# REPORT



# POWER SUPPLY EVALUATION

Virgin Islands Water and Power Authority

AUGUST 26, 20081000 Legion Place, Suite 1100 Orlando, FL 32801-1054 Phone (407) 422-4911 Fax (407) 648-8382 August 26, 2008



### Governing Board of The Virgin Islands Water and Power Authority, and Mr. Hugo Hodge, Executive Director

Post Office 1450 St. Thomas, Virgin Islands, USA 00801

Subject: Power Supply Evaluation

Ladies and Gentlemen:

Presented herewith is the Powe r Supply Evaluation dated August 26, 2008. This report evaluates the Authority’s future electricity and water produ ction options. Representatives of the Authority and the Virgin Islands Public Services Commission (the “PSC”), entered into a Stipulation dated December 12, 2006, in PSC Docket No. 559 to devel op a scope of service for the preparation of a Power Supply Evaluation to evaluate the Author ity’s future electricity and water production options on the island of St. Thomas, including St. John and neighboring islands in the St. Thomas Harbor, and on the island of St. Croix (the “Power Supply Evaluation”). As required in the stipulation, representatives of Georgetown Consulting Group (“George town”) have supplied

a series of draft comments which have been inco rporated in the Power Supply Evaluation. As of this date the Authority has not yet received fina l comments from Georgetown. Since the firm was requested by the Authority to finalize the re port, it is expected that Georgetown’s final comments with the firm’s responses will be provided as a supplement to this report after such

final comments are received.

The information contained in this report regard ing the facilities of the Authority, including availability and cost of fuel supply and descrip tion of such facilities, has been summarized from estimates, data, reports, and records furnished by the management and staff of the Authority, its consultants and advisors, and other sources. While it is believed such sources to be reliable, the firm has not verified the accuracy of any of th e information furnished by and obtained from such sources and offers no assurances with respec t thereto. To its knowledge, the summaries presented herein accurately reflect the informati on obtained from such sources. The firm has been advised that the foregoing information and advice are subject to change based on

indeterminate future events that could include increases in ope rating, capital, financing, and other costs of the Authority. A ny such adverse changes would likely result in an increase in the projected costs of operating the Elect ric System and the Water System.

Any statements herein involving matters of opinion or estimates, whether or not expressly so stated, are intended merely as such and not as re presentation of fact a nd are subject to being affected by fluctuating economic a nd regulatory conditions and occurr ence of other future events which cannot be assured. Therefore, the actual results achieved may vary from projections and

estimates.

As used in this report, the capitalization of any word not normally capitalized indicates that such word is defined in the particular agreem ent or other document discussed herein.

### Governing Board of The Virgin Islands Water and Power Authority August 26, 2008 Page 2

The report summarizes the results of the firm’s st udies and analyses, and t hose of others included herein, as of the dates of those studies or stat ements. Changed conditions occurring after such dates may not be reflected in this report. Any such changed conditions could affect the material presented herein to the extent of such change d conditions and such chan ged conditions would not be reflected in this report.

This report consists of an Executive Summary, a table of contents, eight sections, tables and graphs and Appendices. The eight sections in clude: Background, Description of Alternatives, Environmental Considerations, Description of cases and Results, Financeability, Principal Considerations and Assumptions, C onclusions and Implementation Plan.

Based on the Principal Assumptions set forth in S ection 6, and on the results of our analyses and review of reports prepared by the Authority an d information provided by the Authority which is summarized or referenced to in this Power Suppl y Evaluation, which report should be read in its entirety the firm has set forth conclusions in Section 7 that are summarized in the Executive Summary.

We want to take this opportunity to expres s our appreciation for the spirited cooperation and assistance given us throughout the course of th is study by each member of management and staff of the Authority.

Respectfully submitted,R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Power Supply Evaluation

Virgin Islands Water and Power Authority

Table of Contents

Letter of Transmittal Table of Contents List of Tables List of Figures List of Acronyms

EXECUTIVE SUMMARY

Section 1 BACKGROUND

1.1 General..................................................................................................... 1-1 1.2 Fatal Flaw Analysis.................................................................................. 1-2

1.3 RFP Process ............................................................................................. 1-4 1.4 Description of Existing El ectric Generation and Water

Production Facilities ................................................................................ 1-4 1.4.1 Existing Electric Generation Facilities ........................................ 1-4 1.4.2 Existing Water Production Facilities ........................................... 1-6 1.4.3 Planning Reserve Requirements and Existing Plant Configuration ............................................................................... 1-7 1.4.4 Electric System Load and Capabilities ........................................ 1-8 1.4.5 Electric System Non-Fuel Operations and Maintenance Expenses ...................................................................................... 1-9 1.4.6 Water System Capital Improvements .......................................... 1-9 1.4.7 Water System Operations and Maintenance Expenses................ 1-9

Section 2 DESCRIPTION OF ALTERNATIVES 2.1 Existing Arrangement .............................................................................. 2-1 2.2 Methanol Fuel Supply Option.................................................................. 2-1 2.3 Liquefied Natural Gas.............................................................................. 2-2 2.4 Circulating Fluidize d Bed Technology.................................................... 2-4

2.5 Wind Turbine Generation ........................................................................ 2-5

2.6 Electric Interconnection........................................................................... 2-7

2.7 Reverse Osmosis Water Production......................................................... 2-8

Section 3 ENVIRONMENTAL CONSIDERATIONS

3.1 General..................................................................................................... 3-1

3.2 Potential CO 2 

### Emission Regulations ....................................................... 3-2

## Table of Contents

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### Section 4 DESCRIPTION OF CASES AND RESULTS 4.1 Description of Cases................................................................................ 4-1

4.2 Discussion of Results............................................................................... 4-2

Section 5 FINANCEABILITY 5.1 Financeability of Water System Improvements ...................................... 5-1 5.2 Financeability of Power Supply Alternatives.......................................... 5-2 5.2.1 Population.................................................................................... 5-3

5.2.2 Customers .................................................................................... 5-3 5.2.3 Regulatory.................................................................................... 5-3

5.2.4 Credit Worthiness ........................................................................ 5-4 5.2.5 Outstanding Indebtedness............................................................ 5-5

5.2.6 Issuance of Additional Indebtedness ........................................... 5-6

5.2.7 Other Considerations ................................................................... 5-7

Section 6 PRINCIPAL CONSID ERATIONS AND ASSUMPTIONS 6.1 Principal Considerations and Assumptions Pertaining to the Evaluation of Electric System and Water System Alternatives............... 6-1 6.2 List of Principal Consider ations and Assumptions.................................. 6-1

Section 7 CONCLUSIONS

7.1 Conclusions.............................................................................................. 7-1

Section 8 IMPLEMENTATION PLAN 8.1 Implementation Plan................................................................................ 8-1 8.1.1 Implementation Plan Outline:...................................................... 8-1

This report has been prepared for the use of the c lient for the specific pu rposes identified in the report. The conclusions, observations and re commendations contained herein attributed to R. W. Beck, Inc. (R. W. Beck) constitute the opinions of R. W. Beck. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this report, R. W. Beck has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. R. W. Beck makes no certification and gives no assurances except as explicitly set forth in this report.

Copyright 2008, R. W. Beck, Inc. All rights reserved.

## Table of Contents

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck iii 

## List of Tables and Graphs

Table 2-1 Projected Annual Cost for LNG Operation ............................................... 2-3

Table 2-2 Calculation of the Estimated Cost Adder to Henry Hub Price for Natural Gas Reflecting LNG Operation ..................................................... 2-3 Table 2-3 Cost and Technical Data for CFB Technology........................................... 2-5 Table 2-4 Annual Net Energy Production on a Seasonal and Hourly Basis.............. 2-7 Table 4-1 Comparison of Cases 1-8 and 1-9.............................................................. 4-4 Table 4-2 Comparison of NPV Costs Associated with Adding a 10 MW

Wind Resource to St. Croix........................................................................ 4-7

Table 5- 1 Senior Lien and Subor dinate Lien Indebtedness Rated

“Investment Grade” .................................................................................... 5-4 Table 5-2 Outstanding Long Term Indebtedness for the Electric System and Water System....................................................................................... 5-6

Graph 8-1 Proposed Implementation Plan ................................................................. 8-3

Tables 1 through 10

Graphs 1 through 7



## Appendices

Appendix A – Individual Case Spreadsheets Appendix B – Fatal Flaw Analysis Appendix C – Wind Project Financing Stru ctures: A Review and Comparative Analysis

## Table of Contents

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## List of Acronyms

Addendum Addendum to the Upda ted Wind Resource Analyses AEO Annual Energy Outlook Authority Virgin Islands Water and Power Authority BOO Build, Own, Operate

Btu British Thermal Unit

CAIR Clean Air Interstate Rule CERA Cambridge Energy Research Associates CFB Circulating Fluidized Bed CNG Compressed Natural Gas

CO 2 

### Carbon Dioxide

CT Combustion Turbine

CTG Combustion Turbine Generator DBOOT Design, Build, Operate, Own and Transfer

DC Direct Current

EA Environmental Assessment

Electric Bond Resolution Electric Revenue Bond Resolution adopted by the Authority
on June 8, 1998, as supplemented

Electric Subordinated

Bond Resolution Electric Revenue Subordinat ed Bond Resolution, as supplemented

FAA Federal Aviation Administration Firm R. W. Beck, Inc. GAC Global Asset Consulting Group Georgetown or GCG Georgetown Consulting Group, Inc. HGI Harris Group, Inc. HOVENSA A joint venture between Hovic and Petroleos de Venezuela, S.A. HRSG Heat Recovery Steam Generator HVDC High Voltage Direct Current IDC Interest During Construction IDE Israel Desalination Engineering, Ltd.

kW Kilowatt LNG Liquefied Natural Gas
MACTEC MACTEC, Inc.

MED Multi-effect Distillation MGD Million Gallons per Day

MMBtu Million British Thermal Units MW Megawatt (1,000 kW) MWh Megawatt hour NAAQS National Ambient Air Quality Standard

NO X 

### Nitrogen Oxides NPV net present value O&M Operation and Maintenance

OES Obstruction Evaluation Service

## Table of Contents

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck v OTEC Ocean Thermal Energy Conversion

Pet-coke Petroleum Coke PPA Power Purchase Agreement PSC Virgin Islands Public Service Commission PSD Prevention of Significant Deterioration

Renaissance St. Croix Renaissance Group, LLP RFP Request for Proposals

RO Reverse osmosis

SO 2 

### Sulfur Dioxide T&E Threatened and Endangered TPDES Territorial Pollutant Discharge Elimination System

U.S. United States of America USCOE United States Army Corps of Engineers USEPA United States Environmental protection Agency VIDPNR Virgin Islands Department of Planning and Natural

Resources

Water Bond Resolution Water Revenue Bond Resolution, adopted by the Authority on November 23, 1998R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# EXECUTIVE SUMMARY

Executive Summary

The primary purpose of this Power Supply Ev aluation was to compare selected potential technologies and fuels that would assist the Authority:

(i) To reduce Electric System operating costs and lessen dependence on fossil fuels,

(ii) To develop conceptual projections of electric operating and capital costs for

feasible alternative te chnologies and fuels,

(iii) To compare the cost of utilizing revers e osmosis technology with existing water production technology and costs, and

(iv) To serve as a basis for evaluating respons es to the Request for Proposal (“RFP”) to Provide Electric Energy to the Virg in Islands Water and Power Authority.

As envisioned by the Authority and the Publ ic Services Commission (“PSC”), the Power Supply Evaluation involved a two-step process: a Fatal Flaw Analysis to determine selected feasible alternatives, and a more detailed analysis to identify the most economic and technologically sound alternatives. The Fatal Flaw Analysis which included a review of various proven technologies with respect to siting, environmental permitting, and overall costs, concluded, among other things, that:

(i) Two power generation technologies were projected to reduce the Authority’s operating costs and dependence on oil:

 Circulating Fluidized Be d (“CFB”) units burning pet-coke supplied by

HOVENSA from its St. Croix facili ty and Columbian coal fuel,

 Wind Powered Units

(ii) The Authority should consider other fuel supply options such as methanol and Liquefied Natural Gas (“LNG”), electri cal interconnection alternatives, and

(iii) Reverse Osmosis water pr oduction units shoul d be considered as feasible

alternatives to the exis ting Multi-Effect Distilla tion (“MED”) water production units and for future expansion.

Based on the Fatal Flaw Analysis, and in concer t with representatives of the PSC, cases were developed that involved utilizing various combin ations of existing resources, CFB coal fueled

units and wind resources. Further variati ons were also considered that assumed:

(i) the use of methanol or LNG as a fu el supply with the existing generation resources, and

(ii) installing a high voltage, dire ct current submarine cable to connect the electric systems of St. Thomas and St. Croix.

## EXECUTIVE SUMMARY

ES-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### ES-2 The above combinations were evaluated under two different electrical load scenarios (Base Load and High Requirements Load) and two di fferent environmental compliance scenarios (with and without CO 2 

### allowances). Recognizing the various resources, load, and

environmental considerations resulted in a tota l of forty-eight (48) ca ses being developed and

evaluated.

Graph No. ES-1 has been prepared that compar es the various cases with respect to the two major issues that affect the potential feasibility of the cases, net present value (“NPV”) costs and capital investment. This graph depicts th e trade-off between capital investment, and NPV cost reductions relative to the existing pow er and water production systems (“Existing Arrangement”). Based on the graphical depicti on, the cases plotted in the lower left-hand quadrant represents cases that i nvolve relatively low capital inve stment and high cost reductions relative to the Existing Arrangement. As show n on Graph No. ES-1, a lternatives involving LNG fuel (Existing Arrangement operating on LNG [ Case 1-3 ], Existing Arrangement operating on LNG fuel, plus the installati on of 10 MW of wind power resources [ Case 1-3W ], and the Existing Arrangement operating on LNG fuel with the reverse osmosis water system
[ Case 1-9 ]) are projected to represent cases that ha ve the greatest potential for cost reductions relative to the Existing Arrangement and the lowest projected capital investment.

The cases involving the CFB units [Case 1-4 and 1-4W] are the n earest to the center of the matrix, which indicates that such cases represent th e next best alternatives in terms of a balance with respect to capital investme nt and NPV cost reductions.

Based on the above, Case 1-3 (LNG), Case 1-3W (LNG with the Wind Resources), Case 1-9 (LNG with RO system), Case 1-4 (CFB units), and Case 1-4W (CFB units and Wind Resource) have been selected as worthy of further pursuit by the Authority.

Table A at the end of this Executive Summar y shows projected retirements, and capacity additions over the 20-year period from 2007 th rough 2027 for each case. Table B shows costs broken out by projects associated with each of the five cases referenced on Table A. The financing assumptions, and financing period are also shown under “Finan cial Assumptions” on Table B. All of the projects are assu med to begin commercial operation in 2012.

The projected results for each of the five cases are shown on Table C. The projected difference between each case and the Existing Arrangement, expressed on a levelize d cents per kWh basis over the 15-year period 2012 through 2027, is shown in Column (a) assuming a 1.0 debt service coverage. As shown on Table C, theses cases ar e projected to be appr oximately 0.7 to 5.1 cents per kWh lower than the Existing Arrangement on a levelized basis over the 15-year period 2012

– 2027. It should be noted that none of the cases presented are projected to result in a reduction in costs prior to 2012 due to the lead-time required to implement new electric resource projects. The capital investment for each case is proj ected to range from approximately $196 million to $432 million in 2008 dollars based on current co st projections and general escalation assumptions.

The next steps involved in proceeding with thes e plans are described later in the Report under the section entitled “Implementation Plan.”EXECUTIVE SUMMARYR:\005141\05-01414-10101\8-26-08 PS Eval Report.docES-3Graph No. ES-1Base Load Forecast Without CO2ChargeNPV Costs versus Capital Investment MatrixExistMethanolLNGCFBCFB,ROCFB,InterconnCFB, RO,InterconnExist, WindLNG, WindCFB,WindCFB, RO,WindExisting, ROLNG,RO01000002000003000004000005000006000007000008000009000001000000-1000000 -800000 -600000 -400000 -200000 0 200000NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000)Base Load Forecast Without CO2ChargeNPV Costs versus Capital Investment MatrixExistMethanolLNGCFBCFB,ROCFB,InterconnCFB, RO,InterconnExist, WindLNG, WindCFB,WindCFB, RO,WindExisting, ROLNG,RO01000002000003000004000005000006000007000008000009000001000000-1000000 -800000 -600000 -400000 -200000 0 200000NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000)ExistMethanolLNGCFBCFB,ROCFB,InterconnCFB, RO,InterconnExist, WindLNG, WindCFB,WindCFB, RO,WindExisting, ROLNG,RO01000002000003000004000005000006000007000008000009000001000000-1000000 -800000 -600000 -400000 -200000 0 200000NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000)EXECUTIVE SUMMARYES-4R:\005141\05-01414-10101\8-26-08 PS Eval Report.docTable AVirgin Island Water and Power AuthorityPower Supply Evaluation Implementation SummaryCase Name Case Description Retirement[1]Additions[1]InfrastructuresUnit No. MW Year TypeUnit MW Year Type Year1 - 3 Existing arrangement LNGFuelNone None LNG 20121 – 3 W Existing Arrangement withLNG Fuel and WindNone Wind 10 2012 LNG 20121 - 4 CFB UnitsSt. ThomasSt. Thomas12 12.5 2012 CFB 20 201214 12.5 2012St. CroixSt. Croix10[2]CFB 20 20121 – 4 W CFB Units with WindSt. ThomasSt. Thomas12 12.5 2012 CFB 20 201214 12.5 2012St. CroixSt. Croix10[2]CFB 20 2012Wind 10 20121 – 9 Existing arrangement withLNG Fuel , replace watersystem with R. O.St. ThomasSt. ThomasRO System 2012None None Retirement MED Units 2012St. CroixSt. CroixRO System 2012None None Retirement MED Units 2012[1] Timing of additions and retirements assumed to be 2012 for purpose of the Power Supply Evaluation. Actual timing will besubject to further study.[2] To be placed on standby status or retired.EXECUTIVE SUMMARYES-5R:\005141\05-01414-10101\8-26-08 PS Eval Report.docTable BTotal Projected Capital Costs by Case($000)Case # and Description 1-3 1-3W 1-4 1-4W 1-9Capital Costs[1]ExistingArrangementLNG FuelExistingArrangementLNG Fuel andWindCFB Units CFB Units withWindExistingArrangementwith LNG Fuel,Replace WaterSystem withR.O.St Thomas1 MED Capital Improvement 23,650 23,650 23,650 23,650 02 20 MW CFB 0 0 177,640 177,640 0St Croix3 MED Capital Improvement 22,575 22,575 22,575 22,575 04 10 MW Wind Turbine 0 30,000 0 30,000 05 20 MW CFB 0 0 177,640 177,640 06 LNG Capital 150,000 150,000 0 0 150,0007 RO Systems 0 0 0 0 46,6768Total196,225 226,225 401,505 431,505 196,676Financial Assumptions:9 Construction Cost Escalation 2.30%10 Issuance Expense 3.00%11 Interest Rate 6.00%12 Commercial Operation Date 201213 Financing and Permitting Period 2009-2012[1] Capital costs in 2008 dollars including owner's costs and capitalized interest..

## EXECUTIVE SUMMARY

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc ES- 

### 6 Table C Virgin Islands Water and Power Authority Power Supply Evaluation Results Summary

Results of Cases Without CO2 Allowance Costs
Levelized Costs Diff vs. Existing Arrangement [1] Capital Investment (2008 Dollars) Case Descriptions Cents/kWh $(000)

Base Load (d) (e)

1-3 -4.53 196,225 Same as Existing
Arrangement except using

LNG fuel

1-3W -4.46 226,225 Same as Case 1-3 plus 10

MW Wind Resource at St.

Croix - 2012

1-4 -0.86 401,505 20 MW CFB unit added to

St Thomas and St Croix in

2012

1-4W -0.74 431,505 Same as Case 1-4 plus 10

MW Wind Resource at St.

Croix - 2012

1-9 -5.12 196,676 Same as Case 1-3 above
except add RO units and

retire existin g MED units.

[2] Assumes base load projection. [1] Levelized cost difference compared to projected Existing Arrangement gross levelized electric costs of approximately 24.8 cents/kWh over a 15 year period 2012-2027 assuming a 1.0 debt service coverage for purposes of maintaining consistency among power supply alte rnatives evaluated. Actual debt service cover age will depend upon, among other factors, the

amount to be financed.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 1

BACKGROUND

1.1 General

In the pursuit of identifying the lowest cost , reliable supply of el ectricity and potable water for the Territory, representatives of th e Authority and the Virgin Islands Public Services Commission (the “PSC”), entere d into a Stipulation dated December 12, 2006, in PSC Docket No. 559. Representatives of the Authority a nd the firm and in collaboration with representatives of George town developed a scope of service for the preparation of a Power Supply Evaluation to evaluate the Au thority’s future electricity and water production options on the island of St. Thomas, including St. John and neighboring islands in the St. Thomas Har bor, and on the island of St. Croix (the “Power Supply Evaluation”). As required in the stipulation, representatives of Georgetown have supplied a series of draf t comments which have been incorporated in the Power Supply Evaluation. As of this date the Authority has not yet received final comments from Georgetown. Since th e firm was requested by the Authority to finalize the report, it is expected that Geor getown’s final comments with the firm’s responses will be provided as a supplement to this report after such final comments are received. The overarching objective of the Power Supply Evaluation is to provide the Authority with an understanding of the near - and long-term power supply options that are likely to lower or stabilize the Aut hority’s cost of electric power and water production and simultaneously reduce its dependence on fuel oil.

Because of the historical development of th e Water System and certain characteristics unique to the U.S. Virgin Islands, the Wa ter System serves a small portion of the potential customers in the U.S. Virgin Isla nds. Among such factors is a U. S. Virgin Islands building code requirement that, w ith few exceptions, all new residential and commercial buildings have cisterns. This requirement has reduced the demand for potable water from the Authority. In addition, because of the mountainous, rocky terrain, especially on the islands of St. Th omas and St. John, the construction of the water distribution system has been difficult and costly.

To meet potable water needs, most residen tial and commercial customers connected to the Water System rely on rainwater collec tion and cistern storage as their primary water source and use the Water System as a supplemental source of water supply. Similarly, residential and commercial entities not connected to the Water System, also rely on the collection and st orage of rainwater and on the purchase of supplemental potable water from independent "water haulers" to deliver the water.

Due in part to the general scarcity of fresh water sources in the U.S. Virgin Islands, the high cost of producing potable water through th e desalination of seaw ater and the local building codes that, for the most part, require the construction of rainwater collection and storage facilities in most residential a nd commercial buildings, it is expected that

## Section 1

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### the Water System will continue to be used by its customers as a supplemental source of potable water as opposed to a primary source of supply.

So as to minimize costs, representatives of the Authority, the firm and Georgetown identified the potential electric generation alte rnatives to be evaluated. The evaluation of the limited number of electric generati on alternatives included: (i) Wind Powered Electric Generation Resources; (ii) Opera ting Efficiency Improvements (additional heat recovery steam genera tion); (iii) Waste to Ener gy Power Production; (iv) Circulating Fluidized Bed (“CFB”) Coal/P et-coke Fueled boilers; (v) Slow Speed Diesel Electric Generation; and (vi) Oil/G as Fueled New Combined Cycle Generation.

In addition to these technology based alternatives, the partie s agreed that other options should be addressed: (i) Direct Current (“DC”) Underwater Transmission Cable to connect the electrical systems on the islands of St. Thomas and St. Croix; (ii) Ocean Thermal Energy Conversion (“OTEC”); and (iii) Liquefied Natural Gas (“LNG”).



# 1.2 Fatal Flaw Analysis

In an effort to minimize unnecessary analyses, a Fatal Flaw Analysis 1 

### was undertaken to identify the selected options that appeared to have practical applications in the Territory and are economically feasible. On February 25, 2008, the firm completed the Fatal Flaw Analysis. This analysis included a comparison of the estimated

incremental and allocated cost of reverse osmosis (“RO”) desalination technologies at potential and existing generating sites with the incremental cost of the Authority’s existing desalination operations to determ ine if RO technology should be considered further as a replacement for all water requir ements on the islands of St. Thomas and St. Croix or incremental requirements only.

For the production of electric ity and potable water, the Fatal Flaw Analysis gave consideration to: (i) Operati ng constraints; (ii) Siting alternatives (impediments to installing necessary infrastruct ure); (iii) Fuel supply and pricing (busbar screening, availability of fuel supply); (iv) Envir onmental permitability; and (v) Capital and nonfuel operating costs.

The Fatal Flaw Analysis concluded that 2 

### :

“1. The power generation technologies t hat are projected to reduce costs and dependence on oil for the Authority are:

A. CFB units burning pet-coke from the HOVENSA St. Croix refinery and
Colombian Coal, and

B. Wind Power Units.

2. Retrofitting CT [combustion turbine] Un it No. 23 at St. Thomas with a HRSG for combined cycle operation is projected to result in reduced costs, but this option does not improve the system’s fu el diversity and the capacity of the combined cycle unit is likely to presen t system operation reliability issues.

1 The Fatal Flaw Analysis is appended hereto and identified as Appendix B.

2 Ibid.

## BACKGROUND

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 1-3 3. The slow speed diesel, the municipa l solid waste and the photovoltaic cell technology options are less attractive than the other alternatives. In addition, the slow speed diesel option presents significant environmental permitting challenges that are potentially fatal flaws.

4. The use of methanol (produced by processing pet-coke from the HOVENSA St. Croix refinery) as a fuel in exis ting generating plants, appears to be economically feasible. However, at the projected capital investment of $900 million this option presents a significant financial risk to the Authority.

5. At the current $/MMBtu pric e differential between oil and gas, LNG is feasible as an alternative fuel for the existing ge nerating units. However, there is a risk that in the future this [favorable fuel cost] differential will be eroded and the projected economic benefits from th e high capital investment may not be
realized.

6. Feasible sites have been identified fo r locating generating plants utilizing the various technologies as follows:

A. CFB Plant – St. Thomas: at Gram bokola Hill and near the Bovoni landfill. St. Croix: at the Author ity’s south shore site (with some additional adjacent Port Authority pr operty) and in the area of Hams Bluff on the west coast.

B. Wind Power – St. Thomas: in the area of the Bovoni landfill. St. Croix: on hills that are situated along the islands south coast and

northwest coast.

C. Combined Cycle Retrofit of CT Unit No. 23 – at the existing Krum Bay

Power Plant site.

7. Further emission assessments are re quired in order to determine the environmental permitability of the CFB units at the candidate sites.

8. Reverse Osmosis water production units are a feasible a lternative to the existing MED [Multi-Effect Distillation / Israel Desalination Engineering,
Inc.] units.

9. A high-voltage interconnection between the islands of St. Thomas and St. Croix does not appear to be feasible fo r the continued opera tion of the existing power plants. However, it may prove to be feasible... [and] where a large portion of the existing generation is repl aced or a single new power plant is installed on one island to supply the total Authority Electric System needs. A detailed technical feasibili ty study is required to addr ess unknowns related to the installation of the submarine cable.

10. The Authority may want to consider i ssuing Request for Proposals (“RFP”) to solicit offers for the more capital intensi ve options such as the methanol and LNG fuel supply and interconnection/CFB plant alternatives to reduce the financial risk of these alternatives.”

## Section 1

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# 1.3 RFP Process

A request for proposal (“RFP”) was issu ed by the Authority on December 28, 2007. The purpose of the RFP was to solicit propos als to reduce the costs of providing electricity to the Authority’s customers and decrease the Authority’s dependence on oil by seeking the development or expansion of non-oil fueled electricity generation

facilities on the islands of St. Thomas and St. Croix.

In the RFP, the Authority stated its preference for proposals that would deliver electricity before January 1, 2012 and provi de a 20-year Purchase Power Agreement (“PPA”). The Authority’s stated goal in th e RFP is to displace as much oil fueled energy as possible, taking into considerati on island system reliability and equipment operating constraints. The RFP contained a projection of the maximum amount of electricity that could be displaced on each island over the period 2008 through 2030.

A pre-bid conference was held February 15, 2008, the Fatal Flaw Analysis Report was distributed, and proposal s were due by May 1, 2008.

The proposals received by the Authority are be ing evaluated agains t the lowest cost power supply plans resulting from this power supply evaluation to determine if adding such proposals to the Authority’s lowest co st generation portfolio would result in further cost reductions, in improved fuel dive rsity, or in some other advantages to the Authority.



# 1.4 Description of Existing Electric Generation and

Water Production Facilities

1.4.1 Existing Electric Generation Facilities

The Authority has major generation facilities on the islands of St. Thomas and St. Croix, and has limited backup generation faci lities on the island of St. John. Except for emergency situations, the electric power and energy requirements of the island of St. John are generated on the island of St. Thomas and transmitted to the island of St. John by means of two underwater cables. Because of the extreme water depth between them, the islands of St. Thomas and St. Croix are not interconnected electrically.

The Authority's generating facilities on the is land of St. Thomas (191 MW) are located at the Randolph E. Harley Generating Station at Krum Bay, which is on the southwestern end of the island. All electric generation for the islands of St. Thomas and St. John, and the two smaller islands, Hassel Island and Water Island, are located at this site, except for an emergency diesel -generating unit located on the island of St. John. In addition to generation facilities, the Krum Bay site includes water production, fuel oil unloading and storage, transportation, and warehouse facilities.

To provide, among other things, an additio nal source of steam for water production on the island of St. Thomas, the Authority instal led a waste heat recovery steam generator (“HRSG”), sometimes referred to as a “waste heat boiler.” The HRSG was

## BACKGROUND

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 1-5 constructed in 1997 to utilize the exhaust gases from either or both combustion turbine Units No. 15 and No. 18 for the production of steam for electric generation and as an additional source of steam production on the is land of St. Thomas for the desalination

of water.

All of the existing generati on facilities on the island of St. Croix (117 MW) are

located at the Estate Richmond site on the nor th shore of the island near Christiansted. In addition to generation facilities, th e Estate Richmond site includes water production, fuel oil unloading and st orage and warehouse facilities.

The Authority is proceeding with the in stallation of a second HRSG to convert

Combustion Turbine Unit No. 16 and unit No. 20 at the Estate Richmond Generating Station from simple-cycle operation to comb ined-cycle operation. The installation of

the second waste heat boiler is projected to reduce fuel costs through the improved efficiencies and improve the overall generati ng reliability by increasing the amount of generation available for reserves on the island of St. Croix.

To improve generation efficiencies and to co ntinue to lower system-wide fuel costs, the Authority is contemplating the installati on of an additional HRSG on the island of

St. Thomas as a retrofit to Unit No. 23; its newest combus tion turbine gene rating unit. However, this option does not improve the sy stem’s fuel diversity and the capacity of the frame 6 combined cycle unit at 60 MW is likely to present system reliability and efficiency issues associated with the leve l of spinning reserves required in order to operate the unit at optimum ef ficiency and at the same tim e, maintain the ability to

withstand the loss of the unit while main taining the stability of the system.

The Authority’s four steam generating units range in age from 34 to 39 years. The Authority’s ten combustion tu rbine units range in age fr om three to 36 years. Although some of the generating units have ex ceeded their normal life expectancy, the Authority has refurbished or reconditioned many of its units to extend their useful lives. At this time, the Authority has not es tablished expected retirement dates for its existing steam and combustion turbine generating facilities. However, based on the findings of the initial “ Condition Assessment Study Report ,” HGI found, among other things, that Combustion Turbines Unit No. 12 and No. 14 and Boiler No. 11 on the island of St. Thomas should be dispatched on an emergency basis only and eventually retired when replacement generating resource s become available. Furthermore, with

the addition of a second HRSG at the Estate Richmond Ge nerating Station, HGI recommended that Boiler No. 10 on the island of St. Croix should be used as a standby

unit.

As a part of the Authority’s maintenan ce and refurbishment program, the Authority has scheduled major maintenance on certa in units including Unit No. 13 (37 MW steam) on the island of St. Thomas, one of the Authority’s largest units, that has been temporarily derated to 25 MW. Following th e rewinding of the turbine generator, Unit No. 13 is planned to return to service at its normal ratin g of 37 MW. In addition,

combustion turbine Unit No. 22 on the island of St. Thomas was returned to service in February 2008, after an outage for major ma intenance. Both of these units are assumed to be fully operational over the study period.

## Section 1

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### A listing of the Authority’s existing steam a nd combustion turbine electric generation

units is shown on Table No. 1.



# 1.4.2 Existing Water Production Facilities

To produce potable water, the Authority oper ates nine multi-effect desalination units (“MED”): four desalination units are loca ted at the Randolph E. Harley Generating

Station and four units at the Estate Ri chmond Generating Stati on and one unit on St. John. In order to produce potable water, the desalination un its require both high pressure steam (150 psig) and low pressure st eam (26 psig). This steam is extracted from the steam turbine generating units or s upplied in part by the waste heat boilers. Table No. 2 sets forth a listing of the water producing capability and steam requirements of the Authority 's desalination facilities.

The Authority also operates one vapor co mpression-based desalination unit, known as Unit No. 7, with a capacity of 0.155 MGD, on the island of St. John. In addition, the Authority contracts with Seven Seas Co rporation for the w holesale purchase of desalinated water produced by a reverse os mosis unit on that island. The Authority indicates that the water purchase contract will be terminated when the new pipeline to provide water service to the island of St. John from the is land of St. Thomas is placed

in service in June 2008.

Primary potable water production on the thre e islands is achieved by the use of seawater distillation units (“ desalination”), and some use of groundwater on the island of St. Croix. The desalination process used by the Authority consists of evaporation

of seawater in a vessel util izing steam as a heat source and then recondensing the vapors from the evaporated seawater without the seawater salt minerals. The resulting water product is high-purity potable water that is supplie d to the individual island water distribution systems. All of the di stillation desalination units currently in service were designed and constructed by Israel Desalination Engineering, LTD. (“IDE”).

Due to the age of a number of the desa lination units on the island of St. Thomas (Desalination Units No. 1, No. 2, and No. 6) and on the island of St. Croix (Desalination Units No. 3, No. 4, and No. 5), during the fall of 1997, the Authority

contracted with American Thermal Industr ies, Inc. to prepare a Useful Life Assessment (the “ Useful Life Assessment Report ”) of all the desali nation units. At the time, Desalination Units No. 1 through No. 6 had been in service between 14 and 17 years. Desalination Units No. 7 on the isla nd of St. John had been in service for 8 years and Desalination Units No. 8 and No. 9 had been in service for 5 and 4 years, respectively. The Useful Life Assessmen t Report found, among other things, that the older Desalination Units No. 1 through No. 6 “. . . can be expected to be beneficially kept in service for many years after attaini ng the pending pre-stipulated 20-year useful life expectancy as backed up by the continued use of competent O&M [operation and maintenance] procedures.” American Th ermal Industries, Inc. found, among other things, that “. . . the useful service life of the Authority’s desalination units should be extended to 30 years from the declared in service date for each unit.” Based on the findings of the Useful Life Assessment Re port and the continuation of the existing

## BACKGROUND

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 1-7 maintenance procedures, the Authority report s that it has extended the service life of the desalination units to 30 years and has re vised its accounting practices to reflect the

estimated retirement dates shown on Table No. 2. The planned retirement date of Units No. 1, No. 2 and No. 3 is 2011, and the planned retirement date for Units No. 4,

No. 5 and No. 6 is 2013.

The Useful Life Assessment Report also found that the newer units, Desalination Units No. 7, No. 8, and No. 9 which were installed in more recent years, were in good condition with the exception of Desalinati on Unit No. 7 on the island of St. John, which was then in need of tube repairs. The tube repairs were completed in 2001.

For purposes of the Power Supply Evaluati on, it has been assumed that if new RO facilities are not installed to replace the existing IDE units, th e IDE units, would be

refurbished from time-to-time to extend the useful life.



# 1.4.3 Planning Reserve Requirements and Existing Plant Configuration

Given that the Authority operates two isol ated electric genera tion and distribution systems, and given that the Authority's demand and energy requirements do not deviate significantly by season, the Authority, like other isol ated electric systems, is required to maintain a higher level of generating reserves than interconnected electric systems to provide for scheduled maintena nce and forced outages, and to minimize interruptions in service. To reduce the potential for service interruptions and to improve the quality of service, the Author ity’s established planning criteria for generating reserves calls for the Authority to have sufficient generating capacity on each island to meet its respective electric lo ad requirements with its two largest units out of service. In April 1991, in Docket No. 345, the PSC found, among other things, that the use of this planning criteria for generating reserves was prudent and in the best interest of the Authority's customers. Th e use of these planning criteria has been affirmed by the PSC in subsequent orders.

On the island of St. Thomas, the two la rgest units are Unit No. 13, a steam turbine generator with a reported ne t continuous capacity rating of approximately 37 MW, and Unit No. 23, a combustion turbine generator with a reported net continuous rating of approximately 40 MW. The two largest units on the island of St . Croix are Unit No. 19 and Unit No. 20, two combustion turbin e generators, each with a reported net continuous capacity rating of approximately 22.5 MW.

The generating systems on the islands of St. Thomas and St. Croix involve multi-unit configurations operating in combined cy cle operation. Based on HGI’s Condition Assessment Study Report, the recommended conf iguration on the island of St. Thomas that meets recognized reliability constraints 3 

### assumes that combustion turbine Unit No. 15 and Unit No. 18 are supplying waste heat to the HRSG. Steam turbine generators Unit No. 11 and Unit No. 13 are driven by st eam from the HRSG and Boilers No. 11

and No. 13. Unit No. 22 and Unit No. 23 are brought on as needed to produce

3 The plant must be capable of hand ling steam and electrical demand over a fu ll range of demand with the largest

unit down for maintenance concurrent with the forced outage of the next largest unit.

## Section 1

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### electricity. Unit No. 12 and Unit No. 14 are in reserve status. Steam is supplied to the desalination plant on a continuous basis. Elimination of the extraction steam associated with the existing desalination facilities on the island of St. Thomas is projected to improve plant efficiency by approximately 4 to 9 percent depending on the total plant output (four percent at 80 MW output and nine percent at 40 MW output).

HGI’s recommended configuration on the isla nd of St. Croix that meets recognized reliability constraints 4 

### assumes that combustion turbine Unit No. 16 and Unit No. 20 supply waste heat to the new HRSG, whic h is under construction. Upon completion of the new HRSG, steam turbine generato rs Unit No. 10 and Unit No. 11 would be driven by steam from the new HRSG and the old HRSG. As a backup, Unit 17 can supply waste heat to the old HRSG to driv e the steam turbines. Unit No. 19 will be brought in as needed to produce electricity. This configuration will increase the likelihood that steam will be supplied to th e desalination plant on a continuous basis. Under the new operating confi guration with the new HRSG, the improvement in plant efficiency associated with eliminating th e steam supply to the existing desalination facilities is projected to be less on the isla nd of St. Croix, since the steam is projected to be produced totally by the new and old HRSGs.



# 1.4.4 Electric System Load and Capabilities

In connection with the Consulting Engineer’s Report on the Virgin Islands Water and Power Authority, dated June 2007, projections of future power requirements by island were prepared for the period 2007 through 2011. These projections were based on an abbreviated heuristic analysis of historical demand and en ergy requirements, sales and customer growth, usage patterns and ot her economic parameters, together with adjustments to reflect record levels of high fuel costs.

The projections also reflect a decrease in unaccounted-for losses over time resulting from implementation of the Authority’s loss reduction program. For purposes of the Power Supply Evaluation, the annual average growth rate for the islands of St. Thomas and St. Croix is projected to be 1.2 percent and 0.5 percent, respectively from 2012 through 2027 based on an extension of this forecast. It has been assumed that the Authority will continue to perform nor mal maintenance and repairs of its existing

facilities in accordance with nor mal prudent utility practice.

To reflect the potential for a higher th an expected electrical load, a “Higher Requirements” load forecast was prepared as a sensitivity case. This “higher” load

forecast assumed no reduction in unaccounted-f or losses and annual growth rates of 3 percent and 1.5 percent for th e islands of St. Thomas and St. Croix, respectively.

4 Ibid.

## BACKGROUND

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### R. W. Beck 1-9 

# 1.4.5 Electric System Non-Fuel Operations and Maintenance Expenses

The Authority’s historical non -fuel maintenance expense as reported by the Authority for the period 2005 through 2007 is summarized on Table No. 3. This table also separately summarizes total steam and to tal combustion turbine non-fuel maintenance

expense.

As shown on this table, total non-fuel steam related maintenance expenses for the fiscal years ended 2005, 2006 and 2007 were estimated to be approximately $7.9, $8.4 and $8.1 million dollars per year, respectively, with an average of approximately $8.1 million dollars per year. Combustion turbine related expenses for the fiscal years ended 2005, 2006 and 2007 were estimated to be approximately $1.2, $1.3 and $2.1 million dollars per year, respectively, with an average of approximately $1.5 million dollars per year. Based on these historical results, it was assumed that retiring the Authority’s steam system would reduc e non-fuel maintenance expenses by approximately $8.1 million dollars per year (2007 dollars). Maintenance costs on existing combustion turbine un its are assumed to remain at approximately $1.5 million dollars per year (2007 dollars).



# 1.4.6 Water System Capital Improvements

In order to model the tota l cost to maintain the ex isting MED water production facilities in operating condition for the dura tion of the study period, it was determined that substantial capital improvements woul d be required for each unit on a regular basis. The Authority recen tly obtained an estimate of $1,075,000 in 2008 dollars from the local IDE representative for the refurbishment of Unit No. 9 on the island of St. Croix. The Authority also advised that such refurbishment would be required for each MED unit every three years until it is replaced. Using this cost estimate and frequency, Table No. 4 was de veloped to reflect the estim ated cost and schedule for major maintenance of the wate r production facilities. Thes e costs were included in the

model for each case when the existing water production is re tained for the duration of the study period.



# 1.4.7 Water System Operations and Maintenance Expenses

The Authority’s historical water relate d operating expenses for the period 2003 to

2007 are summarized on Table No. 5. As shown below total water production expenses were reported to be approximately $11.1 million dollars to $19.7 million dollars per year during the period 2003 thr ough 2007. Also shown on this table is the portion of the Authority’s water related oper ating expense that is fuel related. The remaining water related production cost s are non-fuel operation and maintenance costs. Based on the average non-fuel wate r related operations a nd maintenance costs reported over the years 2003 through 2007, a projected value of approximately $5 million dollars per year (2007 dollars) was assu med. It was also assumed that in cases in which a new RO system would replace th e existing desalination system, this annual expense can be eliminated.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 2

DESCRIPTION OF ALTERNATIVES

2.1 Existing Arrangement

The Authority’s existing arrangement alternativ e is assumed to be a continuation of its existing oil fueled electric system a nd water production operation (the “Existing Arrangement”). Under the Base Load forecast scenario, no additional generation or

retirements is assumed at either island. It is further assume d that the existing desalination process will be refurbished fr om time-to-time and will not be retired or replaced. Under the Higher Requiremen ts load forecast scenario, a 40 MW

combustion turbine is assumed to be inst alled in 2016 on the is land of St. Thomas, coinciding with the retirement of steam Unit No. 12 and Unit No. 14.



# 2.2 Methanol Fuel Supply Option

This alternative invol ves converting locally availabl e pet-coke from HOVENSA to liquid methanol fuel that can be burned in the Authority’s existing generating units with minimal combustion system conversion costs. This process is described in more detail in the Fatal Flaw Analysis. Based on the Authority’s total fuel requirement for the islands of St. Thomas, St. John, and St. Croix, a gasification pl ant with a methanol production capacity of one million gallons pe r day is required. The production of methanol from solid fuels such as pet-coke and coal is an established process in the chemical industry.

