	  
										
	 	 	 	  	 = $2,549,250
	  	 	  	 	  	 	  	 	  	 	  	 	  	 
	 adjustment to payment =
	  	 	  	 	  	 	  	 	  	 	  	 	  	 

																															
	 	 	 [
	 	29,000	  	x	  	42.00	 	x	  	164.35	  	]	  	+	  	[	  	9,000	  	x	  	42.00	  	x	  	112.00	  	 ]

	 	 	 	  	  	365	 	  	  	  	  	  	  	  	365	  	  	  

																							
					
	 	 	 	  	    = $664,422.74 reduction
	  	 	  	 

  
 NOTE:

  
 If deficiency for the same period had been 189 MW, adjustment to the Month of
June would be $2,549,250 and the balance ($970,812.27 in this case) would be deducted from Month of July Capacity Charge payment due to Kalaeloa. 
  

 1 

	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 (00:00) – August 18 (24:00)

  
 Impact on Capacity Charge: 

 
 Months of April to September- no impact (capacity paid in advance) 
 Month of September – 
  
 normal payment = 
  

																							
	 	 	 [
	  	180,000 KW	  	x	  	164.35 / KWyr	  	]	  	+	  	[	  	9,000 KW	  	x	  	112.00 / KWyr	  	 ]

	 	  	  	  	12mo / yr	  	  	  	  	  	  	12mo / yr	  
										
	 	 	 	  	 = $2,549,250
	  	 	  	 	  	 	  	 	  	 	  	 	  	 
					
	 	 	 	  	 adjustment to payment =
	  	 	  	 

																															
	 	 	 [
	 	1,000	  	x	  	121.00	 	x	  	164.35	  	]	  	+	  	[	  	9,000	  	x	  	121.00	  	x	  	112.00	  	 ]

	 	 	 	  	  	365	 	  	  	  	  	  	  	  	365	  	  	  

																							
					
	 	 	 	  	 = $388,642.05 reduction
	  	 	  	 

  

 2Agreement 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 

  

 2 

 
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. 
  

 3 

 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. 
  

 4 

	 	(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. 

  

	 	A.	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 

  

 5 

 
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. 
  

 6 

	 	B.	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. 

  

	 	A.	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. 
  

	 	B.	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. 
  

	 	C.	[Reserved.] 

  

	 	D.	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. 
  

	 	E.	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 

  

 7 

 
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. 
  

	 	F.	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. 
  

	 	G.	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. 
  

 8 

	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. 
  

	 	A.	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. 
  

 9 

	 	B.	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]”. 
  

	 	C.	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 
  

 10 

 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 
  

 11 

 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 
  

 12 

 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. 
  

 13 

 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. 
  

 14 

	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: 
  

	 	A.	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. 
  

	 	B.	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 
  

 15 

 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. 
  

	 	C.	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. 
  

	 	D.	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. 
  

	 	E.	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. 

  

	 	F.	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. 
  

 16 

	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 
  

 17 

 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 
  

 18 

 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 
  

 19 

 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

  

 20 

			
	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 96840-0001 
  

			
	 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 96840-0001 
  

			
	 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: 
  

	 	a.	Grounding System 

  

	 	i.	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. 

  

	 	b.	Electronic Components 

  

	 	i.	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. 

  

	 	c.	Training 

  

	 	i.	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). 
  

	 	d.	Study and Implementation 

  

	 	i.	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 14th day of October 1988 between KALAELOA Partners, L.P.
(“Kalaeloa”) and HECO (as heretofore amended and clarified, the “PPA”). 
  
 Test Conditions and Parameters 
  

	1.	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. 

 

 1 

	3.	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. 

  

	4.	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. 

  

	7.	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. 

  

	8.	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.

  

 2 

	  	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. 

  

 3 

	2.	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. 

  

	3.	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 
  

	1.	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. 

  

	3.	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 

  

 4 

	 	•	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. 

  

	7.	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 

  

 5 

	  	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). 

  

	2.	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. 

  

	3.	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

  

 6 

					
			
	 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 

  

 7 

 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. 

  

 8 

 Example 1 
  
 Assumptions 
  

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

  

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

  

	5.	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 1st, 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 31st, 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 1st, 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 31st, 2004) which is the state at which 
  

 2 

 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. 

  

 3 

	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. 

  

 4 

 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 96840-0001 
  
 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: 
  

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

  

	 	b.	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. 
  

 2 

 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	  	x  	  	164.35 / Kwyr	  	]    +    [	  	29,000 KW	  	x    	  	112.00 / Kwyr	  	]
	  	  	  	12mo/ yr	  	  	  	  	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	  	]
	  	  	  	  	  	  	365	  	  	  	  	  	  	 365
	  	  	  

  
 = $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. 
  

 1 

 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	  	x    	  	164.35 / Kwyr	  	]    +    [	  	29,000 KW	  	x    	  	112.00 / Kwyr	  	]
	  	  	  	12mo/ yr	  	  	  	  	12mo/ yr	  

  
 = $2,783,316.67

  

																			
	 adjustment to payment
	  	=	  	 	  	[	  	10,000	  	x    	  	121.00	  	  x  	  	112.00	  	]
	  	  	  	  	  	  	365	  	  	  

  
 = $371,287.67 reduction

  

 2

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