While the Firm is aware that General Electric Company has successfully tested the operation of its frame 5 and frame 6 combusti on turbines on methanol fuel, it is not aware of any facility that burns methanol as a fuel fo r electric power generation. Therefore, should the Authority select the methanol option, it would expose its customers to the technical and financial risks associated with implementing a technology that is still in the development phase.

This alternative assumes the same generati ng resources on each is land as the Existing Arrangement. No additional generation or unit retirements are assumed under the Base Load forecast, except for a 40 MW dedicated combined cycle generating

resource assumed to be added at the methanol plant. The fuel cost projection for the

methanol fuel is shown on Table No. 6. As shown on this table the projected methanol cost is the sum of (i) the pet-coke fuel and methanol tran sportation costs, (ii)

the total all-in costs associated with the dedicated combined cycle unit, and (iii) the methanol plant carrying cost and operating costs, divided by the MMBtu’s of methanol fuel produced by the plant. As s hown on Table No. 6 this cost is projected to start at approximately $10.35 dollars per MMBtu in 2012, and is projected to increase to approximately $12 dollars pe r MMBtu by 2036. The cost escalation of

## Section 2

2-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### approximately 0.6 percent per year is the resu lt of the predominant percentage of fixed capital costs included in the fuel price. No credit is assumed for sales of excess methanol to other parties. Such sales could further reduce the fuel price to the Authority.



# 2.3 Liquefied Natural Gas

In a letter report titled “ Feasibility of Conversion of Fu el Oil to Natural Gas Find

Generator ” and dated July 10, 2007 (“2007 Fuel Conversion Analysis Report”), the firm provided a summary of the firm’s anal ysis of the feasibil ity of converting the Authority’s existing fuel oil fired power plan ts on the islands of St. Thomas and St. Croix to natural gas fuel. Two forms of na tural gas delivery were considered in the analysis: (i) liquefied natural gas (“LNG”), and (ii) compressed natural gas (“CNG”). Natural gas is converted to LNG by cooling until it becomes a liquid, which reduces it volume dramatically (approximately 600 to 1) making it practical to ship and store larger quantities. The conversion to LNG is the process most commonly used in order to ship large quantit ies of natural gas long distances. The CNG process is generally employed for transporting lower volumes of natural gas over relatively short distances utilizing high pressure containers.

Based on the 2007 Fuel Conversion Analysis Report, the most attractive natural gas supply scenario involves supplying LNG to the Territory from the existing Ecoelectrica LNG facility in Puerto Rico by a small ship assumed to be owned and operated by the Authority or under contract to a third party on a long-term basis to make deliveries to the Authority.

From the 2007 Fuel Conversion Analysis Repor t, the capital costs a ssociated with this scenario including purchasing the LNG sh ip, on-site storage and regasification facilities for each island, dock improvements and interconnection facilities for each island are projected to be between $134 to $158 million dollars with an estimated $6 million dollars per year for the ship operations and maintenance contract. The lower end of the range is based on receiving L NG from Puerto Rico. In addition to the capital costs associated with adding infr astructure for the LNG facilities, further capital costs of $5 million per generation si te are estimated for the conversion of existing fuel oil fired steam boilers and co mbustion turbines to natural gas and to provide the required natural gas infrastructur e at the power plants. In addition, the power plant fixed O&M costs are projected to be lower than the costs currently experienced while operating on fuel oil. A summary of the annual cost for LNG suppl y and power plant conversion is provided

in tabulation below.

## DESCRIPTION OF ALTERNATIVES

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 2-3 Table 2-1 Projected Annual Cost for LNG Operation

Capital Cost

New Infrastructure (1) $12,804,805

Power Plant Conversion (2) $952,738
Subtotal Capital Cost (2007 dollars) $13,757,543

Escalation to 2012 (3) 1,656,588

Subtotal $15,414,131

O&M Service Contract (2012 dollars) (4)

$6,000,000

Total Annual Costs W/O fuel $21,414,131

1. Annual debt service associated with capital co sts for new infrastructure support LNG operations: $134,400,000, 20-year term, 5 percent interest rate per year, 5 percent interest during construction, tax-exempt municipal bonds and additional 3 percent for bond issue and first year payment. 2. Annual debt service associated with plant conv ersion capital costs: $5, 000,000 each site, 20-year term, 5 percent interest rate per year. Annual debt service was calculated similar to item 1 above. 3. Escalation from 2007 to 2012 at 2.3 percent. 4. Service contract includes O&M and transportation costs.



### From the above tabulation, the total annual non-fuel cost associated with LNG supply and plant conversion for the year 2012 is estimated at approximately $21.4 million.

The annual average cost per MMBtu attribut ed to the LNG facilities and power plant conversion was developed as shown in the tabulation below.

Table 2-2

Calculation of the Estimated Cost Adder to Henry Hub Price for Natural Gas Reflecting LNG Operation

Heat Rate (Btu/kWh) 2006

Production (MWh) 2006 Fuel Consumption (MMBtu)

St. Thomas 12,000 562,129 6,745,548

St. Croix 12,500 364,504 4,556,300

Total 11,301,848

Total Annual Cost w/o Fuel $21,414,131
Average LNG Facilities Cost ($/MMBtu) 1.90

Additional Service Charge for natural gas price differential between Henry Hub and Puerto Rico ($/MMBtu) .32

Total Cost Adder to Henry Hub Pr ice of Natural Gas ($/MMBtu) 2.22

## Section 2

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### The following process was used in developing the projected annual average natural gas delivered costs.

 

### 2008 price was developed using the 2008 m onthly Henry Hub forward prices to calculate an average annual price and adding the total cost adder of $2.22/MMBtu.

 

### 2009 price was developed using the 2009 m onthly Henry Hub forward prices to calculate an average annual price and adding the total cost adder of $2.22/MMBtu.

 

### 2010-2030 prices were develope d using the annual averag e price calculated above for 2009 and applying the Annual Energy Outlook (“AEO”) 2007 annual escalation factors for gas for each year and adding the total cost adder of $2.22/MMBtu.

 

### 2031 – 2036 prices were developed using the 2030 natural gas price calculated above and applying the annual average AEO escalation factor for the years 2026 to 2030 (since the AEO 2007 projections do not extend beyond 2030) and adding the total cost adder of $2.22/MMBtu.

The projected cost for natural gas delivered to the Authority’s power plants including the processing facilities and power pl ant conversion cost s using the above methodology are provided in Table No. 7.



# 2.4 Circulating Fluidized Bed Technology

The CFB technology option involves the installation of CFB units in the capacity range of 20-40 MW as replacements for a significant portion of the Authority’s existing base load resources. The primary fuel source for the CFB units is anticipated to be pet-coke produced by the HOVENSA Refi nery on the island of St. Croix. However, for the purpose of economic mode ling, a blend of 50 percent pet-coke and 50 percent coal is assumed in order to limit the amount of limestone required for combustion along with the pet-coke and the amount of solid waste resulting from the combustion process. Sensitivity cases on the cost and mix of pet-coke and coal should be considered in order to optimize the plan t design. However, this can be done as a part of the plant optimization if this op tion is selected for implementation by the Authority.

Technical and cost data used in modeling th e CFB plant sizes and configurations used

in the evaluation are shown in the tabulation below.

## DESCRIPTION OF ALTERNATIVES

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 2-5 Table 2-3 Cost and Technical Data for CFB Technology

Plant Size (MW) 20 30 40 40 80 120

Unit Size and Configuration 1 x 20 MW 1 x 30 MW 2 x 20 MW 1 x 40 MW 2 x 40 MW 3 x 40 MW
Capital Cost ($/kW) 8,882 8,158 8,242 7,434 6,134 5,877

Capital Cost ($M) 177.6 244.7 329.7 297.4 490.7 705.2

Variable O&M (1) ($/kWh) 8.18 8.18 8.18 8.18 8.18 8.18

Fixed O&M ($/kW-mo.) 8.33 8.33 8.33 8.33 8.33 8.33

Heat Rate (Btu/kWh) 12,000 12,000 12,000 12,000 12,000 12,000
Capacity Factor (%) 85 85 85 85 85 85

(1) Includes variable cost of limestone for a 50/50 mixture of pet-coke and coal at $1.03/MWh and ash removal at $2.56/MWh.


### The coal price forecast was developed using the 2007 delivered price of $2.90 provided by Rennaissance and escalating th at price annually by escalation factors calculated from the AEO 2007 coal price fore cast in nominal dollars. The AEO coal price forecast in nominal dollars was deve loped by applying general inflation at 2.3 percent to the constant dollar forecast provided by AEO.

The pet-coke forecast was developed in a similar manner using the 2007 pet-coke selling price of $1.43/MMBtu provided by HOVENSA and applying the annual escalations from the AEO 2007 coal nominal pr ice forecast. The firm recognizes that there is a potential benefit to be gained by the Authority if a di scount similar to the current fuel oil price discount is applied to the purchase price of pet-coke from Hovensa. Such a discount is subject to ne gotiation between the parties. The economic

benefits of the discount can be examined as a sensitivity case if this option is selected for implementation by the Authority.

The annual price forecasts for coal and pe t-coke delivered to the Authority are provided in Table No. 8. The use of lowe r cost pet-coke and coal would reduce the Authority’s dependence on oil. However, ther e may be socio-political issues that need

to be addressed.



# 2.5 Wind Turbine Generation

Based on the Fatal Flaw Analysis, wind turbin e generation was identi fied as one of the power generation technologies that is pr ojected to reduce costs and to reduce the Authority’s dependence on oil.

Energy generated by wind turbine generators is “non-dispatchable” and must be absorbed by the electric system as and when it is produced. As a result, such generating resources cannot be relied on as dependable capacity resources and can only serve in the role of producers of energy. In addition, because of the inconsistency and potential for sudden variations in th e level of the wind resource, sufficient

## Section 2

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### spinning reserve capacity must always be available to the system to maintain the overall system performance in the event th at the wind resource is diminished or lost

. 

### Because of the difficulty in transporting com ponents of the wind turbine generators to suitable locations in the Virgin Islands, th e report recommends that the 850 kW sized unit be considered rather than the larger 1.5 MW and 2.0 MW units. The firm has assumed the wind farm would contain genera ting resources similar to the Vesta V52 (850 kW) with a total (wi nd farm) rated capacity of approximately 10 MW. We understand Vesta no longer manufactures the V52 turbin e; however, other vendors manufacture similar type and size units.

The estimated total capital cost to install 10 MW of wind turbine generators on the islands of St. Croix and St. Thomas (on- shore installation) is approximately $30 million for each island or $3,000 per kW. All of the O&M costs associated with the

units are assumed to be fixed cost s at an estimated $50/kW-yr.

In April 2006, a report titled “ A Detailed Wind Energy Case Study for Po int Udall on
St. Croix, Crown Mountain on St. Thom as and Estate Concordia on St. John ” was prepared for the Virgin Islands Energy O ffice, a division of the Department of Planning and Natural Resources, Government of the U.S. Virgin Islands by Energy Answers Corporation of Puerto Rico (the “Wind Resource Analyses”), which

described an assessment of the wind resour ce potential based on measurements taken

at one location each on the islands of St. Croix, St. John and St. Thomas. The Wind Resource Analyses contains an analysis of the data including wind speed, wind speed range, wind direction, directi onal variations, seasonal vari ation, frequency distribution, and correlation with a long term source (for the 10 meter height only), for a five month period that excluded the trad itionally high wind months. A second report, titled

“

Addendum to the Updated Wind Resource Analyses ” (the “Addendum”) extends the data set from the Wind Resource Analyses provides rose, hourly average wind speed versus date, and frequency distribution for the results measured at 10 meters and 30 meters height. The firm supplemented the Wind Resource Analyses and the Addendum with maps and data from the Wi nd Atlas of the United States, and air and satellite photos.

Based on the data described above the firm wa s only able to devel op projections of the net energy production of a 10 MW wind farm on the island of St. Croix.

The Wind Resource analyses and the Adde ndum do not provide su fficient data to estimate and analyze the potential wind gene ration of a wind farm on the island of St. Thomas. Due to the incompleteness of the data, the observation that certain data reported at the St. Thomas site is unusua l and needs further verification, and the complex terrain, reasonable assumptions regarding the annual amount of net generation and the distribution of the net en ergy over time on the island of St. Thomas cannot be developed based on the available wind data.

The data regarding the island of St. Croix was based on measurements taken from an

anemometer mounted at 10 meters and 20 mete rs high atop Bee Hill, in the eastern reaches of the island near Divi Carina Bay Resort Hotel. It was assumed that this

would be the location of the wind farm atop the ridge that extends east-west.

## DESCRIPTION OF ALTERNATIVES

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 2-7 Based on a very preliminary analysis, us ing the wind frequency data from the Addendum, the power curve for the V52 wind tu rbine, and gross-to-net loss factors, an annual net energy output was estimated to be approximately 18,000 MWh for the St. Croix location, which re presents an annual capacity factor of approximately 21 percent. Using the limited data availa ble, the annual net energy production was

distributed on a seasonal a nd hourly basis as follows:

Table 2-4 Annual Net Energy Production on a Seasonal and Hourly Basis

Synthesized Daily Distribution

Hour Jan Feb March A pril May June July A ugust Sept Oct Nov Dec
7:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417
8:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
9:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
10:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
11:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
12:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
13:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
14:00 1,889 2,091 2,720 2,810 8,045 8,313 8,045 8,045 2,810 2,720 1,952 1,889
15:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417
16:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417
17:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417
18:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417
19:00 1,417 1,568 2,040 2,108 6,034 6,235 6,034 6,034 2,108 2,040 1,464 1,417

Total 673,338 673,338 969,581 969,581 2,868,048 2,868, 048 2,868,048 2,868,048 969, 581 969,581 673,338 673,338



### The Wind Resource Analyses specifically warn s that it should be used for a reference only. Since no data is availa ble for a specific wind farm site, the data from the Wind Resource Analyses was used as a proxy for actual site data. Due to the incompleteness of the data reported in the Wind Resource Analyses and the complexity of the terrain in eastern St. Croix, there is much uncertainty surrounding the actual net energy production until such ti me as specific wind farm site data is

available.



# 2.6 Electric Interconnection

The electric interconnection option involves the in stallation of a high voltage, direct current (“DC”) submarine cable to connect the electric systems on the islands of St. Thomas and St. Croix. Based on a preliminary assessment, the submarine cable interconnection would be approximately 100 miles long. Such an interconnection would present the Authority with potential savings in the form of larger sized generators with associated economies of scale, lower pl anning reserves and reduced spinning reserves.

The estimated cost of the interconnec tion using a 100 mile long 150 kV DC interconnection along with two high voltage DC terminals with a design capacity of 150 MW is in the range of $300 to $350 million. For the economic analyses associated with this study, a capital cost estimate of $350 m illion was used. This cost

## Section 2

2-8 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### estimate is preliminary as there are signi ficant unknowns relating to the cable route and installation requirements.

The Authority has had discussions with th e Puerto Rico Electric Power Authority (“PREPA“) regarding the pot ential purchase of 20-30 MW of power via submarine

transmission line from PREPA to the Aut hority’s system on St. Thomas. Although this potential arrangement has not been addressed as part of this power supply evaluation such an interconnection arrangement may provide benefits to the Authority such as reduced power supply costs, re duced operating reserves requirements, improved system reliability, potential econom ic long- or short-term arrangements, potential participation in non-o il fired generation to be developed in Puerto Rico, and the potential to take advant age of economies of scale in the development of larger generating units . Due to the potential benef its regarding this alternative, discussions with PREPA should be given priority by the Authority. If this arrangement is shown to be beneficial, the Authority plans to incorpor ate this option in future power supply

evaluations.



# 2.7 Reverse Osmosis Water Production

Water production by RO units rather than the MED units currently operated by the Authority was examined as a pa rt of the Fatal Flaw Analysis and was determined to be a feasible option for the Authority to pursu e. Thus, an economic evaluation of the replacement of the IDE units with RO un its was performed. Based on findings from the Fatal Flaw Analysis, the main criteria established in developing the parameters for

this alternative are as follows:

 

### The RO technology would replace the exis ting MED capacity in its entirety

on the islands of St. Thomas and St . Croix and would eliminate non-fuel operations and maintenance expenses and capital expenditures associated with the existing facility.

 

### The proposed RO plants would be co-loc ated at the site of the power plant

on each island.

 

### Cases were prepared assuming altern atively that: (i) the existing steam boilers for Unit No. 11, and unit No. 13 on the island of St. Thomas and

Unit No. 10 and Unit No. 11 on the isla nd of St. Croix would be retired in conjunction with the replacement of th e MED units and replaced with CFB generating units, or (ii) the current multi-unit combined cycle configurations would be retained on each island, adjust ed to reflect no steam extraction that is currently used to supply the MED units.

 

### The proposed RO facility at each is land would be comprised of two 1.5 MGD capacity units.

 

### The estimated costs developed by th e firm and used in the economic modeling for each RO facility are:

## DESCRIPTION OF ALTERNATIVES

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 2-9 Capital Cost = $23.3 million

Annual O&M Cost 5 

### = $3.3 million

 

### Maximum demand associated with th e RO plant is assumed to be approximately 3.5 MW and 3.0 MW for the islands of St. Thomas and St. Croix respectively, and annual energy requirements are assumed to b e 24.4 GWh and 21.0 GWh annually for the isla nds of St. Thomas and St. Croix respectively.

5 Excludes cost of electricity supply to RO facility.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 3

ENVIRONMENTAL CONSIDERATIONS

3.1 General

Any of the power generation or water produc tion options selected for implementation by the Authority must be designed, constructed, and operated in compliance with applicable federal, Territorial, and local regulations, guidelines, policies, codes, standards, and laws. Some of the key permits and appr ovals that may be required from various agencies are listed in Table No. 3. While the list is not exhaustive, it is intended to provide an indication of the ty pes of permits that may be required for construction of power generation and water pr oduction facilities on the islands of St. Thomas and St. Croix. It was noted that permitting requirements will vary based on the technology selected and desi gn of the facility, as well as site specific conditions. For the U.S. Virgin Islands, regulatory pr ograms fall under the juri sdiction of several different agencies and the agency identifiers in Table No. 8 are intended to be generic in nature, particularly at the Territorial level.

Emission rates of specified pollutants and the net increase in the emission of these pollutants at a particular site will determ ine whether a proposed emissions source will be able to be permitted as a minor source under air quality regulations or will be defined as a major source and require permitting under the federal Prevention of Significant Deterioration (“PSD”) rules. At this time, it appears the most significant obstacle that will affect permitting of a generating facility, based on a technology using combustion, and is related to air quality. NO X 

### and SO 2 

### emissions from such a facility are the primary concern. A recent study performed for the Authority by MACTEC (February 22, 2005) indicates that the PSD increment for NO X 

### is virtually

exhausted at or near the existing Authority’s power pl ant sites on the islands of

St. Thomas and St. Croix. This means that any new major source construction at or adjacent to the existing sites would likely have difficulty in securing a PSD permit, without off-setting NO X 

### emission reductions from the existing units, which would have to be in sufficient amounts to classify the new addition as a minor source. There were also various scenarios evaluated by MACTEC in which the National Ambient Air Quality Standard (“NAAQS”) for NO X 

### was predicted to be exceeded. Again, in these scenarios, an air quality permit for cons truction would not be issued to a project.

There is also information to indicate that SO 2 

### emissions, and possibly NO X 

### emissions,

are a concern on the south shore on the island of St. Croix near the HOVENSA refinery. For power generation options th at include combustion sources, the best strategy will likely be to de sign the facility such that modeled emissions result in impacts below the deminimis levels for each pollutant of concern. It was noted that the deminimis levels do not apply for Class I areas, the nearest of which is the Virgin

Islands National Park located on the island of St. John. Emissions from power plants located at sites on the islands of St. Thomas or St. Croix would not be expected to

## Section 3

3-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### impact the National Park on the island of St. John due to the distance separating the islands and the prevailing winds.

The Virgin Islands Department of Planni ng and Natural Resources (“VIDPNR”), and the Coastal Zone Management approval process requires preparation of an Environmental Assessment (“EA”) . The EA includes, among other things, analyses of impacts on air quality, wetlands, cultural and historical resources, and threatened and endangered species. As part of this approva l, public notice and a public hearing would be required to receive comments from interested parties. The EA and public involvement process could be initiated for any of the proposed options at the existing power plant sites or at the new sites. S upport from the general public for any new site development would need to be strong in order to overcome any opposition from special interest groups.



# 3.2 Potential CO 2 

# Emission Regulations

CO 2 

### is recognized as a greenhouse gas, which accumulates in the atmosphere and could create significant change s in regional climates around the world. Large amounts

of CO 2 

### are produced during combustion of fossil fu els in power plants and at this time, several incentive based po licy options for reducing CO 2 

### emissions in the U. S. and its territories are being considered for imp lementation by the U. S. government.

The proposed incentive based policy options include: (i) a tax on CO 2 

### emissions, and (ii) a cap on the total annual level of emissions combined with a system of tradable

emission allowances.

Under a carbon tax policy, the government would likely impose a mandatory fee for each ton of carbon emitted. The primary purpos e of the tax would be to motivate CO 2 

### emitters to reduce their emissions if the cost of doing so is less than the cost of paying the tax. As a result, the tax would pl ace an upper limit on the cost of reducing emissions, but the total amount of CO 2 

### that would be emitted in any given year would

be uncertain.

In contrast, under a cap-and-trade program, the government would set a limit on total emissions during some period and would requi re regulated entities to hold rights, or allowances, to the CO 2 

### emissions permitted under the cap. Each allowance would

entitle the holder to emit one ton of CO 2 

### over a specified period. After the allowances for a given period were distributed, entit ies would be free to buy and sell the allowances among themselves. Unlike a tax, a cap-and-trade progr am would place an upper limit on the amount of CO 2 

### emissions but the cost of reducing CO 2 

### emissions would vary on the basis of fluctuations in the energy markets, the weather and the technologies available for reducing CO 2 

### emissions.

At this time it is unclear which of the tw o approaches will be se lected or when the selected approach will be implemented. It is also uncertain what the level of tax

would be if the CO 2 

### tax option is selected or what the cap would be set at and how allowances would be allocated if the cap-and -trade option is select ed. For the purpose of comparing the various power supply alternatives in th is study, a sensitivity case has been prepared in which it is assumed that a CO 2 

### tax of $11/ton is implemented by

## ENVIRONMENTAL CONSIDERATIONS

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 3-3 2012 and would escalate at an annual uniform rate to $30/ton by the year 2025.
Thereafter, it was assumed the CO 2 

### tax would escalate at the general inflation rate assumed to be 2.3 percent.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 4

DESCRIPTION OF CASES AND RESULTS

4.1 Description of Cases

As a reference point for projected power supply costs and water production costs Cases 1-1 and 2-1 were prepared assuming the Existing Arrangement. Cases starting with a designation of “1” refer to the Base Load forecast; Cases starting with the designation of “2” refer to the High Require ment Load forecast. Based on the Fatal Flaw Analysis conclusion that CFB units burning a mix of pet-coke and coal would reduce the Authority’s costs and dependence on oil, the firm prepared cases which

utilized these units in various sizes and c onfigurations to meet the Authority’s load requirements under different scenarios includi ng permutations involving (i) the Base Load forecast and High Requirements load forecast, and (ii) with and without replacement of the existing MED desa lination system with RO technology.

The Fatal Flaw Analysis concluded that the use of methanol and LNG as fuels in the Authority’s existing generating plants appe ared to be economically feasible with

certain attentive risks associated with re latively high capital investment, and with respect to LNG, the dependence on the contin uation of the current differential between oil and gas prices. Cases 1-2, and 2-2 were prepared to evaluate the methanol fuel supply options and Cases 1-3 and 2-3 were pr epared to evaluate the LNG fuel supply options.

As indicated in the Fatal Flaw Analysis, th e CFB unit fueled with 50 percent coal and 50 percent pet-coke is projected to be lo wer than the Authority’s displaced energy costs. To the extent a resource is projected to be lower than the Authority’s displaced energy costs at a given capacity factor, the Authority is projected to benefit from adding that resource to its existing system if the resour ce is capable of producing energy at the given capacity factor and if the Authority’s system is capable of accepting that amount of energy at the given cap acity factor. In order to evaluate the CFB’s projected dispatch on the Aut hority’s system, a production simulation computer model, PROMODTM, was utilized. This chronological model simulates economic dispatch of the Authority’s generating systems taking into account fuel costs, unit efficiency, load requirements, equipment operating constraints, and random forced outages. Cases 1-4 and 2-4 were prep ared to evaluate adding CFB units fueled with 50 percent coal and 50 percent pet-coke to the Authority’s existing system with no other major change.

Since the Fatal Flaw Analysis indicated that a CFB unit fueled 50 percent coal/50 percent pet-coke is projected to be lower than the Authority’s average system energy cost, cases were prepared to evaluate whet her an economic benef it could be achieved by replacing major portions of its generating sy stem with such resources. In replacing the existing steam system with CFB units, th e remaining simple cycle CT units were

## Section 4

4-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### assumed to supply spinning reserve requirement s. These cases also involved replacing the existing desalination sy stem with RO technology, which appeared to be an economically beneficial option based on the Fa tal Flaw Analysis. The addition of the RO system and elimination of the existing desalination system is also projected to provide more operational flexib ility for the generating plan t, since a constant steam supply is not required for the RO system. I nherent in this analysis is the assumption that there would be a reduction in production staffing levels and th at Cases 1-5 and 2-5 were prepared assuming such a major repl acement of the Authority’s existing steam system and water production system as desc ribed above. To evaluate the potential economic benefits of just replacing th e existing desalinati on system with RO, assuming no other changes to the water or el ectric generating systems, Cases 1-8 and 1-9 were prepared, which were the same as Cases 1-1 and 1-3, respectively, except that RO is assumed to replace th e existing MED desalination system.

The Fatal Flaw Analysis also indicated that a high volta ge interconnectio n between the

islands of St. Thomas and St. Croix ma y not be feasible with the Existing Arrangement, but may prove to be feasible for a scenario where a large portion of the existing generation is replaced by a new power plant installed on one island to supply power to both islands. To evaluate the be nefits of operating an integrated system, interconnected island systems with the addi tion of CFB units fueled with 50 percent coal and 50 percent pet-coke were assumed in cases 1-6 and 2-6. Cases 1-7 and 2-7 assumed an interconnected system and fu rther assumed replacing existing steam generation with new CFB units fueled with 50 percent coal and 50 percent pet-coke and replacing the existing desalination systems with RO systems.

In order to evaluate the potential economi c benefits of adding wind powered resources to the Authority’s power supply portfolio, ca ses were prepared assuming the addition

of a 10 MW wind farm facili ty is added to the island of St. Croix. As previously explained, wind data from St. Thomas is not complete and could not be used to develop projections of wind net generation on the island of St. Thomas. Based on discussions with the Authority, it was deci ded to develop case s based on adding wind powered resources to Cases 1-1 and 2-1 (t he Existing Arrangement), Cases 1-3 and 2-3 (LNG fuel supply) and Cases 1-4 and 2- 4 (adding CFB units to the existing system with no other major changes), and Cases 1- 5 and 2-5 (replacing the Authority’s steam system and water production system). Th ese case numbers are designated with a “W” at the end (e.g., Case 1-1W, Case 1-3W, etc.).

Based on the foregoing, Table No. 9 provide s a summary the cases prepared to evaluate the Authority’s power s upply and water production options.



# 4.2 Discussion of Results

The results of the Power Supply Evaluatio n are summarized in Table No. 10. Column (a) shows the projected cumulative net present value costs for each case over the period 2008 through 2027 in thousands of dollars for the case assuming the Base Load and High Requirement Load, under the assumption with and without CO 2 

### allowance costs. These costs include projec ted fuel costs, non-fuel electric production O&M costs, non-fuel water related produc tion O&M costs, incremental generating

## DESCRIPTION OF CASES AND RESULTS

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 4-3 unit additions, incremental RO system additions, and associated incremental O&M

costs.

Column (b) in Table No. 10 shows the projec ted differences in cumulative net present

value costs between each case and the Ex isting Arrangement over the period 2008 through 2027 in thousands of dollars for th e cases assuming the Base Load Forecast and High Requirements Load Forecast under the assumptions with and without CO 2 

### allowance costs.

Column (c) on Table No. 10 shows the project ed levelized gross electric system cost for each case on a dollar per MWh basis over the period 2008 through 2027, and Column (d) shows the difference between each case and the Existing Arrangement on a dollar per MWh basis. Levelized gross electr ic cost includes fuel and electricity cost associated with producing el ectric capacity and energy an d water, but excludes nonfuel water related production O&M, incremen tal RO system additions, and associated incremental RO capital costs.

Column (e) on Table No. 10 shows the projec ted capital investment in thousands of

dollars for each case associat ed with generation, replacement of the water system with a RO system, high voltage DC interconnecti on, the LNG infrastructure, methanol and wind power related capital costs as appropriate.

With respect to cases not involving wind pow ered resources, Cases 1-2 and 2-2 (the methanol fuel supply option Base Load Forecast and High Requirements Load Forecast, respectively) with and without CO 2 

### allowance costs are projected to be the lowest cost case compared to the Existing Arrangement on a projected cumulative net present value costs and projec ted levelized power supply co sts basis. Cases 1-3 and 2- 3 (the LNG fuel supply option, Base and High Load Requirements) are projected to be

the second lowest case on a cumulative net present value and le velized power supply cost basis, with CO 2 

### allowance and without CO 2 

### allowance costs. Cases 1-7 and 2-7 (adding CFB units, high voltage DC interconn ection and RO systems and retiring the existing steam units) are projected to be the next lowest cost case.

The previously mentioned cases are projected to result in net present value cost reductions of $211 million dollars to $863 m illion dollars relative to the Existing Arrangement over the period 2008 through 2027. Of these three lowest cost

alternatives and associated cases (methanol, LNG and high voltage DC interconnection), the LNG fuel supply alternativ es (Cases 1-3 and 2-3) are projected to have a capital investments of $196 million dollars and $241 million dollars, whereas

the other two alternatives in clude projected capital inve stments of approximately $0.9 to $1.1 billion dollars.

Cases 1-4 and 2-4 (adding CFB units to th e existing steam and water system) are projected to result in a ne t present value cost reduction of $91 million dollars and $212 million dollars relative to the Existing Arrangement under the Base Load and High Requirements Load Forecast scenario, respectively, without CO 2 

### allowance costs and $74 million dollars and $197 million dollars if CO 2 

### allowances are assumed, respectively. Capital investment associated with Cases 1-4 and 2-4 are projected to be approximately $402 million dollars and $513 million dollars, respectively.

## Section 4

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### Cases 1-5 and 2-5 (adding CFB units to re place the existing steam system and adding an RO system to replace existing desalinatio n system) are projected to result in a net present value cost reduction of $82 m illion and $340 million dollars, respectively, relative to the Existing Arrangement without CO 2 

### allowance and a reduction of $59 million dollar reduction of $292 milli on dollars, respectively, if CO 2 

### allowances are assumed. Capital investment associated w ith Cases 1-5 and 2-5 are projected to be approximately $566 million dollars and $912 million dollars, respectively in 2008

dollars.

Cases 1-8 and 1-9 involve replacing the existing MED desalination systems on both islands with RO systems Co lo cated at the site of the pow er plant on each island. It

was assumed that the extraction steam from the existing steam Unit No. 11 and No. 13 on the island of St. Thomas would no longe r be required. Thereby allowing the plant to achieve the same output level as when supplying steam to the MED units with less fuel input to Boilers No. 11 and No. 13. As a result, the St. Thomas combined cycle configuration is projected to have an effici ency improvement in the range of 4 percent to 9 percent depending on the output level (four percent at 80 MW output and nine percent at 40 MW output. With respect to St. Croix, efficiency improvements are projected to be less because under the ne w HRSG combined cycl e configuration, the steam turbine for Unit No. 11 is projected to be typically operated from steam supplied totally by the new HRSG and th e old HRSG, not the unit boilers. Ther efore, there is less time when a fuel reduction or efficiency improvement can be achieved due to the

elimination of the steam supply to the MED units.

A comparison of Cases 1-8 and 1-9, whic h assume adding the RO system with corresponding Cases 1-1 and 1-3 without the RO system is summarized below.

Table 4-1 Comparison of Cases 1-8 and 1-9

NPV Cost Difference vs. Existing $ (000)

Without CO 2 

### Allowance Cost With CO 2 

### Allowance Cost

Case 1-1 0 0 Case 1-8 7,126 6,796 Additional NPV Benefit $(000) (7,126 ) (6,796)

Case 1-3 (477,953) (534,131) Case 1-9 ( 456,304) (512,037) Additional NPV Benefit $(000) (21,649) (22,094)



### As these cases show, under the Base Load forecast scenario, adding the RO system by itself is not projected to increase the NPV cost reduction relative to the Existing Arrangement. This comparison indicates that the incremental capital investment, operations and maintenance costs, and costs of the additional electricity load associated with adding the RO system are not projected to be offset by more efficient electric energy production and reductions in operation and maintenance and capital

## DESCRIPTION OF CASES AND RESULTS

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 4-5 improvements associated with retiring the existing MED salination system. Based on the firm’s analysis of the combined Water System and Electric System, the cost of replacing all of the MED units with RO f acilities was projected to have only a minor impact on total Electric System and Water Sy stem costs. However, such an analysis does not address the recogni zed and PSC approved allocat ion of costs and value between the Electric System and Water System , which reflects the symbiotic benefits of operating combined electricity and wate r production facilities . This recognized allocation methodology attempts to assign a value (in excess of fuel cost) to the waste heat provided by the Electric System to the Water System. This approach strives to equitably share costs between the two system s, and essentially assures the Electric System that the Water System is not receiving a “free ride.”

When such factors as equity are taken into account, the in stallation of RO facilities may reduce the cost of producing water fr om those calculated in the Power Supply Evaluation. Under the electric power supply al ternatives studied, where total Electric System and Water System costs are projecte d to be reduced compared to the Existing Arrangement, the projected costs of both th e Electric System and the Water System may be reduced with the replacement of the existing MED facilities by new RO

facilities.

Given the differing steam supply requirement s for water production on the island of St. Thomas and on the island of St. Croix, among other things, the potential for cost reductions resulting from the replacement of all or a portion of the MED facilities with RO facilities may be different by island. Accordingly, a refined study of converting all or a portion of the existing MED facilitie s to RO facilities should be undertaken to identify the costs and benefits of total replacement or partial replacement of the MED facilities, and the timing and the location of su ch RO facilities. Also, given the initial results of this analysis, and since the market is the true measure of the cost of RO facilities, subject to the findings of a refined study, cons ideration should be given to issuing a Request for Proposals to acquire an RO facility as a “pilot program.”

With regard to adding new water supply capacity, although the firm has not compared the cost and performance of RO facilitie s to new MED facilities the minor cost difference associated with the existing incr emental MED system costs versus all-in costs for an RO facility suggest that RO facilities may be more cost effective for future expansion. This observation may be verified based on the findings of the previously mentioned refined study.

Cases 1-6 and 2-6 (adding CFB units, interc onnection and no changes to the existing electric or water system) are projected to result in cumulative net a present value cost increase approximately $96 million dollars and a decrease of $27 million dollars, respectively relative to the Ex isting Arrangement without CO 2 

### allowance. If CO 2 

### allowances are assumed, the projected cumulative net present value cost increases by approximately $97 million dollars (Case 1-6) and decreases by approximately $27 million dollars (Case 2-6). The capital investment associated with Cases 1-6 and 2-6 is projected to be approximately $574 million dollars and $641 million dollars, respectively.

## Section 4

4-6 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### Projected annual gross electric costs for the Authority in dollars per MWh for each of

the cases with CO 2 

### allowances and without CO 2 

### allowances are shown on Graphs 2 through 5.

As indicated by these results the cases i nvolving the methanol fuel supply option (Cases 1-2 and 2-2) and the combination of additional CFBs, replacing steam system, replacing the water system and interconnecti on (Cases 1-7 and 2-7) are projected to result in significant cost reductions relati ve to the Existing Arrangement, but both are also projected to involve significant capital investment as show n on Table No. 9 and Graphs 2 through 5.

Alternatives that are projected to also result in cost reductions although to a lesser degree, and represent a lesser and potential ly more achievable capital investment include cases involving the L NG fuel supply option (Cases 1-3 and 2-3) and adding CFB units to the existing system (Cases 1-4 and 2-4).

A comparison of Cases 1-4 to 1-6 and 2-4 to 2-6 indicates that adding the high voltage

interconnection between the islands simultane ously with the addition of CFB units is not expected to result in lower costs relati ve to the Existing Arrangement assuming the continued operation of the existing power plan ts. The reason for this result is that the minimum operating levels on the existing pl ant configuration that are required to continue to supply steam to the water system are projected to limit the potential output of the CFB units during periods of low load.

A comparison of Cases 1-4 to 1-5 indicates that the replacement of the Authority’s existing steam system and existing MED de salination system (Cases 1-5) does not result in reduced NPV costs compared to Case 1-4 and also requires additional capital investment for the RO system, a larger 40 MW CFB unit on St. Thomas, and an additional 40 MW combustion turbine unit on St. Thomas. Under the High Requirement Load Forecast, Case 2-5 wh ich involves replacing the existing steam system and water system allows for higher utilization of the CFB units, resulting in lower projected costs of operation than Case 2-4 in which the existing steam system and water system are not replaced. This result indicates that replacing the steam system with new CFB units and adding RO on both islands is not projected to reduce costs compared to just adding the CFB units unless the electric load increases similar to the High Requirement Case. As shown on Table No. 10 and Graphs 2 through 5, Case 2-5 involves a higher cap ital investment than Case 2-4.

With respect to cases involving wind pow er resources a comparison of each wind powered cases and the corres ponding cases without wind pow er is summarized below:

## DESCRIPTION OF CASES AND RESULTS

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 4-7 Table 4-2 Comparison of NPV Costs Associated with Adding a

10 MW Wind Resource to St. Croix

NPV Cost Difference vs. Existing $ (000)

Without CO 2 

### Allowance Cost With CO 2 

### Allowance Cost

Case 1-1 0 0

Case 1-1W 609 (2,183) Additional NPV Benefit $(000) (609) 2,183

Case 1-3 (477,953) (534,131) Case 1-3W (470,714) (528,983) Additional NPV Benefit $(000) (7,239) (5,148)

Case 1-4 (90,516) (73,605) Case 1-4W (77,985) (64,137) Additional NPV Benefit $(000) (12,531) (9,468)

Case 1-5 (82,041) (58,911) Case 1-5W (112,336) (89,224) Additional NPV Benefit $(000) 30,295 30,313



### High Requirements Load Forecast Without CO 2 

### Allowance Cost With CO 2 

### Allowance Cost

Case 2-1 0 0 Case 2-1W (14,992) (19,530) Additional NPV Benefit $(000) 14,992 19,530

Case 2-3 (584,355) (653,976) Case 2-3W (587,739 (660,861) Additional NPV Benefit $(000) 3,384 6,885

Case 2-4 (212,293) (196,567) Case 2-4W (212,607) (196,899) Additional NPV Benefit $(000) 314 332

Case 2-5 (339,782) (291,792) Case 2-5W (380,098) (336,293) Additional NPV Benefit $(000) 40,316 44,501



### Under the Base Load forecast scenario, thes e results indicate that contrary to the intuitive expectation, adding the 10 MW wi nd powered resources does not generally

increase the NPV cost reduction relative to the Existing Arrangement, the exceptions are that under Case 1-1 (the Existing Arrangement) when CO 2 

### allowance costs are assumed, adding the wind powered resource is projected to re duce NPV costs by approximately $2.2 million dollars, and unde r Case 1-5, with and without CO 2

## Section 4

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### allowances, adding the wind powered resour ce is projected to further reduce NPV costs by approximately $30.3 million dollars.

These results are driven by the relatively low capacity factor of 21 percent versus the relatively high capital costs of approxim ately $3,000 dollars per kW in 2008 dollars.

The projected result that no benefit is pr ovided by adding a wind powered resource under Case 1-3 (which invol ves adding LNG fuel) and Ca se 1-4 (which involves adding CFB units), is explained by the obser vation that both of these cases involves reducing the cost of the energy that is displaced by the wind powered resource.

The projected results that indicate adding a wind powered resource to Case 1-5 (major replacement of existing steam and water production), further reduces NPV costs relative to the existing arrangement is e xplained by the observation that, under Case 1- 5 gas fueled units can be displaced to a greater degree than under Cases 1-1, 1-3 and 1-4 that assume the existing steam and water production faci lities are retained, since under Case 1-5 a continuous steam supply from the existing steam units and HRSG is not required.

Under the Higher Load Requirement Fo recast, adding the wind power resource improves all of the cases. This is projected since at the higher load the wind powered generation is projected to di splace predominately gas fueled simple cycle generation.

In order to compare the previously descri bed cases with respect to the two major issues that affect the potential feasibility, NPV costs and capital investment, a set of matrices have been developed, which are se t forth on Graph No. 6 and Graph No. 7. These graphs depict the trade-off between capital investment, which is plotted on the Y-axis, and NPV costs reductions relative to the Existing Arrangement, which is plotted on the X-axis. Based on this graphica l depiction, the cases plotted in the lower left-hand quadrant represent cases that involve relatively low capital investment and high cost reductions relative to the Existi ng Arrangement. The only cases in this quadrant are Case No. 1-3 and Case No. 2- 3 (LNG fuel supply). Case No. 1-4 and

Case No. 2-4 are the nearest cases to the center of the matrix, which indicates that such cases represent a balance with resp ect to capital investment and NPV cost reductions. Cases in the upper quadrant or and to the far right represent the least attractive options to the Authority.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 5

FINANCEABILITY

5.1 Financeability of Water System Improvements

As a part of the issues to be addressed in the Power Supply Evaluation, the firm was required to consider the technical feasibil ity of producing potable water from the IDE

units and from the use of new RO facilities . While the technical and economic issues of potential potable water production alternat ives were evaluated and are discussed herein, it became clear that there are other major issues that must be addressed that materially affect the economic feasibility of potable water production and the long term financial viability of the Water Syst em, and perhaps, the Authority. In the economic evaluation of replacing the existi ng MED system with an RO system there

are other factors to consider other than th e readily quantifiable costs associated with water production.

Because of existing Territorial Legislati on, among other factors, the Water System (both production and distributio n) developed into a supplem ental potable water system whereby, when potable water is not availabl e from customer owned cisterns or other sources, customers look to the Authority to directly or indirec tly provide potable water. Due to the difficulty and cost of extending the distribution system throughout the islands, there are many areas where pot able water must be provided by private “water haulers,” cisterns, self-produced wa ter for private use and for resale to end users, or some combination thereof.

Existing Legislation and building codes esse ntially require, with few exceptions, that all residential and commercial buildings have cisterns; that the Au thority is prohibited from requiring customers to “hook up” to th e potable water distri bution system when

and where water distribution facilities are in place, and that the Authority is prohibited from imposing a monthly fee regardless of us age to recover a portion of the fixed costs associated with standing ready to provide water service on demand.

The age and then construc tion practices, among other re asons, of the distribution system have also contributed to a higher than normal amount of unaccounted for water and losses, and distribution costs when co mpared to a distributed RO system. Moreover, the central location of the exis ting water production f acilities near the steam production facilities requires a signifi cant amount of pumping costs to deliver potable water throughout the distribution syst em and on the island of St. Thomas over the mountainous, rocky terrain. Discretely locating RO facilities near the population

centers would result in redu ced pumping costs, reduced labor requirements, reduced

unaccounted for water and losses as well as make potable water available where population centers exist and the dema nd for potable water is higher.

All of these factors contribut e to the Authority’s high cost of potable water and have allowed private, third party water producers to sell water to larger users, (e.g., hotels,

## Section 5

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### schools) and other third parties and end user s at rates below those allowed by the PSC and charged by the Authority. The high cost of water production a nd distribution, the availability of potable water from competito rs, together with a reluctance on the part of the Authority to seek rate relief and the PSC to grant rate relief, have contributed to the Authority’s failure to comply with the rate covenant in its bond resolution. Assuming all else remains unc hanged and the Authority seeks and the PSC grants an increase in potable water rates to cure the existing covenant default, such action will tend to encourage existing pot able water customers to conserve and reduce water usage and/or to seek out lower cost water providers.

Given the situation and the existing legislati on, it may not be possible to finance, at a reasonable cost, any new improvements or te chnological changes to the Water System regardless of the estimated long te rm net present value savings.



# 5.2 Financeability of Power Supply Alternatives

As a part of the Power Supply Evaluation, the firm was to address on a cursory basis, the financeability of the various alternatives evaluated. As discussed herein, most of

the various alternatives are estimated to reduce costs to the Authority and to customers over the useful life (approximately 25 years) of the technology and facilities studied. However, some of these alternatives require significant amounts of capital investment and other risks. For a discussion of pot ential alternative third party financing arrangements used for wind project s, see the white paper titled “ Wind Project Financing Structures: A Review and Comparative Analysis” provided by GCG which is included as Appendix C.

In addition to the socio-political factors associated with the public acceptance of new technologies to the Territory (e.g. the introdu ction of pet-coke/coal fueled generating resources or the liquefaction/gasification of pet-coke into methanol), certain financial

factors must be considered in the decision process. Some of these financial factors

include

(i) The number of people that perman ently reside in the Territory;

(ii) The number of Authority customers that ultimately will pay for service and their ability or willingness to pay for service;

(iii) The willingness of the PSC to approve rate increases and to enforce the prompt payment for service;

(iv) The credit worthiness of the Terr itory and the Au thority and the willingness of investors to pur chase Authority indebtedness;

(v) The existing outstanding indebt edness of the Authority; and

(vi) The existing restrictions on the i ssuance of additional indebtedness by the Authority as set forth in the Electric Bond Resolution, the

Subordinated Electric Bond Resolution and the Water Bond

Resolution.

## FINANCEABILITY

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 5-3 

# 5.2.1 Population

At 2006, the reported population of the Territory was 112,801 people with 53,155 people residing on the island of St. Thom as, 55,287 people residing on the island of St. Croix and 4,359 people residing on the island of St. John. Because the Territory is a highly desirable tourist destination, there were over 2.5 million visitor arrivals during 2006. On average, the visitors equa te to an additional 7,000 people per day in the Territory.



# 5.2.2 Customers

At June 30, 2007 the Author ity provided electric and wa ter service to over 65,000 residential, commercial and government custom ers. The customer base in the three primary islands for the Electric System was 53,628 and for the Water System was 12,078. As discussed hereinafter, many of th e Water System customers do not rely on the Water System for year round service. Rather, the Water System is predominantly used by customers as a supplemental water s upply during dry periods or when water is

not available from other sources.

The Electric System is essentially the sole provider of electric service in the Territory with exception of a few en tities, including HOVENSA, wh ich produce electricity for

their own use. Sales for re sale electric services are not available in the Territory.



# 5.2.3 Regulatory

The electric and water rate levels and st ructures are based on existing Territorial Legislation and are regulated by the PSC. In the past, in carrying out its duties to the people of the Territory and to the Authority and after the holding of hearings, the PSC has tended to reduce increases and to defer, as opposed to disallow, in rates or the recovery of fuel costs. At the present time, the average residential customer using 500 kWh of electricity pays approximately $170 per month and using 2,400 gallons of water pays approximately $56.00 per month. These amounts are based on fuel oil costs of approximately $90.00 per barrel, as opposed to the current market price of $110 per barrel. Thus, the cost of electricity and water ar e expected to continue to

increase. 6



### The cost of electricity in the Territory is over 3.5 times the average cost in the

continental United States a nd the cost of water is ove r $23.00 per 1,000 gallons, which is significantly higher than the cost throughout most of the United States.

In addition, in the past there has been an unwillingness or inability for certain governmental customers to pay for electric and water service on a current basis.

6 These rates are based on the Authority’s cost during the first six months of 2008, as a result of unprecedented fuel oil prices

, the LEAC Factor is projected to increase effective July 1, 2008

.

## Section 5

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# 5.2.4 Credit Worthiness

The Authority has access to the financial markets. Although jointly managed and operated, the Electric System and the Water System are independently financed. For many years, the Authority has taken action to improve its credit worthiness and to obtain investment grade ratings on its in debtedness. At the present time the Authority’s Electric System senior lien and subordinate lien indebtedness are rated as “Investment Grade” by the nationally recognized rating agencies:

Table 5- 1

Senior Lien and Subordinate Lien Indebtedness

Rated “Investment Grade”

Electric System Ratings (*)

Senior Lien

Bonds Subordinate Lien

Bonds

Fitch Ratings, Inc. BBB BBBMoody’s Investor Services, Inc. Baa 2 Baa 3

Standard & Poor’s Rating Services BBB- BBB-

(*) Underlying, un-enhanced rating at May 2007.



### On June 20, 2008, Standard & Poor’s Rating Se rvices (“Standard & Poor’s”) issued a report on the Authority’s credit rating and out look. Standard & Poor’s affirmed the Authority’s existing ratings and placed the Authority’s indebtedness on “negative

outlook.”

Among other things, Standard & Poor’s lists the following factors underlying its rationale for a negative outlook for the Electric System’s indebtedness:

(i) “... financial and rate impact s of rapidly rising global oil prices...”

(ii) The increase in “...the balance of unrecovered fuel amounts...”

(iii) “... the PSC has at times shown some reluctance to pass all of the costs on to customers on a timely basis.”

(iv) “...Unlike many of its peers in the public power sector, WAPA is not free to set its own rates, as rate increases are subject to approval by the Virgin Islands Public Services Commission.”

(v) “...Liquidity is weak, and collections are slow.”

(vi) “...the islands’ limited economy...”

Standard & Poor’s reports that:

## FINANCEABILITY

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### R. W. Beck 5-5 “Given the global oil pri ce situation, if WAPA’s unrecovered fuel cost balance increases significantly, or if its currently high user rates reduce demand and collections significantly, Standard & Poor’s could lower the rating. If WAPA is able to reduce its unrecovered fuel costs balance over time through PSC-approved rate adjustments, and if costs moderate—improving the affordability of electricity sales to

customers—the outlook coul d return to stable.”

At this time, the Water System is not rated by the national rating agencies.

In 2008, it was determined that the Authority failed to comply with the rate covenant in the Water Bond Resolution during fiscal year ended June 30, 2007. The Authority

has taken action to seek immediate rate re lief from the PSC to cure the covenant default. On May 6, 2008, in Docket No. 576, the Authority filed for Emergency Rate Relief for the Water System to cure a “covenant default.” On May 8, 2008, the PSC extended its deliberations on the emergency rate request for 60 days. In early July 2008, the Technical Consultant requested th at additional time be permitted for its review of the request ed Emergency Rate Relief filing. The Authority has agreed to extending the suspension period to August 8, 2008. It is projected that the Authority may not have sufficient net revenues to co mply with the rate covenant during the fiscal year ended June 30, 2008. Should the Authority proceed with potential plans to finance new or replacement water production facilities, it is doubtful that the Authority’s Water System indebtedness will receive an investment grade rating.

With regard to the Electric System, shoul d the Authority elect to finance new or replacement production facilities, the rating agencies may reduce the ratings due to the

relative size of the associated indebtedness and other risks. Reduction in credit ratings will result in increased interest costs, ma y require the Authority to consider credit enhancement and may limit the number and type of investors that can purchase Authority indebtedness.



# 5.2.5 Outstanding Indebtedness

Under the Authority’s enabling legislation, at this time the Authority is permitted to issue indebtedness up to a maximum of $350,000,000. At June 30, 2007, the Authority reports that the outstandi ng long term indebtedness totals $241,785,000,

which amount is below the current authorized amount.

The Authority’s outstanding indebtedness is se cured in part by separate and distinct claims on revenues, reserve fund balances and credit enhancements. At June 30, 2007 the reported outstanding long term indebte dness for the Electric System and Water System was:

## Section 5

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### Table 5-2 Outstanding Long Term Indebtedness for the Electric System and Water System

Electric System Water System Total

Dollars in Thousands

Senior Bonds $139,930 $29,270 $169,200

Subordinate Bonds 57,585 - 57,585

Line of Credit 15,000 - 15,000

Total $212,515 $29,270 $241,785



# 5.2.6 Issuance of Additional Indebtedness

The Electric Bond Resolution, the Subordina te Electric Bond Resolution and the

Water Bond Resolution include restrictions on the issuance of additional pari passu and subordinated indebtedness. In gene ral to protect exis ting bond holders, the

various resolutions esta blish criteria that must be me t in order for the Authority to

issue indebtedness. In addition to demonstr ating the ability of th e Authority to meet certain cash flow projections , the Authority must demons trate that it has and is projected to meet the a pplicable rate covenant.

With regard to the Electric System, to the extent the Authority elects to finance the costs of construction through the issuance of senior lien debt, the Authority must have rates in place to produce revenues sufficient to provide an additional 25 percent of

annual senior lien debt service in order to comply with the 1.25 times debt service coverage requirement in the Electric Bond Resolution. Should the Authority elect to

finance the costs of construction with subor dinated debt, the Authority’s rates must produce revenues sufficient to provide an addi tional 15 percent of a nnual debt service, after the payment of operation and maintena nce expense and debt service in order to comply with the 1.15 times debt service coverage requirement in the Subordinated

Electric Bond Resolution. To the extent the Authority complies with its “Mission Statement” additional increases in rates and revenues will be required.

The Water Bond Resolution also contains restriction on the i ssuance of additional

indebtedness. Like the Electric Bond Reso lution, the Water Bond Resolution requires that water rates must be in place to produce revenues in excess of the annual debt service by 25 percent, after the payment of operation and maintenance expenses and

debt service.

Based on the foregoing, it may be difficult for th e Authority to issue the needed debt at

a reasonable cost to finance some of the more capital intensive alternatives.

## FINANCEABILITY

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### R. W. Beck 5-7 

# 5.2.7 Other Considerations

Given the Authority’s unique situation and significant amount of capital investment that is required to reduce its dependency on volatile, high cost fuel oil, consideration should be given to seeking fe deral assistance in the form of grants to lesson the financial impact on the Authority and its customers. The Authority reports that working with members of the U.S. House of Representative’s Appropriations Committee, the Virgin Islands delegate to the U.S. Congress, and the Governor, $500,000 has been included in a “Bill” to study practical ways to electrically

interconnect the islands of St . Thomas and St. Croix and pot entially reduce or stabilize (due to the fluctuation of fuel oil prices) utility bills to customers.

While many procurement schemes have gain ed popularity over the years, e.g., Build, Own, Operate (“BOO”), Design, Build, Operat e, Own and Transfer (“DBOOT”), such options may be worth of future considera tions. Although direct Authority ownership should result in the lowest cost to acquiring new facilities, as the Authority does not earn a profit, does not pay income taxes and can issue lower cost tax exempt indebtedness, it may be necessary for the Au thority to consider a DBOOT or a similar procurement. The DBOOT mechanism woul d not require the Authority to issue indebtedness and would likely result in lowe r labor costs. However, the Authority would be required to pay the higher cost of capital (higher interest costs and after tax profits) and income taxes.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 6

PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS

6.1 Principal Considerations and Assumptions Pertaining to the Evaluation of Electric System and Water System Alternatives

The estimates and projections of potential pla nned operations of the Electric System and Water System as summarized in this report have be en based upon the firm’s understanding, among other matters, of the pr ovisions of the Electric Revenue Bond Resolution adopted by the Authority on June 8, 1998, as supplemented (the “Electric Bond Resolution”) and the Electric Revenue Subordinated Bond Resolution, as supplemented, (the “Electric Subordinated Bond Resolution”), and the Water Revenue Bond Resolution, adopted by the Authority on November 23, 1998 (the “Water Bond Resolution”) as well as certain contracts, ag reements, regulations, statutory requirements and planned operations. In the preparation of this report and the conclusions, the firm has made certain assumptions with respect to conditions, which may ex ist, or to events, which may occur in the futu re. While the firm belie ves these assumptions are reasonable for the purpose of this report, they are dependent on future events and actual results may differ from those assumed. In addition, the firm has used and relied upon certain information and assump tions provided to us by the Authority and others. While

the firm believes the use of such informa tion and assumptions to be reasonable for the purpose of this report and the sources to be reliable, it has not independently verified the accuracy or validity of the information and of fers no assurances with respect thereto. Some actual conditions may vary significan tly from the respective assumptions due to unanticipated events and circumst ances. To the extent that actual conditions differ from those assumed herein or provided to the firm by the Authority and others, the actual results will vary from those pr ojected herein. The report su mmarizes the firm’s work up to the date of the report. Thus, changed conditions occurring or becoming known after such date could affect the material pres ented to the extent of such changes.



# 6.2 List of Principal Considerations and Assumptions

The Principal Considerations and Assumptions are:

1. The reported data and information pertai ning to the historical operations and cost of the Authority’s Electric Syst em and Water System are accurate and reflect, to the extent possible normalized System operations. The parameters in the study were developed based upon actua l data averaged for the three year period fiscal years 2005-2007. For the St. Croix Plant these parameters have remained relatively consta nt; however, during fiscal year 2008 the St. Thomas

## Section 6

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### Plant experienced the prolonged unavaila bility of its heat recovery steam generator adversely impacting overall plant performance on a three year average basis. The study results are ba sed upon what the firm believes to be normal operations of the St. Thomas Plant. However, if the St. Thomas Plant for whatever reason were to continue in the future to operate at its fiscal year 2008 performance levels the findings of the Report would understate the

economic benefits of the a lternatives considered.

2. The existing allocation of shared operating and capital costs between the Electric System and the Water System is reasonable and will not be materially changed into the future.

3. While a detailed analysis of the number of people needed and cost to operate the Electric System and the Water System was outside the scope of this Power Supply Evaluation, adjustments to labor co sts were recognized for each of the

various alternatives identified.

For example, under a scenario whereby there is no material change in the existing facilities to produce electricit y, steam, and potable water, the existing labor costs (operation and maintenance cost s) were escalated. However, if a new resource (CFB facilities) to be de veloped is being analyzed, the existing operation and maintenance expense was deleted and replaced with revised estimates of operations and maintenance expenses based on typical industry averages. Unless already considered in preparing the cost estimate, the typical operation and maintenance expenses we re adjusted upwar d by approximately 25 percent so as to capture the additiona l cost associated with doing work in the U.S. Virgin Islands.

4. For the Electric System and the Water System, general inflation and laborrelated costs have been projected above cu rrent levels at 2.3 percent per year.

5. The cost of fuel oil from 2007 through 2009 has been projected on the basis of information provided by the Authority’s fuel consultant, and reflects the favorable pricing provisi ons contained in the HOVENSA agreement. The 2007 and 2008 average cost of delivered No. 2 fuel oil as provided by the Authority’s fuel consultant are $13.13 MMBtu ($76.15 BBL) and $16.55 MMBtu ($96.00 BBL), respectiv ely. In addition, for purposes of estimating the future cost of oil, the projected cr ude oil cost estimates contained in the AEO 2007 projected fuel prices were ut ilized after adjustment by 2.3 percent annually for inflation. Fuel cost proj ections are shown graphically on Graph No. 1. It should be noted that in July 2008, the market price of crude oil was over $120.00 per barrel or approximately $21.00 per MMBtu. To the extent that current fuel oil prices remain high er than prices used in the study, the NPV savings associated with the power suppl y alternatives presented in the study

are understated.

6. The cost of pet-coke fuel has been projected on the basis of information provided by HOVENSA and reflects a delivered cost of $1.43 MMBtu in

## PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS

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### R. W. Beck 6-3 2007. The $1.43 MMBtu is equivalent to paying approximately $8.30 per

barrel for No. 2 fuel oil.

7. The cost of coal fuel has been projec ted on the basis of information provided by Renaissance and reflects 11,600 Btu/ pound, 0.7 percent sulphur Colombian coal. The reported 2007 co st of coal is $2.90/MMBtu (equivalent to paying $16.82 per barrel for No. 2 fuel oil) was escalated on the basis of information contained in the AEO 2007 projected fuel price for gas, adjusted by 2.3 percent annually for inflation.

8. The cost of LNG has been projected on th e basis of an adder developed from a detailed report prepared by the firm’s Global Asset Consulting Group in July 2007 and an underlying Henry Hub Gas pri ce based on forward prices for 2008

and 2009 escalated thereafter on the basi s of information contained in AEO 2007 projected fuel price for gas, and an assumed general inflation rate of 2.3 percent annually.

9. The cost of methanol has been project ed on the basis of developing an on island, publicly financed methanol pr oduction plant utilizing pet-coke from

HOVENSA as a feed stock. The metha nol production plant is projected to produce approximately 1,000,000 gallons per day at estimated direct construction costs of approximately $1 bi llion dollars. The development of the methanol fuel price shown on Table N o. 6 does not assume any discount from HOVENSA for the pet-coke purchase, nor sales of excess methanol production to other parties.

10. It has been assumed that the Authority and its Electric System and Water System will continue to be a wholly-own ed instrumentality of the Government.

11. No assumption has been made to reflect any changes in existing federal or Territorial laws and/or regulations to reflect, among other things, more stringent environmental requirements (other than a sensitivity study to estimate the potential impact on the Authority s hould a tax or fee be assessed on CO 2 

### emissions), increased competition for electric service and customers, and changes in existing tax laws a nd the imposition of new tax laws.

12. It has been assumed that demand a nd energy sales will increase during the study period. For purposes of evalua ting the effects on the various power supply alternatives, two growth scenarios have been recognized for the Electric System and one scenario for the Water System. Based on the results of an analysis of historical growth in cust omers, sales and usage patterns on each island, taking into consideration the c ontinued high cost of fuel oil, power supply requirements are projected to increase annually by 1.2 percent on the island of St. Thomas and 0.5 percent on the is land of St. Croix. As a sensitivity case, power supply requirements are also projected to increase annually by 3 percent on the island of St . Thomas and 1.5 percent on the island of St. Croix.

With regard to projected sales of potable water, it was assumed that sales of potable water would rema in essentially flat.

## Section 6

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### No assumptions or provisions have b een made or included in the load projections utilized herein to reflec t unforeseen material load changes or changes in customer consumption charac teristics which may be the result of, but not limited to, increased compet ition for customers brought about by existing and potential changes in legisl ation, deviations from normal weather conditions, including natural disasters, su ch as hurricanes, earthquakes, etc.,

modifications to or limitations on existi ng generation or distribution facilities, generation station or unit fa ilures, further significant increases or decreases in the cost of fuel oil, or other unforeseen events.

13. All capital costs are reported in 2008 dollars unless stated otherwise.

14. The financing of the major generation a nd water production facilities is based on the assumptions that:

a. The Authority will be able to issue revenue bond indebtedness that is exempt from most U.S. income taxes,

b. The Authority will be able to issue the debt at a reasonable annual interest rate of 5 percent,

c. To issue such indebtedness, the Authority will incur issuance expense equal to 3 percent of the principal amount of bonds which expense would be funded from bond proceeds,

d. The debt service reserve requirement is equal to the estimated maximum annual debt service payment,

e. The life of the indebtedness will be approximately 25 years and the structure of the debt service will be essentially level for 25 years.

f. The planning level capital cost estimates are assumed to reflect the total capital amount to be financed in cluding the interest expense during construction period typical for each such project; and

g. To the extent interest rates are higher than assumed during the construction period or the constructi on period is longer than typical for a given resource, the project capit al (direct construction cost and financing cost) will be hi gher than assumed herein.

h. For purposes of consistency in comp aring alternatives, a debt service coverage of 1.0 was assumed for all alternatives. The actual debt service coverage would depend on, among other things, the amount of the capital expenditure being financed.

15. The estimated direct construction cost of the various gene rating alternatives

evaluated have been based on the firm ’s estimates for generic electric generating resources developed by the Global Asset Consulting (“GAC”) practice based on recent experience and indus try sources and adjusted to reflect the estimated increased cost of constructing such facilities in the Territory. However, in a February 2008 report publ ished by IHS, Inc. and Cambridge Energy Research Associates (“CERA”), it was reported that the cost of new

## PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS

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### R. W. Beck 6-5 power plant construction during 2007 increased by 27 percent and during 2005 through 2007 such costs increased by a pproximately 76 percent. Although, the estimates of direct construction costs utilized herein attempted to recognize the recent “run-up” in costs, no allowance have been included in the projections of

direct construction costs should th ese unprecedented in creases in costs continue beyond 2007.

16. The estimated direct construction cost of RO facilities was based on the firm’s estimates of generic RO facilities adjust ed to reflect the estimated increased cost of constructing such facilities in the Territory.

17. All generating and water production faci lities will be wholly owned, operated and financed by the Authority.

18. The heat rate data and condition asso ciated with the Authority’s existing generating resources are based on data contained in the Condition Assessment Study Report and information provided by the Authority.

19. The technologies, fuel type, rated cap acity and in service date of the Authority’s existing generating resources are based on information provided by the Authority as summarized on Table 1.

20. The capability of the Authority’s wate r production facilit ies is based on information provided by the Authority as summarized on Table No. 2.

21. The Authority’s planning criteria fo r generating reserves, assuming the existing isolated electric system, is the requirement to have sufficient generating capacity on each island to meet its respective load requirement with its two largest units out of service.

22. The assumed generating configurations on the islands of St. Thomas and St. Croix assume that the Authority will c ontinue to meet recognized reliability constraints that include the requirement that each plant be capable of handling

steam and electrical demand over a full ra nge of demand with the largest unit

down for maintenance concurrent with th e forced outage of the next largest

unit.

23. For cases in which CO 2 

### allowances are assumed, the cost of such allowances is projected to be $11 dollars per ton in 2012, increasing to $30 dollars per ton in 2025. This cost projection is based on the firm’s evaluation of potential legislation being considered and a review of industry projections.

24. The power generation and water producti on options evaluated herein are assumed to be designed, constructed and operated in compliance with applicable environmental air quality rule s. To the extent emissions exceed the PSD increment at a given site, off-setting NO X 

### or SO 2 

### emission reduction will be obtained in sufficient amounts to classify the new addition as a minor source. No cap-and-trade program is assumed for NO X 

### and SO 2 

### since the U.S. Virgin Islands are not subject to the Cl ean Air Interstate Rule (“CAIR”) which establishes such programs.

## Section 6

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### 25. The total non-fuel steam related electr ic production expenses are projected to be approximately $8.1 million dollars annually in 2007 dollars based on an average of the Authority’s reported hi storical costs for the period 2005 through

2007 as shown on Table No. 4. These cost s are assumed to be avoidable in the event of the retirement of the Authority’s existing steam units and HRSG

facilities.

26. Total non-fuel water related producti on expenses are projected to be approximately $5 million dollars annually in 2007 dollars based on an average for the Authority’s reported historical and costs over the years 2003 through

2007. These costs were assumed to be avoi dable in the event of the retirement of the Authority’s existing MED desalination system.

27. The Authority’s non-fuel combustion turbine related O&M expenses are projected to be approxim ately $1.5 million dollars a nnually based on historical information over the period 2005 through 2007 as reported by the Authority

and as shown on Table No. 3. Such cost s were assumed to escalate at an inflation rate of 2.3 percent.

28. The earliest year in which new gene rating resources or water production facilities were assumed to be added to the Authority’s system is 2012, based on the minimum projected lead time for approvals, permitting and construction. Additional generating resources were assu med to be added as needed to meet the Authority’s planni ng reserve criteria.

29. Inherent in the development of non-fue l production operati ng expenses for the various alternatives evaluated, (w ith the exception of the Existing Arrangement), changes in the staffing levels and skills have been assumed. While no production staffing st udies are warranted at this time, given state-ofthe-art contemporary, new facilities, it is likely that retraining existing personnel will be necessary and that an overall reduction in production staffing

will occur.

30. In developing the cost estimate and schedule for retubing the existing MED water production units for extended life over the study period. The cost estimate provided by IDE for retubing Un it No. 9 in 2008 a nd the Authority’s estimate that each unit will require retubing at thee year intervals were used. For future years, the IDE 2008 estim ate of $1,075,000 was escalated annually at an assumed inflation rate of 2.3 percen t. The cost and schedule for retubing

the MED units are shown on Table No. 4.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 7

CONCLUSIONS

7.1 Conclusions

Based on the Principal Assumptions and C onclusions set forth herein and on the results of our analysis and review of re ports prepared by or for the Authority and information provided by the Authority and ot hers which is summar ized or referred to in this Power Supply Evaluation, which repor t should be read in its entirety in conjunction with the following, th e firm is of the opinion that:

1. Of the various electric generation and wa ter production alternatives evaluated, four standout as being technologically feasible, potentially environmentally compliant, financially affordable and wo rthy of pursuit under certain scenarios:

(i) supplemental wind powered electric generation,

(ii) electric generation using LNG as a fuel source,

(iii) electric generation using CFB boilers fueled on a mixture of pet-coke and coal; and

(iv) water production through the systematic installa tion of RO facilities.

2. Like many Caribbean island power system s the authority finds itself dependent upon fuel oil which in recent years has s ubjected the Authority’s customers to increasing rate levels and volatility. Given that the Authority also faces significant issues, which impact its abili ty to diversify its primary energy source and lower rates including the siting, permitting, construction, and financing of new generating resources, the existing resource portfolio was reasonable at the time it was implemented. At this time it is critical that the Authority explore all reasonable devel opment and financing strategies in undertaking the actions required to successfully implement the above

alternatives.

3. With respect to cases not involving wind powered resources, Cases 1-2 and 2-2 (the methanol fuel supply option Base Load Forecast and High Requirements Load Forecast, respective ly) with and without CO 2 

### allowance costs are projected to be the lowest cost case co mpared to the Existing Arrangement on a projected cumulative net present value costs and a projected levelized power supply costs basis. Cases 1-3 and 2-3 (the LNG fuel supply option, Base and High Load Requirements) are projected to be the second lowest case on a cumulative net present value and levelized power supply cost basis, with CO 2 

### allowance and without CO 2 

### allowance costs. Case s 1-7 and 2-7 (adding CFB units, high voltage DC interconnecti on and RO systems and retiring the existing steam units) are projected to be the next lowest cost case.

## Section 7

7-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### The previously mentioned cases are projecte d to result in net present value cost reductions of $211 million dollars to $863 million dollars relative to the Existing Arrangement over the period 2008 through 2027. Of these three

lowest cost alternatives and associat ed cases (methanol, LNG and high voltage DC interconnection), the LNG fuel suppl y alternative (Cases 1-3 and 2-3) are projected to have a capital invest ment of $196 million and $241 million,

whereas the other two alternatives in clude projected capital investments of approximately $0.9 to $1.1 billion dollars.

4. Cases 1-3 and 2-3 (the LNG fuel supply option, Base and High Load Requirement) represents the best trade-o ff between capital investment and cost reduction relative to the Existing Arrangement of the cases evaluated herein, but such projected cost reductions ar e dependent on the continuation of the

current differential betw een oil and gas prices.

5. Cases 1-4 and 2-4 (adding CFB units to the existing steam and water system) are projected to result in a net pres ent value cost reduction of $91 million dollars and $212 million dollars relative to the Existing Arrangement under the Base Load Forecast and High Requirements Load Forecast scenario, respectively, without CO 2 

### allowance costs and $74 million dollars and $197

million dollars if CO 2 

### allowances are assumed, respectively. Capital

investment associated with Cases 1-4 and 2-4 are projected to be approximately $402 million dollars and $513 million dollars, respectively. These cases represent a balance between capital investment and cost reduction relative to the Existing Arrangement a nd also are projected to reduce the Authority’s dependence on oil fuel.

6. With respect to cases not involving wind powered resources, replacing the steam system with new CFB units a nd adding RO on both islands is not projected to reduce costs compared to ju st adding the CFB units unless electric load increases similar to the High Lo ad Requirements case. When a 10 MW wind powered resource on St. Croix is included, replacing the steam system with new CFB units and adding RO on both islands is projected to reduce costs compared to just adding CFB units under both load forecast and high requirement load forecast assumptions.

7. Given the differing steam supply requi rements for water production on the

island of St. Thomas and on the island of St. Croix, among other things, the potential for cost reductions resulting from the replacement of all or a portion of the MED facilities with RO facilities may be different by island. Accordingly, a refined study of converti ng all or a portion of the existing MED

facilities to RO facilities should be undertaken to identify the costs and benefits of total replacement or partia l replacement of the MED facilities, and the timing and the location of such RO fac ilities. Also, given the initial results of the firm’s analysis, and since the mark et is the true measure of the cost of RO facilities, subject to the findings of a refined study, consideration should be given to issuing a Request for Proposals to acquire an RO f acility as a “pilot program.” With regard to adding ne w water supply capacity, although the firm has not compared the cost and performance of RO facilities to new MED

## CONCLUSIONS

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 7-3 facilities the minor cost difference asso ciated with the existing incremental MED system costs versus all-in costs for an RO facility suggest that RO facilities may be more cost effective for future expansion. This observation may be verified based on the findings of the previously mentioned refined study.

8. The cases involving the methanol fuel supply option (Cases 1-2 and 2-2) and the combination of additional CFBs, repl acing the steam system, replacing the water system and interconnection (Cases 1- 7 and 2-7) are projected to result in significant cost reductions relative to the Existing Arrangement, but both are also projected to involve significant capital investment and associated financial risk to the Authority.

9. With respect to cases involving wind powered resources, adding the 10 MW wind powered resource on the island of St . Croix under the Base Load forecast assumption is projected to improve Case 1-1 (the Existing Arrangement) with

CO 2 

### allowance costs assumed and Case 1-5 (major replacement of existing steam system and water production) with and without CO 2 

### allowance costs assumed. Adding the 10 MW wind resour ce on the island of St. Croix under the High Requirement load forecast is projected to improve Cases 2-1 (the Existing Arrangement),Case 2-3 (the L NG fuel supply alternative), Case 2-4 (which involves adding CFB units) and Case 2-5 (major replacement of existing steam and water system).

10. Securing environmental air permits for the CFB units at the Authority’s existing plant sites on the islands of St. Thomas and St. Croix will be difficult and will likely require obtaining offse tting emission reductions from existing

units.

11. Adding a high voltage interconnection between the islands is pr ojected to be an economically feasible option if the exis ting steam system and water system is also replaced, but such alternatives requi re a significant capital investment with

the associated financial risk.

12. The following financial factors may aff ect the Authority’s ability to issue

additional indebtedness:

(i) The number of people that perman ently reside in the Territory;

(ii) The number of Authority customers that ultimately will pay for service and their ability or willingness to pay for service;

(iii) The willingness of the PSC to approve rate increases and to enforce the prompt payment for service;

(iv) The credit worthiness of the Terr itory and the Authority and the willingness of investors to pur chase Authority indebtedness;

(v) The existing outstanding indebt edness of the Authority; and

(vi) The existing restrictions on the i ssuance of additional indebtedness by the Authority as set forth in the Electric Bond Resolution, the

## Section 7

7-4 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### Subordinated Electric Bond Re solution and the Water Bond

Resolution.

Based on the foregoing, the Authority ma y find it difficult to issue the needed

debt at a reasonable cost to finan ce some of the more capital intensive

alternatives.

13. Although direct Authority ownership shoul d result in the lowest cost to acquiring new facilities, it may be necessa ry for the Authority to consider a design, build, operate, own and transfer or similar procurement arrangement so that the Authority would not be requ ired to issue further indebtedness.

The firm expresses its sincere appreciation to representatives of the Authority, HGI, Georgetown MACTEC, HOVENSA, Renaissa nce and others for their assistance, guidance, input and spirited c ooperation. The firm is prep ared to present and discuss its findings with the Authority and others.R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

# Section 8

IMPLEMENTATION PLAN

8.1 Implementation Plan

In order for the Authority to move forwar d with the integration of the new electric supply resources into the Author ity’s system, there are a number of steps that need to

be undertaken as described below in the im plementation plan outline and shown on the flow diagram depicted in Graph 8-1.



# 8.1.1 Implementation Plan Outline:

1. Resolve Comments on Power Supply Evaluation - This involves meeting with the Authority and GCG in a collaborat ive effort to resolve the comments provided by GCG and finalize the Draft Power Supply Evaluation.

2. Receive Formal Governing Board Approval – Incorporate GCG’s comments in the finalized Power Supply Evaluation Report and submit the final report to the Authority’s Governing Board for approval.

3. Receive PSC Comments – After finalizing the Power Supply Evaluation, the Authority will obtain PSC comments that the Power Supply Evaluation represents a reasonable plan for the Authority.

4. Integrate with the Power Supply Evaluation with RFP Proposals - The Authority will prepare an evaluation to compare the highest ranked proposals and/or combination of proposals from th e RFP process with the most economic alternatives from the Power Supply Ev aluation and develop an integrated resource plan that reflects the Authority’s best plan.

5. Modify Plan – Based on discussions with PR EPA, and appropriate evaluation

of alternatives such as electrical interconnect with PREPA, the Authority will modify the proposed plan as necessary.

6. Formal Governing Board and PSC Approval for Revised Plan – After developing a revised plan that incl udes any potential arrangement with PREPA, the Authority will obtain form al Governing Board and PSC approval to proceed. This may require further m odifications to the plan and associated

further evaluations.

7. Refine Details of the Plan –The major assumptions and data used in developing the plan will be further re fined. This will include, among other things, developing detailed cost estimat es and performance data for proposed projects, reviewing retirement of exis ting facilities and associated costs, developing costs for any required infrastr ucture associated with the plan, and projecting funding requirements.

## Section 8

8-2 R. W. Beck R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### 8. Obtain Governing Board and PSC Approval for Detailed Plans – To the extent the detailed review of the plan reveal s a significant change in cost, or the

benefits of the selected plan have substantially ch anged, the Authority will seek formal Governing Board and PSC a pproval to proceed. This may require

further modifications to the plan and further evaluation.

9. Develop Financing Plan and Finalize Contracts – The Authority will develop a detailed financing plan for each project that will include the monthly cash flows, capitalized interest, fund requ irements, bond amount and debt service payment. Power purchase contracts a nd construction contra cts and any other agreements will be negotiated and finalized.

10. Rate Analysis – Based on the contemplated debt service requirement, and power purchase payments, the Authority will prepare a rate analysis to determine the rate impact associated with the proposed plan.

11. Governing Board/PSC Approval of Proposed Rates – To the extent the rate analysis indicated changes to the Authority’s electric or water rates, the Authority will obtain approval from the Governing Board and PSC to implement necessary rate changes.

12. Execute Contracts – The Authority will execute construction and power purchase contracts associ ated with implementing the proposed power supply plan

## IMPLEMENTATION PLAN

R:\005141\05-01414-10101\8-26-08 PS Eval Report.doc 

### R. W. Beck 8-3 Graph 8-1 Proposed Implementation Plan

Resolve Comments on Power Supply Evaluation Study

Integrate Power Supply

Alternatives With RFP Proposals

Modify Plan Discussions

With

PREPA

Formal

Board/PSC Approval Receive PSC

Concurrence

Refine

Details

of Plan

Formal

Board/PSC Approval

Financing

Plan/

Contracts

Rate Analysis

Formal
Board/PSC Approval

Approve

Construction

and/or

Contracts NO

YES YES NO YES NO Virgin Islands Water and Power Authority Power Supply Evaluation

Receive Formal Governing Board Approval

### Table No. 1

Ln. Rated In Service

No. Unit No. Technolo gy Fuel T yp e Ca p acit y Date

(a) (b) (c) (d) (e) (f)



### 1 7 (St. John) 

### Reciprocating Engine Generator No. 2 Oil 2.5 1985

2 11 Fired Boiler/STG [1] 

### No. 6 Oil 18.5 1968

3 12 Simple Cycle CTG No. 2 Oil 12.5 1970

4 14 Simple Cycle CTG No. 2 Oil 12.5 1972

5 13 Fired Boiler/STG [1] 

### No. 6 Oil 36.9 1973

6 15 Combined Cycle CTG/HRSG [1] 

### No. 2 Oil 20.9 [2] 

### 1981

7 18 Combined Cycle CTG/HRSG [1] 

### No. 2 Oil 23.5 [2] 

### 1993

8 22 Simple Cycle CTG No. 2 Oil 24 2001

9 23 Simple Cycle CTG No. 2 Oil 39.5 2004

10 Total 190.8

Ln. Rated

No. Unit No. Technolo gy Fuel T yp e Ca p acit y In Service

11 10 Fired Boiler/STG [3] 

### No. 6 Oil 10 1967

12 11 Fired Boiler/STG [3] 

### No. 6 Oil 19.1 1970

13 16 Combined Cycle CTG/HRSG [3] 

### No. 2 Oil 20.9 [2] 

### 1981

14 17 Combined Cycle CTG/HRSG [3] 

### No. 2 Oil 21.9 [2] 

### 1988

15 19 Simple Cycle CTG No. 2 Oil 22.5 1994

16 20 Simple Cycle CTG No. 2 Oil 22.5 1994

17 Total 116.9 VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation

Summary of Existing Oil-Fueled Production Facilities

[1] Fired boilers and HRSGs deliver steam to steam headers to supply STGs No. 11 and No. 12 and four MED water
production units.

[2] Capacity shows CTG output only.

[3] Fired boilers and HRSGs deliver steam to steam headers to supply STGs No. 10 and No. 11 and four MED water
production units. 

### St. Thomas / St. John - Randolph E. Harley Generating Station

St. Croix - Estate Richmond Generating Station

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/ 31/2008Table No. 2VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply EvaluationSummary of Existing Water Production Facilities [1]CommercialPlanned DesignLow Pressure SteamHigh Pressure SteamLine In Service RetirementCapabilityCapability [2] Requirements [3] Requirements [4]No. Location Status Date Date (MGD) (MGD) (lb/hr) (lb/hr)(a) (b) (c) (d) (e) (f) (g) (h) (i)ISLAND OF ST. THOMASSt. Thomas1Unit No. 1 Krum Bay In Service May 1981 Apr 20111.25 1.25 45,000 1,0002Unit No. 2 Krum Bay In Service Aug 1981 Jul 20111.25 1.25 45,000 1,0003Unit No. 6 Krum Bay In Service Dec 1983 Nov 20130.55 0.36 22,500 8404Unit No. 8 Krum Bay In Service Feb 1992 Jan 20221.401.4050,0001,0505Total 4.454.26162,5003,890ISLAND OF ST. CROIXSt. Croix6Unit No. 3 Richmond In Service Dec 1981 Nov 20111.25 1.25 45,000 1,0007Unit No. 4 Richmond In Service Jul 1983 Jun 20130.55 0.55 22,500 8408Unit No. 5 Richmond In Service Sep 1983 Aug 20130.55 0.55 22,500 8409Unit No. 9 Richmond In Service Jun 1993 May 20231.301.3045,0001,00010Total 3.653.65135,0003,680ISLAND OF ST. JOHNSt. John11Unit No. 7 Cruz Bay In Service Jul 1990 Jun 20200.150.150012TOTAL SYSTEM(MGD)8.258.062975007570[1]Based on informationprovided bythe Authority.[2]As of June,2007.[3]26psig.[4]150psig.FaciltiyIDE Unit No.R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xlsTable No. 3

Ln. No. Description 2005 2006 2007

(a) (b) (c) (d) Island of St. Thomas - Randolph E. Harle y

1 Steam Unit No. 11 $165,867 $239,091 $230,933

2 Steam Unit No. 13 242,697 292,829 165,997

3 Total Steam 408,564 531,920 396,931

4 Combustion Turbine Unit No. 12 27,987 141,800 79,088

5 Combustion Turbine Unit No. 14 274,693 52,920 33,021

6 Combustion Turbine Unit No. 15 167,177 418,103 123,322

7 Combustion Turbine Unit No. 18 39,409 181,839 128,752

8 Combustion Turbine Unit No. 22 30,872 46,952 63,343

9 Total CT 540,139 841,612 427,526

10 Waste Heat Boiler No. 21 (23) 46,599 20,566 82,778

11 Total Island of St. Thoma s 995,302 1,394,098 907,235

Island of St. Joh n

12 Diesel Unit No. 7J 11,689 12,078 17,266

13 Total Island of St. Joh n 11,689 12,078 17,266

14 Total Islands of St. Thomas & St. Joh n 1,006,990 1,406,176 924,501

Island of St. Croix - Estate Richmond Generating Statio n

15 Steam Unit No. 10 230,356 26,980 1,036,235

16 Steam Unit No. 11 233,453 431,948 407,652

17 Total Steam 463,809 458,928 1,443,886

18 Combustion Turbine Unit No. 16 171,115 172,754 126,606

19 Combustion Turbine Unit No. 17 112,995 119,411 1,411,457

20 Combustion Turbine Unit No. 19 178,230 126,101 164,766

21 Combustion Turbine Unit No. 20 180,604

22 Total CT 642,944 418,267 1,702,830

23 Waste Heat Boiler No. 21 79,084 81,841 52,843

24 Total Island of St. Croi x 1,185,836 959,036 3,199,559

Other Production Maintenance

25 Miscellaneous Steam Units 6,880,055 7,293,135 6,165,723

26 Miscellaneous CT's 6,456

27 Total Other Production Maintenanc e 6,886,511 7,293,135 6,165,723

28 TOTAL COMBINED ISLAND S $9,079,337 $9,658,348 $10,289,783

TOTAL COMBINED ISLANDS by Typ e

Stea m

29 Island of St. Thomas 408,564 531,920 396,931

30 Island of St. Croix 463,809 458,928 1,443,886

31 Miscellaneous Steam 6,880,055 7,293,135 6,165,723

Waste Heat Boiler

32 Island of St. Thomas 46,599 20,566 82,778

33 Island of St. Croix 79,084 81,841 52,843

34 Total Steam 7,878,110 8,386,390 8,142,161

Combustion Turbin e

35 Island of St. Thomas 540,139 841,612 427,526

36 Island of St. Croix 642,944 418,267 1,702,830

37 Miscellaneous CT 6,456 0 0

38 Total CT 1,189,538 1,259,879 2,130,356

39 Diesel - Island of St. Joh n 11,689 12,078 17,266

40 TOTAL COMBINED ISLAND S $9,079,337 $9,658,348 $10,289,783

Total Combined System Productio n

41 Generation (MWh) 920,814 926,502 932,551

42 System Cost ($/MWh) 9.86 10.42 11.03

Steam Power Generation

43 St Thomas Units 11 &13 $408,564 $531,920 $396,931

44 St Thomas WHB# 21 $46,599 $20,566 $82,778

45 St Croix #s 10 & 11 $463,809 $458,928 $1,443,886

46 St Croix WHB #21 $79,084 $81,841 $52,843

47 Miscellaneous Steam $6,880,055 $7,293,135 $6,165,723

48 Total Steam O&M Cost $7,878,110 $8,386,390 $8,142,161

49 Average Steam O&M Cost ($) 2005-2007 $8,135,554

CT Power Generation

50 St Thomas #s 12, 14, 15, 18, 22, $540,139 $841,612 $427,526

51 St Croix #s 16, 17, 19, 20 $642,944 $418,267 $1,702,830

52 Miscellaneous CT $6,456 $0 $0

53 Total CT O&M Cos t $1,189,538 $1,259,879 $2,130,356

54 Average CT O&M Cost ($) 2005-2007 $1,526,591

* Detail data provided by the Authority. VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation Schedule of Historical Maintenance Expense *

Fiscal Year Ended June 30VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply EvaluationCapital Improvement Schedule for MED Units($000)Table No. 4Page 1 of 2Ln. NoDescription2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024St. Croix MED Capital Costs1Unit No. 3$0$0 $1,232 $0 $0 $1,319 $0 $0 $1,412 $0 $0 $1,512 $02Unit No. 401,204 0 0 1,289 0 0 1,381 0 0 1,478 0 03Unit No. 501,204 0 0 1,289 0 0 1,381 0 0 1,478 0 04Unit No. 9 1,177 0 0 1,260 0 0 1,349 0 0 1,445 0 0 1,5475Total St. Croix ($)$1,177 $2,409 $1,232 $1,260 $2,579 $1,319 $1,349 $2,761 $1,412 $1,445 $2,956 $1,512 $1,547St. Thomas MED Capital Costs6Unit No. 1 $1,177 $0 $0 $1,260 $0 $0 $1,349 $0 $0 $1,445 $0 $0 $1,5477Unit No. 2 1,177 0 0 1,260 0 0 1,349 0 0 1,445 0 0 1,5478Unit No. 601,204 0 0 1,289 0 0 1,381 0 0 1,478 0 09Unit No. 800 1,232 0 0 1,319 0 0 1,412 0 0 1,512 010Total St. Thomas ($)$2,355 $1,204 $1,232 $2,521 $1,289 $1,319 $2,699 $1,381 $1,412 $2,889 $1,478 $1,512 $3,09311Total System Cost ($) 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640[1] The Overhaul cost per MED unit in 2008 dollars is approximately $1,075,000.[2] The $1,075,000 cost estimate provided by VIWAPA.[3] The Overhaul cost per MED unit has been escalated at inflation (2.3%) annually.[4] The O&M costs are assumed to continue at the current level.R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/31/2008VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply EvaluationCapital Improvement Schedule for MED Units($000)Table No. 4Page 2 of 2Ln. NoDescriptionSt. Croix MED Capital Costs1Unit No. 32Unit No. 43Unit No. 54Unit No. 95Total St. Croix ($)St. Thomas MED Capital Costs6Unit No. 17Unit No. 28Unit No. 69Unit No. 810Total St. Thomas ($)11Total System Cost ($)2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036$0 $1,619 $0 $0 $1,733 $0 $0 $1,855 $0 $0 $1,986 $01,582 0 0 1,694 0 0 1,814 0 0 1,942 0 01,582 0 0 1,694 0 0 1,814 0 0 1,942 0 00 0 1,656 0 0 1,773 0 0 1,898 0 0 2,032$3,165 $1,619 $1,656 $3,388 $1,733 $1,773 $3,627 $1,855 $1,898 $3,883 $1,986 $2,032$0 $0 $1,656 $0 $0 $1,773 $0 $0 $1,898 $0 $0 $2,0320 0 1,656 0 0 1,773 0 0 1,898 0 0 2,0321,582 0 0 1,694 0 0 1,814 0 0 1,942 0 00 1,619 0 0 1,733 0 0 1,855 0 0 1,986 0$1,582 $1,619 $3,312 $1,694 $1,733 $3,546 $1,814 $1,855 $3,796 $1,942 $1,986 $4,0644,747 3,237 4,968 5,082 3,466 5,319 5,441 3,711 5,694 5,825 3,973 6,096[1] The Overhaul cost per MED unit in 2008 dollars is approximately $1,075,000.[2] The $1,075,000 cost estimate provided by VIWAPA.[3] The Overhaul cost per MED unit has been escalated at inflation (2.3%) annually.[4] The O&M costs are assumed to continue at the current level.R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/31/2008Table No. 5

Line

No. Description 2003 2004 2005 2006 2007

Production [1]

1 Fuel $74,722,526 $78,467,819 $107,827,279 $150,489,486 $165,074,275

2 O&M 29,374,405 17,238,219 14,525,629 16,400,691 13,339,130 3 Allocation to Water System (6,022,637) (5,893,247) (8,879,257) (16,285,397) (14,294,281)

Subtotal Fuel and

4 Allocation to Water 68,699,889 72,574,572 98,948,022 134,204,089 150,779,994

5 Electric System Fuel Cost [2] 136,249,523 150,779,994

Based on the above, it appears that the allocation to the Water System is comprised of fuel cost which is included in the

Water Production O&M Cost shown below from data provided by the Authority.

6 Total Water Production Expenses $11,103,855 $11,597,540 $14,085,280 $19,909,213 $19,708,554

7 Non-Fuel O&M Water System $5,081,218 $5,704,293 $5,206,023 $3,623,816 $5,414,273

Water Production

Desalination Plant Gallons
8 St. Thomas Desalination Plant 964,370 953,833 979,321 970,851 1,008,528
9 St. Croix Desalination Plant 1,089,116 1,078,400 1,070,431 1,026,911 1,012,800

10 Total Desalination Plant Gallons 2,053,486 2,032,233 2,049,752 1,997,762 2,021,328 11 Cost per Kgal 2.47 2.81 2.54 1.81 2.68

12 Total Cost per Kgal 5.41 5.71 6.87 9.97 9.75

Five Year Average for 2003-2007 13 Average Non-Fuel O&M Water System ($) $5,005,925
14 Average Water Production (Gallons) 2,030,912

[1] Source: Electric System Operating Expenses (From Five Year Comparative Summary of Operations (Unaudited), page 40.
[2] Source: Financial Statements and Supplemental Schedule, Years Ended June 30, 2007 and 2006 (Page 15). VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation

Water Production Cost Allocation

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/ 31/2008Table No.6Page 1 of 2Ln. No.Description2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024St. Croix Fuel Requirements1MMBtu4,635,5494,653,8084,667,4294,684,6854,704,1834,719,5074,736,6114,753,7214,771,7174,785,9724,805,0194,825,5294,843,1772Petcoke ($/MMBtu) 1.68 1.70 1.71 1.73 1.77 1.81 1.85 1.89 1.93 1.98 2.05 2.11 2.173Subtotal Petcoke ($) 7,784,247 7,896,754 8,002,813 8,116,523 8,324,943 8,531,021 8,745,396 8,965,052 9,191,814 9,499,543 9,827,290 10,169,267 10,516,739Petcoke Transportation Cost4Transportation Cost ($/ton)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.005Transportation Cost ($/MMBtu) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.006Subtotal Transportation ($)00000000000007Total St. Croix Petcoke ($)7,784,247 7,896,754 8,002,813 8,116,523 8,324,943 8,531,021 8,745,396 8,965,052 9,191,814 9,499,543 9,827,290 10,169,267 10,516,739St. Thomas Fuel Requirements8MMBtu8,817,1418,921,1289,009,0639,105,3179,208,6839,306,8779,415,0939,523,3319,626,1639,732,1719,833,4119,936,61910,037,0539Petcoke ($/MMBtu) 1.68 1.70 1.71 1.73 1.77 1.81 1.85 1.89 1.93 1.98 2.05 2.11 2.1710Subtotal Petcoke ($) 14,806,186 15,137,702 15,447,013 15,775,556 16,296,506 16,823,190 17,383,465 17,960,069 18,542,988 19,317,118 20,111,424 20,940,321 21,795,005Methanol Transportation Cost11Transportation Cost ($/ton)4.48 4.58 4.69 4.80 4.91 5.02 5.14 5.25 5.38 5.50 5.63 5.76 5.8912Transportation Cost ($/MMBtu) 0.16 0.16 0.16 0.17 0.17 0.18 0.18 0.18 0.19 0.19 0.20 0.20 0.2113Subtotal Transportation ($) 1,383,979 1,432,508 1,479,900 1,530,113 1,583,076 1,636,755 1,693,870 1,752,750 1,812,424 1,874,529 1,937,591 2,002,960 2,069,73814Total St. Thomas ($)16,190,165 16,570,210 16,926,913 17,305,669 17,879,582 18,459,946 19,077,335 19,712,819 20,355,413 21,191,646 22,049,015 22,943,281 23,864,743CC at Methanol Plant15Plant Rating (MW) 40 40 40 40 40 40 40 40 40 40 40 40 4016MWh Generated (MWh) 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,84017Annual Capital Carrying Cost ($) 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,41718Fixed Annual O&M Cost ($) 4,369,611 4,470,112 4,572,925 4,678,102 4,785,698 4,895,769 5,008,372 5,123,565 5,241,407 5,361,959 5,485,284 5,611,445 5,740,50919CO2 Allowance Cost ($) 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,85020Variable Annual O&M ($) 834,260 853,448 873,077 893,158 913,700 934,715 956,214 978,207 1,000,705 1,023,722 1,047,267 1,071,354 1,095,99621Average Heat Rate (MMBtu/MWh) 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.722Annual Fuel Consumed (MMBtu) 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,3682,293,368 2,293,36823Total Annual Fuel Operating Cost ($) 3,851,139 3,891,472 3,932,228 3,973,410 4,058,549 4,145,512 4,234,338 4,325,067 4,417,741 4,552,043 4,690,427 4,833,018 4,979,94524Total Annual Operating Cost ($) 18,662,276 18,822,299 18,985,496 19,151,936 19,365,214 19,583,263 19,806,191 20,034,106 20,267,120 20,544,990 20,830,245 21,123,085 21,423,71625Total Annual Operating Cost ($/MWh)62.66 63.20 63.74 64.30 65.02 65.75 66.50 67.26 68.05 68.98 69.94 70.92 71.93Methanol Plant26Annual Capital Carrying Cost ($) 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,02027Fixed Annual O&M Cost ($) 14,005,163 14,327,282 14,656,810 14,993,916 15,338,776 15,691,568 16,052,474 16,421,681 16,799,380 17,185,766 17,581,038 17,985,402 18,399,06628Variable Annual O&M ($)000000000000029Total Annual OperatingCost ($)96,584,184 96,906,303 97,235,830 97,572,937 97,917,797 98,270,589 98,631,495 99,000,702 99,378,400 99,764,786 100,160,059 100,564,423 100,978,08730Total Cost ($) 139,220,873 140,195,565 141,151,052 142,147,066 143,487,536 144,844,819 146,260,417 147,712,678 149,192,747 151,000,965 152,866,609 154,800,056 156,783,28531Methanol Fuel Cost ($/MMBtu) 10.35 10.33 10.32 10.31 10.31 10.33 10.34 10.35 10.36 10.40 10.44 10.49 10.54VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply EvaluationMethanol Fuel CostR:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/31/2008Table No.6Page 2 of 2Ln. No.DescriptionSt. Croix Fuel Requirements1MMBtu2Petcoke ($/MMBtu)3Subtotal Petcoke ($)Petcoke Transportation Cost4Transportation Cost ($/ton)5Transportation Cost ($/MMBtu)6Subtotal Transportation ($)7Total St. Croix Petcoke ($)St. Thomas Fuel Requirements8MMBtu9Petcoke ($/MMBtu)10Subtotal Petcoke ($)Methanol Transportation Cost11Transportation Cost ($/ton)12Transportation Cost ($/MMBtu)13Subtotal Transportation ($)14Total St. Thomas ($)CC at Methanol Plant15Plant Rating (MW)16MWh Generated (MWh)17Annual Capital Carrying Cost ($)18Fixed Annual O&M Cost ($)19CO2 Allowance Cost ($)20Variable Annual O&M ($)21Average Heat Rate (MMBtu/MWh)22Annual Fuel Consumed (MMBtu)23Total Annual Fuel Operating Cost ($)24Total Annual Operating Cost ($)25Total Annual Operating Cost ($/MWh)Methanol Plant26Annual Capital Carrying Cost ($)27Fixed Annual O&M Cost ($)28Variable Annual O&M ($)29Total Annual OperatingCost ($)30Total Cost ($)31Methanol Fuel Cost ($/MMBtu)2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 20364,860,6654,883,3434,901,0484,901,0484,901,0484,901,0484,901,0484,901,0484,901,0484,901,0484,901,0484,901,0482.24 2.31 2.38 2.46 2.53 2.61 2.69 2.78 2.87 2.96 3.05 3.1410,875,582 11,269,739 11,666,091 12,032,756 12,410,946 12,801,023 13,203,360 13,618,342 14,046,367 14,487,845 14,943,198 15,412,8640.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.000.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0000000000000010,875,582 11,269,739 11,666,091 12,032,756 12,410,946 12,801,023 13,203,360 13,618,342 14,046,367 14,487,845 14,943,198 15,412,86410,154,21110,262,25010,358,80410,358,80410,358,80410,358,80410,358,80410,358,80410,358,80410,358,80410,358,80410,358,8042.24 2.31 2.38 2.46 2.53 2.61 2.69 2.78 2.87 2.96 3.05 3.1422,719,721 23,683,133 24,657,327 25,432,308 26,231,646 27,056,108 27,906,483 28,783,585 29,688,254 30,621,357 31,583,787 32,576,4676.02 6.16 6.30 6.45 6.60 6.75 6.90 7.06 7.22 7.39 7.56 7.730.21 0.22 0.22 0.23 0.23 0.24 0.24 0.25 0.25 0.26 0.26 0.272,142,057 2,214,640 2,286,893 2,339,491 2,393,299 2,448,345 2,504,657 2,562,264 2,621,196 2,681,484 2,743,158 2,806,25124,861,778 25,897,773 26,944,219 27,771,799 28,624,946 29,504,453 30,411,140 31,345,849 32,309,450 33,302,841 34,326,945 35,382,71840 40 40 40 40 40 40 40 40 40 40 40297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,8406,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,4175,872,540 6,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,206,207 7,371,949 7,541,5042,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,8501,121,203 1,146,991 1,173,372 1,200,360 1,227,968 1,256,211 1,285,104 1,314,661 1,344,898 1,375,831 1,407,475 1,439,8477.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.72,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,368 2,293,3685,131,337 5,292,615 5,458,963 5,630,538 5,807,506 5,990,036 6,178,303 6,372,488 6,572,775 6,779,358 6,992,433 7,212,20621,732,348 22,054,482 22,385,385 22,725,301 23,074,482 23,433,185 23,801,678 24,180,232 24,569,131 24,968,663 25,379,125 25,800,82472.97 74.05 75.16 76.30 77.47 78.68 79.91 81.19 82.49 83.83 85.21 86.6382,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,02018,822,245 19,255,157 19,698,025 20,151,080 20,614,555 21,088,689 21,573,729 22,069,925 22,577,533 23,096,816 23,628,043 24,171,488000000000000101,401,265 101,834,177 102,277,046 102,730,100 103,193,575 103,667,710 104,152,750 104,648,945 105,156,554 105,675,837 106,207,064 106,750,509158,870,974 161,056,171 163,272,741 165,259,957 167,303,949 169,406,371 171,568,927 173,793,368 176,081,501 178,435,185 180,856,332 183,346,91410.58 10.63 10.70 10.83 10.96 11.10 11.24 11.39 11.54 11.69 11.85 12.01VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply EvaluationMethanol Fuel CostR:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/31/2008VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation

Projected Fuel Prices ($/MMBtu) Table No. 7

Line Fuel Oil [1] Solid Fuel Natural Gas Methanol[5]

N o. Yea r N o. 2 N o. 6 Petcoke [2] Coal [3] LNG [4] (a) (b) (c) (e) (f) (g) (h)

1 2007 13.13 11.40 1.43 2.90 9.15

2 2008 16.55 15.36 1.50 3.04 12.10

3 2009 15.92 14.77 1.57 3.18 11.88

4 2010 16.42 15.23 1.64 3.33 11.63

5 2011 16.34 15.16 1.66 3.36 11.15

6 2012 16.26 15.09 1.68 3.40 11.09 10.35

7 2013 16.18 15.02 1.70 3.43 11.02 10.33

8 2014 16.10 14.94 1.71 3.47 11.28 10.32

9 2015 16.03 14.87 1.73 3.51 11.38 10.31

10 2016 16.53 15.34 1.77 3.58 11.77 10.31

11 2017 17.05 15.82 1.81 3.66 12.37 10.33

12 2018 17.58 16.32 1.85 3.74 12.44 10.34

13 2019 18.13 16.83 1.89 3.82 12.55 10.35

14 2020 18.70 17.36 1.93 3.90 12.96 10.36

15 2021 19.38 17.99 1.98 4.02 13.21 10.40

16 2022 20.09 18.64 2.05 4.14 13.73 10.44

17 2023 20.82 19.32 2.11 4.27 14.27 10.49

18 2024 21.57 20.02 2.17 4.40 14.88 10.54

19 2025 22.35 20.74 2.24 4.53 15.16 10.58

20 2026 23.05 21.40 2.31 4.67 15.51 10.63

21 2027 23.78 22.07 2.38 4.82 16.01 10.70

22 2028 24.52 22.76 2.46 4.97 16.63 10.83

23 2029 25.29 23.47 2.53 5.13 17.17 10.96

24 2030 26.09 24.21 2.61 5.29 17.60 11.10

25 2031 26.90 24.97 2.69 5.45 18.15 11.24

26 2032 27.75 25.75 2.78 5.62 18.71 11.39

27 2033 28.62 26.56 2.87 5.80 19.29 11.54

28 2034 29.52 27.39 2.96 5.98 19.89 11.69

29 2035 30.44 28.25 3.05 6.17 20.52 11.85

30 2036 31.40 29.14 3.14 6.37 21.16 12.01

[1] Fuel Oil Prices for 2007 based on delivered fuel costs for the Authority for the period june through October 2007.
Fuel Oil Prices for 2008-2009 based on forward prices for crude oil plus $3.75/mmBtu, as supplied by the Authority's

Fuel Consultant. Future prices based on 2009 forward price escalated at rates based on AEO 2007 for

Crude Oil. Inflation assumed to be 2.3% per year. Escalation from 2031-2036 based on the combined

annual average of the last 5 years of growth for Crude Oil.

[2] Pet-coke price is based on supply from Hovensa's refinery to a power plant operating at the St. Croix south shore site.
[3] Colombian Coal; 11,600 Btu/lb; 0.7% sulfur; Recent price for June 2007 is $2.85-$2.90 based on note from Mr. Zakaria

of Rennaissance. Escalation for 2007-2030 is based on AEO 2007 Table A-15 Coal Supply Disposition and Prices.

Escalation 2030-2036 Based on AEO 2007 Table A-15 Coal Supply Dispostion and Prices forecast for 2025-2030.

[4] Data from Page 7 of Letter Report to Glenn Rothgeb from Ivan Clark dated July 10, 2007 and titled

"Report - Feasibility of the Conversion of Fuel oil to Natural Gas Generation".

[5] Refer to Table No. 5 for the calculation of projected price of methanol.

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/ 31/2008

### Table No. 8

Approval Responsible

A g enc y Timing

“No Hazard” Determination Federal Aviation
Administration (FAA)

Obstruction Evaluation
Services (OES) To be obtained prior to start

of construction. Required to demonstrate no hazards to
aviation if exhaust stack or buildings exceed
certain height thresholds

Hazardous Waste Identification

Number United States

Environmental
Protection Agency
(USEPA) To be obtained prior to start
of operation. Required if the Project is to use, manage, and
dispose material categorized as hazardous
waste. Disposal must follow manifest
tracking system.

Oil Spill Prevention Control and

Countermeasure Plan USEPA To be prepared prior to start
of operation Required as per 40 CAR 112, Oil Pollution
Prevention regulations, if the Project stores
more than 1,320 gallons at the site (including
electrical equipment, transformer oil). Plan
must be prepared before start of operation.

Clean Water Act Section 404

Wetland Permit U. S. Army Corps of
Engineers (USCOE) To be obtained prior to start

of construction. Required if discharge of dredge or fill

material into wetlands and waters of the US
is necessary for project construction. Also
triggered by other actions.

Section 10 Permit USCOE To be obtained prior to start

of construction Required for construction of facilities in
navigable waters and shoreline facilities

Threatened and Endangered
(T&E) Species Determination US Fish and Wildlife

Service Determination required

before start of construction May be required to assess impact of project i f
a federal permit, such as a Section 404, is
required

Air Quality Construction Permit USEPA To be obtained prior to start

of construction. Required to construct an air emissions source
if permitting falls under federal Prevention of
Significant Deterioration (PSD) rules. Sets
forth air emission limits, monitoring, and
reporting requirements.

Title V Permit to Operate Virgin Islands
Department of Planning

and Natural Resources To be applied for within 12

months after start of
operation Will incorporate all air quality permit
requirements into one document

Coastal Zone Management
Approval VIDPNR Required prior to start of

construction Approval requires the preparation of an

Environmental Assessment for all facilities in

the coastal zone

Territorial Pollutant Discharge
Elimination System (TPDES)
Permit for Discharges of Storm

water Associated with

Construction Activities VIDPNR To be obtained prior to start

of construction. Required for storm water management during

construction.

TPDES Permit for Discharge of

Process Wastewater VIDPNR To be obtained prior to start
of operation. Required for wastewater discharges. May
include storm water discharges.

TPDES General Permit for
storm water Discharges

Associated with Industrial

Activities VIDPNR To be obtained prior to start
of operation. May be a general permit. Could also be
included in TPDES permit for wastewater
discharge.

Zoning/Land Use Approvals Local Municipality To be obtained as necessary
in the development process May be required depending on location TERRITORIAL / LOCAL 

### Listing of Key Permits and Approvals VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation

CommentsTable No. 9

COMBUSTION TECHNOLOGY CASES

Ma j or Retirements

Case 1-1 Existin g Arran g emen t Base N one N one

Case 1-2 Same as Case 1-1above except

usin g Methanol fue l Base Methanol Plant (St Croix) None

Case 1-3 Same as Case 1-1above except

usin g LNG fue l Base LNG Facilities (St. Thomas

and St. Croix ) None

Case 1-4 Add CFB Units Base

20 MW CFB -2012 ( St. Units 12

, 14 ( St.

20 MW CFB -2012 ( St. Croix ) N one ( St. Croix )

Case 1-5 Add CFB, add RO Units, retire

existin g Steam Plants

, retire Base

Units 40 MW CFB, 40 MW CT, RO

Plant - 2012

, - ( St. Thomas ) Units 11, 12, 13, 14,

MED Plant - ( St. 20 MW CFB, RO Plant -2012
( St. Croix ) Units 10, 11, MED

Plant - ( St. Croix )

Case 1-6 Add electric interconnection, Base 20 MW CFB 2012 (St. Croix) Units 12, 14 (St.

CFB Units HVDC Interconnect - (St.

Thomas to St. Croix )

Case 1-7 Add electric interconnection,
add CFB, add RO Units, retire

existin g Steam Plants

, retire Base 2 x 40 MW CFB, RO Plant –
2012 (St. Croix) Units 11, 12, 13, 14,
MED Plant - (St.

Thomas ) HVDC Interconnect - (St.

Thomas to St. Croix ) Units 10, 11, MED

Plant - ( St. Croix )

Case 1-8 Same as Case 1-1 above except add RO units and retire existing

MED units Base None MED Plant

Case 1-9 Same as Case 1-3 above except add RO units and retire existing

MED units Base None MED Plant

Case 2-1 Existing Arrangement High

Re q uiremen t
40 MW CT - ( St. Thomas ) N one

Case 2-2 Same as Case 2-1 above except

usin g Methanol fue l High

Re q uiremen t Methanol Plant (St Croix) None

Case 2-3 Same as Case 2-1 above except

usin g LNG fue l High

Re q uiremen t LNG Facilities (St. Thomas

and St. Croix ) None

Case 2-4 Add CFB Units High

Re q uiremen t
30 MW CFB - 2012 ( St. Units 12

, 14 ( St.

20 MW CFB - 2012 ( St. Coix ) N one ( St. Croix )

Case 2-5 Add CFB Units, add RO Units,

retire existin g Steam Plants

, High

Re q uiremen t Units 40 MW CFB, 40 MW CT, RO
Plant - 2012, - (St. Thomas) Units 11, 12, 13, 14,
MED Plant - (St.

20 MW CFB, RO Plant -2012
( St. Croix ) Units 10, 11, MED

Plant - ( St. Croix )

Case 2-6 Add electric interconnection

, Hi g h 20 MW CFB 2012 ( St. Croix ) CFB Units HVDC Interconnect - (St.
Thomas to St. Croix)

Case 2-7 Add electric interconnection,
add CFB, add RO Units, retire existing Steam Plants, retire High Requirement 2 x 40 MW CFB, RO Plant -
2012, 1 x 40 MW CFB – 2015
(St. Croix) Units 11, 12, 13, 14,
MED Plant - (St.
Thomas)
HVDC Interconnect - (St.

Thomas to St. Croix ) Units 10, 11, MED

Plant - ( St. Croix )

Case 1-1W Same as Case 1-1, but with

addition of Wind Resource Base Same as Case 1-1 plus 10 MW

Wind Resource at St. Croix - Same as Case 1-1

Case 1-3W Same as Case 1-3, but with

addition of Wind Resource Base Same as Case 1-3 plus 10 MW

Wind Resource at St. Croix - Same as Case 1-3

Case 1-4W Same as Case 1-4, but with

addition of Wind Resource Base Same as Case 1-4 plus 10 MW

Wind Resource at St. Croix - Same as Case 1-4

Case 1-5W Same as Case 1-5, but with

addition of Wind Resource Base Same as Case 1-5 plus 10 MW

Wind Resource at St. Croix - Same as Case 1-5

Case 2-1W Same as Case 2-1, but with

addition of Wind Resource High Requirement Same as Case 2-1 plus 10 MW

Wind Resource at St. Croix - Same as Case 2-1

Case 2-3W Same as Case 2-3, but with

addition of Wind Resource High Requirement Same as Case 2-3 plus 10 MW

Wind Resource at St. Croix - Same as Case 2-3

Case 2-4W Same as Case 2-4, but with

addition of Wind Resource High Requirement Same as Case 2-4 plus 10 MW

Wind Resource at St. Croix - Same as Case 2-4

Case 2-5W Same as Case 2-5, but with

addition of Wind Resource High Requirement Same as Case 2-5 plus 10 MW

Wind Resource at St. Croix - Same as Case 2-5 COMBUSTION TECHNOLOGY CASES WITH WIND POWER Units 12, 14 (St.
Thomas) VIRGIN ISLANDS WATER AND POWER AUTHORITY Power Supply Evaluation - Case Description

Case No. Case Description Load Forecast Major AdditionsVirgin Islands Water and Power Authority Power Supply Evaluation

Results Summary Table No. 10

Results of Cases Without CO2 Allowance Costs

Total NPV Costs [1]

2007-2027 NPV Cost Diff vs. Existing

Arrangement Levelized

Gross Electric Costs [2] Levelized Costs Diff vs. Existing

Arrangement Capital Investment (2008 Dollars) $(000) $(000) $/MWh $/MWh $(000)

Base Load (a) (b) (c) (d) (e)

1-1 2,723,496 0 247.66 0.00 46,225
1-1W 2,724,105 609 247.72 0.06 76,225 1-2 1,948,039 (775,457) 174.23 (73.43) 946,225 1-3 2,245,543 (477,953) 202.40 (45.26) 196,225 1-3W 2,252,782 (470,714) 203.09 (44.57) 226,225 1-4 2,632,980 (90,516) 239.09 (8.57) 401,505 1-4W 2,645,511 (77,985) 240.27 (7.38) 431,505 1-5 2,641,455 (82,041) 230.82 (16.84) 566,176 1-5W 2,611,160 (112,336) 228.04 (19.62) 596,176
1-6 2,819,989 96,493 256.79 9.14 573,865 1-7 2,482,575 (240,922) 216.25 (31.41) 887,396 1-8 2,730,622 7,126 238.99 (8.66) 46,676 1-9 2,267,193 (456,304) 196.50 (51.16) 196,676

High Load

2-1 3,189,954 0 248.01 0.00 90,725 2-1W 3,174,963 (14,992) 246.80 (1.21) 120,725 2-2 2,327,212 (862,742) 178.58 (69.43) 990,725 2-3 2,605,599 (584,355) 200.98 (47.02) 240,725 2-3W 2,602,215 (587,739) 200.71 (47.30) 270,725 2-4 2,977,661 (212,293) 230.92 (17.08) 513,105 2-4W 2,977,347 (212,607) 230.90 (17.11) 543,105 2-5 2,850,172 (339,782) 213.44 (34.57) 911,576 2-5W 2,809,856 (380,098) 210.28 (37.73) 941,576 2-6 3,163,392 (26,563) 245.87 (2.14) 640,965 2-7 2,763,717 (426,237) 205.39 (42.61) 1,101,916

Results of Cases With CO2 Allowance Costs

Total NPV Costs [1]

2007-2027 NPV Cost Diff vs. Existing

Arrangement Levelized

Gross Electric Costs [2] Levelized Costs Diff vs. Existing

Arrangement Capital Investment (2008 Dollars) $(000) $(000) $/MWh $/MWh $(000)

Base Load (a) (b) (c) (d) (e)

1-1 2,941,127 0 268.27 0.00 46,225 1-1W 2,938,944 (2,183) 268.06 (0.21) 76,225 1-2 2,082,585 (858,542) 186.97 (81.29) 946,225 1-3 2,406,996 (534,131) 217.69 (50.58) 196,225 1-3W 2,412,144 (528,983) 218.18 (50.09) 226,225 1-4 2,867,522 (73,605) 261.30 (6.97) 401,505 1-4W 2,876,990 (64,137) 262.19 (6.07) 431,505 1-5 2,882,216 (58,911) 252.90 (15.37) 566,176 1-5W 2,851,903 (89,224) 250.12 (18.15) 596,176
1-6 3,038,093 96,966 277.45 9.18 573,865 1-7 2,729,712 (211,415) 238.91 (29.35) 887,396 1-8 2,947,923 6,796 258.92 (9.34) 46,676 1-9 2,429,090 (512,037) 211.34 (56.92) 196,676

High Load

2-1 3,461,340 0 269.85 0.00 90,725 2-1W 3,441,811 (19,530) 268.27 (1.57) 120,725 2-2 2,507,940 (953,401) 193.12 (76.72) 990,725 2-3 2,807,365 (653,976) 217.22 (52.63) 240,725 2-3W 2,800,480 (660,861) 216.67 (53.18) 270,725 2-4 3,264,773 (196,567) 254.03 (15.82) 513,105 2-4W 3,264,441 (196,899) 254.00 (15.84) 543,105 2-5 3,169,548 (291,792) 238.44 (31.40) 911,576 2-5W 3,125,047 (336,293) 234.96 (34.89) 941,576 2-6 3,434,720 (26,621) 267.70 (2.14) 640,965 2-7 3,076,120 (385,220) 229.86 (39.99) 1,101,916

[1] Total NPV costs include both Electric Power Supply Costs and Water Production Related Costs.

[2] Levelized Gross Electric Costs include total Electric Power Supply Costs, including fuel and power supply costs related to w ater, but excluding non-fuel O&M

and capital costs related to water

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls; 8/25/2008Virgin Islands Water and Power AuthorityPower Supply EvaluationProjected Fuel CostGraph No. 1R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xlsGrph 1 - Fuel Cost5/1/2008051015202530352008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036

($/MMBtu)No. 2 Fuel OilNo. 6 Fuel OilPet CokeCoalLNGMethanol[5]

### Virgin Islands Water and Power Authority
Power Supply Evaluation Projected Annual Power Supply Cost and Capital Investment Requirements 

### Graph No. 2

Base Load Forecast

Total Electric Costs with CO 2 

### Charge ($/MWh)

0 50 100 150 200 250 300 350 400

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026($/MWh)

1-1 1-1W 1-2 1-3 1-3W

1-4 1-4W 1-5 1-5W 1-6

1-7 1-8 1-9



### Base Load Forecast Capital Investment (2008 Dollars) ($000)

$431,505 $596,176 $946,225 $887,396

$573,865 $566,176

$76,225 $226,225

$196,225 $401,505

$46,225 $196,676

$46,676

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

1-1 1-1W 1-2 1-3 1-3W 1-4 1-4W 1-5 1-5W 1-6 1-7 1-8 1-9

Case($000) Existing Debt Incremental Capital Investment

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls Base with CO2 7/24/2008

### Virgin Islands Water and Power Authority
Power Supply Evaluation Projected Annual Power Supply Cost and Capital Investment Requirements 

### Graph No. 3

High Requirements Load Forecast

Total Electric Costs with CO 2 

### Charge ($/MWh)

0 50 100 150 200 250 300 350 400

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026($/MWh)

2-1 2-1W 2-2 2-3

2-3W 2-4 2-4W 2-5

2-5W 2-6 2-7



### High Requirements Load Forecast Capital Investment (2008 Dollars) ($000)

$240,725 $640,965 $941,576 $1,101,916

$911,576

$513,105

$270,725 $990,725

$120,725 $543,105

$90,725

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

2-1 2-1W 2-2 2-3 2-3W 2-4 2-4W 2-5 2-5W 2-6 2-7

Case($000) Existing Debt Incremental Capital Investment

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls High with CO2 7/24/2008

### Virgin Islands Water and Power Authority
Power Supply Evaluation Projected Annual Power Supply Cost and Capital Investment Requirements 

### Graph No. 4

Base Load Forecast

Total Electric Costs without CO 2 

### Charge ($/MWh)

0 50 100 150 200 250 300 350 400

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026($/MWh)

1-1 1-1W 1-2 1-3 1-3W

1-4 1-4W 1-5 1-5W 1-6

1-7 1-8 1-9



### Base Load Forecast Capital Investment (2008 Dollars) ($000)

$946,225

$196,225 $566,176 $573,865 $887,396

$46,225 $401,505 $596,176

$431,505
$76,225 $226,225

$46,676 $196,676

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

1-1 1-1W 1-2 1-3 1-3W 1-4 1-4W 1-5 1-5W 1-6 1-7 1-8 1-9

Case($000) Existing Debt Incremental Capital Investment

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls Base without CO2 7/24/2008

### Virgin Islands Water and Power Authority
Power Supply Evaluation Projected Annual Power Supply Cost and Capital Investment Requirements 

### Graph No. 5

High Requirements Load Forecast

Total Electric Costs without CO 2 

### Charge ($/MWh)

0 50 100 150 200 250 300 350 400

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026($/MWh)

2-1 2-1W 2-2 2-3

2-3W 2-4 2-4W 2-5

2-5W 2-6 2-7



### High Requirements Load Forecast Capital Investment (2008 Dollars) ($000)

$990,725 $941,576

$640,965 $513,105

$270,725

$240,725 $911,576 $1,101,916

$120,725 $543,105

$90,725

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

2-1 2-1W 2-2 2-3 2-3W 2-4 2-4W 2-5 2-5W 2-6 2-7

Case($000) Existing Debt Incremental Capital Investment

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls High without CO2 7/24/2008

### Virgin Islands Water and Power Authority
Power Supply Evaluation Comparison of Capital Investment and NPV Costs Graph No. 6



### Base Load Forecast with CO 2 

### Charge
NPV Costs versus Capital Investment Matrix

1-1 1-2

1-3 1-4 1-5

1-6 1-7

1-1W 1-3W 1-4W 1-5W

1-8 1-9

0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000

(1,000,000) (800,000) (600,000) (400,000) (200,000) 0 200,000

NPV Cost Diff vs. Existing Arrangement $(000)Additional Capital Investment $(000)



### High Requirements Load Forecast with CO 2 

### Charge
NPV Costs versus Capital Investment Matrix

2-1 2-2

2-3 2-4 2-5

2-6

2-1W 2-3W 2-4W 2-5W

0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000

(1,000,000) (800,000) (600,000) (400,000) (200,000) 0 200,000

NPV Cost Diff vs. Existing Arrangement $(000)Additional Capital Investment $(000)

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls With CO2 Matrices 7/24/2008

### Virgin Islands Water and Power Authority
Power Supply Evaluation Comparison of Capital Investment and NPV Costs Graph No. 7



### Base Load Forecast without CO 2 

### Charge
NPV Costs versus Capital Investment Matrix

1-1 1-2

1-3 1-4 1-5 1-7

1-1W 1-3W 1-4W 1-5W

1-8 1-9

0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000

(1,000,000) (800,000) (600,000) (400,000) (200,000) 0 200,000

NPV Cost Diff vs. Existing Arrangement $(000)Additional Capital Investment $(000)



### High Requirements Load Forecast without CO 2 

### Charge
NPV Costs versus Capital Investment Matrix

2-1 2-2

2-3 2-4 2-5

2-6

2-1W 2-3W 2-4W 2-5W

0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000

(1,000,000) (800,000) (600,000) (400,000) (200,000) 0 200,000

NPV Cost Diff vs. Existing Arrangement $(000)Additional Capital Investment $(000) 1-6

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v6.xls Without CO2 Matrices 7/24/2008

# Appendix A Individual Case Spreadsheets

### Virgin Islands Water and Power Authority
Power Supply Evaluation Appendix A

No. Case Description

1 1-1 Reference Case- Base Load, no retirements,all oil 2 1-1W Same as Case 1-1, add Wind Project

3 1-2 Same as Case 1-1 but with methanol fuel

4 1-3 Same as Case 1-1 but with LNG fuel 5 1-3W Same as Case 1-1 but with LNG fuel, add Wind Project 6 1-4 Base Load, add CFB , replace older capacity 7 1-4W Base Load, add CFB , add Wind Project, replace older capacity 8 1-5 Base Load, Replace Steam Units with CFB and RO 9 1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO 10 1-6 Base Load, Add CFB, Interconnected System 11 1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System 12 1-8 Same as Case 1-1, Replace existing MED water system with RO 13 1-9 Same as Case 1-3, Replace existing MED water system with RO 14 2-1 High Requirements Load , no retirements, all oil fuel 15 2-1W Same as Case 2-1, add Wind Project

16 2-2 Same as Case 2-1 but with methanol fuel

17 2-3 Same as Case 2-1 but with LNG fuel 18 2-3W Same as Case 2-1 but with LNG fuel, add Wind Project 19 2-4 High Requirements Load, Add CFBs, replace older capacity 20 2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity 21 2-5 High Requirements Load, Replace Steam Units with CFB and RO 22 2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO 23 2-6 High Requirements Load, add CFB, Interconnected System 24 2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\ PowerSupply Cost Summary_v5.xls ReadMe Page 1 of 25;8/1/2008; RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 21Case:1-1 Reference Case- Base Load, no retirements,all oil200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 326,138 327,273 328,440 329,731 329,651Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,538 66,916 67,373 67,886 68,765 71,819 74,759 77,823 81,234 84,870 88,422 92,586 96,800 101,222 105,644 109,153 112,423CO2 Charge ($000)3,423 4,051 4,711 5,425 6,167 6,912 7,704 8,555 9,459 10,337 11,308 12,298 13,349 14,416 14,790 15,126CC 2MWh49,873 47,522 47,458 46,613 46,510 47,241 48,068 46,513 46,600 46,953 47,985 47,714 47,426 49,305 49,137 49,337 50,104 50,868 51,435 53,581Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,489 11,006 11,240 11,502 11,190 11,654 12,203 12,961 13,389 13,834 14,992 15,574 16,299 17,268 18,252 19,013 20,410CO2 Charge ($000)592 710 837 926 1,049 1,184 1,345 1,478 1,615 1,836 1,991 2,169 2,384 2,607 2,697 2,875Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 73,907 73,852 73,840 73,604 76,257 78,866 81,735 84,590 87,629 91,241 94,861 98,633 102,757 106,873 110,679 114,832Total CO2 Charge ($000)000004,015 4,761 5,548 6,351 7,216 8,096 9,049 10,033 11,074 12,172 13,299 14,467 15,733 17,023 17,487 18,001Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-1Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 21Case:1-1 Reference Case- Base Load, no retirements,all oil200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 203,542 203,681 204,596 204,994 212,587 221,327 230,086 239,540 249,242 260,838 272,246 284,418 297,522 310,697 323,377 336,997Total Authority CO2 Charges ($000)0000011,535 13,696 16,032 18,454 20,986 23,702 26,565 29,633 32,857 36,294 39,815 43,538 47,547 51,672 53,334 55,156Total Authority Incremental Non-fuel Production Cost ($000)000000000000000000000Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 235,043 237,803 240,292 244,824 255,441 266,081 279,536 292,584 304,636 321,632 337,126 352,085 371,300 389,203 402,543 420,236Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 223,508 224,106 224,260 226,370 234,455 242,379 252,971 262,951 271,780 285,339 297,311 308,546 323,753 337,531 349,209 365,079NPV with CO2 Charge ($000)2,941,127NPV without CO2 Charge ($000)2,723,496R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-1Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 22Case:1-1W Same as Case 1-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh440,702 424,991 427,346 430,844434,820 429,190 443,099 453,055 435,697 453,067 443,673 456,369 457,654 468,153 461,015 463,962 464,198 468,958 468,850 494,740Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,150107,272 106,155 109,957 112,942 112,662 121,704 123,867 132,284 137,774 147,012 150,787 158,000 164,785 173,116 178,288 193,383CO2 Charge ($000)5,914 6,871 8,204 9,586 10,386 12,091 13,165 14,948 16,464 18,417 19,725 21,508 23,271 25,293 25,868 27,864Unit 13MWh30,299 40,164 41,135 41,99441,813 47,322 42,387 39,646 51,322 43,974 49,902 45,724 47,666 44,385 51,503 55,057 58,720 61,488 63,320 55,479Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6409,052 10,277 9,300 8,806 11,854 10,645 12,492 12,009 13,052 12,872 15,545 17,518 19,506 21,390 22,709 20,903CO2 Charge ($000)539 720 752 803 1,182 1,135 1,426 1,458 1,677 1,735 2,186 2,552 2,950 3,341 3,523 3,220Unit 15MWh979 380 140 21080 612 874 60 80 405 319 532 697 489 260 808 569 773 1,532Fuel + CO2 Charge ($000)308 126 49 7329 216 317 0 23 32 150 131 236 308 224 118 406 306 412 807CO2 Charge ($000)1 13 22 0 2 3 15 14 26 36 27 15 54 42 56 108Unit 18MWh8,470 12,805 13,357 14,56813,775 17,082 11,630 12,310 16,375 14,318 17,623 15,674 15,048 14,559 16,744 13,894 15,870 17,187 16,910 13,107Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,4523,497 4,253 2,977 3,161 4,454 4,042 4,990 4,732 4,659 4,695 5,653 4,910 5,781 6,479 6,412 5,166CO2 Charge ($000)179 257 208 249 385 374 495 499 521 552 693 624 763 884 868 694Unit 22MWh80,936 83,941 84,753 85,54489,052 93,142 94,197 97,242 104,104 105,034 107,784 111,308 113,505 116,592 120,655 123,061 124,868 126,617 127,378 127,517Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34915,589 16,330 16,602 17,197 19,058 19,973 21,299 22,837 24,187 25,901 27,911 29,614 31,329 33,041 34,260 35,338CO2 Charge ($000)798 983 1,153 1,356 1,637 1,847 2,108 2,405 2,696 3,026 3,409 3,762 4,132 4,509 4,642 4,754Unit 23MWh4,000 3,318 5,469 5,6406,159 5,453 7,714 4,846 6,842 5,226 9,759 7,405 9,995 7,714 9,595 11,663 11,432 9,178 14,948 7,953Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,717 1,541 2,090 1,382 2,030 1,645 3,006 2,449 3,350 2,760 3,558 4,449 4,516 3,879 6,219 3,483CO2 Charge ($000)88 93 146 109 175 152 297 258 374 327 436 565 596 529 842 468New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 129,636 129,837 130,759 131,386 136,313 142,438 148,297 154,859 161,499 169,456 177,200 185,582 194,558 203,613 212,501 221,970Total CO2 Charge ($000)000007,520 8,936 10,485 12,103 13,768 15,602 17,507 19,583 21,760 24,092 26,477 29,026 31,766 34,598 35,800 37,109Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-1WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 22Case:1-1W Same as Case 1-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953292,274 293,289 294,843 297,472 299,239 300,629 301,610 303,669 305,959 306,107 308,031 309,939 311,340 312,556 314,060 314,628Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53864,344 64,752 65,322 66,136 69,097 71,922 74,895 78,185 81,728 85,174 89,207 93,321 97,660 101,949 105,402 108,724CO2 Charge ($000)3,292 3,894 4,533 5,218 5,933 6,650 7,414 8,234 9,109 9,957 10,895 11,856 12,880 13,912 14,282 14,628CC 2MWh49,873 47,522 47,458 46,61344,910 45,938 46,329 45,083 45,121 45,561 46,526 46,296 45,898 47,683 47,497 47,529 48,059 48,758 49,133 50,659Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,48910,641 10,939 11,098 10,859 11,298 11,855 12,580 13,005 13,401 14,512 15,069 15,717 16,577 17,509 18,176 19,309CO2 Charge ($000)572 691 808 899 1,017 1,150 1,306 1,435 1,565 1,777 1,927 2,091 2,288 2,501 2,578 2,720Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)548 560 573 586 600 614 628 642 657 672 687 703 719 736 753 770Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 71,120 71,106 71,079 70,878 73,445 75,977 78,756 81,521 84,455 87,952 91,454 95,090 99,070 103,046 106,718 110,685Total CO2 Charge ($000)000003,864 4,585 5,341 6,116 6,950 7,800 8,720 9,669 10,674 11,734 12,822 13,947 15,168 16,413 16,860 17,348Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-1WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 22Case:1-1W Same as Case 1-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 200,756 200,943 201,838 202,264 209,757 218,415 227,052 236,380 245,954 257,408 268,654 280,673 293,628 306,659 319,219 332,656Total Authority CO2 Charges ($000)0000011,384 13,520 15,825 18,219 20,718 23,402 26,226 29,253 32,433 35,826 39,299 42,973 46,934 51,011 52,660 54,457Total Authority Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 235,304 238,099 240,550 245,095 255,593 266,132 279,441 292,336 304,232 321,057 336,354 351,128 370,161 387,890 401,113 418,615Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 223,920 224,579 224,725 226,876 234,874 242,730 253,215 263,083 271,799 285,231 297,055 308,154 323,227 336,879 348,454 364,158NPV with CO2 Charge ($000)2,938,944NPV without CO2 Charge ($000)2,724,105R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-1WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 23Case:1-2 Same as Case 1-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh392,080 378,931 381,059 384,781 389,904 386,544 400,119 412,117 399,451 417,883 410,061 425,909 428,335 442,386 438,758 444,851 447,016 454,348 455,417 482,395Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15065,659 65,267 67,922 70,241 68,471 72,263 71,670 75,023 76,302 79,755 80,034 82,142 83,816 86,246 87,096 92,804CO2 Charge ($000)3,362 3,917 4,684 5,499 5,987 6,998 7,629 8,718 9,618 10,831 11,655 12,775 13,866 15,135 15,509 16,752Unit 13MWh23,373 28,884 29,869 30,163 30,317 34,370 30,478 26,664 35,402 29,694 36,531 30,073 32,758 27,579 32,585 33,399 34,936 35,495 38,191 28,382Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6404,659 5,302 4,735 4,245 5,699 4,859 5,901 4,966 5,421 4,648 5,596 5,797 6,160 6,393 6,853 5,212CO2 Charge ($000)239 320 329 332 504 471 629 579 687 637 821 902 1,021 1,123 1,222 942Unit 15MWh979 380 140 210 50 542 824 60 80 385 269 462 647 439 237 748 539 743 1,500Fuel + CO2 Charge ($000)308 126 49 7312 122 191 0 14 19 84 63 116 156 107 56 190 143 191 374CO2 Charge ($000)1 7 13 0 1 2 9 7 15 21 16 9 32 25 34 68Unit 18MWh15,039 23,443 23,898 25,426 24,460 29,267 22,617 24,186 31,350 27,715 30,427 30,735 29,780 30,429 34,802 33,760 37,270 40,098 38,349 35,515Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,4523,523 4,239 3,351 3,618 4,711 4,221 4,687 4,863 4,792 5,069 5,873 5,920 6,639 7,312 7,103 6,805CO2 Charge ($000)181 256 233 283 416 409 500 567 607 693 860 921 1,100 1,284 1,266 1,229Unit 22MWh135,620 135,691 136,178 136,558 137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 144,012 144,473 144,338 144,502 144,556Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34914,993 15,144 15,330 15,532 15,850 15,997 16,239 16,468 16,748 17,000 17,296 17,581 17,931 18,198 18,363 18,539CO2 Charge ($000)768 910 1,059 1,214 1,389 1,549 1,729 1,915 2,113 2,309 2,522 2,734 2,968 3,194 3,270 3,347Unit 23MWh4,000 3,318 5,469 5,640 6,159 5,453 7,744 4,846 6,842 5,226 9,759 7,445 10,055 7,744 9,635 11,683 11,486 9,185 14,978 7,979Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,093 984 1,343 888 1,266 1,001 1,782 1,419 1,892 1,506 1,900 2,320 2,300 1,921 3,015 1,656CO2 Charge ($000)56 59 93 69 112 97 190 165 240 209 279 361 381 337 538 299New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 85,331 85,589 86,461 87,126 87,603 88,836 89,677 90,851 91,989 93,434 94,653 96,116 97,670 99,114 100,783 102,753Total CO2 Charge ($000)000004,607 5,468 6,411 7,398 8,409 9,525 10,685 11,950 13,280 14,699 16,153 17,701 19,367 21,098 21,839 22,637Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-2Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 23Case:1-2 Same as Case 1-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 326,138 327,273 328,440 329,731 329,651Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53842,597 43,000 43,495 44,185 44,874 45,505 46,124 46,912 47,792 48,471 49,441 50,410 51,423 52,362 52,940 53,412CO2 Charge ($000)2,182 2,583 3,003 3,459 3,931 4,407 4,911 5,454 6,030 6,590 7,209 7,840 8,510 9,190 9,429 9,643CC 2MWh49,873 47,522 47,458 46,613 46,510 47,241 48,068 46,513 46,600 46,953 47,985 47,714 47,426 49,305 49,137 49,337 50,104 50,868 51,435 53,581Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4897,159 7,326 7,522 7,338 7,430 7,573 7,829 7,878 7,936 8,369 8,468 8,637 8,925 9,202 9,380 9,864CO2 Charge ($000)367 440 519 574 650 733 833 915 1,000 1,137 1,233 1,343 1,477 1,615 1,670 1,781Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 47,207 47,303 47,495 47,491 47,723 47,938 48,209 48,421 48,698 49,113 49,467 49,864 50,362 50,759 51,221 51,852Total CO2 Charge ($000)000002,549 3,022 3,522 4,032 4,581 5,140 5,744 6,369 7,031 7,727 8,442 9,183 9,987 10,805 11,099 11,423Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-2Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 23Case:1-2 Same as Case 1-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 132,538 132,893 133,956 134,617 135,326 136,774 137,886 139,272 140,687 142,548 144,120 145,980 148,033 149,873 152,004 154,605Total Authority CO2 Charges ($000)000007,157 8,491 9,932 11,430 12,990 14,665 16,430 18,320 20,311 22,426 24,595 26,884 29,354 31,903 32,938 34,060Total Authority Incremental Non-fuel Production Cost ($000)000000000000000000000Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 159,661 161,809 163,552 167,423 170,183 172,490 177,200 181,003 183,536 189,474 193,779 196,993 203,617 208,610 210,774 216,748Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 152,504 153,318 153,620 155,993 157,193 157,825 160,771 162,684 163,225 167,048 169,184 170,108 174,263 176,707 177,836 182,688NPV with CO2 Charge ($000)2,082,585NPV without CO2 Charge ($000)1,948,039R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-2Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 24Case:1-3 Same as Case 1-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh392,080 378,931 381,059 384,781 389,904 386,544 400,119 412,117 399,451 417,883 410,061 425,909 428,335 442,386 438,758 444,851 447,016 454,348 455,417 482,395Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15073,862 73,191 77,918 81,411 81,821 90,180 89,776 94,647 98,832 104,569 108,062 114,085 119,988 124,735 127,876 139,181CO2 Charge ($000)4,035 4,701 5,621 6,600 7,186 8,399 9,156 10,462 11,544 12,999 13,988 15,332 16,641 18,165 18,614 20,106Unit 13MWh23,373 28,884 29,869 30,163 30,317 34,370 30,478 26,664 35,402 29,694 36,531 30,073 32,758 27,579 32,585 33,399 34,936 35,495 38,191 28,382Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6405,244 5,955 5,439 4,921 6,845 6,068 7,397 6,275 7,032 6,122 7,585 8,057 8,828 9,260 10,084 7,843CO2 Charge ($000)287 384 395 398 605 565 756 695 825 765 986 1,083 1,227 1,348 1,467 1,131Unit 15MWh979 380 140 210 50 542 824 60 80 385 269 462 647 439 237 748 539 743 1,500Fuel + CO2 Charge ($000)308 126 49 7313 137 220 0 17 24 105 80 150 204 144 78 273 208 281 564CO2 Charge ($000)1 9 16 0 2 2 11 9 17 25 19 10 38 30 41 81Unit 18MWh15,039 23,443 23,898 25,426 24,460 29,267 22,617 24,186 31,350 27,715 30,427 30,735 29,780 30,429 34,802 33,760 37,270 40,098 38,349 35,515Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,4523,965 4,760 3,849 4,195 5,657 5,272 5,876 6,144 6,217 6,667 7,954 8,228 9,513 10,587 10,448 10,228CO2 Charge ($000)217 307 280 340 500 491 600 680 729 832 1,033 1,106 1,321 1,542 1,520 1,476Unit 22MWh135,620 135,691 136,178 136,558 137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 144,012 144,473 144,338 144,502 144,556Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34916,853 16,971 17,573 17,981 18,941 19,947 20,325 20,763 21,679 22,272 23,346 24,398 25,651 26,302 26,943 27,789CO2 Charge ($000)921 1,091 1,269 1,456 1,665 1,858 2,073 2,296 2,534 2,769 3,024 3,279 3,559 3,830 3,922 4,014Unit 23MWh4,000 3,318 5,469 5,640 6,159 5,453 7,744 4,846 6,842 5,226 9,759 7,445 10,055 7,744 9,635 11,683 11,486 9,185 14,978 7,979Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,225 1,099 1,536 1,026 1,514 1,245 2,224 1,785 2,444 1,985 2,566 3,210 3,282 2,771 4,421 2,481CO2 Charge ($000)67 71 111 83 134 116 227 198 287 250 334 431 456 404 643 358New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 95,634 95,550 98,841 100,655 104,703 111,304 112,881 115,353 120,417 124,179 130,273 136,814 144,295 148,543 153,846 160,920Total CO2 Charge ($000)000005,529 6,562 7,693 8,878 10,091 11,430 12,823 14,341 15,937 17,640 19,384 21,242 23,241 25,319 26,207 27,166Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 24Case:1-3 Same as Case 1-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 326,138 327,273 328,440 329,731 329,651Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53847,899 48,207 49,880 51,188 53,644 56,765 57,754 59,168 61,889 63,554 66,762 69,985 73,591 75,708 77,715 80,096CO2 Charge ($000)2,618 3,098 3,603 4,149 4,716 5,287 5,892 6,543 7,234 7,905 8,648 9,405 10,209 11,025 11,311 11,568CC 2MWh49,873 47,522 47,458 46,613 46,510 47,241 48,068 46,513 46,600 46,953 47,985 47,714 47,426 49,305 49,137 49,337 50,104 50,868 51,435 53,581Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4898,060 8,222 8,637 8,508 8,886 9,458 9,815 9,947 10,288 10,984 11,444 12,005 12,788 13,320 13,785 14,808CO2 Charge ($000)440 528 623 689 780 881 1,001 1,100 1,202 1,366 1,481 1,613 1,774 1,940 2,007 2,139Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 52,900 52,803 54,291 54,858 57,033 60,055 60,677 61,473 63,741 65,266 68,077 70,971 74,396 76,063 78,182 81,197Total CO2 Charge ($000)000003,059 3,627 4,226 4,838 5,497 6,167 6,893 7,642 8,436 9,271 10,129 11,019 11,983 12,965 13,318 13,707Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 24Case:1-3 Same as Case 1-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 148,534 148,353 153,133 155,513 161,736 171,360 173,558 176,826 184,158 189,445 198,350 207,786 218,690 224,607 232,028 242,117Total Authority CO2 Charges ($000)000008,588 10,189 11,918 13,716 15,588 17,598 19,715 21,983 24,373 26,911 29,513 32,261 35,224 38,284 39,524 40,872Total Authority Incremental Non-fuel Production Cost ($000)000000000000000000000Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 177,088 178,967 184,714 190,605 199,192 210,009 216,158 222,220 231,068 240,857 252,927 264,175 280,145 289,724 297,385 311,071Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 168,501 168,779 172,796 176,889 183,604 192,411 196,443 200,237 206,696 213,946 223,414 231,914 244,921 251,440 257,860 270,199NPV with CO2 Charge ($000)2,406,996NPV without CO2 Charge ($000)2,245,543R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 25Case:1-3W Same as Case 1-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh392,080 378,931 381,059 384,781389,915 386,589 400,229 412,198 399,676 418,298 410,829 427,227 430,013 444,387 440,953 447,256 449,382 456,607 457,449 484,269Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15073,864 73,198 77,935 81,424 81,858 90,252 89,913 94,885 99,148 104,955 108,505 114,592 120,511 125,247 128,348 139,630CO2 Charge ($000)4,035 4,701 5,623 6,601 7,189 8,405 9,170 10,489 11,580 13,047 14,045 15,400 16,714 18,239 18,683 20,170Unit 13MWh23,373 28,884 29,869 30,16330,322 34,348 30,454 26,671 35,401 29,657 36,494 29,915 32,671 27,163 32,320 33,235 34,516 35,096 37,879 28,192Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6405,245 5,952 5,435 4,922 6,845 6,060 7,388 6,238 7,013 6,016 7,516 8,012 8,704 9,142 9,988 7,783CO2 Charge ($000)288 384 395 399 605 564 755 691 823 752 977 1,077 1,209 1,331 1,453 1,122Unit 15MWh979 380 140 21080 612 874 60 80 405 319 532 697 489 260 808 569 773 1,532Fuel + CO2 Charge ($000)308 126 49 7321 155 233 0 17 24 111 95 173 221 162 86 296 219 294 577CO2 Charge ($000)1 10 17 0 2 2 11 11 20 28 21 11 41 32 43 83Unit 18MWh15,039 23,443 23,898 25,42624,414 29,173 22,510 24,098 31,126 27,337 29,677 29,565 28,179 28,825 32,862 31,517 35,319 38,215 36,630 33,825Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,4523,958 4,746 3,831 4,184 5,609 5,195 5,702 5,866 5,824 6,262 7,422 7,594 8,928 9,992 9,883 9,659CO2 Charge ($000)217 306 279 339 496 484 582 650 683 781 964 1,021 1,240 1,455 1,438 1,394Unit 22MWh135,620 135,691 136,178 136,558137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 144,012 144,473 144,338 144,502 144,556Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34916,853 16,971 17,573 17,981 18,941 19,947 20,325 20,763 21,679 22,272 23,346 24,398 25,651 26,302 26,943 27,789CO2 Charge ($000)921 1,091 1,269 1,456 1,665 1,858 2,073 2,296 2,534 2,769 3,024 3,279 3,559 3,830 3,922 4,014Unit 23MWh4,000 3,318 5,469 5,6406,159 5,453 7,714 4,846 6,842 5,226 9,759 7,405 9,995 7,714 9,595 11,663 11,432 9,178 14,948 7,953Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,225 1,099 1,531 1,026 1,514 1,245 2,224 1,778 2,433 1,979 2,558 3,206 3,271 2,770 4,414 2,475CO2 Charge ($000)67 71 111 83 134 116 227 197 285 249 333 431 454 403 642 357New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 95,637 95,559 98,846 100,658 104,693 111,293 112,845 115,292 120,343 124,080 130,145 136,669 144,145 148,381 153,689 160,771Total CO2 Charge ($000)000005,529 6,563 7,693 8,878 10,090 11,429 12,818 14,333 15,927 17,626 19,364 21,219 23,217 25,291 26,180 27,140Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 25Case:1-3W Same as Case 1-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953292,274 293,289 294,843 297,472 299,239 300,629 301,610 303,669 305,959 306,107 308,031 309,939 311,340 312,556 314,060 314,628Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53846,058 46,331 47,996 49,231 51,611 54,610 55,581 56,947 59,597 61,220 64,326 67,469 71,001 73,060 75,044 77,461CO2 Charge ($000)2,518 2,978 3,467 3,991 4,538 5,086 5,670 6,297 6,967 7,615 8,333 9,067 9,850 10,640 10,923 11,188CC 2MWh49,873 47,522 47,458 46,61344,910 45,938 46,329 45,083 45,121 45,561 46,526 46,296 45,898 47,683 47,497 47,529 48,059 48,758 49,133 50,659Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4897,792 8,002 8,333 8,256 8,614 9,188 9,527 9,661 9,966 10,632 11,073 11,577 12,277 12,778 13,178 14,009CO2 Charge ($000)426 514 601 669 757 856 972 1,068 1,164 1,322 1,433 1,556 1,703 1,861 1,918 2,023Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)548 560 573 586 600 614 628 642 657 672 687 703 719 736 753 770Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 50,906 50,841 52,262 52,828 54,931 57,857 58,467 59,243 61,433 62,915 65,633 68,422 71,725 73,338 75,382 78,259Total CO2 Charge ($000)000002,943 3,492 4,068 4,659 5,294 5,942 6,642 7,365 8,131 8,937 9,766 10,623 11,553 12,500 12,841 13,211Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 25Case:1-3W Same as Case 1-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 146,543 146,400 151,108 153,486 159,625 169,150 171,311 174,536 181,776 186,995 195,778 205,092 215,870 221,719 229,071 239,030Total Authority CO2 Charges ($000)000008,473 10,055 11,761 13,537 15,384 17,371 19,460 21,698 24,057 26,563 29,130 31,842 34,770 37,792 39,021 40,351Total Authority Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 178,179 180,090 185,755 191,635 200,126 210,836 216,934 222,937 231,678 241,381 253,310 264,416 280,239 289,731 297,327 310,884Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 169,706 170,036 173,994 178,098 184,742 193,465 197,474 201,239 207,620 214,818 224,179 232,573 245,470 251,939 258,306 270,533NPV with CO2 Charge ($000)2,412,144NPV without CO2 Charge ($000)2,252,782R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-3WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 26Case:1-4 Base Load, add CFB , replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh440,702 424,991 427,346 430,844366,371 368,734 371,378 375,107 376,773 380,120 381,652 383,737 388,558 390,717 393,386 396,864 402,479 402,415 413,198 409,780Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15088,670 89,438 90,371 91,590 95,631 99,851 104,060 108,536 113,922 119,156 124,837 130,824 137,870 143,101 151,042 154,228CO2 Charge ($000)4,891 5,795 6,751 7,773 8,829 9,920 11,062 12,269 13,622 14,939 16,343 17,808 19,474 20,908 21,913 22,219Unit 13MWh30,299 40,164 41,135 41,99430,671 32,911 32,860 32,154 33,895 33,701 34,895 34,741 34,051 34,260 36,199 37,591 37,068 40,117 37,213 37,858Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6406,851 7,361 7,356 7,309 7,926 8,202 8,795 9,037 9,310 9,709 10,705 11,547 11,899 13,498 12,894 13,551CO2 Charge ($000)407 513 590 666 785 875 1,003 1,095 1,192 1,303 1,499 1,682 1,798 2,108 2,001 2,088Unit 15MWh979 380 140 21088 190 110 176 10 10 676 10 77 30 146 50Fuel + CO2 Charge ($000)308 126 49 730 30 70 0 42 0 71 4 0 5 279 5 38 16 77 29CO2 Charge ($000)0 2 5 0 4 0 7 0 0 1 34 1 5 2 10 4Unit 18MWh8,470 12,805 13,357 14,5682,888 4,111 4,226 3,668 5,836 5,097 5,174 7,494 6,470 6,737 6,990 9,435 8,561 8,554 8,705 8,245Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,452787 1,133 1,160 1,040 1,659 1,518 1,602 2,312 2,141 2,341 2,481 3,442 3,301 3,464 3,495 3,495CO2 Charge ($000)40 68 80 82 142 140 159 243 238 273 303 437 435 473 474 470Unit 22MWh80,936 83,941 84,753 85,54441,057 41,456 43,739 47,500 48,759 52,080 53,083 57,399 62,262 66,301 66,615 66,501 70,774 75,272 75,829 78,180Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,3497,182 7,312 7,764 8,460 9,041 10,036 10,651 11,986 13,459 14,937 15,663 16,342 18,018 19,920 20,742 21,982CO2 Charge ($000)367 439 539 667 776 928 1,054 1,262 1,500 1,745 1,912 2,076 2,376 2,718 2,811 2,958Unit 23MWh4,000 3,318 5,469 5,6401,481 703 1,327 1,089 219 821 3,238 1,585 319 667 1,858 2,761 1,588 2,298 2,905 1,557Fuel + CO2 Charge ($000)1,035 845 1,471 1,479395 198 373 319 67 258 989 522 113 246 694 1,082 652 967 1,232 699CO2 Charge ($000)20 12 26 25 6 24 98 55 13 29 85 137 86 132 167 94New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,304 1,342 1,383 1,425 1,468 1,509 1,554 1,597 1,643 1,687 1,734 1,780 1,828 1,870 1,899 2,077Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh145,500 146,401 147,459 148,554 149,601 150,366 151,326 152,064 152,911 153,462 154,214 154,745 155,355 155,313 154,203 164,831Fuel + CO2 Charge ($000)6,503 6,963 7,453 7,971 8,563 9,152 9,792 10,447 11,139 11,888 12,684 13,480 14,336 15,159 15,443 16,950CO2 Charge ($000)2,061 2,448 2,858 3,294 3,752 4,215 4,718 5,239 5,789 6,356 6,956 7,561 8,213 8,851 8,986 9,829CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 102,602 103,159 103,696 104,181 108,636 112,915 117,860 122,680 127,728 133,637 140,209 147,017 153,728 160,934 168,565 173,271Total CO2 Charge ($000)000007,787 9,276 10,849 12,507 14,293 16,103 18,101 20,164 22,355 24,645 27,132 29,703 32,387 35,192 36,362 37,663Incremental Non-fuel Production Cost ($000)0000019,134 19,221 19,313 19,406 19,502 19,598 19,697 19,797 19,901 20,004 20,111 20,219 20,330 20,437 20,532 20,777R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 26Case:1-4 Base Load, add CFB , replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953207,090 206,913 208,933 209,187 209,058 209,255 211,971 212,262 214,491 213,742 210,999 215,249 216,455 218,092 223,812 180,182Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53849,921 50,133 50,725 51,040 53,024 55,136 57,858 60,157 63,007 65,478 67,680 71,483 74,706 78,497 82,217 69,346CO2 Charge ($000)2,553 3,012 3,515 4,022 4,546 5,098 5,727 6,335 7,022 7,655 8,266 9,082 9,850 10,711 11,140 9,331CC 2MWh49,873 47,522 47,458 46,61331,686 31,674 30,424 31,241 32,500 32,474 30,569 30,954 30,302 31,575 35,051 31,066 31,860 30,522 32,614 63,729Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4897,594 7,626 7,378 7,636 8,262 8,537 8,364 8,796 8,952 9,715 11,203 10,398 11,142 11,086 12,192 24,581CO2 Charge ($000)410 484 542 637 750 828 868 971 1,045 1,189 1,432 1,383 1,541 1,583 1,729 3,461Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,140 1,172 1,207 1,239 1,275 1,310 1,346 1,385 1,420 1,459 1,500 1,546 1,582 1,628 1,582 1,809Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh127,218 127,912 128,715 129,129 129,894 130,530 131,127 131,803 132,153 132,750 133,414 134,364 134,440 135,190 128,470 143,536Fuel + CO2 Charge ($000)5,708 6,107 6,532 6,956 7,465 7,976 8,519 9,091 9,668 10,324 11,016 11,750 12,453 13,244 12,915 14,817CO2 Charge ($000)1,809 2,147 2,505 2,874 3,271 3,674 4,105 4,559 5,025 5,520 6,041 6,591 7,134 7,733 7,515 8,592CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 58,452 58,223 58,073 58,099 60,183 62,049 64,040 66,179 68,535 71,153 74,160 76,575 79,777 82,799 86,939 87,360Total CO2 Charge ($000)000004,771 5,643 6,562 7,533 8,567 9,600 10,700 11,865 13,093 14,363 15,740 17,056 18,524 20,028 20,384 21,384Incremental Non-fuel Production Cost ($000)0000018,970 19,052 19,137 19,220 19,309 19,398 19,490 19,584 19,678 19,776 19,877 19,985 20,084 20,194 20,215 20,509R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 26Case:1-4 Base Load, add CFB , replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 161,053 161,382 161,769 162,281 168,819 174,964 181,900 188,859 196,263 204,790 214,370 223,593 233,504 243,733 255,504 260,631Total Authority CO2 Charges ($000)0000012,558 14,920 17,412 20,040 22,860 25,703 28,801 32,029 35,448 39,009 42,872 46,759 50,911 55,219 56,746 59,047Total Authority Incremental Non-fuel Production Cost ($000)0000038,104 38,273 38,449 38,627 38,811 38,996 39,187 39,382 39,578 39,780 39,989 40,204 40,415 40,631 40,747 41,287Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 231,682 235,001 237,293 242,323 252,358 260,714 272,774 283,681 293,827 308,079 322,295 334,684 351,061 366,417 378,830 389,046Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 219,124 220,081 219,881 222,283 229,498 235,011 243,973 251,652 258,379 269,071 279,423 287,925 300,150 311,197 322,084 330,000NPV with CO2 Charge ($000)2,867,522NPV without CO2 Charge ($000)2,632,980R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 27Case:1-4W Base Load, add CFB , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.7Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh440,702 424,991 427,346 430,844366,371 368,734 371,378 375,107 376,773 380,120 381,652 383,737 388,560 390,748 393,386 396,864 402,481 402,461 413,196 409,780Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15088,670 89,438 90,371 91,590 95,631 99,851 104,060 108,536 113,922 119,164 124,837 130,824 137,870 143,114 151,041 154,228CO2 Charge ($000)4,891 5,795 6,751 7,773 8,829 9,920 11,062 12,269 13,623 14,940 16,343 17,808 19,474 20,910 21,913 22,219Unit 13MWh30,299 40,164 41,135 41,99430,686 32,909 32,868 32,225 33,907 33,738 34,967 34,836 34,183 34,288 36,262 37,661 37,177 40,178 37,223 37,939Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6406,854 7,361 7,357 7,322 7,929 8,210 8,811 9,060 9,341 9,713 10,721 11,566 11,931 13,512 12,897 13,577CO2 Charge ($000)407 513 590 667 785 876 1,005 1,098 1,196 1,304 1,502 1,685 1,803 2,111 2,001 2,092Unit 15MWh979 380 140 21088 190 110 176 10 10 676 10 77 30 154 30Fuel + CO2 Charge ($000)308 126 49 730 30 70 0 42 0 71 4 0 5 279 5 38 16 80 17CO2 Charge ($000)0 2 5 0 4 0 7 0 0 1 34 1 5 2 11 2Unit 18MWh8,470 12,805 13,357 14,5682,874 4,131 4,226 3,655 5,824 5,063 5,125 7,399 6,336 6,679 6,944 9,423 8,607 8,578 8,704 8,285Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,452785 1,135 1,160 1,038 1,657 1,513 1,590 2,295 2,107 2,329 2,471 3,440 3,312 3,470 3,494 3,505CO2 Charge ($000)40 68 80 82 142 140 157 242 235 272 302 437 437 473 473 472Unit 22MWh80,936 83,941 84,753 85,54441,057 41,456 43,739 47,500 48,759 52,080 53,083 57,399 62,262 66,301 66,615 66,501 70,774 75,272 75,829 78,180Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,3497,182 7,312 7,764 8,460 9,041 10,036 10,651 11,986 13,459 14,937 15,663 16,342 18,018 19,920 20,742 21,982CO2 Charge ($000)367 439 539 667 776 928 1,054 1,262 1,500 1,745 1,912 2,076 2,376 2,718 2,811 2,958Unit 23MWh4,000 3,318 5,469 5,6401,480 686 1,319 1,031 219 817 3,215 1,585 319 667 1,840 2,702 1,430 2,166 2,891 1,455Fuel + CO2 Charge ($000)1,035 845 1,471 1,479395 193 371 302 67 258 984 522 113 246 689 1,064 591 912 1,226 658CO2 Charge ($000)20 12 26 24 6 24 97 55 13 29 84 135 78 125 166 89New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,304 1,342 1,383 1,425 1,468 1,509 1,554 1,597 1,643 1,687 1,734 1,780 1,828 1,870 1,899 2,077Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh145,500 146,401 147,459 148,554 149,601 150,366 151,326 152,064 152,911 153,462 154,214 154,745 155,355 155,313 154,203 164,831Fuel + CO2 Charge ($000)6,503 6,963 7,453 7,971 8,563 9,152 9,792 10,447 11,139 11,888 12,684 13,480 14,336 15,159 15,443 16,950CO2 Charge ($000)2,061 2,448 2,858 3,294 3,752 4,215 4,718 5,239 5,789 6,356 6,956 7,561 8,213 8,851 8,986 9,829CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 102,602 103,157 103,696 104,176 108,637 112,916 117,859 122,685 127,726 133,637 140,212 147,017 153,712 160,914 168,562 173,256Total CO2 Charge ($000)000007,787 9,276 10,849 12,507 14,293 16,103 18,101 20,165 22,356 24,646 27,133 29,704 32,385 35,189 36,361 37,661Incremental Non-fuel Production Cost ($000)0000019,134 19,221 19,313 19,406 19,502 19,598 19,697 19,797 19,901 20,004 20,111 20,219 20,330 20,437 20,532 20,777R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 27Case:1-4W Base Load, add CFB , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953202,415 202,349 203,953 203,739 203,652 203,603 205,736 205,907 207,695 205,980 203,102 207,608 208,430 209,800 215,206 172,336Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53849,138 49,356 49,875 50,110 52,058 54,083 56,655 58,882 61,594 63,804 65,893 69,670 72,720 76,357 79,929 67,171CO2 Charge ($000)2,513 2,965 3,457 3,949 4,464 5,001 5,608 6,201 6,865 7,459 8,048 8,851 9,588 10,419 10,830 9,038CC 2MWh49,873 47,522 47,458 46,61331,468 31,400 30,183 30,935 32,154 32,073 30,214 30,546 29,903 31,080 34,433 30,521 31,475 29,998 31,849 62,389Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4897,544 7,563 7,321 7,564 8,177 8,435 8,270 8,684 8,838 9,567 11,013 10,221 11,011 10,901 11,914 24,080CO2 Charge ($000)407 480 537 631 743 818 858 959 1,032 1,171 1,408 1,360 1,523 1,557 1,690 3,391Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,060 1,088 1,122 1,155 1,189 1,224 1,262 1,298 1,335 1,379 1,420 1,461 1,497 1,544 1,501 1,723Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh118,292 118,767 119,720 120,440 121,138 121,903 122,860 123,535 124,257 125,425 126,273 127,005 127,187 128,199 121,832 136,779Fuel + CO2 Charge ($000)5,320 5,684 6,089 6,502 6,977 7,465 7,998 8,538 9,107 9,771 10,445 11,125 11,801 12,579 12,267 14,140CO2 Charge ($000)1,686 1,998 2,336 2,686 3,057 3,438 3,854 4,281 4,734 5,224 5,728 6,240 6,760 7,345 7,138 8,199CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)560 573 586 600 614 628 642 657 672 687 703 719 736 753 770 788Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 57,396 57,158 56,956 56,910 58,949 60,726 62,603 64,663 66,909 69,288 72,167 74,565 77,661 80,516 84,453 84,763Total CO2 Charge ($000)000004,606 5,444 6,330 7,266 8,263 9,257 10,320 11,441 12,631 13,854 15,183 16,451 17,871 19,321 19,658 20,628Incremental Non-fuel Production Cost ($000)0000022,100 22,191 22,289 22,386 22,486 22,589 22,697 22,804 22,915 23,033 23,150 23,269 23,385 23,513 23,553 23,862R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 27Case:1-4W Base Load, add CFB , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 159,998 160,315 160,652 161,085 167,586 173,642 180,462 187,347 194,635 202,925 212,378 221,582 231,373 241,430 253,015 258,019Total Authority CO2 Charges ($000)0000012,392 14,720 17,179 19,773 22,556 25,360 28,422 31,606 34,987 38,500 42,317 46,155 50,256 54,510 56,019 58,289Total Authority Incremental Non-fuel Production Cost ($000)0000041,234 41,413 41,601 41,793 41,988 42,187 42,394 42,601 42,815 43,036 43,261 43,488 43,715 43,950 44,086 44,639Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 233,591 236,873 239,095 244,027 253,998 262,241 274,162 284,966 294,974 308,963 323,020 335,354 351,575 366,724 378,952 389,030Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 221,199 222,153 221,916 224,254 231,442 236,880 245,741 253,360 259,988 270,462 280,704 289,199 301,319 312,214 322,933 330,741NPV with CO2 Charge ($000)2,876,990NPV without CO2 Charge ($000)2,645,511R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-4WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 28Case:1-5 Base Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 692,398 700,412 708,523 716,731 725,037CC 1MWh440,702 424,991 427,346 430,844Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,1500000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh30,299 40,164 41,135 41,994Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6400000000000000000CO2 Charge ($000)Unit 15MWh979 380 140 21095,162 95,773 96,842 95,897 96,027 97,786 99,109 99,403 100,330 101,353 101,433 102,687 103,595 104,710 105,159 105,651Fuel + CO2 Charge ($000)308 126 49 7331,622 31,824 32,184 32,199 33,550 35,113 36,750 38,236 39,976 41,864 43,665 45,767 48,003 50,267 51,908 53,618CO2 Charge ($000)1,618 1,914 2,234 2,539 2,882 3,247 3,638 4,027 4,456 4,895 5,334 5,814 6,331 6,859 7,033 7,214Unit 18MWh8,470 12,805 13,357 14,568142,103 143,881 144,772 143,891 145,363 146,354 146,174 147,142 148,773 148,579 148,368 150,141 151,929 152,721 153,692 154,698Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,45232,889 33,272 33,624 33,682 35,299 36,767 38,191 39,860 41,804 43,478 45,260 47,552 50,047 52,304 54,129 56,054CO2 Charge ($000)1,683 2,001 2,333 2,658 3,032 3,400 3,781 4,198 4,660 5,083 5,528 6,041 6,600 7,137 7,334 7,542Unit 22MWh80,936 83,941 84,753 85,544100,012 105,240 106,429 108,557 111,485 113,525 117,242 118,517 120,109 122,350 122,530 125,021 126,084 126,376 128,014 128,920Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34917,516 18,452 18,776 19,282 20,553 21,694 23,282 24,442 25,700 27,266 28,521 30,239 31,772 33,158 34,595 35,864CO2 Charge ($000)896 1,110 1,303 1,520 1,766 2,006 2,305 2,574 2,865 3,185 3,484 3,842 4,190 4,525 4,688 4,825Unit 23MWh4,000 3,318 5,469 5,6407,056 4,860 7,607 9,267 11,344 10,445 10,066 10,991 17,289 14,005 14,315 17,563 17,598 22,058 25,355 22,434Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,967 1,382 2,148 2,516 3,226 3,128 3,168 3,652 5,674 4,870 5,249 6,639 6,962 8,857 10,654 9,680CO2 Charge ($000)101 83 149 201 277 289 314 384 633 572 643 843 918 1,209 1,443 1,302New ResourcesCT1Fixed O&M ($000)1,366 1,397 1,429 1,462 1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)118 127 136 140 162 179 195 215 225 242 236 282 305 307 355 377Capital Cost ($000)3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930MWh35,834 37,649 39,603 39,795 45,074 48,633 51,817 55,771 56,979 59,920 57,253 66,717 70,578 69,446 78,537 81,671Fuel + CO2 Charge ($000)8,854 9,386 9,890 9,968 11,732 13,137 14,613 16,274 17,237 18,978 18,952 22,886 25,209 25,876 30,022 32,183CO2 Charge ($000)453 565 688 789 1,009 1,215 1,447 1,715 1,923 2,220 2,315 2,908 3,325 3,531 4,068 4,330CFB 1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,077 2,127 2,173 2,269 2,272 2,326 2,380 2,434 2,438 2,552 2,726 2,676 2,738 2,802 2,807 2,934Capital Cost ($000)26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264MWh231,801 232,114 231,744 236,614 231,507 231,751 231,739 231,719 226,892 232,157 242,428 232,599 232,646 232,690 227,895 232,808Fuel + CO2 Charge ($000)10,338 11,017 11,691 12,669 13,221 14,092 14,981 15,902 16,508 17,959 19,911 20,256 21,457 22,702 22,823 23,934CO2 Charge ($000)3,275 3,871 4,481 5,231 5,787 6,491 7,217 7,973 8,578 9,598 10,915 11,362 12,290 13,255 13,281 13,879CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 95,161 95,789 97,125 97,378 102,828 107,285 112,284 117,495 123,787 128,861 133,339 142,529 149,794 156,649 166,285 172,241Total CO2 Charge ($000)000008,026 9,544 11,188 12,938 14,752 16,647 18,701 20,871 23,114 25,554 28,218 30,811 33,655 36,515 37,847 39,091Incremental Non-fuel Production Cost ($000)0000038,134 38,326 38,516 38,755 38,920 39,137 39,354 39,580 39,749 40,038 40,369 40,530 40,785 41,024 41,255 41,586R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 28Case:1-5 Base Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 396,297 398,174 400,059 401,955 403,859(37)CC 1MWh306,767 302,805 304,385 306,953Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,5380000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,873 47,522 47,458 46,613Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4890000000000000000CO2 Charge ($000)Unit 16MWh000011,792 11,794 11,706 11,927 12,601 13,213 13,434 13,245 13,974 13,873 14,454 14,275 14,554 13,866 12,989 14,416Fuel + CO2 Charge ($000)00003,614 3,632 3,604 3,726 3,920 4,354 4,600 4,621 5,262 5,202 5,876 6,055 6,118 6,191 5,939 6,762CO2 Charge ($000)185 218 250 294 336 403 455 486 586 608 717 769 808 845 805 910Unit 17MWh000050,846 52,273 53,417 54,389 52,706 55,654 56,898 57,632 58,675 60,787 62,344 64,089 62,861 67,070 68,556 68,026Fuel + CO2 Charge ($000)000011,498 11,799 12,114 12,326 12,514 13,574 14,340 15,065 15,829 17,091 18,157 19,348 19,962 21,986 23,041 23,648CO2 Charge ($000)588 709 840 972 1,074 1,255 1,419 1,586 1,764 1,998 2,217 2,458 2,632 3,000 3,122 3,182Unit 19MWh0000353 617 736 904 2,422 1,208 847 1,541 736 1,008 205 530 1,962 1,461 1,934 1,972Fuel + CO2 Charge ($000)0000117 194 243 289 756 408 317 576 290 422 92 236 898 706 964 980CO2 Charge ($000)6 12 17 23 65 38 31 61 32 49 11 30 118 96 131 132Unit 20MWh0000156,482 157,257 157,588 158,035 158,668 158,757 159,566 160,084 160,475 160,771 161,037 161,051 162,091 161,364 162,160 162,797Fuel + CO2 Charge ($000)000035,378 35,597 35,854 36,148 37,699 39,103 40,793 42,460 44,244 46,134 48,161 50,163 52,622 54,563 56,441 58,354CO2 Charge ($000)1,810 2,140 2,488 2,852 3,237 3,616 4,038 4,471 4,931 5,393 5,881 6,373 6,940 7,446 7,648 7,851New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,231 1,275 1,316 1,360 1,410 1,449 1,502 1,551 1,596 1,648 1,700 1,749 1,797 1,845 1,895 1,943Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh156,827 156,007 156,353 156,335 156,831 156,334 156,355 156,355 156,839 156,160 156,360 156,356 156,700 156,339 156,360 156,358Fuel + CO2 Charge ($000)6,995 7,408 7,892 8,377 8,967 9,506 10,109 10,734 11,420 12,091 12,856 13,616 14,454 15,256 15,664 16,081CO2 Charge ($000)2,217 2,604 3,027 3,461 3,929 4,378 4,871 5,383 5,936 6,465 7,051 7,638 8,280 8,907 9,114 9,324CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 52,797 52,946 53,085 53,265 55,216 57,256 59,344 61,468 63,795 66,429 69,264 72,150 75,276 78,408 81,230 84,426Total CO2 Charge ($000)000004,806 5,684 6,621 7,602 8,640 9,689 10,815 11,988 13,249 14,512 15,877 17,268 18,778 20,294 20,819 21,399Incremental Non-fuel Production Cost ($000)0000019,061 19,155 19,246 19,342 19,444 19,537 19,645 19,751 19,853 19,964 20,077 20,187 20,299 20,412 20,528 20,643R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 28Case:1-5 Base Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 147,958 148,735 150,210 150,643 158,043 164,541 171,628 178,963 187,582 195,290 202,603 214,679 225,070 235,057 247,515 256,667Total Authority CO2 Charges ($000)0000012,832 15,228 17,810 20,540 23,393 26,336 29,515 32,859 36,363 40,067 44,096 48,079 52,433 56,810 58,666 60,491Total Authority Incremental Non-fuel Production Cost ($000)0000057,195 57,481 57,762 58,096 58,365 58,673 58,999 59,331 59,602 60,002 60,446 60,717 61,083 61,435 61,783 62,229Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 230,903 234,566 239,113 242,825 253,565 263,538 274,360 285,605 298,238 310,295 322,332 338,919 354,293 369,277 384,214 395,917Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 218,071 219,338 221,303 222,285 230,172 237,203 244,844 252,746 261,876 270,229 278,237 290,840 301,860 312,468 325,548 335,427NPV with CO2 Charge ($000)2,882,216NPV without CO2 Charge ($000)2,641,455R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 29Case:1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 692,398 700,412 708,523 716,731 725,037CC 1MWh440,702 424,991 427,346 430,844Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,1500000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh30,299 40,164 41,135 41,994Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6400000000000000000CO2 Charge ($000)Unit 15MWh979 380 140 21095,195 95,853 96,902 96,060 96,095 97,871 99,270 99,486 100,423 101,445 101,524 102,940 103,799 104,837 105,400 105,919Fuel + CO2 Charge ($000)308 126 49 7331,628 31,838 32,195 32,229 33,562 35,131 36,783 38,255 39,997 41,887 43,688 45,834 48,060 50,303 51,981 53,701CO2 Charge ($000)1,618 1,915 2,234 2,542 2,883 3,248 3,641 4,029 4,458 4,898 5,336 5,823 6,338 6,864 7,043 7,225Unit 18MWh8,470 12,805 13,357 14,568142,249 143,974 144,922 144,091 145,509 146,452 146,376 147,294 148,885 148,769 148,480 150,397 152,084 152,922 153,891 154,970Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,45232,914 33,288 33,650 33,720 35,329 36,788 38,233 39,893 41,830 43,524 45,287 47,617 50,091 52,363 54,194 56,142CO2 Charge ($000)1,684 2,002 2,335 2,661 3,034 3,401 3,785 4,201 4,663 5,089 5,532 6,050 6,606 7,145 7,343 7,553Unit 22MWh80,936 83,941 84,753 85,544100,035 105,290 106,447 108,612 111,526 113,548 117,323 118,566 120,152 122,398 122,580 125,111 126,142 126,430 128,057 128,973Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34917,519 18,458 18,778 19,288 20,558 21,697 23,293 24,449 25,707 27,273 28,529 30,254 31,782 33,168 34,603 35,875CO2 Charge ($000)897 1,110 1,304 1,521 1,766 2,006 2,306 2,575 2,866 3,186 3,485 3,844 4,192 4,526 4,689 4,827Unit 23MWh4,000 3,318 5,469 5,6406,982 4,850 7,589 9,197 11,306 10,346 9,968 10,973 17,245 14,009 14,266 17,413 17,561 22,004 25,165 22,248Fuel + CO2 Charge ($000)1,035 845 1,471 1,4791,948 1,379 2,143 2,499 3,217 3,102 3,140 3,648 5,661 4,873 5,235 6,589 6,955 8,840 10,579 9,611CO2 Charge ($000)100 83 149 200 276 287 311 384 631 573 641 837 918 1,206 1,433 1,293New ResourcesCT1Fixed O&M ($000)1,366 1,397 1,429 1,462 1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)117 126 135 139 161 179 194 214 224 240 235 280 303 305 353 376Capital Cost ($000)3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930MWh35,704 37,433 39,384 39,442 44,855 48,518 51,463 55,499 56,772 59,582 57,040 66,260 70,197 69,115 78,238 81,259Fuel + CO2 Charge ($000)8,822 9,331 9,836 9,885 11,680 13,104 14,517 16,198 17,175 18,880 18,881 22,731 25,076 25,757 29,918 32,031CO2 Charge ($000)452 562 684 783 1,005 1,212 1,437 1,707 1,916 2,209 2,307 2,888 3,308 3,515 4,053 4,309CFB 1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,077 2,127 2,173 2,270 2,272 2,326 2,380 2,434 2,438 2,552 2,727 2,676 2,738 2,802 2,807 2,934Capital Cost ($000)26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264MWh231,803 232,118 231,754 236,619 231,509 231,756 231,746 231,724 226,894 232,161 242,437 232,606 232,647 232,693 227,901 232,812Fuel + CO2 Charge ($000)10,338 11,018 11,691 12,670 13,221 14,092 14,981 15,903 16,508 17,959 19,912 20,257 21,457 22,702 22,824 23,934CO2 Charge ($000)3,275 3,871 4,481 5,231 5,787 6,491 7,217 7,973 8,578 9,598 10,915 11,363 12,290 13,255 13,281 13,879CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 95,144 95,769 97,107 97,356 102,816 107,269 112,250 117,477 123,767 128,844 133,316 142,479 149,769 156,622 166,257 172,207Total CO2 Charge ($000)000008,025 9,543 11,187 12,936 14,751 16,645 18,697 20,869 23,111 25,552 28,216 30,804 33,652 36,511 37,842 39,086Incremental Non-fuel Production Cost ($000)0000038,134 38,325 38,515 38,753 38,920 39,136 39,353 39,579 39,748 40,037 40,368 40,528 40,783 41,022 41,254 41,584R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 29Case:1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 396,297 398,174 400,059 401,955 403,85918,008CC 1MWh306,767 302,805 304,385 306,953Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,5380000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,873 47,522 47,458 46,613Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4890000000000000000CO2 Charge ($000)Unit 16MWh00009,109 9,983 9,999 8,960 10,994 11,241 11,348 11,794 11,924 11,924 12,038 12,015 12,661 12,287 11,458 12,687Fuel + CO2 Charge ($000)00002,809 3,072 3,086 2,819 3,408 3,700 3,906 4,119 4,560 4,496 4,979 5,144 5,377 5,528 5,313 6,030CO2 Charge ($000)185 218 250 294 336 403 455 486 586 608 717 769 808 845 805 910Unit 17MWh000040,885 41,703 42,792 44,593 41,999 45,011 45,836 46,447 47,580 49,370 51,278 52,821 51,569 55,212 56,455 56,230Fuel + CO2 Charge ($000)00009,560 9,758 10,082 10,497 10,428 11,443 12,092 12,759 13,424 14,565 15,605 16,658 17,147 18,938 19,856 20,462CO2 Charge ($000)588 709 840 972 1,074 1,255 1,419 1,586 1,764 1,998 2,217 2,458 2,632 3,000 3,122 3,182Unit 19MWh0000242 522 555 707 2,146 989 690 1,153 618 820 181 428 1,517 1,013 1,499 1,625Fuel + CO2 Charge ($000)000081 163 187 227 662 338 261 433 247 348 82 194 702 501 761 813CO2 Charge ($000)6 12 17 23 65 38 31 61 32 49 11 30 118 96 131 132Unit 20MWh0000151,226 151,743 152,085 152,978 153,294 153,577 154,841 155,100 155,707 156,284 156,501 156,647 157,696 157,207 158,188 158,747Fuel + CO2 Charge ($000)000034,587 34,764 35,011 35,355 36,834 38,231 39,971 41,553 43,329 45,258 47,212 49,199 51,613 53,578 55,453 57,318CO2 Charge ($000)1,810 2,140 2,488 2,852 3,237 3,616 4,038 4,471 4,931 5,393 5,881 6,373 6,940 7,446 7,648 7,851New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,231 1,275 1,316 1,360 1,410 1,449 1,502 1,551 1,596 1,648 1,700 1,749 1,797 1,845 1,895 1,943Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh156,793 155,972 156,325 156,311 156,818 156,315 156,340 156,338 156,827 156,157 156,357 156,347 156,693 156,338 156,356 156,355Fuel + CO2 Charge ($000)6,994 7,406 7,890 8,376 8,966 9,505 10,108 10,733 11,419 12,091 12,856 13,615 14,454 15,256 15,664 16,080CO2 Charge ($000)2,217 2,604 3,027 3,461 3,929 4,378 4,871 5,383 5,936 6,465 7,051 7,638 8,280 8,907 9,114 9,324CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 49,225 49,480 49,635 49,673 51,657 53,528 55,524 57,609 59,730 62,246 64,856 67,543 70,515 73,507 76,227 79,304Total CO2 Charge ($000)000004,806 5,684 6,621 7,602 8,640 9,689 10,815 11,988 13,249 14,512 15,877 17,268 18,778 20,294 20,819 21,399Incremental Non-fuel Production Cost ($000)0000019,061 19,155 19,246 19,342 19,444 19,537 19,645 19,751 19,853 19,964 20,077 20,187 20,299 20,412 20,528 20,643R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 29Case:1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 144,369 145,248 146,742 147,028 154,473 160,796 167,774 175,086 183,497 191,090 198,171 210,022 220,284 230,128 242,484 251,511Total Authority CO2 Charges ($000)0000012,831 15,227 17,808 20,538 23,392 26,334 29,512 32,857 36,360 40,064 44,093 48,072 52,429 56,806 58,662 60,485Total Authority Incremental Non-fuel Production Cost ($000)0000057,195 57,480 57,761 58,095 58,364 58,673 58,998 59,330 59,601 60,001 60,445 60,715 61,082 61,434 61,781 62,227Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 227,313 231,078 235,643 239,207 249,993 259,792 270,501 281,725 294,150 306,092 317,897 334,253 349,502 364,343 379,177 390,755Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 214,482 215,851 217,835 218,669 226,601 233,458 240,989 248,868 257,789 266,027 273,804 286,181 297,072 307,538 320,515 330,270NPV with CO2 Charge ($000)2,851,903NPV without CO2 Charge ($000)2,611,160R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-5WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 210Case:1-6 Base Load, Add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509CC 1MWh440,702 424,991 427,346 430,844430,711 434,107 435,933 439,236 443,044 442,815 447,940 444,308 454,537 466,241 426,305 447,834 457,931 461,862 462,375 484,476Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,15098,754 99,789 100,639 101,879 106,692 110,629 115,997 119,492 126,854 134,796 129,581 140,944 150,196 157,578 162,422 175,204CO2 Charge ($000)5,448 6,466 7,519 8,648 9,851 10,991 12,332 13,503 15,169 16,901 16,951 19,186 21,210 23,023 23,566 25,244Unit 13MWh30,299 40,164 41,135 41,99428,417 33,856 34,139 34,137 34,537 33,501 37,816 35,501 31,446 51,132 34,063 44,086 41,873 43,940 47,813 39,575Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6406,770 7,974 8,154 8,206 8,589 8,713 10,073 9,876 9,218 15,530 10,486 14,379 14,314 15,662 17,232 14,862CO2 Charge ($000)402 556 656 750 853 929 1,149 1,199 1,181 2,088 1,474 2,095 2,165 2,447 2,673 2,289Unit 15MWh979 380 140 210Fuel + CO2 Charge ($000)308 126 49 73CO2 Charge ($000)Unit 18MWh8,470 12,805 13,357 14,5681,586 3,029 2,385 2,406 3,351 3,118 3,806 4,388 2,535 4,572 5,932 5,145 4,798 5,266 8,179 4,773Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,452437 847 665 687 994 939 1,205 1,393 861 1,629 2,145 1,996 1,902 2,191 3,331 2,056CO2 Charge ($000)22 51 46 54 85 87 119 147 96 191 263 254 251 299 451 276Unit 22MWh80,936 83,941 84,753 85,54446,342 42,144 45,343 47,201 48,253 51,621 50,215 52,969 56,261 67,881 46,756 65,632 65,063 68,432 66,911 68,474Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,3498,066 7,377 7,977 8,359 8,917 9,888 9,991 11,011 12,137 15,154 11,058 15,936 16,542 18,071 18,190 19,176CO2 Charge ($000)413 445 555 659 768 914 989 1,160 1,353 1,770 1,352 2,025 2,182 2,466 2,465 2,580Unit 23MWh4,000 3,318 5,469 5,640904 363 724 756 44 607 754 1,253 507 652 1,502 852 1,139 232 2,374 1,043Fuel + CO2 Charge ($000)1,035 845 1,471 1,479240 105 200 219 13 182 240 414 180 241 570 340 473 101 1,025 473CO2 Charge ($000)12 6 14 17 1 17 24 44 20 28 70 43 62 14 139 64New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 107,969 108,569 108,844 109,221 113,647 117,413 122,892 126,133 131,433 146,371 133,729 149,993 157,555 165,355 172,906 181,317Total CO2 Charge ($000)000006,297 7,524 8,790 10,129 11,558 12,938 14,613 16,052 17,818 20,978 20,110 23,602 25,870 28,248 29,294 30,454Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-6Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 210Case:1-6 Base Load, Add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835CC 1MWh306,767 302,805 304,385 306,953278,443 281,400 285,156 288,673 291,671 297,810 298,714 309,933 310,542 268,146 362,491 323,218 325,302 326,928 328,839 327,892Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,53861,531 62,307 63,238 64,157 67,179 70,881 73,782 78,901 82,079 73,516 103,635 95,639 100,254 104,756 108,405 111,465CO2 Charge ($000)3,146 3,743 4,383 5,056 5,760 6,554 7,302 8,310 9,149 8,588 12,658 12,150 13,222 14,295 14,688 14,997CC 2MWh49,873 47,522 47,458 46,613225 25 25 70175 75 250 706Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,4890 54 6 6 0 184 0 0 0 0 0 25 26 0 95 276CO2 Charge ($000)0 3 0 1 0 18 0 0 0 0 0 3 4 0 13 39Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,386 1,419 1,454 1,490 1,530 1,563 1,602 1,642 1,701 1,814 1,758 1,799 1,846 1,882 1,926 1,970Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh154,735 154,794 155,072 155,310 155,916 155,744 155,963 156,349 158,271 164,976 156,351 156,357 156,819 156,340 156,360 156,360Fuel + CO2 Charge ($000)6,904 7,352 7,827 8,324 8,916 9,471 10,084 10,733 11,515 12,773 12,855 13,616 14,468 15,256 15,660 16,081CO2 Charge ($000)2,188 2,584 3,002 3,440 3,907 4,362 4,859 5,383 5,983 6,829 7,050 7,638 8,288 8,908 9,112 9,324CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection Costs30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914Methanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 63,101 63,382 63,687 63,991 66,428 69,602 71,706 75,941 78,462 70,872 96,782 89,489 93,234 96,811 100,346 103,461Total CO2 Charge ($000)000005,334 6,331 7,385 8,496 9,667 10,934 12,161 13,693 15,132 15,418 19,708 19,792 21,514 23,202 23,814 24,360Incremental Non-fuel Production Cost ($000)0000050,131 50,212 50,298 50,385 50,478 50,565 50,659 50,756 50,872 51,044 51,049 51,152 51,262 51,363 51,473 51,585R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-6Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 210Case:1-6 Base Load, Add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 171,070 171,950 172,530 173,213 180,076 187,015 194,598 202,075 209,895 217,243 230,511 239,482 250,789 262,165 273,252 284,779Total Authority CO2 Charges ($000)0000011,632 13,855 16,175 18,625 21,225 23,872 26,774 29,744 32,951 36,396 39,818 43,394 47,384 51,450 53,107 54,813Total Authority Incremental Non-fuel Production Cost ($000)0000050,131 50,212 50,298 50,385 50,478 50,565 50,659 50,756 50,872 51,044 51,049 51,152 51,262 51,363 51,473 51,585Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 252,799 256,443 258,667 263,599 273,646 282,504 294,916 305,987 316,256 329,184 346,443 358,157 375,666 391,813 403,665 419,259Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 241,167 242,588 242,491 244,974 252,421 258,632 268,142 276,242 283,305 292,788 306,625 314,763 328,281 340,362 350,557 364,446NPV with CO2 Charge ($000)3,038,093NPV without CO2 Charge ($000)2,819,989R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-6Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 211Case:1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 692,398 700,412 708,523 716,731 725,037CC 1MWh440,702 424,991 427,346 430,844Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,1500000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh30,299 40,164 41,135 41,994Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,6400000000000000000CO2 Charge ($000)Unit 15MWh979 380 140 21041,022 41,580 42,404 41,881 42,455 42,403 42,819 43,912 44,751 45,019 43,753 45,084 45,986 45,290 47,332 46,468Fuel + CO2 Charge ($000)308 126 49 7314,238 14,458 14,742 14,801 15,431 15,820 16,617 17,672 18,436 19,351 19,686 20,947 22,197 22,736 24,110 24,612CO2 Charge ($000)729 870 1,024 1,168 1,326 1,463 1,645 1,861 2,055 2,263 2,405 2,661 2,928 3,102 3,267 3,311Unit 18MWh8,470 12,805 13,357 14,568120,913 122,073 122,146 121,650 123,696 125,841 125,432 129,214 129,610 130,234 130,638 133,108 135,217 137,400 139,597 139,576Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,45229,715 29,964 30,131 30,262 31,789 33,328 34,525 36,546 38,106 39,828 41,585 43,803 46,202 48,554 50,566 52,065CO2 Charge ($000)1,520 1,802 2,091 2,388 2,730 3,082 3,418 3,849 4,248 4,657 5,080 5,565 6,093 6,625 6,851 7,005Unit 22MWh80,936 83,941 84,753 85,54459,510 62,729 65,803 67,752 74,678 77,862 82,074 84,088 89,267 90,666 91,341 94,247 97,567 101,366 105,706 106,383Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34910,412 11,031 11,626 12,061 13,820 14,915 16,374 17,403 19,153 20,339 21,392 22,944 24,743 26,742 28,707 29,775CO2 Charge ($000)533 664 808 951 1,188 1,379 1,621 1,833 2,135 2,376 2,614 2,915 3,263 3,649 3,890 4,006Unit 23MWh4,000 3,318 5,469 5,6408,486 7,418 9,901 8,509 10,408 13,304 11,944 13,526 14,476 12,883 11,877 18,706 19,474 19,697 23,610 22,794Fuel + CO2 Charge ($000)1,035 845 1,471 1,4792,299 2,000 2,684 2,276 2,979 3,901 3,666 4,284 4,843 4,451 4,335 6,936 7,513 7,892 9,787 9,678CO2 Charge ($000)118 120 187 181 256 361 363 451 540 522 530 881 992 1,077 1,326 1,302New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 53,764 53,998 55,073 54,712 58,520 61,680 64,136 67,911 71,559 74,152 76,370 82,608 87,380 91,471 97,837 100,506Total CO2 Charge ($000)000002,899 3,456 4,110 4,687 5,500 6,284 7,047 7,995 8,979 9,818 10,628 12,022 13,276 14,454 15,334 15,624Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-7Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 211Case:1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 396,297 398,174 400,059 401,955 403,859CC 1MWh306,767 302,805 304,385 306,953Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,5380000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,873 47,522 47,458 46,613Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,489CO2 Charge ($000)Unit 16MWh0000878 720 1,795 2,433 604 1,503 1,628 1,184 1,385 2,272 1,346 1,693 2,704 2,217 1,874 3,629Fuel + CO2 Charge ($000)0000249 198 496 677 182 455 532 413 488 799 522 684 1,081 950 828 1,621CO2 Charge ($000)13 12 35 53 16 42 53 43 55 93 64 87 143 130 112 218Unit 17MWh000062,478 66,087 64,270 66,078 67,827 68,173 70,843 71,846 75,101 75,316 74,166 78,386 77,309 80,757 80,961 81,699Fuel + CO2 Charge ($000)000012,729 13,495 13,140 13,547 14,447 15,094 16,182 17,010 18,474 19,263 19,795 21,694 22,329 24,268 25,020 26,009CO2 Charge ($000)651 812 913 1,070 1,241 1,396 1,602 1,792 2,060 2,253 2,418 2,756 2,944 3,311 3,390 3,499Unit 19MWh0000156 204 284 374 136 355 42 197 76 214 173 282 997 93 282 812Fuel + CO2 Charge ($000)000045 61 88 113 44 114 15 69 29 84 70 115 428 46 137 390CO2 Charge ($000)2 4 6 9 4 11 1 7 3 10 9 15 56 6 19 52Unit 20MWh000076,343 77,996 80,195 81,317 84,141 83,815 87,686 86,930 92,451 92,522 91,936 96,239 97,470 100,639 105,040 105,690Fuel + CO2 Charge ($000)000018,481 18,918 19,384 19,768 21,193 21,767 23,591 24,538 26,727 27,801 28,821 31,230 32,978 35,379 37,897 39,266CO2 Charge ($000)946 1,138 1,346 1,561 1,821 2,013 2,335 2,585 2,980 3,252 3,521 3,968 4,350 4,828 5,135 5,283New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,807 2,862 2,930 2,997 3,076 3,137 3,210 3,284 3,370 3,437 3,517 3,598 3,691 3,765 3,852 3,940Capital Cost ($000)21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672MWh313,272 312,329 312,508 312,444 313,470 312,565 312,630 312,638 313,562 312,654 312,685 312,691 313,619 312,677 312,715 312,719Fuel + CO2 Charge ($000)13,974 14,830 15,770 16,743 17,922 19,005 20,213 21,463 22,827 24,208 25,709 27,231 28,934 30,512 31,327 32,158CO2 Charge ($000)4,429 5,213 6,048 6,918 7,853 8,754 9,739 10,763 11,864 12,943 14,100 15,274 16,576 17,815 18,228 18,647CFB2Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,724 2,796 2,869 2,992 3,004 3,077 3,154 3,231 3,225 3,391 3,621 3,558 3,640 3,728 3,735 3,904Capital Cost ($000)21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672MWh304,086 305,098 305,973 311,908 306,155 306,529 307,171 307,566 300,120 308,420 321,975 309,295 309,252 309,613 303,214 309,847Fuel + CO2 Charge ($000)13,570 14,489 15,442 16,709 17,491 18,645 19,864 21,114 21,843 23,864 26,450 26,940 28,527 30,211 30,370 31,858CO2 Charge ($000)4,299 5,091 5,919 6,899 7,656 8,588 9,569 10,586 11,350 12,754 14,499 15,112 16,340 17,640 17,672 18,474CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection Costs30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914Methanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 48,709 49,722 50,054 51,048 52,689 54,278 57,097 58,830 62,076 64,714 66,757 70,683 73,868 77,637 81,024 85,128Total CO2 Charge ($000)0000010,340 12,270 14,266 16,510 18,591 20,803 23,300 25,776 28,312 31,305 34,610 37,211 40,408 43,730 44,556 46,174Incremental Non-fuel Production Cost ($000)0000088,546 88,875 89,222 89,622 89,929 90,284 90,660 91,042 91,357 91,832 92,389 92,660 93,094 93,520 93,885 94,420R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-7Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 211Case:1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 102,473 103,720 105,127 105,760 111,209 115,958 121,232 126,741 133,636 138,866 143,126 153,291 161,248 169,108 178,860 185,634Total Authority CO2 Charges ($000)0000013,239 15,726 18,375 21,198 24,090 27,087 30,347 33,771 37,291 41,123 45,238 49,234 53,684 58,183 59,889 61,798Total Authority Incremental Non-fuel Production Cost ($000)0000088,546 88,875 89,222 89,622 89,929 90,284 90,660 91,042 91,357 91,832 92,389 92,660 93,094 93,520 93,885 94,420Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 217,176 221,444 226,056 230,125 238,993 247,318 256,456 266,005 276,975 286,758 295,942 310,629 323,733 336,787 348,885 358,383Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 203,937 205,718 207,681 208,928 214,903 220,231 226,110 232,234 239,685 245,635 250,703 261,396 270,048 278,603 288,995 296,585NPV with CO2 Charge ($000)2,729,712NPV without CO2 Charge ($000)2,482,575R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-7Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 212Case:1-8 Same as Case 1-1, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 692,398 700,412 708,523 716,731 725,037CC 1MWh440,702 424,991 427,346 430,844386,378 414,458 404,065 413,508 421,889 412,818 412,630 413,054 413,464 423,066 415,866 416,428 418,337 420,020 421,505 443,117Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,150 86,743 93,285 91,250 93,807 99,285 100,929 104,874 109,026 113,367 121,013 123,919 129,209 135,301 141,255 146,011157,763CO2 Charge ($000)4,782 6,038 6,808 7,962 9,152 10,027 11,147 12,320 13,547 15,160 16,210 17,588 19,107 20,638 21,185 22,731Unit 13MWh30,299 40,164 41,135 41,99499,964 86,779 94,895 93,231 92,716 102,839 104,282 108,715 111,849 112,895 120,885 128,704 130,403 136,859 138,215 134,629Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,640 20,347 17,719 19,582 19,470 20,153 23,437 24,631 27,008 28,992 31,013 34,599 38,773 41,018 45,041 46,853 47,919CO2 Charge ($000)1,212 1,241 1,583 1,775 2,010 2,500 2,812 3,279 3,725 4,178 4,863 5,649 6,203 7,036 7,269 7,382Unit 15MWh979 380 140 21080 867 1,355 10 442 328 501 859 568 408 903 689 914 1,661Fuel + CO2 Charge ($000)308 126 49 730 29 303 453 4 0 164 130 220 369 260 189 441 360 476 855CO2 Charge ($000)0 2 21 36 0 0 16 14 25 43 32 24 58 49 64 115Unit 18MWh8,470 12,805 13,357 14,56819,716 16,281 17,397 17,772 15,246 16,987 16,905 18,432 17,844 17,147 19,764 17,018 19,264 21,398 20,778 16,872Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,4524,908 4,025 4,275 4,410 4,002 4,653 4,719 5,375 5,368 5,362 6,460 5,811 6,849 7,883 7,712 6,544CO2 Charge ($000)252 243 299 350 347 430 468 567 600 630 792 738 904 1,075 1,044 880Unit 22MWh80,936 83,941 84,753 85,54497,008 94,960 98,140 100,683 104,142 108,329 111,418 113,636 115,230 116,278 119,065 120,666 121,772 122,899 123,129 123,075Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,34917,256 17,067 17,719 18,267 19,634 21,134 22,600 23,901 25,170 26,500 28,223 29,715 31,230 32,770 33,837 34,831CO2 Charge ($000)883 1,027 1,230 1,440 1,687 1,954 2,237 2,517 2,806 3,096 3,447 3,775 4,119 4,472 4,585 4,686Unit 23MWh4,000 3,318 5,469 5,6407,243 4,760 9,052 5,036 4,906 5,336 7,925 7,132 10,012 7,319 9,253 11,098 11,247 8,717 14,410 7,487Fuel + CO2 Charge ($000)1,035 845 1,471 1,4792,026 1,318 2,446 1,457 1,491 1,687 2,479 2,358 3,372 2,629 3,442 4,258 4,453 3,709 6,031 3,280CO2 Charge ($000)104 79 170 117 129 156 245 249 377 311 422 541 588 506 817 441New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 124,047 124,814 125,463 126,184 131,243 136,773 142,542 148,852 155,410 163,468 171,135 179,639 188,313 197,241 205,956 214,957Total CO2 Charge ($000)000007,233 8,630 10,111 11,681 13,326 15,068 16,925 18,946 21,080 23,419 25,767 28,316 30,979 33,776 34,964 36,235Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-8Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 212Case:1-8 Same as Case 1-1, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 396,297 398,174 400,059 401,955 403,859CC 1MWh306,767 302,805 304,385 306,953306,373 313,671 315,349 321,350 325,094 324,185 323,250 323,673 323,621 325,440 323,472 323,239 323,925 323,584 321,429 326,164Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,538 66,407 68,169 68,806 70,356 73,932 76,387 79,066 82,093 85,172 89,229 92,321 95,940 100,187 104,082 106,405 111,233CO2 Charge ($000)3,397 4,099 4,774 5,551 6,348 7,063 7,827 8,645 9,493 10,431 11,275 12,189 13,213 14,203 14,418 14,966CC 2MWh49,873 47,522 47,458 46,61377,736 70,037 69,061 62,323 59,798 62,577 66,134 67,326 69,657 69,239 73,179 75,522 76,773 78,642 84,083 80,215Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,489 16,924 15,331 15,204 13,794 13,758 14,963 16,434 17,381 18,693 19,368 21,338 22,953 24,343 25,959 28,595 28,111CO2 Charge ($000)910 968 1,107 1,141 1,238 1,452 1,706 1,918 2,182 2,371 2,728 3,054 3,360 3,708 4,056 3,959Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 79,023 78,432 78,128 77,457 80,103 82,836 85,967 88,910 92,190 95,795 99,656 103,650 107,956112,131 116,526 120,419Total CO2 Charge ($000)000004,307 5,067 5,881 6,692 7,587 8,514 9,533 10,564 11,675 12,802 14,003 15,243 16,573 17,911 18,474 18,925Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-8Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 212Case:1-8 Same as Case 1-1, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 203,071 203,246 203,591 203,641 211,346 219,609 228,509 237,761 247,600 259,263 270,791 283,289 296,269 309,372 322,483 335,375Total Authority CO2 Charges ($000)0000011,540 13,697 15,992 18,373 20,912 23,582 26,458 29,510 32,755 36,222 39,771 43,559 47,552 51,687 53,438 55,160Total Authority Incremental Non-fuel Production Cost ($000)000000000000000000000Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Non-Fuel production Expense STT ($000) [1]5,012 5,127 5,245 5,365 5,489 5,615 5,744 5,876 6,012 6,150 6,291 6,436 6,584 6,735 6,890 7,049 7,211 7,377 7,546 7,720 7,898Non-Fuel production Expense STC ($000) [1]3,124 3,196 3,269 3,344 3,421 3,500 3,581 3,663 3,747 3,833 3,922 4,012 4,104 4,198 4,295 4,394 4,495 4,598 4,704 4,812 4,923Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Non-Fuel Expenses STT ($000) [2]604 618 632 647 662 677 692 708 725 741 758 776 794 812 831 850 869 889 910 931 952Non-Fuel Expenses STC ($000) [2]922 944 965 988 1,010 1,033 1,057 1,082 1,106 1,132 1,158 1,185 1,212 1,240 1,268 1,297 1,327 1,358 1,389 1,421 1,454Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal System Non-fuel O&M STT ($000) [3]2,404 2,459 2,516 2,574 2,6330000000000000000Existing Desal System Non-fuel O&M STC ($000) [3]2,602 2,662 2,723 2,785 2,8490000000000000000Existing Desal Capital Improvements ($000)Existing Desal Capital Improvements STT ($000) [3]Existing Desal Capital Improvements STC ($000) [3]New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 236,645 239,391 242,455 245,318 256,006 267,392 279,632 292,411 305,980 321,606 337,192 353,998 371,502 389,285 404,703 419,887Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 225,104 225,694 226,463 226,946 235,094 243,810 253,175 262,901 273,225 285,385 297,421 310,439 323,951 337,598 351,265 364,727NPV with CO2 Charge ($000)2,947,923NPV without CO2 Charge ($000)2,730,622R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls1-8Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 213Case:1-9 Same as Case 1-3, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 88.5 88.5 89.5 90.6 95.2 96.3 97.4 98.5 99.7 100.8 102.0 103.2 104.4 105.6 106.8 108.0 109.3 110.6 111.9 113.2Energy Requirements563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 692,398 700,412 708,523 716,731 725,037CC 1MWh440,702 424,991 427,346 430,844406,232 402,539 416,479 428,767 415,399 434,369 426,046 442,315 444,639 459,026 455,065 461,188 463,238 470,640 471,555 499,286Fuel + CO2 Charge ($000)105,342 97,604 101,047 101,150 70,029 69,360 73,804 77,077 77,429 85,301 84,881 89,447 93,361 98,737 101,991 107,630 113,152 117,579 120,490 131,089CO2 Charge ($000)3,826 4,455 5,325 6,249 6,800 7,944 8,657 9,888 10,905 12,274 13,202 14,465 15,693 17,123 17,539 18,937Unit 13MWh30,299 40,164 41,135 41,99431,586 35,792 31,724 27,741 36,815 30,866 37,955 31,232 34,005 28,616 33,796 34,626 36,204 36,768 39,544 29,375Fuel + CO2 Charge ($000)6,227 8,006 8,438 8,640 5,136 5,829 5,321 4,813 6,691 5,928 7,225 6,126 6,862 5,971 7,395 7,851 8,599 9,016 9,815 7,631CO2 Charge ($000)282 376 387 390 591 552 738 679 805 746 962 1,055 1,195 1,313 1,428 1,101Unit 15MWh979 380 140 21052 564 857 0 62 83 400 279 480 671 455 246 775 558 770 1,552Fuel + CO2 Charge ($000)308 126 49 73 14 142 229 0 18 25 109 83 155 212 150 81 283 215 291 583CO2 Charge ($000)1 9 16 0 2 2 11 9 18 26 19 11 39 31 42 84Unit 18MWh8,470 12,805 13,357 14,56825,484 30,478 23,541 25,163 32,601 28,809 31,614 31,919 30,914 31,574 36,095 35,000 38,623 41,536 39,708 36,759Fuel + CO2 Charge ($000)2,037 2,989 3,218 3,452 4,132 4,957 4,006 4,364 5,883 5,480 6,105 6,381 6,453 6,918 8,249 8,530 9,859 10,967 10,818 10,586CO2 Charge ($000)226 320 291 354 520 510 623 707 757 863 1,071 1,146 1,369 1,597 1,574 1,528Unit 22MWh80,936 83,941 84,753 85,544143,678 144,382 144,968 145,824 147,521 147,217 147,849 148,194 148,762 148,871 149,186 149,301 149,716 149,514 149,622 149,618Fuel + CO2 Charge ($000)13,790 13,717 14,282 14,349 17,558 17,673 18,292 18,707 19,697 20,734 21,118 21,563 22,504 23,109 24,213 25,294 26,582 27,245 27,898 28,762CO2 Charge ($000)960 1,136 1,321 1,515 1,732 1,931 2,154 2,384 2,631 2,873 3,136 3,399 3,688 3,968 4,061 4,154Unit 23MWh4,000 3,318 5,469 5,6406,417 5,678 8,061 5,042 7,116 5,432 10,139 7,732 10,438 8,035 9,993 12,112 11,903 9,514 15,509 8,259Fuel + CO2 Charge ($000)1,035 845 1,471 1,479 1,277 1,145 1,599 1,067 1,574 1,294 2,310 1,854 2,537 2,060 2,661 3,328 3,402 2,871 4,577 2,568CO2 Charge ($000)70 74 116 86 139 121 236 205 298 259 346 447 473 418 666 370New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 128,740 123,288 128,504 129,143 92,781 92,737 95,795 97,435 101,509 107,701 109,329 111,580 116,459 119,965 125,923 132,191 139,420 143,443 148,580 155,046Total CO2 Charge ($000)000005,364 6,369 7,456 8,594 9,783 11,060 12,419 13,872 15,413 17,042 18,737 20,524 22,456 24,450 25,309 26,174Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls1-9Page 1 of 3;8/25/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 213Case:1-9 Same as Case 1-3, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 56.0 56.2 56.5 56.8 57.0 57.3 57.6 57.8 58.1 58.4 58.7 59.0 59.2 59.5 59.8 60.1Energy Requirements360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 396,297 398,174 400,059 401,955 403,859CC 1MWh306,767 302,805 304,385 306,953302,814 311,271 310,330 313,299 317,077 314,974 315,623 316,274 317,282 319,812 316,979 317,535 318,512 318,837 318,643 323,426Fuel + CO2 Charge ($000)64,284 61,273 63,397 63,538 46,982 48,403 49,752 51,059 53,860 56,352 57,292 58,426 60,893 63,025 65,235 68,139 71,621 73,495 75,101 78,583CO2 Charge ($000)2,568 3,111 3,593 4,139 4,735 5,248 5,845 6,461 7,118 7,840 8,450 9,157 9,936 10,703 10,931 11,350CC 2MWh49,873 47,522 47,458 46,61386,611 75,812 80,111 77,873 75,198 79,952 81,259 82,251 83,282 80,939 86,829 87,847 87,974 87,842 90,283 85,316Fuel + CO2 Charge ($000)11,360 10,415 10,723 10,489 13,808 12,139 13,242 13,105 13,192 14,817 15,291 15,775 16,621 16,588 18,604 19,666 20,657 21,161 22,261 21,692CO2 Charge ($000)754 780 955 1,061 1,159 1,380 1,560 1,744 1,941 2,063 2,408 2,643 2,865 3,082 3,240 3,133Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 75,644 71,688 74,120 74,028 57,468 56,652 58,445 58,964 61,158 64,541 65,180 65,997 68,455 69,711 72,981 76,004 79,477 80,872 83,191 85,792Total CO2 Charge ($000)000003,323 3,891 4,549 5,200 5,894 6,628 7,404 8,205 9,059 9,902 10,859 11,800 12,801 13,784 14,171 14,483Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls1-9Page 2 of 3;8/25/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 213Case:1-9 Same as Case 1-3, Replace existing MED water system with RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 204,383 194,976 202,623 203,170 150,249 149,389 154,241 156,399 162,667 172,243 174,509 177,577 184,914 189,675 198,904 208,195 218,897 224,315 231,771 240,838Total Authority CO2 Charges ($000)000008,687 10,260 12,005 13,794 15,677 17,688 19,823 22,077 24,473 26,944 29,595 32,324 35,257 38,234 39,481 40,656Total Authority Incremental Non-fuel Production Cost ($000)000000000000000000000Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Non-Fuel production Expense STT ($000) [1]5,012 5,127 5,245 5,365 5,489 5,615 5,744 5,876 6,012 6,150 6,291 6,436 6,584 6,735 6,890 7,049 7,211 7,377 7,546 7,720 7,898Non-Fuel production Expense STC ($000) [1]3,124 3,196 3,269 3,344 3,421 3,500 3,581 3,663 3,747 3,833 3,922 4,012 4,104 4,198 4,295 4,394 4,495 4,598 4,704 4,812 4,923Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Non-Fuel Expenses STT ($000) [2]604 618 632 647 662 677 692 708 725 741 758 776 794 812 831 850 869 889 910 931 952Non-Fuel Expenses STC ($000) [2]922 944 965 988 1,010 1,033 1,057 1,082 1,106 1,132 1,158 1,185 1,212 1,240 1,268 1,297 1,327 1,358 1,389 1,421 1,454Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal System Non-fuel O&M STT ($000) [3]2,404 2,459 2,516 2,574 2,6330000000000000000Existing Desal System Non-fuel O&M STC ($000) [3]2,602 2,662 2,723 2,785 2,8490000000000000000Existing Desal Capital Improvements ($000)Existing Desal Capital Improvements STT ($000) [3]Existing Desal Capital Improvements STC ($000) [3]New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 180,969 182,096 189,116 193,497 202,092 214,133 218,997 224,794 235,012 242,741 255,129 267,670 281,836 290,775 300,034 310,846Total Electric and Water Without CO2 Charge ($000)14,668 219,389 210,327 218,327 219,235 172,282 171,836 177,112 179,703 186,414 196,444 199,174 202,717 210,539 215,797 225,534 235,345 246,578 252,540 260,554 270,189NPV with CO2 Charge ($000)2,429,090NPV without CO2 Charge ($000)2,267,193R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls1-9Page 3 of 3;8/25/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 214Case:2-1 High Requirements Load , no retirements, all oil fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh449,159 385,716 448,406 453,360 454,582 480,427 466,555 513,432 430,979 486,545 492,539 521,325 493,214 512,628 520,864 530,515 559,590 544,455 534,776 550,083Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,139 111,013 117,644 114,559 126,399 109,959 128,663 134,988 148,078 145,252 157,057 166,010 175,824 193,052 195,318 197,503 209,115CO2 Charge ($000)6,120 7,615 8,547 10,728 10,136 12,783 14,348 16,733 17,358 19,675 21,717 23,934 27,263 28,537 28,656 30,131Unit 13MWh31,293 74,466 43,638 48,090 54,192 48,757 67,571 55,504 64,173 45,799 49,027 44,629 68,137 69,376 76,180 83,439 82,867 104,138 117,017 125,004Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,126 12,139 11,298 15,689 13,558 14,996 11,228 12,500 12,154 19,121 20,560 23,713 27,242 28,821 37,193 42,745 47,105CO2 Charge ($000)723 791 1,265 1,237 1,493 1,198 1,427 1,476 2,455 2,766 3,330 3,969 4,357 5,811 6,632 7,258Unit 15MWh1,159 761 100 318 220 130 869 40 277 60 20 91 100 963 626 560 1,110 1,603Fuel + CO2 Charge ($000)355 249 35 107 80 47 303 15 104 0 25 9 40 0 48 419 311 283 551 796CO2 Charge ($000)4 3 21 1 9 0 2 1 4 0 6 53 41 38 74 107Unit 18MWh9,075 25,082 15,070 15,973 15,369 12,530 17,773 8,763 14,503 9,845 12,723 8,442 14,404 13,856 16,967 16,151 14,314 21,219 25,692 27,412Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,880 3,863 3,126 4,363 2,180 4,014 2,810 3,586 2,563 4,367 4,380 5,535 5,459 5,072 7,805 9,571 10,602CO2 Charge ($000)198 189 305 172 346 260 355 271 488 515 678 693 670 1,065 1,296 1,426Unit 22MWh85,208 103,456 100,225 108,759 117,644 122,559 128,463 130,199 135,237 134,445 135,933 137,471 140,291 141,833 142,582 143,274 143,971 143,905 143,878 144,102Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,017 20,388 21,324 22,402 22,834 24,528 25,326 26,532 27,779 29,298 30,749 32,188 33,638 35,209 36,638 37,741 38,933CO2 Charge ($000)1,043 1,283 1,555 1,800 2,107 2,342 2,626 2,926 3,266 3,592 3,931 4,274 4,643 5,000 5,114 5,238Unit 23MWh4,655 8,719 8,761 8,099 11,693 8,896 12,259 6,362 6,020 4,449 7,301 4,763 10,705 10,329 11,335 12,315 10,792 13,115 24,548 19,542Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,153 3,189 2,416 3,343 1,749 1,724 1,349 2,238 1,560 3,564 3,584 4,095 4,541 4,073 5,180 9,542 7,878CO2 Charge ($000)163 146 233 138 148 125 221 165 398 422 502 577 538 706 1,292 1,059New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)304 282 312 336 399 423 456 495 517 585 639 691Capital Cost ($000)4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305MWh84,507 76,709 82,917 87,250 101,256 104,880 110,475 117,231 119,842 132,504 141,345 149,481Fuel + CO2 Charge ($000)0000000019,848 19,074 21,527 23,663 28,254 30,669 33,647 37,103 39,621 45,149 49,419 53,868CO2 Charge ($000)00001,707 1,764 2,131 2,493 3,151 3,587 4,111 4,714 5,226 6,161 6,696 7,248CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 142,420 145,828 148,734 152,659 159,227 169,980 180,285 191,743 202,778 216,440 230,961 246,011 263,421 280,248 297,312 315,830Total CO2 Charge ($000)000008,252 10,026 11,926 14,075 15,947 18,470 21,112 24,063 27,119 30,559 34,276 38,214 42,738 47,318 49,762 52,467Incremental Non-fuel Production Cost ($000)0000000006,104 6,117 6,182 6,242 6,342 6,403 6,475 6,553 6,616 6,725 6,821 6,916R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 214Case:2-1 High Requirements Load , no retirements, all oil fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,047 333,222 330,887 327,570 324,126 320,434 315,156 314,890 313,520 313,296 313,605Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,169 71,103 71,568 71,738 72,324 75,083 77,860 80,383 83,071 85,729 88,637 91,649 94,300 98,338 102,056 105,103 108,378CO2 Charge ($000)3,638 4,304 4,978 5,706 6,448 7,199 7,957 8,749 9,555 10,362 11,194 11,980 12,969 13,926 14,241 14,582CC 2MWh49,051 51,273 49,299 51,079 52,560 57,039 64,155 68,945 75,907 82,134 91,034 99,555 109,070 118,388 128,505 140,661 147,684 154,942 161,964 168,497Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,475 12,436 13,558 15,341 16,591 19,000 21,391 24,659 28,037 31,941 36,166 40,957 46,764 51,207 55,973 60,290 64,620CO2 Charge ($000)669 856 1,117 1,373 1,710 2,075 2,560 3,095 3,729 4,428 5,237 6,222 7,069 7,995 8,551 9,102Unit 16MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh56 141 281 461 743 1,389 1,682 1,735 1,550 2,749 3,021 3,460Fuel + CO2 Charge ($000)0 0 0 0 0 0 0 0 20 52 108 184 307 599 756 812 7551,386 1,557 1,822CO2 Charge ($000)0 0 0 0 2 5 11 19 34 70 92 103 99 189 211 245Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 79,233 79,967 80,984 81,835 85,944 90,024 94,622 99,429 104,657 110,541 116,839 123,570 130,162 137,304 143,946 150,892Total CO2 Charge ($000)000004,306 5,160 6,095 7,079 8,159 9,279 10,527 11,863 13,319 14,860 16,523 18,305 20,138 22,110 23,004 23,928Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 214Case:2-1 High Requirements Load , no retirements, all oil fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 221,653 225,795 229,718 234,494 245,171 260,004 274,908 291,172 307,435 326,981 347,799 369,581 393,583 417,553 441,258 466,722Total Authority CO2 Charges ($000)0000012,558 15,186 18,021 21,154 24,106 27,749 31,639 35,926 40,438 45,419 50,799 56,519 62,876 69,428 72,765 76,395Total Authority Incremental Non-fuel Production Cost ($000)0000000006,104 6,117 6,182 6,242 6,342 6,403 6,475 6,553 6,616 6,725 6,821 6,916Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 254,178 261,407 267,403 277,024 297,249 314,922 335,614 356,751 376,753 403,304 430,137 456,782 489,306 520,540 546,677 578,115Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 241,619 246,221 249,381 255,870 273,143 287,173 303,975 320,825 336,315 357,885 379,338 400,262 426,430 451,112 473,911 501,721NPV with CO2 Charge ($000)3,461,340NPV without CO2 Charge ($000)3,189,954R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 215Case:2-1W Same as Case 2-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh449,159 385,716 448,406 453,360454,582 480,427 466,555 513,432 430,979 486,545 492,539 521,325 493,214 512,628 520,864 530,515 559,590 544,455 534,776 550,083Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,139111,013 117,644 114,559 126,399 109,959 128,663 134,988 148,078 145,252 157,057 166,010 175,824 193,052 195,318 197,503 209,115CO2 Charge ($000)6,120 7,615 8,547 10,728 10,136 12,783 14,348 16,733 17,358 19,675 21,717 23,934 27,263 28,537 28,656 30,131Unit 13MWh31,293 74,466 43,638 48,09054,192 48,757 67,571 55,504 64,173 45,799 49,027 44,629 68,137 69,376 76,180 83,439 82,867 104,138 117,017 125,004Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,12612,139 11,298 15,689 13,558 14,996 11,228 12,500 12,154 19,121 20,560 23,713 27,242 28,821 37,193 42,745 47,105CO2 Charge ($000)723 791 1,265 1,237 1,493 1,198 1,427 1,476 2,455 2,766 3,330 3,969 4,357 5,811 6,632 7,258Unit 15MWh1,159 761 100 318220 130 869 40 277 60 20 91 100 963 626 560 1,110 1,603Fuel + CO2 Charge ($000)355 249 35 10780 47 303 15 104 0 25 9 40 0 48 419 311 283 551 796CO2 Charge ($000)4 3 21 1 9 0 2 1 4 0 6 53 41 38 74 107Unit 18MWh9,075 25,082 15,070 15,97315,369 12,530 17,773 8,763 14,503 9,845 12,723 8,442 14,404 13,856 16,967 16,151 14,314 21,219 25,692 27,412Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,8803,863 3,126 4,363 2,180 4,014 2,810 3,586 2,563 4,367 4,380 5,535 5,459 5,072 7,805 9,571 10,602CO2 Charge ($000)198 189 305 172 346 260 355 271 488 515 678 693 670 1,065 1,296 1,426Unit 22MWh85,208 103,456 100,225 108,759117,644 122,559 128,463 130,199 135,237 134,445 135,933 137,471 140,291 141,833 142,582 143,274 143,971 143,905 143,878 144,102Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01720,388 21,324 22,402 22,834 24,528 25,326 26,532 27,779 29,298 30,749 32,188 33,638 35,209 36,638 37,741 38,933CO2 Charge ($000)1,043 1,283 1,555 1,800 2,107 2,342 2,626 2,926 3,266 3,592 3,931 4,274 4,643 5,000 5,114 5,238Unit 23MWh4,655 8,719 8,761 8,09911,693 8,896 12,259 6,362 6,020 4,449 7,301 4,763 10,705 10,329 11,335 12,315 10,792 13,115 24,548 19,542Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1533,189 2,416 3,343 1,749 1,724 1,349 2,238 1,560 3,564 3,584 4,095 4,541 4,073 5,180 9,542 7,878CO2 Charge ($000)163 146 233 138 148 125 221 165 398 422 502 577 538 706 1,292 1,059New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)304 282 312 336 399 423 456 495 517 585 639 691Capital Cost ($000)4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305MWh84,507 76,709 82,917 87,250 101,256 104,880 110,475 117,231 119,842 132,504 141,345 149,481Fuel + CO2 Charge ($000)0000000019,848 19,074 21,527 23,663 28,254 30,669 33,647 37,103 39,621 45,149 49,419 53,868CO2 Charge ($000)00001,707 1,764 2,131 2,493 3,151 3,587 4,111 4,714 5,226 6,161 6,696 7,248CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 142,420 145,828 148,734 152,659 159,227 169,980 180,285 191,743 202,778 216,440 230,961 246,011 263,421 280,248 297,312 315,830Total CO2 Charge ($000)000008,252 10,026 11,926 14,075 15,947 18,470 21,112 24,063 27,119 30,559 34,276 38,214 42,738 47,318 49,762 52,467Incremental Non-fuel Production Cost ($000)0000000006,104 6,117 6,182 6,242 6,342 6,403 6,475 6,553 6,616 6,725 6,821 6,916R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 215Case:2-1W Same as Case 2-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508322,218 326,204 328,963 334,282 336,478 339,062 339,257 339,549 338,649 336,676 333,559 329,214 326,395 324,430 322,418 321,743Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16968,395 69,269 70,029 71,278 74,496 77,706 80,750 83,922 87,066 90,316 93,511 96,438 99,980 103,626 106,285 109,358CO2 Charge ($000)3,499 4,165 4,859 5,624 6,397 7,185 7,993 8,838 9,704 10,559 11,421 12,252 13,186 14,140 14,401 14,713CC 2MWh49,051 51,273 49,299 51,07948,165 49,906 53,270 53,694 57,633 61,181 67,136 73,144 80,373 88,493 98,018 109,234 118,695 126,701 135,402 142,876Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,47511,719 12,190 13,080 13,253 14,794 16,334 18,641 21,115 24,132 27,715 32,044 37,263 42,249 46,994 51,764 56,278CO2 Charge ($000)630 770 953 1,097 1,331 1,585 1,935 2,331 2,818 3,393 4,097 4,958 5,832 6,712 7,342 7,927Unit 16MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh23 62 163 326 686 979 1,066 1,008 2,029 2,405 2,783Fuel + CO2 Charge ($000)0 0 0 0 0 0 0 0 0 1 2 7 15 35 54 63 65 141 170 200CO2 Charge ($000)0 0 0 0 2 5 11 19 34 70 92 103 99 189 211 245Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)548 560 573 586 600 614 628 642 657 672 687 703 719 736 753 770Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 75,984 76,523 77,297 77,812 81,559 85,267 89,454 93,856 98,657 104,044 109,998 116,451 123,176 129,718 136,265 142,951Total CO2 Charge ($000)000004,129 4,935 5,812 6,720 7,730 8,774 9,939 11,188 12,556 14,022 15,611 17,313 19,118 21,042 21,954 22,885Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 215Case:2-1W Same as Case 2-1, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 218,405 222,352 226,031 230,470 240,787 255,247 269,739 285,599 301,435 320,484 340,959 362,462 386,597 409,966 433,577 458,781Total Authority CO2 Charges ($000)0000012,381 14,961 17,738 20,796 23,677 27,245 31,051 35,252 39,675 44,580 49,886 55,527 61,856 68,360 71,716 75,352Total Authority Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 9,354 9,380 9,460 9,534 9,648 9,725 9,812 9,906 9,985 10,111 10,223 10,336Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 253,950 260,949 266,655 275,878 295,685 312,923 333,135 353,796 373,297 399,291 425,721 452,024 484,668 515,271 541,349 572,551Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 241,569 245,987 248,917 255,082 272,008 285,679 302,084 318,544 333,621 354,710 375,835 396,497 422,813 446,911 469,632 497,199NPV with CO2 Charge ($000)3,441,811NPV without CO2 Charge ($000)3,174,963R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-1WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 216Case:2-2 Same as Case 2-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh401,690 350,736 410,081 422,963 432,692 464,471 457,483 507,865 422,204 477,924 485,788 517,383 492,626 515,247 524,775 535,148 565,700 550,664 541,057 556,670Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13975,942 81,499 80,419 89,475 75,017 85,584 87,644 94,069 90,383 95,549 98,524 101,758 109,163 107,751 106,667 110,653CO2 Charge ($000)3,889 4,891 5,546 7,004 6,560 8,288 9,329 10,931 11,393 12,976 14,347 15,826 18,059 18,909 18,994 19,974Unit 13MWh23,755 53,722 30,886 30,668 32,843 25,539 37,346 21,511 35,087 25,342 30,027 21,280 38,119 35,147 39,355 41,457 36,717 52,414 65,849 68,914Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1265,349 4,238 6,201 3,704 6,194 4,550 5,320 3,910 6,937 6,525 7,407 7,875 7,204 10,499 13,141 13,988CO2 Charge ($000)275 256 431 290 546 441 567 456 878 893 1,085 1,225 1,194 1,843 2,341 2,526Unit 15MWh1,159 761 100 318 220 130 869 40 277 60 20 91 100 963 626 560 1,110 1,603Fuel + CO2 Charge ($000)355 249 35 10755 32 209 10 70 0 16 5 24 0 28 235 170 149 285 405CO2 Charge ($000)3 2 15 1 6 0 2 1 3 0 4 37 28 26 51 73Unit 18MWh15,947 44,647 26,547 31,017 32,798 30,415 40,921 33,815 42,356 28,463 29,333 28,064 39,798 41,756 46,546 50,025 51,194 64,751 69,307 75,464Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,8805,323 5,146 7,002 6,167 6,881 4,783 5,021 5,064 7,208 7,796 8,806 9,749 10,335 13,036 14,112 15,548CO2 Charge ($000)273 310 485 483 606 463 535 590 912 1,063 1,288 1,516 1,712 2,288 2,514 2,807Unit 22MWh137,099 140,448 140,832 142,080 143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 144,818 145,217 144,761 144,818 144,818Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01716,658 16,783 16,995 17,150 17,401 17,539 17,750 17,965 18,255 18,488 18,761 19,055 19,429 19,686 19,854 20,039CO2 Charge ($000)853 1,008 1,173 1,341 1,525 1,698 1,890 2,089 2,303 2,511 2,735 2,963 3,215 3,455 3,536 3,618Unit 23MWh4,655 8,719 8,761 8,099 11,693 8,896 12,259 6,362 6,020 4,449 7,301 4,763 10,705 10,329 11,335 12,315 10,792 13,115 24,548 19,542Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1532,181 1,657 2,302 1,208 1,156 882 1,425 967 2,154 2,101 2,344 2,541 2,221 2,754 4,964 4,017CO2 Charge ($000)112 100 160 94 102 85 152 113 273 289 344 395 368 484 885 726New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)304 283 313 337 400 425 460 503 526 590 640 694Capital Cost ($000)4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305MWh84,481 76,852 83,171 87,572 101,487 105,454 111,575 119,162 121,755 133,632 141,677 150,216Fuel + CO2 Charge ($000)0000000013,315 12,489 13,733 14,712 17,114 18,117 19,414 20,963 21,829 24,167 25,792 27,580CO2 Charge ($000)00001,169 1,209 1,463 1,711 2,161 2,465 2,833 3,260 3,613 4,242 4,593 4,979CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 100,103 102,788 105,318 108,501 109,522 113,643 116,971 120,803 124,152 128,379 132,647 136,954 142,161 146,794 151,900 157,527Total CO2 Charge ($000)000005,405 6,567 7,809 9,213 10,513 12,185 13,938 15,890 17,924 20,197 22,637 25,222 28,190 31,248 32,915 34,704Incremental Non-fuel Production Cost ($000)0000000006,104 6,118 6,183 6,243 6,343 6,406 6,479 6,561 6,624 6,730 6,822 6,920R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-2Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 216Case:2-2 Same as Case 2-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,059 333,239 330,887 327,570 324,126 320,468 315,156 314,890 313,520 313,296 313,605Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16948,584 49,030 49,337 49,882 50,356 50,873 51,140 51,493 51,818 52,153 52,535 52,713 53,625 54,295 54,717 55,269CO2 Charge ($000)2,489 2,945 3,406 3,905 4,412 4,926 5,445 5,987 6,539 7,091 7,661 8,198 8,875 9,530 9,745 9,978CC 2MWh49,051 51,273 49,299 51,079 52,560 57,039 64,155 68,945 75,907 82,109 91,009 99,555 109,070 118,388 128,455 140,661 147,684 154,942 161,964 168,497Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4758,699 9,504 10,790 11,701 13,027 14,272 16,015 17,742 19,706 21,713 23,939 26,650 28,464 30,347 31,987 33,586CO2 Charge ($000)445 570 744 915 1,139 1,382 1,705 2,062 2,484 2,950 3,487 4,145 4,709 5,326 5,697 6,063Unit 16MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh56 141 281 461 743 1,389 1,682 1,735 1,550 2,749 3,021 3,460Fuel + CO2 Charge ($000)00000 0 0 0 13 34 69 114 186 353 434 454 412 738 812 930CO2 Charge ($000)0 0 0 0 1 3 7 13 23 48 63 71 68 130 145 168Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 54,348 55,019 55,976 56,764 57,844 58,866 60,066 61,287 62,663 64,131 65,698 67,404 68,849 70,396 71,929 73,576Total CO2 Charge ($000)000002,935 3,515 4,151 4,819 5,552 6,312 7,157 8,062 9,046 10,089 11,211 12,413 13,652 14,985 15,586 16,209Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-2Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 216Case:2-2 Same as Case 2-1 but with methanol fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 154,451 157,807 161,294 165,264 167,366 172,509 177,037 182,091 186,815 192,510 198,344 204,358 211,010 217,190 223,830 231,102Total Authority CO2 Charges ($000)000008,340 10,083 11,959 14,032 16,065 18,497 21,095 23,952 26,970 30,285 33,848 37,636 41,842 46,233 48,501 50,913Total Authority Incremental Non-fuel Production Cost ($000)0000000006,104 6,118 6,183 6,243 6,343 6,406 6,479 6,561 6,624 6,730 6,822 6,920Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 182,757 188,315 192,917 200,673 211,403 218,175 227,201 235,697 242,665 253,702 263,736 272,684 285,706 296,987 304,985 317,017Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 174,417 178,233 180,957 186,640 195,338 199,678 206,106 211,745 215,695 223,416 229,888 235,048 243,865 250,754 256,484 266,104NPV with CO2 Charge ($000)2,507,940NPV without CO2 Charge ($000)2,327,212R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-2Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 217Case:2-3 Same as Case 2-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh401,690 350,736 410,081 422,963 432,692 464,471 457,483 507,865 422,204 477,924 485,788 517,383 492,626 515,247 524,775 535,148 565,700 550,664 541,057 556,670Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13979,539 85,090 85,892 96,548 83,460 99,438 102,215 110,491 108,998 116,638 123,853 131,582 145,497 145,090 145,810 154,505CO2 Charge ($000)4,345 5,465 6,197 7,827 7,330 9,261 10,425 12,214 12,731 14,499 16,032 17,684 20,179 21,129 21,224 22,319Unit 13MWh23,755 53,722 30,886 30,668 32,843 25,539 37,346 21,511 35,087 25,342 30,027 21,280 38,119 35,147 39,355 41,457 36,717 52,414 65,849 68,914Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1265,596 4,424 6,619 3,991 6,905 5,281 6,198 4,593 8,362 7,980 9,325 10,172 9,594 14,129 17,960 19,533CO2 Charge ($000)307 286 481 323 609 492 633 509 980 996 1,211 1,367 1,333 2,058 2,613 2,820Unit 15MWh1,159 761 100 318 220 130 869 40 277 60 20 91 100 963 626 560 1,110 1,603Fuel + CO2 Charge ($000)355 249 35 10757 34 223 11 78 0 18 6 29 0 35 303 226 202 393 569CO2 Charge ($000)3 2 16 1 7 0 2 1 3 0 5 41 31 29 57 82Unit 18MWh15,947 44,647 26,547 31,017 32,798 30,415 40,921 33,815 42,356 28,463 29,333 28,064 39,798 41,756 46,546 50,025 51,194 64,751 69,307 75,464Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,8805,569 5,371 7,473 6,648 7,671 5,552 5,850 5,947 8,688 9,522 11,077 12,592 13,762 17,539 19,281 21,701CO2 Charge ($000)305 346 541 539 677 517 597 659 1,018 1,187 1,437 1,692 1,910 2,554 2,806 3,134Unit 22MWh137,099 140,448 140,832 142,080 143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 144,818 145,217 144,761 144,818 144,818Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01717,344 17,422 18,047 18,391 19,262 20,258 20,579 20,981 21,889 22,436 23,458 24,495 25,745 26,356 26,985 27,825CO2 Charge ($000)948 1,120 1,303 1,489 1,694 1,887 2,099 2,320 2,559 2,789 3,039 3,292 3,572 3,838 3,928 4,019Unit 23MWh4,655 8,719 8,761 8,099 11,693 8,896 12,259 6,362 6,020 4,449 7,301 4,763 10,705 10,329 11,335 12,315 10,792 13,115 24,548 19,542Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1532,275 1,725 2,450 1,298 1,284 1,021 1,656 1,133 2,589 2,570 2,944 3,273 2,950 3,698 6,773 5,597CO2 Charge ($000)125 111 178 105 113 95 169 125 304 322 383 440 410 539 985 808New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)304 283 313 337 400 425 460 503 526 590 640 694Capital Cost ($000)4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305MWh84,481 76,852 83,171 87,572 101,487 105,454 111,575 119,162 121,755 133,632 141,677 150,216Fuel + CO2 Charge ($000)0000000014,781 14,453 15,953 17,218 20,563 22,046 24,328 27,000 28,983 32,417 35,123 38,369CO2 Charge ($000)00001,301 1,346 1,628 1,905 2,405 2,743 3,153 3,629 4,021 4,721 5,112 5,542CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 104,347 106,736 111,987 116,602 121,711 132,405 136,917 142,636 151,118 158,654 169,761 181,273 195,300 204,565 215,598 229,376Total CO2 Charge ($000)000006,033 7,330 8,716 10,284 11,730 13,597 15,553 17,733 20,000 22,537 25,259 28,144 31,457 34,868 36,726 38,722Incremental Non-fuel Production Cost ($000)0000000006,104 6,118 6,183 6,243 6,343 6,406 6,479 6,561 6,624 6,730 6,822 6,920R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 217Case:2-3 Same as Case 2-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,059 333,239 330,887 327,570 324,126 320,468 315,156 314,890 313,520 313,296 313,605Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16950,896 51,209 52,711 53,837 56,084 59,121 59,656 60,506 62,514 63,709 66,093 68,177 71,494 73,137 74,831 77,215CO2 Charge ($000)2,782 3,291 3,807 4,364 4,931 5,506 6,086 6,691 7,308 7,925 8,562 9,162 9,919 10,651 10,892 11,152CC 2MWh49,051 51,273 49,299 51,079 52,560 57,039 64,155 68,945 75,907 82,109 91,009 99,555 109,070 118,388 128,455 140,661 147,684 154,942 161,964 168,497Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4759,106 9,918 11,519 12,615 14,486 16,574 18,669 20,829 23,754 26,497 30,084 34,445 37,921 40,847 43,712 46,885CO2 Charge ($000)498 637 831 1,021 1,272 1,544 1,904 2,303 2,775 3,295 3,895 4,629 5,260 5,948 6,362 6,772Unit 16MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh56 141 281 461 743 1,389 1,682 1,735 1,550 2,749 3,021 3,460Fuel + CO2 Charge ($000)00000 0 0 0 15 39 80 134 224 431 545 587 549 9941,110 1,299CO2 Charge ($000)0 0 0 0 1 4 8 15 26 54 71 79 76 145 162 188Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 56,723 57,199 59,592 61,066 64,380 68,681 70,407 72,461 76,383 79,363 84,195 89,339 94,710 98,234 102,238 107,287Total CO2 Charge ($000)000003,280 3,928 4,638 5,385 6,205 7,053 7,998 9,008 10,109 11,273 12,527 13,871 15,255 16,744 17,416 18,111Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 217Case:2-3 Same as Case 2-1 but with LNG fuel200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 161,070 163,934 171,579 177,668 186,091 201,086 207,324 215,097 227,501 238,017 253,956 270,612 290,010 302,799 317,836 336,662Total Authority CO2 Charges ($000)000009,313 11,259 13,354 15,670 17,935 20,650 23,551 26,741 30,109 33,810 37,787 42,015 46,711 51,612 54,141 56,833Total Authority Incremental Non-fuel Production Cost ($000)0000000006,104 6,118 6,183 6,243 6,343 6,406 6,479 6,561 6,624 6,730 6,822 6,920Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 190,349 195,619 204,596 214,714 231,998 248,906 259,943 271,493 286,491 302,734 323,286 343,317 369,576 387,974 404,632 428,498Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 181,036 184,360 191,242 199,044 214,063 228,255 236,392 244,752 256,382 268,924 285,500 301,302 322,864 336,363 350,491 371,664NPV with CO2 Charge ($000)2,807,365NPV without CO2 Charge ($000)2,605,599R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 218Case:2-3W Same as Case 2-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh401,690 350,736 410,081 422,963434,024 465,770 458,825 509,098 424,389 480,067 487,188 518,275 493,179 515,371 524,373 534,071 564,236 549,182 539,355 554,463Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13979,739 85,286 86,101 96,743 83,815 99,805 102,456 110,644 109,096 116,657 123,766 131,352 145,170 144,752 145,414 153,976CO2 Charge ($000)4,356 5,478 6,212 7,842 7,361 9,295 10,449 12,231 12,742 14,502 16,021 17,653 20,133 21,080 21,167 22,243Unit 13MWh23,755 53,722 30,886 30,66832,847 25,181 37,106 21,372 34,909 25,226 30,051 21,265 38,198 35,402 39,557 41,509 36,880 52,573 65,914 69,035Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1265,595 4,357 6,569 3,959 6,877 5,253 6,200 4,588 8,374 8,023 9,357 10,180 9,622 14,151 17,966 19,550CO2 Charge ($000)307 282 477 321 607 489 633 509 982 1,002 1,216 1,368 1,337 2,061 2,614 2,822Unit 15MWh1,159 761 100 318240 210 929 40 277 60 20 91 100 963 626 560 1,110 1,603Fuel + CO2 Charge ($000)355 249 35 10762 55 239 11 78 0 18 6 29 0 35 303 226 202 393 569CO2 Charge ($000)3 4 17 1 7 0 2 1 3 0 5 41 31 29 57 82Unit 18MWh15,947 44,647 26,547 31,01731,462 29,403 39,769 32,721 42,505 28,743 29,467 28,528 40,140 41,987 47,020 51,009 52,282 65,889 70,247 76,864Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,8805,315 5,166 7,225 6,366 7,682 5,579 5,845 5,997 8,725 9,522 11,116 12,710 13,905 17,693 19,405 21,931CO2 Charge ($000)291 333 523 516 678 520 597 664 1,022 1,187 1,442 1,708 1,930 2,577 2,824 3,167Unit 22MWh137,099 140,448 140,832 142,080143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 144,818 145,217 144,761 144,818 144,818Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01717,344 17,422 18,047 18,391 19,262 20,258 20,579 20,981 21,889 22,436 23,458 24,495 25,745 26,356 26,985 27,825CO2 Charge ($000)948 1,120 1,303 1,489 1,694 1,887 2,099 2,320 2,559 2,789 3,039 3,292 3,572 3,838 3,928 4,019Unit 23MWh4,655 8,719 8,761 8,09911,673 8,886 12,249 6,362 6,078 4,424 7,297 4,755 10,713 10,315 11,458 12,485 10,954 13,458 24,929 19,713Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1532,273 1,724 2,448 1,298 1,293 1,016 1,654 1,128 2,583 2,548 2,953 3,300 2,978 3,765 6,851 5,625CO2 Charge ($000)124 111 178 105 114 95 169 125 303 319 384 444 414 548 997 812New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)296 275 307 332 396 423 459 502 526 589 641 697Capital Cost ($000)4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305 4,305MWh82,266 74,571 81,617 86,239 100,503 104,858 111,178 119,034 121,807 133,472 141,992 150,730Fuel + CO2 Charge ($000)0000000014,370 13,981 15,588 16,880 20,288 21,838 24,128 26,855 28,879 32,285 35,107 38,408CO2 Charge ($000)00001,265 1,302 1,591 1,867 2,373 2,718 3,127 3,609 4,007 4,702 5,110 5,547CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 104,297 106,682 111,918 116,493 121,652 132,305 136,800 142,508 151,000 158,508 169,581 181,080 195,101 204,370 215,424 229,192Total CO2 Charge ($000)000006,030 7,327 8,711 10,275 11,725 13,587 15,540 17,717 19,984 22,516 25,232 28,114 31,424 34,835 36,696 38,691Incremental Non-fuel Production Cost ($000)0000000006,096 6,109 6,177 6,238 6,339 6,403 6,477 6,561 6,624 6,729 6,824 6,922R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 218Case:2-3W Same as Case 2-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508322,218 326,204 328,963 334,282 336,478 338,841 338,323 338,907 337,192 335,385 332,419 328,053 325,895 323,148 320,612 319,808Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16949,411 50,022 51,932 53,550 56,159 59,519 60,354 61,603 63,869 65,325 67,878 70,182 73,275 74,728 76,054 78,277CO2 Charge ($000)2,701 3,215 3,751 4,341 4,938 5,543 6,157 6,812 7,466 8,126 8,793 9,432 10,166 10,882 11,070 11,305CC 2MWh49,051 51,273 49,299 51,07948,165 49,906 53,270 53,694 57,633 61,406 68,111 73,794 81,848 89,793 99,168 110,409 119,220 128,001 137,252 144,951Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4758,345 8,672 9,551 9,800 10,969 12,357 13,930 15,393 17,778 20,044 23,170 26,982 30,563 33,696 37,002 40,292CO2 Charge ($000)456 557 689 794 963 1,151 1,421 1,702 2,076 2,492 3,000 3,626 4,239 4,907 5,386 5,820Unit 16MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 17MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Unit 19MWh23 62 163 326 686 979 1,066 1,008 2,029 2,405 2,783Fuel + CO2 Charge ($000)0 0 0 0 0 6 18 47 98 213 317 361 358 739 8931,060CO2 Charge ($000)0 0 0 0 0 1 2 5 11 26 41 49 50 108 130 153Unit 20MWhFuel + CO2 Charge ($000)CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)548 560 573 586 600 614 628 642 657 672 687 703 719 736 753 770Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 54,599 54,922 57,043 58,215 61,228 65,188 66,723 68,524 72,190 74,937 79,532 84,418 89,742 93,266 97,364 102,351Total CO2 Charge ($000)000003,157 3,772 4,440 5,134 5,901 6,694 7,579 8,519 9,554 10,645 11,834 13,107 14,455 15,897 16,585 17,278Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 3,353 3,369 3,386 3,403 3,420R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 218Case:2-3W Same as Case 2-1 but with LNG fuel, add Wind Project200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 158,897 161,604 168,961 174,709 182,880 197,493 203,523 211,033 223,191 233,445 249,114 265,498 284,842 297,636 312,788 331,543Total Authority CO2 Charges ($000)000009,187 11,099 13,151 15,409 17,626 20,282 23,119 26,236 29,539 33,161 37,066 41,221 45,879 50,732 53,281 55,969Total Authority Incremental Non-fuel Production Cost ($000)000003,197 3,210 3,223 3,236 9,346 9,373 9,455 9,530 9,645 9,725 9,815 9,914 9,994 10,115 10,226 10,342Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 191,247 196,339 204,998 214,730 231,719 248,199 258,982 270,210 284,913 300,832 321,059 340,761 366,946 385,317 402,128 425,936Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 182,060 185,240 191,847 199,321 214,094 227,917 235,863 243,974 255,374 267,671 283,993 299,540 321,067 334,585 348,847 369,967NPV with CO2 Charge ($000)2,800,480NPV without CO2 Charge ($000)2,602,215R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-3WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 219Case:2-4 High Requirements Load, Add CFBs, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh449,159 385,716 448,406 453,360364,663 370,035 377,902 351,864 432,141 403,487 367,629 443,237 427,215 449,295 459,853 470,452 499,807 491,430 487,000 507,094Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13988,481 89,535 91,411 85,021 108,274 104,050 97,723 121,582 120,784 131,522 139,527 148,012 163,382 166,565 169,665 181,337CO2 Charge ($000)4,881 5,795 6,820 7,208 9,994 10,338 10,387 13,739 14,434 16,477 18,252 20,148 23,073 24,336 24,617 26,128Unit 13MWh31,293 74,466 43,638 48,09030,312 34,850 35,251 54,727 14,853 37,718 67,274 35,584 53,708 52,239 57,822 67,425 65,942 85,358 97,391 103,903Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1266,838 7,865 7,960 12,424 3,585 9,388 17,011 9,527 14,857 15,166 17,588 21,651 22,411 30,072 35,117 38,795CO2 Charge ($000)406 551 644 1,138 355 1,001 1,941 1,157 1,908 2,043 2,472 3,155 3,389 4,698 5,448 5,978Unit 15MWh1,159 761 100 31840 513 461124 60 20 30 50 73 1,149Fuel + CO2 Charge ($000)355 249 35 1070 15 171 144 0 0 0 0 0 57 29 10 16 27 40 555CO2 Charge ($000)0 1 12 11 0 0 0 0 0 7 4 1 2 4 5 74Unit 18MWh9,075 25,082 15,070 15,9732,569 5,089 4,702 9,248 1,927 7,203 15,275 7,038 10,957 10,883 13,536 12,262 10,116 14,543 20,458 21,423Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,880697 1,386 1,308 2,533 537 2,099 4,536 2,201 3,553 3,600 4,550 4,284 3,734 5,521 7,765 8,336CO2 Charge ($000)36 83 92 201 46 194 449 232 398 424 558 544 493 753 1,052 1,121Unit 22MWh85,208 103,456 100,225 108,75942,430 44,990 49,659 67,714 57,075 75,767 87,375 81,353 92,482 96,176 99,913 106,087 110,168 120,247 126,861 129,384Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,0177,428 7,970 8,886 12,059 10,715 14,552 17,262 16,776 19,649 21,216 22,927 25,276 27,384 31,084 33,824 35,531CO2 Charge ($000)380 480 618 951 920 1,346 1,709 1,767 2,191 2,478 2,801 3,211 3,612 4,242 4,583 4,780Unit 23MWh4,655 8,719 8,761 8,0991,730 592 2,455 2,231 261 130 696 594 232 1,128 1,717 1,591 1,239 1,486 4,189 4,979Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,153456 159 658 637 79 41 229 203 85 419 616 604 493 603 1,805 2,170CO2 Charge ($000)23 10 46 51 7 4 23 21 10 49 75 77 65 82 244 292New ResourcesCT1Fixed O&M ($000)1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877Variable O&M ($000)6 31 10 34 35 46 52 41 54 82 72Capital Cost ($000)4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404MWh1,537 8,318 2,588 8,647 8,675 11,076 12,421 9,470 12,278 18,193 15,659Fuel + CO2 Charge ($000)0 0 0 0 0 4052,351 751 2,624 2,753 3,644 4,229 3,360 4,503 6,804 6,055CO2 Charge ($000)0 0 0 0 0 37 233 79 294 324 447 537 444 614 922 814CFB 1Fixed O&M ($000)3,211 3,284 3,360 3,437 3,516 3,597 3,680 3,764 3,851 3,940 4,030 4,123 4,218 4,315 4,414 4,516Variable O&M ($000)1,924 2,007 2,092 2,187 2,251 2,328 2,402 2,453 2,524 2,577 2,638 2,698 2,769 2,824 2,889 2,955Capital Cost ($000)21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617MWh214,724 218,971 223,150 227,990 229,451 231,958 233,932 233,505 234,858 234,382 234,526 234,540 235,230 234,510 234,540 234,540Fuel + CO2 Charge ($000)9,601 10,416 11,275 12,226 13,127 14,108 15,126 16,032 17,098 18,148 19,283 20,425 21,702 22,884 23,496 24,119CO2 Charge ($000)3,043 3,662 4,323 5,052 5,751 6,498 7,288 8,040 8,887 9,703 10,575 11,457 12,432 13,361 13,671 13,986CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 104,733 106,763 109,113 110,433 119,244 125,226 132,207 142,036 150,529 161,375 172,981 185,360 198,973 213,170 227,973 243,724Total CO2 Charge ($000)000008,768 10,582 12,556 14,612 17,073 19,418 22,029 25,036 28,120 31,504 35,183 39,130 43,510 48,090 50,543 53,173Incremental Non-fuel Production Cost ($000)0000026,751 26,908 27,069 27,241 27,384 33,447 33,664 33,813 34,031 34,210 34,410 34,608 34,801 35,007 35,241 35,441R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 219Case:2-4 High Requirements Load, Add CFBs, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508226,166 219,852 226,659 230,827 236,142 201,876 275,737 244,495 248,947 251,732 256,184 258,679 265,293 267,916 272,124 277,054Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16953,534 52,136 53,837 54,872 58,042 51,246 72,837 66,661 70,197 73,753 77,870 81,690 86,773 90,968 94,784 98,936CO2 Charge ($000)2,737 3,135 3,736 4,329 4,977 4,738 7,210 7,020 7,824 8,622 9,510 10,378 11,444 12,413 12,843 13,311CC 2MWh49,051 51,273 49,299 51,07928,929 37,702 35,575 35,552 33,847 73,199 3,350 39,124 40,387 42,394 43,446 46,682 46,332 49,981 51,920 53,925Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4756,922 9,052 8,578 8,641 8,587 19,201 918 11,075 11,892 13,000 13,904 15,551 16,110 18,076 19,314 20,671CO2 Charge ($000)374 572 625 715 780 1,863 95 1,222 1,388 1,591 1,777 2,069 2,224 2,582 2,740 2,911Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh000034 45 101 23 90 169 23 168 363 398Fuel + CO2 Charge ($000)00000 0 0 0 12 17 0 40 9 39 0 79 11 85 187 208CO2 Charge ($000)0 0 0 0 1 2 0 4 1 5 0 10 1 12 25 28Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,140 1,172 1,207 1,239 1,275 1,310 1,346 1,385 1,420 1,459 1,500 1,546 1,582 1,628 1,582 1,809Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh137,357 139,164 140,361 141,809 143,694 144,315 146,226 147,692 148,509 149,892 151,140 151,986 152,651 153,227 153,834 154,182Fuel + CO2 Charge ($000)6,149 6,628 7,105 7,618 8,234 8,793 9,471 10,154 10,828 11,618 12,437 13,245 14,090 14,960 15,417 15,862CO2 Charge ($000)1,949 2,330 2,725 3,147 3,608 4,050 4,563 5,092 5,628 6,211 6,821 7,430 8,071 8,734 8,971 9,198CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 61,545 61,779 62,434 62,939 65,510 68,605 71,358 74,592 78,085 81,980 86,103 90,678 95,244 100,347 105,124 110,229Total CO2 Charge ($000)000005,060 6,037 7,085 8,192 9,365 10,653 11,868 13,339 14,842 16,429 18,108 19,887 21,741 23,741 24,579 25,448Incremental Non-fuel Production Cost ($000)0000018,970 19,052 19,137 19,220 19,309 19,398 19,490 19,584 19,678 19,776 19,877 19,985 20,084 20,194 20,215 20,509R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 219Case:2-4 High Requirements Load, Add CFBs, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 166,278 168,542 171,547 173,372 184,754 193,831 203,565 216,628 228,614 243,355 259,084 276,038 294,217 313,516 333,097 353,953Total Authority CO2 Charges ($000)0000013,828 16,619 19,641 22,804 26,439 30,071 33,897 38,375 42,962 47,933 53,291 59,017 65,251 71,832 75,122 78,621Total Authority Incremental Non-fuel Production Cost ($000)0000045,721 45,960 46,206 46,461 46,693 52,846 53,154 53,397 53,708 53,986 54,287 54,593 54,886 55,201 55,456 55,950Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 245,793 251,546 257,057 264,013 279,753 297,799 313,501 331,811 347,822 369,775 391,726 413,777 440,583 467,383 489,507 516,607Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 231,966 234,927 237,416 241,209 253,315 267,728 279,604 293,437 304,860 321,841 338,435 354,760 375,333 395,552 414,385 437,986NPV with CO2 Charge ($000)3,264,773NPV without CO2 Charge ($000)2,977,661R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 220Case:2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.3Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh449,159 385,716 448,406 453,360364,678 370,035 377,933 351,987 432,138 403,712 367,753 443,239 427,278 449,388 459,813 470,496 500,046 491,515 487,355 507,299Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13988,484 89,535 91,417 85,044 108,274 104,097 97,750 121,582 120,799 131,544 139,516 148,023 163,447 166,589 169,770 181,400CO2 Charge ($000)4,881 5,795 6,821 7,210 9,994 10,342 10,390 13,739 14,436 16,479 18,251 20,150 23,082 24,340 24,632 26,137Unit 13MWh31,293 74,466 43,638 48,09030,302 34,885 35,208 54,626 14,860 37,542 67,300 35,700 53,864 52,284 57,944 67,521 65,781 85,415 97,082 103,728Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1266,835 7,871 7,950 12,396 3,586 9,335 17,007 9,548 14,886 15,169 17,618 21,673 22,344 30,067 34,993 38,738CO2 Charge ($000)406 551 643 1,135 355 996 1,941 1,160 1,912 2,043 2,476 3,158 3,379 4,697 5,429 5,969Unit 15MWh1,159 761 100 31840 513 464124 60 20 30 50 73 1,149Fuel + CO2 Charge ($000)355 249 35 1070 15 171 145 0 0 0 0 0 57 29 10 16 27 40 555CO2 Charge ($000)0 1 12 11 0 0 0 0 0 7 4 1 2 4 5 74Unit 18MWh9,075 25,082 15,070 15,9732,564 5,054 4,713 9,246 1,924 7,208 15,316 7,015 11,184 11,022 13,614 12,417 10,255 14,575 20,479 21,425Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,880697 1,376 1,310 2,532 536 2,100 4,541 2,186 3,594 3,627 4,564 4,317 3,766 5,514 7,768 8,336CO2 Charge ($000)36 83 92 201 46 194 450 231 402 427 559 548 497 752 1,052 1,121Unit 22MWh85,208 103,456 100,225 108,75942,430 44,990 49,659 67,714 57,075 75,767 87,375 81,353 92,482 96,176 99,913 106,088 110,172 120,252 126,869 129,387Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,0177,428 7,970 8,886 12,059 10,715 14,552 17,262 16,776 19,649 21,216 22,927 25,276 27,385 31,085 33,825 35,531CO2 Charge ($000)380 480 618 951 920 1,346 1,709 1,767 2,191 2,478 2,801 3,211 3,612 4,242 4,583 4,780Unit 23MWh4,655 8,719 8,761 8,0991,730 592 2,455 2,207 261 130 696 594 232 1,128 1,717 1,591 1,239 1,451 4,189 4,979Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,153456 159 658 633 79 41 229 203 85 419 616 604 493 588 1,805 2,170CO2 Charge ($000)23 10 46 51 7 4 23 21 10 49 75 77 65 80 244 292New ResourcesCT1Fixed O&M ($000)1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)6 31 10 33 35 46 52 41 55 84 74Capital Cost ($000)4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404 4,404MWh1,483 8,126 2,493 8,202 8,399 10,916 12,125 9,249 12,133 18,118 15,624Fuel + CO2 Charge ($000)0 0 0 0 0 3902,297 724 2,490 2,667 3,589 4,130 3,281 4,449 6,775 6,041CO2 Charge ($000)0 0 0 0 0 36 227 76 278 314 440 525 433 607 918 812CFB 1Fixed O&M ($000)3,211 3,284 3,360 3,437 3,516 3,597 3,680 3,764 3,851 3,940 4,030 4,123 4,218 4,315 4,414 4,516Variable O&M ($000)1,924 2,007 2,092 2,187 2,251 2,328 2,402 2,453 2,524 2,577 2,638 2,698 2,769 2,824 2,889 2,955Capital Cost ($000)21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617MWh214,724 218,971 223,150 227,990 229,451 231,958 233,932 233,505 234,858 234,382 234,526 234,540 235,230 234,510 234,540 234,540Fuel + CO2 Charge ($000)9,601 10,416 11,275 12,226 13,127 14,108 15,126 16,032 17,098 18,148 19,283 20,425 21,702 22,884 23,496 24,119CO2 Charge ($000)3,043 3,662 4,323 5,052 5,751 6,498 7,288 8,040 8,887 9,703 10,575 11,457 12,432 13,361 13,671 13,986CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 104,732 106,759 109,110 110,425 119,244 125,208 132,185 142,018 150,484 161,345 172,963 185,331 198,931 213,120 227,936 243,717Total CO2 Charge ($000)000008,768 10,582 12,556 14,611 17,073 19,415 22,027 25,034 28,115 31,501 35,181 39,126 43,503 48,083 50,536 53,171Incremental Non-fuel Production Cost ($000)0000026,751 26,908 27,069 27,241 27,384 33,481 33,699 33,849 34,066 34,247 34,449 34,648 34,842 35,049 35,285 35,486R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 220Case:2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.1Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508216,847 209,249 215,588 220,489 223,928 192,163 262,783 232,448 237,463 238,481 243,184 246,179 252,843 255,583 259,082 262,407Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16951,945 50,310 51,933 53,065 55,848 49,430 70,324 64,240 67,820 70,912 74,978 78,803 83,799 87,923 91,493 95,159CO2 Charge ($000)2,737 3,135 3,736 4,329 4,977 4,738 7,210 7,020 7,824 8,622 9,510 10,378 11,444 12,413 12,843 13,311CC 2MWh49,051 51,273 49,299 51,07927,793 36,959 33,984 32,917 32,470 68,422 1,650 36,073 36,286 39,806 40,284 42,808 42,135 45,353 47,814 51,342Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4756,653 8,879 8,201 8,006 8,243 17,960 452 10,216 10,689 12,214 12,901 14,264 14,657 16,407 17,793 19,694CO2 Charge ($000)374 572 625 715 780 1,863 95 1,222 1,388 1,591 1,777 2,069 2,224 2,582 2,740 2,911Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh000017 6 45 11 39 90 6 122 299 340Fuel + CO2 Charge ($000)00000 0 0 0 6 2 0 18 5 17 0 42 3 62 156 182CO2 Charge ($000)0 0 0 0 1 2 0 4 1 5 0 10 1 12 25 28Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,140 2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010Variable O&M ($000)1,140 1,172 1,207 1,239 1,275 1,310 1,346 1,385 1,420 1,459 1,500 1,546 1,582 1,628 1,582 1,809Capital Cost ($000)15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690MWh131,517 133,963 136,101 137,713 140,053 141,366 143,299 145,119 146,288 147,892 149,363 150,457 151,302 152,217 153,020 153,496Fuel + CO2 Charge ($000)5,895 6,387 6,895 7,404 8,031 8,619 9,286 9,982 10,671 11,467 12,295 13,116 13,969 14,864 15,338 15,793CO2 Charge ($000)1,949 2,330 2,725 3,147 3,608 4,050 4,563 5,092 5,628 6,211 6,821 7,430 8,071 8,734 8,971 9,198CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)548 560 573 586 600 614 628 642 657 672 687 703 719 736 753 770Variable O&M ($000)0000000000000000Capital Cost ($000)2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650MWh18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044Fuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 59,433 59,539 59,945 60,283 62,763 65,358 68,194 71,117 74,343 78,181 82,065 86,338 90,686 95,515 100,201 105,379Total CO2 Charge ($000)000005,060 6,037 7,085 8,192 9,365 10,653 11,868 13,339 14,842 16,429 18,108 19,887 21,741 23,741 24,579 25,448Incremental Non-fuel Production Cost ($000)0000022,168 22,262 22,360 22,456 22,558 22,662 22,767 22,876 22,984 23,098 23,215 23,338 23,453 23,580 23,618 23,929R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 220Case:2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 164,165 166,299 169,055 170,709 182,007 190,565 200,379 213,134 224,827 239,526 255,028 271,669 289,618 308,635 328,137 349,096Total Authority CO2 Charges ($000)0000013,828 16,619 19,641 22,803 26,439 30,068 33,895 38,373 42,957 47,930 53,289 59,013 65,243 71,824 75,114 78,620Total Authority Incremental Non-fuel Production Cost ($000)0000048,919 49,170 49,429 49,697 49,943 56,143 56,466 56,725 57,051 57,345 57,663 57,985 58,295 58,629 58,902 59,415Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 246,878 252,513 257,788 264,584 280,256 297,828 313,625 331,644 347,373 369,301 391,044 412,797 439,387 465,922 487,987 515,213Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 233,050 235,894 238,147 241,781 253,818 267,760 279,730 293,271 304,416 321,371 337,755 353,783 374,143 394,098 412,872 436,593NPV with CO2 Charge ($000)3,264,441NPV without CO2 Charge ($000)2,977,347R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-4WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 221Case:2-5 High Requirements Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 105.7 108.8 112.0 115.2 118.6 122.0 125.6 129.3 133.0 136.9 140.9 145.0 149.3 153.7 158.2 162.8Energy Requirements563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 929,369 956,514 984,474 1,013,272 1,042,935CC 1MWh449,159 385,716 448,406 453,360Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,1390000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh31,293 74,466 43,638 48,090Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1260000000000000000CO2 Charge ($000)Unit 15MWh1,159 761 100 318102,085 103,737 104,646 42,389 42,635 41,568 43,243 45,638 47,737 49,601 50,240 51,832 53,695 57,330 58,706 61,708Fuel + CO2 Charge ($000)355 249 35 10732,842 33,230 33,526 14,840 15,487 15,672 16,685 18,066 19,186 20,377 21,282 22,785 24,351 26,460 27,512 29,533CO2 Charge ($000)1,680 1,998 2,325 1,171 1,330 1,449 1,652 1,903 2,139 2,383 2,600 2,895 3,212 3,610 3,728 3,973Unit 18MWh9,075 25,082 15,070 15,973149,572 151,299 153,118 109,062 113,978 116,642 120,075 124,332 129,916 135,517 140,229 142,582 144,484 148,394 149,817 155,548Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,88034,143 34,528 35,044 28,456 30,408 31,932 33,788 35,857 38,332 41,033 43,760 46,075 48,505 51,591 53,522 56,682CO2 Charge ($000)1,747 2,076 2,432 2,246 2,612 2,952 3,345 3,777 4,273 4,798 5,345 5,854 6,397 7,040 7,252 7,626Unit 22MWh85,208 103,456 100,225 108,759123,577 125,576 128,860 49,035 58,776 67,994 73,194 79,059 86,346 91,297 96,432 103,110 109,848 118,080 122,594 126,317Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01721,478 21,898 22,567 8,882 11,078 13,256 14,780 16,512 18,669 20,513 22,567 25,045 27,814 31,062 33,246 35,149CO2 Charge ($000)1,099 1,317 1,566 700 953 1,226 1,463 1,739 2,082 2,396 2,757 3,182 3,668 4,239 4,505 4,729Unit 23MWh4,655 8,719 8,761 8,09912,342 15,079 17,296 4,640 7,144 5,863 8,113 7,913 12,731 11,800 18,518 22,259 24,901 34,063 40,747 44,394Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1533,358 4,160 4,814 1,268 1,955 1,757 2,474 2,545 4,163 4,151 6,640 8,313 9,640 13,490 16,500 18,619CO2 Charge ($000)172 250 334 102 168 162 245 268 464 488 813 1,056 1,271 1,841 2,235 2,505New ResourcesCT1Fixed O&M ($000)1,366 1,397 1,429 1,462 1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)196 219 234 69 76 100 122 144 167 197 229 282 321 394 440 503Capital Cost ($000)3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930MWh59,531 65,139 67,983 19,599 21,166 27,086 32,305 37,336 42,282 48,891 55,587 66,846 74,263 89,314 97,306 108,940Fuel + CO2 Charge ($000)14,648 16,148 16,910 4,931 5,479 7,327 9,040 10,862 12,787 15,442 18,284 22,749 26,357 32,949 36,885 42,466CO2 Charge ($000)750 970 1,173 392 471 677 895 1,145 1,426 1,807 2,234 2,890 3,477 4,496 4,997 5,713CFB 1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,081 2,191 2,330 2,394 2,446 2,546 2,655 2,762 2,774 2,943 3,025 3,101 3,241 3,177 3,332 3,415Capital Cost ($000)21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672MWh232,244 239,009 248,552 249,559 249,273 253,609 258,598 262,922 258,142 267,671 268,942 269,551 275,385 263,856 270,550 271,001Fuel + CO2 Charge ($000)10,360 11,351 12,547 13,403 14,274 15,454 16,748 18,069 18,796 20,717 22,097 23,482 25,406 25,750 27,101 27,865CO2 Charge ($000)3,282 3,990 4,813 5,534 6,248 7,118 8,069 9,061 9,767 11,072 12,113 13,172 14,553 15,035 15,770 16,159CFB 2Fixed O&M ($000)4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,551 2,635 2,714 2,783 2,856 2,965 3,006 3,076 3,147 3,229 3,292 3,370 3,447Capital Cost ($000)23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202MWh266,009 268,515 270,428 271,002 271,893 275,917 273,424 273,525 273,550 274,332 273,416 273,591 273,528Fuel + CO2 Charge ($000)0 0 0 14,262 15,361 16,449 17,521 18,660 20,091 21,171 22,489 23,822 25,310 26,682 27,408 28,131CO2 Charge ($000)0 0 0 5,891 6,731 7,576 8,441 9,356 10,443 11,320 12,334 13,363 14,499 15,578 15,948 16,312CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 108,099 110,713 112,766 70,006 75,529 80,685 86,926 93,323 101,430 109,141 118,925 129,859 140,306 156,145 167,739 181,428Total CO2 Charge ($000)000008,730 10,602 12,642 16,036 18,513 21,161 24,110 27,249 30,593 34,264 38,195 42,411 47,077 51,839 54,435 57,017Incremental Non-fuel Production Cost ($000)0000033,623 33,888 34,178 64,656 65,048 65,506 65,967 66,436 66,853 67,372 67,842 68,335 68,894 69,273 69,864 70,407R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 221Case:2-5 High Requirements Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 54.5 55.3 56.2 57.0 60.9 61.7 62.6 63.5 64.4 65.3 66.3 67.2 68.2 69.1 70.1 71.1 72.2 73.2 74.3 75.3Energy Requirements360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 478,375 485,236 492,199 499,266 506,440CC 1MWh317,225 320,208 327,636 331,508Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,1690000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,051 51,273 49,299 51,079Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4750000000000000000CO2 Charge ($000)Unit 16MWh000015,576 15,446 1,133 4,125 3,881 2,730 3,711 5,439 4,965 5,145 5,330 8,409 7,902 9,742 11,667 12,227Fuel + CO2 Charge ($000)00004,628 4,560 341 1,204 1,185 859 1,203 1,837 1,770 1,929 2,134 3,414 3,431 4,399 5,259 5,763CO2 Charge ($000)237 274 24 95 102 79 119 193 197 225 260 434 453 600 713 776Unit 17MWh0000104,200 106,608 60,077 66,661 65,265 67,577 68,914 70,232 73,078 76,198 79,630 79,866 83,671 86,099 88,223 90,428Fuel + CO2 Charge ($000)000020,562 21,065 14,520 15,614 15,977 16,930 17,806 18,766 20,014 21,351 22,906 23,859 25,711 27,165 28,481 29,808CO2 Charge ($000)1,052 1,267 1,008 1,232 1,372 1,565 1,763 1,976 2,230 2,496 2,797 3,031 3,390 3,707 3,859 4,011Unit 19MWh000023,053 24,037 23,022 22,852 22,817 22,877 22,860 22,979 23,183 23,045 22,725 23,067 23,060 22,959 23,847 23,569Fuel + CO2 Charge ($000)00007,749 8,065 7,816 7,807 8,106 8,435 8,755 9,144 9,576 9,935 10,220 10,781 11,248 11,663 12,391 12,654CO2 Charge ($000)397 485 543 616 696 780 867 963 1,067 1,162 1,248 1,370 1,483 1,591 1,679 1,702Unit 20MWh0000132,153 135,048 59,848 69,939 66,701 69,119 71,523 72,789 75,960 77,803 80,287 81,480 84,217 86,378 87,513 91,308Fuel + CO2 Charge ($000)000031,903 32,488 16,539 18,923 18,858 20,286 21,633 22,909 24,589 26,295 28,096 29,565 31,659 33,654 35,062 37,276CO2 Charge ($000)1,632 1,953 1,149 1,493 1,619 1,876 2,141 2,412 2,740 3,073 3,431 3,756 4,176 4,592 4,751 5,015New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010 3,080Variable O&M ($000)1,404 1,429 1,443 1,481 1,521 1,559 1,596 1,635 1,676 1,711 1,754 1,796 1,840 1,880 1,924 1,969Capital Cost ($000)14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123MWh156,734 155,943 153,948 154,379 155,021 155,313 155,449 155,664 155,985 155,665 155,956 156,096 156,368 156,140 156,222 156,268Fuel + CO2 Charge ($000)6,991 7,405 7,773 8,274 8,865 9,445 10,052 10,687 11,359 12,054 12,824 13,594 14,425 15,237 15,650 16,071CO2 Charge ($000)2,216 2,603 2,982 3,419 3,884 4,350 4,843 5,360 5,904 6,445 7,033 7,625 8,263 8,896 9,106 9,319CFB2Fixed O&M ($000)2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010 3,080Variable O&M ($000)1,367 1,264 1,396 1,450 1,497 1,551 1,591 1,648 1,690 1,749 1,794 1,844 1,889 1,944Capital Cost ($000)14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780MWh145,846 131,803 142,265 144,414 145,771 147,606 148,026 149,925 150,259 152,042 152,420 153,113 153,377 154,293Fuel + CO2 Charge ($000)0 0 7,382 7,084 8,154 8,799 9,442 10,148 10,794 11,620 12,363 13,250 14,072 14,949 15,371 15,873CO2 Charge ($000)0 0 2,829 2,927 3,572 4,053 4,549 5,089 5,610 6,212 6,779 7,432 8,062 8,728 8,944 9,204CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 66,301 67,001 45,837 49,125 49,900 52,050 54,609 57,498 60,351 63,570 66,994 70,815 74,719 78,951 83,164 87,419Total CO2 Charge ($000)000005,533 6,582 8,534 9,781 11,244 12,704 14,282 15,994 17,750 19,613 21,549 23,648 25,826 28,116 29,052 30,027Incremental Non-fuel Production Cost ($000)0000017,717 17,792 36,296 36,336 36,616 36,818 37,015 37,223 37,423 37,636 37,844 38,071 38,290 38,512 38,737 38,975R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 221Case:2-5 High Requirements Load, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 174,400 177,714 158,603 119,131 125,429 132,735 141,535 150,821 161,781 172,711 185,919 200,674 215,026 235,096 250,902 268,846Total Authority CO2 Charges ($000)0000014,263 17,184 21,176 25,817 29,757 33,865 38,392 43,242 48,344 53,877 59,744 66,059 72,904 79,955 83,487 87,044Total Authority Incremental Non-fuel Production Cost ($000)0000051,339 51,680 70,474 100,992 101,664 102,324 102,982 103,659 104,276 105,008 105,686 106,406 107,184 107,784 108,601 109,382Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 252,920 259,701 263,585 259,486 270,615 282,913 297,127 312,174 329,092 346,533 366,537 388,584 410,820 438,810 459,240 481,804Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 238,658 242,517 242,410 233,669 240,858 249,048 258,735 268,932 280,748 292,656 306,793 322,525 337,916 358,856 375,753 394,760NPV with CO2 Charge ($000)3,169,548NPV without CO2 Charge ($000)2,850,172R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 222Case:2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 105.7 108.8 112.0 115.2 118.6 122.0 125.6 129.3 133.0 136.9 140.9 145.0 149.3 153.7 158.2 162.8Energy Requirements563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 929,369 956,514 984,474 1,013,272 1,042,935CC 1MWh449,159 385,716 448,406 453,360Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,1390000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh31,293 74,466 43,638 48,090Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1260000000000000000CO2 Charge ($000)Unit 15MWh1,159 761 100 318102,085 103,737 104,646 42,389 42,635 41,568 43,243 45,638 47,737 49,601 50,240 51,832 53,695 57,330 58,706 61,708Fuel + CO2 Charge ($000)355 249 35 10732,842 33,230 33,526 14,840 15,487 15,672 16,685 18,066 19,186 20,377 21,282 22,785 24,351 26,460 27,512 29,533CO2 Charge ($000)1,680 1,998 2,325 1,171 1,330 1,449 1,652 1,903 2,139 2,383 2,600 2,895 3,212 3,610 3,728 3,973Unit 18MWh9,075 25,082 15,070 15,973149,572 151,299 153,118 109,062 113,978 116,642 120,075 124,332 129,916 135,517 140,229 142,582 144,484 148,394 149,817 155,548Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,88034,143 34,528 35,044 28,456 30,408 31,932 33,788 35,857 38,332 41,033 43,760 46,075 48,505 51,591 53,522 56,682CO2 Charge ($000)1,747 2,076 2,432 2,246 2,612 2,952 3,345 3,777 4,273 4,798 5,345 5,854 6,397 7,040 7,252 7,626Unit 22MWh85,208 103,456 100,225 108,759123,577 125,576 128,860 49,035 58,776 67,994 73,194 79,059 86,346 91,297 96,432 103,110 109,848 118,080 122,594 126,317Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01721,478 21,898 22,567 8,882 11,078 13,256 14,780 16,512 18,669 20,513 22,567 25,045 27,814 31,062 33,246 35,149CO2 Charge ($000)1,099 1,317 1,566 700 953 1,226 1,463 1,739 2,082 2,396 2,757 3,182 3,668 4,239 4,505 4,729Unit 23MWh4,655 8,719 8,761 8,09912,342 15,079 17,296 4,640 7,144 5,863 8,113 7,913 12,731 11,800 18,518 22,259 24,901 34,063 40,747 44,394Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1533,358 4,160 4,814 1,268 1,955 1,757 2,474 2,545 4,163 4,151 6,640 8,313 9,640 13,490 16,500 18,619CO2 Charge ($000)172 250 334 102 168 162 245 268 464 488 813 1,056 1,271 1,841 2,235 2,505New ResourcesCT1Fixed O&M ($000)1,366 1,397 1,429 1,462 1,496 1,530 1,565 1,601 1,638 1,676 1,714 1,754 1,794 1,835 1,877 1,921Variable O&M ($000)196 219 234 69 76 100 122 144 167 197 229 282 321 394 440 503Capital Cost ($000)3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930MWh59,531 65,139 67,983 19,599 21,166 27,086 32,305 37,336 42,282 48,891 55,587 66,846 74,263 89,314 97,306 108,940Fuel + CO2 Charge ($000)14,648 16,148 16,910 4,931 5,479 7,327 9,040 10,862 12,787 15,442 18,284 22,749 26,357 32,949 36,885 42,466CO2 Charge ($000)750 970 1,173 392 471 677 895 1,145 1,426 1,807 2,234 2,890 3,477 4,496 4,997 5,713CFB 1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,081 2,191 2,330 2,394 2,446 2,546 2,655 2,762 2,774 2,943 3,025 3,101 3,241 3,177 3,332 3,415Capital Cost ($000)21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672MWh232,244 239,009 248,552 249,559 249,273 253,609 258,598 262,922 258,142 267,671 268,942 269,551 275,385 263,856 270,550 271,001Fuel + CO2 Charge ($000)10,360 11,351 12,547 13,403 14,274 15,454 16,748 18,069 18,796 20,717 22,097 23,482 25,406 25,750 27,101 27,865CO2 Charge ($000)3,282 3,990 4,813 5,534 6,248 7,118 8,069 9,061 9,767 11,072 12,113 13,172 14,553 15,035 15,770 16,159CFB 2Fixed O&M ($000)4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,551 2,635 2,714 2,783 2,856 2,965 3,006 3,076 3,147 3,229 3,292 3,370 3,447Capital Cost ($000)23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202MWh266,009 268,515 270,428 271,002 271,893 275,917 273,424 273,525 273,550 274,332 273,416 273,591 273,528Fuel + CO2 Charge ($000)0 0 0 14,262 15,361 16,449 17,521 18,660 20,091 21,171 22,489 23,822 25,310 26,682 27,408 28,131CO2 Charge ($000)0 0 0 5,891 6,731 7,576 8,441 9,356 10,443 11,320 12,334 13,363 14,499 15,578 15,948 16,312CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 108,099 110,713 112,766 70,006 75,529 80,685 86,926 93,323 101,430 109,141 118,925 129,859 140,306 156,145 167,739 181,428Total CO2 Charge ($000)000008,730 10,602 12,642 16,036 18,513 21,161 24,110 27,249 30,593 34,264 38,195 42,411 47,077 51,839 54,435 57,017Incremental Non-fuel Production Cost ($000)0000033,623 33,888 34,178 64,656 65,048 65,506 65,967 66,436 66,853 67,372 67,842 68,335 68,894 69,273 69,864 70,407R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5WPage 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 222Case:2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 54.5 55.3 56.2 57.0 60.9 61.7 62.6 63.5 64.4 65.3 66.3 67.2 68.2 69.1 70.1 71.1 72.2 73.2 74.3 75.3Energy Requirements360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 478,375 485,236 492,199 499,266 506,440CC 1MWh317,225 320,208 327,636 331,508Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,1690000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,051 51,273 49,299 51,079Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4750000000000000000CO2 Charge ($000)Unit 16MWh000013,407 13,992 926 3,590 3,495 2,136 2,799 4,555 2,873 3,223 2,767 5,765 5,025 6,824 8,909 9,271Fuel + CO2 Charge ($000)00004,087 4,213 285 1,067 1,090 668 916 1,574 998 1,199 1,090 2,326 2,158 3,064 3,959 4,318CO2 Charge ($000)209 253 20 84 93 62 91 166 111 140 133 296 285 418 536 581Unit 17MWh000099,591 101,577 63,964 69,862 67,768 69,802 69,832 70,438 72,535 74,661 77,602 76,912 80,278 82,302 83,416 85,680Fuel + CO2 Charge ($000)000019,774 20,193 15,010 15,997 16,268 17,193 17,885 18,727 19,876 21,056 22,518 23,292 25,023 26,392 27,480 28,761CO2 Charge ($000)1,012 1,214 1,042 1,262 1,397 1,590 1,770 1,972 2,215 2,461 2,750 2,959 3,299 3,601 3,724 3,870Unit 19MWh000022,936 23,930 22,982 22,830 22,800 22,865 22,830 22,963 23,132 23,015 22,725 23,019 23,036 22,908 23,706 23,293Fuel + CO2 Charge ($000)00007,717 8,035 7,804 7,801 8,101 8,431 8,746 9,139 9,559 9,924 10,220 10,763 11,239 11,641 12,330 12,526CO2 Charge ($000)395 483 542 616 696 780 866 963 1,066 1,160 1,248 1,367 1,482 1,588 1,671 1,685Unit 20MWh0000121,100 123,709 32,674 44,931 42,575 46,989 51,369 53,963 58,725 62,249 66,114 68,671 71,939 74,990 77,179 81,235Fuel + CO2 Charge ($000)000030,171 30,743 8,747 11,870 11,797 13,599 15,224 16,705 18,665 20,817 22,974 24,859 27,082 29,345 31,133 33,610CO2 Charge ($000)1,543 1,848 608 936 1,012 1,257 1,507 1,759 2,080 2,433 2,805 3,158 3,572 4,004 4,218 4,522New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)2,190 2,240 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010 3,080Variable O&M ($000)1,404 1,429 1,452 1,489 1,529 1,564 1,601 1,639 1,682 1,714 1,757 1,798 1,843 1,881 1,925 1,970Capital Cost ($000)14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123MWh156,665 155,872 154,837 155,249 155,867 155,770 155,911 156,043 156,532 155,943 156,191 156,260 156,572 156,266 156,297 156,333Fuel + CO2 Charge ($000)6,988 7,401 7,817 8,320 8,913 9,472 10,081 10,713 11,398 12,075 12,843 13,608 14,443 15,249 15,658 16,078CO2 Charge ($000)2,215 2,602 2,999 3,438 3,905 4,363 4,857 5,372 5,925 6,456 7,043 7,633 8,273 8,903 9,111 9,323CFB2Fixed O&M ($000)2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 2,812 2,877 2,943 3,010 3,080Variable O&M ($000)1,410 1,296 1,426 1,470 1,514 1,562 1,605 1,656 1,696 1,754 1,800 1,846 1,893 1,947Capital Cost ($000)14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780MWh150,348 135,146 145,301 146,436 147,439 148,721 149,386 150,664 150,819 152,415 152,896 153,315 153,671 154,546Fuel + CO2 Charge ($000)0 0 7,603 7,259 8,323 8,919 9,547 10,223 10,891 11,676 12,408 13,282 14,115 14,969 15,400 15,899CO2 Charge ($000)0 0 2,914 3,000 3,647 4,108 4,600 5,127 5,661 6,243 6,804 7,450 8,086 8,740 8,961 9,219CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection CostsMethanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 63,364 64,184 39,142 42,979 43,742 46,124 48,708 51,722 54,329 57,854 61,269 65,266 69,061 73,403 77,739 81,992Total CO2 Charge ($000)000005,374 6,401 8,125 9,335 10,750 12,160 13,691 15,358 17,057 18,893 20,784 22,863 24,998 27,255 28,220 29,200Incremental Non-fuel Production Cost ($000)0000017,716 17,791 36,347 36,376 36,654 36,843 37,037 37,239 37,443 37,647 37,853 38,078 38,298 38,515 38,741 38,979(159) (181) (409) (446) (495) (544) (591) (636) (693) (720) (765) (785) (828) (861) (832) (827)R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5WPage 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 222Case:2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 171,463 174,898 151,908 112,985 119,272 126,809 135,635 145,045 155,759 166,995 180,194 195,125 209,367 229,548 245,478 263,420Total Authority CO2 Charges ($000)0000014,103 17,003 20,766 25,371 29,263 33,321 37,801 42,607 47,651 53,157 58,979 65,274 72,075 79,094 82,655 86,217Total Authority Incremental Non-fuel Production Cost ($000)0000051,339 51,680 70,525 101,032 101,702 102,349 103,004 103,675 104,296 105,019 105,695 106,413 107,192 107,788 108,606 109,386Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030 4,030$/kGal Excl. Energy Costs5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 6.52 6.63 6.73 6.84 6.96Total Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 249,824 256,703 256,531 252,934 264,001 276,467 290,657 305,779 322,398 340,108 360,055 382,256 404,341 432,406 452,988 475,554Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 235,720 239,700 235,765 227,563 234,738 243,146 252,856 263,172 274,747 286,951 301,076 316,982 332,266 353,311 370,333 389,337NPV with CO2 Charge ($000)3,125,047NPV without CO2 Charge ($000)2,809,856R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-5WPage 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 223Case:2-6 High Requirements Load, add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 105.7 108.8 112.0 115.2 118.6 122.0 125.6 129.3 133.0 136.9 140.9 145.0 149.3 153.7 158.2 162.8Energy Requirements563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407CC 1MWh449,159 385,716 448,406 453,360390,476 457,585 446,620 442,876 457,434 466,709 473,307 498,515 471,082 486,057 491,921 498,312 524,613 509,438 500,855 517,963Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,13988,968 104,753 102,281 101,649 108,869 114,935 120,764 131,951 129,301 138,984 146,409 154,319 169,157 170,840 172,886 183,882CO2 Charge ($000)4,905 6,780 7,631 8,617 10,036 11,419 12,836 14,911 15,452 17,411 19,152 21,007 23,888 24,961 25,084 26,495Unit 13MWh31,293 74,466 43,638 48,09044,832 28,007 39,568 47,292 47,115 51,845 57,080 54,455 76,952 82,407 90,981 100,877 104,055 128,739 144,042 151,917Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,12610,431 6,547 9,226 11,115 11,531 13,264 14,979 14,975 21,908 24,499 27,994 32,426 34,956 44,541 50,958 55,395CO2 Charge ($000)620 458 745 1,018 1,148 1,415 1,709 1,817 2,811 3,295 3,928 4,724 5,284 6,959 7,907 8,536Unit 15MWh1,159 761 100 318225Fuel + CO2 Charge ($000)355 249 35 1070 0 0 0 0 0 0 0 0 0 0 0 0 0 0 121CO2 Charge ($000)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16Unit 18MWh9,075 25,082 15,070 15,9734,590 4,009 5,214 6,806 7,710 7,661 11,017 8,119 13,274 14,801 19,503 19,460 17,820 25,405 31,275 34,141Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,8801,234 1,037 1,407 1,865 2,115 2,167 3,244 2,513 4,194 4,836 6,502 6,719 6,534 9,660 11,973 13,537CO2 Charge ($000)63 62 99 148 183 200 321 265 469 567 796 854 862 1,318 1,622 1,821Unit 22MWh85,208 103,456 100,225 108,75958,998 45,331 54,555 64,305 69,124 77,990 81,188 86,496 97,105 99,501 101,688 108,263 110,010 115,964 119,459 124,945Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01710,292 7,991 9,644 11,403 12,723 14,853 16,034 17,718 20,543 21,834 23,210 25,646 27,134 29,763 31,602 34,097CO2 Charge ($000)527 481 671 899 1,094 1,373 1,587 1,866 2,290 2,551 2,836 3,258 3,579 4,061 4,282 4,588Unit 23MWh4,655 8,719 8,761 8,099393 2,158 1,074 1,781 1,807 1,171 3,718 2,663 6,717 7,328 11,118 11,839 9,986 15,260 23,955 21,933Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,153113 568 303 504 525 367 1,170 875 2,276 2,624 4,021 4,425 3,929 6,161 9,863 9,332CO2 Charge ($000)6 34 21 40 45 34 116 92 254 309 492 562 519 840 1,336 1,255New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 104,917 113,079 113,695 115,813 123,257 131,145 139,622 149,081 156,946 168,644 180,932 193,130 207,577 222,826 237,049 253,654Total CO2 Charge ($000)000006,121 7,816 9,166 10,723 12,506 14,441 16,569 18,951 21,276 24,133 27,204 30,405 34,132 38,140 40,231 42,711Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-6Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 223Case:2-6 High Requirements Load, add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 54.5 55.3 56.2 57.0 60.9 61.7 62.6 63.5 64.4 65.3 66.3 67.2 68.2 69.1 70.1 71.1 72.2 73.2 74.3 75.3Energy Requirements360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416CC 1MWh317,225 320,208 327,636 331,508307,738 295,941 311,971 321,965 329,041 335,641 342,923 349,636 364,161 369,752 376,508 384,895 391,580 397,650 402,443 403,036Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,16966,353 64,704 67,591 69,595 73,583 77,485 81,832 86,279 92,544 97,575 103,160 109,252 115,465 121,618 126,441 130,414CO2 Charge ($000)3,395 3,892 4,692 5,492 6,320 7,164 8,101 9,087 10,316 11,408 12,600 13,880 15,228 16,596 17,132 17,546CC 2MWh49,051 51,273 49,299 51,079200 749 375 575 1,225 375 950 2,445 2,844 4,013 2,908 4,135 10,335 15,096Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,4750 48 0 183 95 152 336 107 284 755 916 1,344 1,015 1,506 3,883 5,828CO2 Charge ($000)0 3 0 15 9 15 35 12 34 93 117 179 140 215 550 820Unit 16MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 17MWh0000Fuel + CO2 Charge ($000)0000CO2 Charge ($000)Unit 19MWh00006Fuel + CO2 Charge ($000)00000000000000000003CO2 Charge ($000)0000000000000000Unit 20MWhFuel + CO2 Charge ($000)0000CO2 Charge ($000)New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)3,284 3,360 3,437 3,516 3,597 3,680 3,764 3,851 3,940 4,030 4,123 4,218 4,315 4,414 4,516 4,619Variable O&M ($000)2,105 2,146 2,199 2,249 2,308 2,354 2,408 2,464 2,528 2,578 2,638 2,698 2,769 2,824 2,889 2,955Capital Cost ($000)20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968MWh234,974 234,168 234,497 234,527 235,191 234,509 234,540 234,540 235,260 234,510 234,540 234,540 235,230 234,510 234,540 234,540Fuel + CO2 Charge ($000)10,481 11,119 11,834 12,567 13,447 14,259 15,164 16,101 17,126 18,158 19,284 20,425 21,702 22,884 23,496 24,119CO2 Charge ($000)3,322 3,909 4,538 5,193 5,892 6,568 7,306 8,075 8,902 9,708 10,576 11,457 12,432 13,361 13,671 13,986CFB2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection Costs30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914Methanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 70,118 68,068 70,194 71,645 74,904 78,149 81,890 85,314 90,704 95,279 100,066 105,505 110,382 115,837 122,466 128,011Total CO2 Charge ($000)000006,717 7,804 9,230 10,700 12,221 13,747 15,442 17,173 19,251 21,209 23,293 25,516 27,800 30,172 31,354 32,353Incremental Non-fuel Production Cost ($000)0000057,272 57,388 57,518 57,648 57,787 57,916 58,055 58,197 58,350 58,491 58,643 58,798 58,966 59,120 59,287 59,457R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-6Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 223Case:2-6 High Requirements Load, add CFB, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 175,035 181,147 183,890 187,458 198,162 209,293 221,512 234,395 247,650 263,923 280,998 298,636 317,960 338,663 359,515 381,665Total Authority CO2 Charges ($000)0000012,838 15,620 18,395 21,423 24,726 28,188 32,011 36,124 40,526 45,342 50,498 55,921 61,932 68,312 71,585 75,063Total Authority Incremental Non-fuel Production Cost ($000)0000057,272 57,388 57,518 57,648 57,787 57,916 58,055 58,197 58,350 58,491 58,643 58,798 58,966 59,120 59,287 59,457Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,910 9,115 9,325 9,539 9,759 9,983 10,213 10,448 10,688 10,934 11,185 11,443 11,706 11,975 12,250 12,532 12,820Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,483 5,609 5,738 5,870 6,005 6,143 6,284 6,429 6,576 6,728 6,882 7,041 7,203 7,368 7,538 7,711 7,889Existing Desal Capital Improvements ($000)000003,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 3,024 4,640 4,747 3,237 4,968New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy CostsTotal Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 265,111 274,581 279,466 287,905 302,543 316,449 334,464 352,128 369,064 392,257 415,203 437,484 465,088 492,928 516,219 544,268Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 252,273 258,960 261,071 266,482 277,816 288,261 302,452 316,003 328,537 346,914 364,705 381,563 403,156 424,617 444,634 469,205NPV with CO2 Charge ($000)3,434,720NPV without CO2 Charge ($000)3,163,392R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-6Page 3 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 224Case:2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand88.2 90.8 93.6 96.4 99.3 105.7 108.8 112.0 115.2 118.6 122.0 125.6 129.3 133.0 136.9 140.9 145.0 149.3 153.7 158.2 162.8Energy Requirements563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 929,369 956,514 984,474 1,013,272 1,042,935CC 1MWh449,159 385,716 448,406 453,360Fuel + CO2 Charge ($000)106,771 87,489 104,708 105,1390000000000000000CO2 Charge ($000)0000000000000000Unit 13MWh31,293 74,466 43,638 48,090Fuel + CO2 Charge ($000)6,472 14,831 9,051 10,1260000000000000000CO2 Charge ($000)Unit 15MWh1,159 761 100 31844,078 46,065 46,184 39,769 41,272 40,539 41,132 43,202 44,148 45,347 45,581 47,670 50,605 52,440 55,048 56,538Fuel + CO2 Charge ($000)355 249 35 10714,798 15,271 15,468 14,370 15,193 15,467 16,246 17,492 18,365 19,352 20,095 21,617 23,621 24,750 26,299 27,590CO2 Charge ($000)757 919 1,074 1,133 1,305 1,430 1,608 1,843 2,047 2,263 2,455 2,746 3,115 3,377 3,563 3,712Unit 18MWh9,075 25,082 15,070 15,973133,361 136,696 138,689 64,179 62,532 64,591 68,579 76,668 80,697 94,271 93,403 97,888 101,494 113,624 117,428 125,400Fuel + CO2 Charge ($000)2,188 5,893 3,629 3,88031,566 32,127 32,593 17,380 17,372 18,286 19,924 22,657 24,691 29,889 30,225 32,684 35,050 40,250 42,545 46,519CO2 Charge ($000)1,615 1,932 2,262 1,372 1,493 1,691 1,972 2,386 2,753 3,495 3,692 4,152 4,623 5,492 5,764 6,259Unit 22MWh85,208 103,456 100,225 108,75994,980 102,519 106,408 59,900 64,836 74,150 80,026 85,348 94,895 98,939 105,443 109,904 112,996 121,743 125,661 128,430Fuel + CO2 Charge ($000)14,458 16,629 16,704 18,01716,621 17,978 18,779 10,683 12,011 14,269 15,994 17,687 20,371 22,074 24,484 26,487 28,306 31,573 33,543 35,251CO2 Charge ($000)851 1,081 1,304 842 1,032 1,319 1,583 1,863 2,271 2,579 2,991 3,365 3,733 4,308 4,545 4,743Unit 23MWh4,655 8,719 8,761 8,09918,332 18,512 19,673 5,136 5,917 6,532 6,593 10,091 11,487 14,251 18,022 25,847 31,107 38,701 45,320 52,274Fuel + CO2 Charge ($000)1,200 2,242 2,318 2,1534,873 4,927 5,199 1,384 1,709 1,917 2,046 3,222 3,771 4,916 6,393 9,434 11,705 15,209 18,198 21,491CO2 Charge ($000)249 296 361 109 147 177 203 340 421 576 781 1,199 1,544 2,075 2,465 2,891New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 2Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB 3Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Total Fuel Cost ($000) 0 131,445 127,333 136,445 139,422 64,385 66,075 67,039 40,360 42,307 45,322 48,844 54,627 59,706 67,318 71,278 78,760 85,667 96,528 104,246 113,246Total CO2 Charge ($000)000003,472 4,229 5,000 3,457 3,978 4,618 5,366 6,431 7,492 8,913 9,919 11,462 13,016 15,253 16,338 17,605Incremental Non-fuel Production Cost ($000)000000000000000000000R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-7Page 1 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 224Case:2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Island of St. CroixIncremental Electric and Water Production CostsPeak Demand53.7 54.5 55.3 56.2 57.0 60.9 61.7 62.6 63.5 64.4 65.3 66.3 67.2 68.2 69.1 70.1 71.1 72.2 73.2 74.3 75.3Energy Requirements360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 478,375 485,236 492,199 499,266 506,440CC 1MWh317,225 320,208 327,636 331,508Fuel + CO2 Charge ($000)65,864 63,789 66,863 67,1690000000000000000CO2 Charge ($000)0000000000000000CC 2MWh49,051 51,273 49,299 51,079Fuel + CO2 Charge ($000)11,180 11,220 11,131 11,475CO2 Charge ($000)Unit 16MWh00002,004 2,494 3,530 500 218 882 733 584 1,847 1,830 2,718 3,382 5,815 5,846 7,856 11,437Fuel + CO2 Charge ($000)0000564 714 969 152 64 274 241 198 613 671 1,014 1,287 2,283 2,454 3,315 4,998CO2 Charge ($000)29 43 67 12 6 25 24 21 69 78 124 164 301 335 449 672Unit 17MWh000076,536 81,406 78,592 55,417 57,454 62,114 67,210 69,280 75,211 79,388 83,429 89,598 91,700 99,034 101,310 103,962Fuel + CO2 Charge ($000)000015,241 16,232 15,773 12,305 13,129 14,477 15,999 17,004 18,988 20,755 22,646 25,230 26,859 29,989 31,572 33,382CO2 Charge ($000)780 976 1,095 971 1,128 1,339 1,584 1,791 2,117 2,427 2,766 3,205 3,541 4,092 4,278 4,491Unit 19MWh0000345 657 908 50 97 65 123 227 264 689 890 1,964 1,044 2,508 3,588Fuel + CO2 Charge ($000)0000102 195 275 0 16 35 24 44 85 103 270 366 844 475 1,163 1,694CO2 Charge ($000)5 12 19 0 1 3 2 5 10 12 33 46 111 65 158 228Unit 20MWh000095,610 103,166 103,340 66,113 75,616 80,538 87,173 91,063 99,554 95,609 109,639 114,542 118,347 128,936 133,502 140,864Fuel + CO2 Charge ($000)000022,333 24,110 24,205 17,241 20,427 22,252 24,676 26,687 29,721 29,236 34,883 37,612 40,242 45,267 48,116 52,109CO2 Charge ($000)1,143 1,450 1,680 1,361 1,755 2,057 2,443 2,811 3,313 3,419 4,260 4,778 5,307 6,177 6,520 7,011New ResourcesCT1Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)CFB1Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,810 2,866 3,031 2,889 3,069 3,134 3,209 3,283 3,369 3,437 3,517 3,598 3,691 3,765 3,852 3,940Capital Cost ($000)20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764MWh313,632 312,666 323,275 301,248 312,791 312,191 312,501 312,546 313,505 312,646 312,701 312,711 313,637 312,680 312,720 312,720Fuel + CO2 Charge ($000)13,990 14,846 16,308 16,145 17,885 18,983 20,205 21,457 22,823 24,208 25,711 27,232 28,936 30,513 31,328 32,159CO2 Charge ($000)4,434 5,219 6,251 6,671 7,836 8,744 9,735 10,760 11,862 12,943 14,100 15,275 16,577 17,815 18,228 18,648CFB2Fixed O&M ($000)4,379 4,480 4,583 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,769 2,837 2,995 2,918 3,000 3,081 3,164 3,245 3,357 3,423 3,507 3,594 3,687 3,764 3,852 3,940Capital Cost ($000)20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764MWh309,086 309,581 319,461 304,250 305,729 306,909 308,165 308,943 312,426 311,376 311,859 312,343 313,284 312,583 312,705 312,715Fuel + CO2 Charge ($000)13,787 14,697 16,127 16,315 17,484 18,670 19,926 21,206 22,753 24,112 25,643 27,201 28,904 30,503 31,326 32,161CO2 Charge ($000)4,368 5,164 6,186 6,742 7,658 8,599 9,600 10,632 11,827 12,892 14,063 15,258 16,558 17,810 18,228 18,649CFB3Fixed O&M ($000)4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 5,624 5,753 5,885 6,021 6,159Variable O&M ($000)2,595 2,632 2,750 2,875 2,978 2,988 3,181 3,284 3,382 3,543 3,504 3,690 3,802Capital Cost ($000)22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229MWh270,593 268,230 273,932 279,991 283,468 278,009 289,381 292,030 293,918 301,050 291,032 299,584 301,710Fuel + CO2 Charge ($000)0 0 0 14,549 15,380 16,714 18,157 19,509 20,273 22,429 24,025 25,635 27,805 28,428 30,033 31,043CO2 Charge ($000)0 0 0 6,007 6,732 7,699 8,748 9,783 10,534 11,987 13,170 14,379 15,927 16,598 17,476 18,001Wind ProjectFixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)Interconnection Costs30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914Methanol Plant CostsLNG Capital CostsTotal Fuel Cost ($000) 0 77,043 75,009 77,993 78,644 55,258 57,929 58,358 54,942 59,268 62,939 67,092 70,302 75,524 77,755 85,676 91,458 97,550 104,736 111,518 119,846Total CO2 Charge ($000)0000010,758 12,864 15,298 21,765 25,117 28,466 32,136 35,803 39,731 43,758 48,517 53,106 58,323 62,892 65,336 67,700Incremental Non-fuel Production Cost ($000)0000086,778 87,104 87,633 117,138 117,760 118,354 118,977 119,581 120,143 120,833 121,470 122,114 122,851 123,359 124,126 124,831R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-7Page 2 of 3;7/24/2008;RWBeck Inc.Virgin Islands Water and Power AuthorityPower Supply EvaluationAppendix 224Case:2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System200720082009201020112012201320142015201620172018201920202021202220232024202520262027Total Authority System Eelctric and Water Production CostsTotal Authority Fuel Costs ($000) 0 208,489 202,342 214,438 218,066 119,644 124,004 125,397 95,302 101,576 108,261 115,936 124,929 135,230 145,073 156,955 170,218 183,217 201,265 215,764 233,093Total Authority CO2 Charges ($000)0000014,230 17,093 20,299 25,222 29,095 33,083 37,502 42,234 47,223 52,671 58,436 64,569 71,339 78,145 81,674 85,304Total Authority Incremental Non-fuel Production Cost ($000)0000086,778 87,104 87,633 117,138 117,760 118,354 118,977 119,581 120,143 120,833 121,470 122,114 122,851 123,359 124,126 124,831Existing Electric Resource Expenses:Steam RelatedNon-Fuel production Expense ($000) [1]8,136 8,323 8,514 8,710 8,9100000000000000000Combustion TurbineNon-Fuel Expenses ($000) [2]1,527 1,562 1,598 1,634 1,672 1,710 1,750 1,790 1,831 1,873 1,916 1,960 2,006 2,052 2,099 2,147 2,197 2,247 2,299 2,352 2,406Existing Desal System Non-fuel O&M ($000) [3]5,006 5,121 5,239 5,359 5,4830000000000000000Existing Desal Capital Improvements ($000)New Water ResourcesWater Production Requirements (Kgals/year)[7]2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912 2,030,912RO System:Annual O&M Excl. Electric Energy Costs ($000)[5]7,178 7,343 7,512 7,685 7,861 8,042 8,227 8,416 8,610 8,808 9,010 9,218 9,430 9,647 9,869 10,095Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184 6,184$/kGal Excl. Energy Costs6.58 6.66 6.74 6.83 6.92 7.00 7.10 7.19 7.28 7.38 7.48 7.58 7.69 7.79 7.90 8.02Total Electric and Water With CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 235,724 243,477 248,814 253,362 264,349 275,841 288,786 303,350 319,442 335,668 354,203 374,499 395,268 420,898 439,968 461,913Total Electric and Water Without CO2 Charge ($000)14,668 223,494 217,692 230,142 234,130 221,494 226,384 228,516 228,140 235,254 242,757 251,284 261,116 272,219 282,997 295,767 309,930 323,929 342,753 358,294 376,608NPV with CO2 Charge ($000)3,076,120NPV without CO2 Charge ($000)2,763,717R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls2-7Page 3 of 3;7/24/2008;RWBeck Inc.

# Appendix B Fatal Flaw Analysis1000 Legion Place Suite 1100, Orlando Florid a 32801 407-422-4911 Fax: 407-648-83822
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### February 25, 2008

Mr. Glenn Rothgeb Chief Operating Officer Virgin Islands Water and Power Authority

P.O. Box 1450 St. Thomas, VI 00804

Subject: Virgin Islands Water and Power Authority Power Supply Evaluation Fatal Flaw Analysis

Dear Mr. Rothgeb:

R. W. Beck has completed the Fatal Flaw An alysis in connection with the Power Supply Evaluation for the Virgin Islands Water and Power Authority (the “Authority”) under the provisions of the Professional Services Agreement between R. W. Beck and the Authority dated January 5, 2005. This letter Report summarizes our methodology, assumptions and findings from the Fatal Flaw Analysis.



## Background

The Authority has negotiated with R. W. Beck to update the Authority’s plans for power generation expansion and potable water producti on. Pursuant to the Scope of Services developed in collaboration with the Public Service Commission (PSC) and the Authority, R. W. Beck will prepare a power supply study to evaluate the Authority’s future power and water production options on the islands of St. Thomas and St. Croix (the “Power Supply Study”). The overarch ing objective of the Power Su pply Study is to provide the Authority with an understanding of near- a nd long-term power suppl y options that would improve the Authority’s cost of electric power production and simu ltaneously reduce its dependence on fuel oil.

The Authority requested that we consider the following candidate near-term supply-side options:

 

### Wind Powered Resources;

 

### Efficiency Improvements;

 

### Waste to Energy Proposals (if av ailable from the Authority);

 

### Circulating Fluidized Bed (CFB) Coal/Pet-coke Unit;

 

### Slow-Speed Diesel;

 

### Retrofitting existing simple cycle generating units to convert to combined cycle operation; and

 

### Other options to be determined.

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### R. W. Beck was also requested to consid er on a high level basis long-term options including:

 

### Direct current (DC) transmission intert ie between St. Thomas and St. Croix;

 

### Ocean Thermal Energy Conversion (OTEC); and

 

### Liquefied Natural Gas (LNG)

The initial phase of the Power Supply Study is the Fatal Flaw An alysis. This analysis is a high-level fatal flaw review of the candidate near-term electric s upply technologies at existing sites and potential new sites. This analysis also included a comparison of the incremental and fully allocated cost of reve rse osmosis (RO), desalination technologies at new or existing sites with the incremental cost of existing desalination to determine if the RO technology should be considered further as a replacement for a ll water requirements

on St. Thomas and St. Croix or incremental re quirements only. This initial phase of the evaluation addresses the following items.

 

### Operating constraints;

 

### Siting alternatives (impediments to installing necessary infrastructure);

 

### Fuel supply and pricing (busbar screen ing, availability of fuel supply);

 

### Environmental permitability; and

 

### Capital and non-fuel operating costs

As instructed by the Authority, the power supply evaluation relies upon information

contained in the Condition Assessment St udy Report prepared by Harris Group, Inc. (HGI) in 2005, and various a ssociated data and models provided by HGI in electronic format for purposes of fuel consumption and technical parameters relating to the Authority’s existing system.



## Existing Generation Facilities

The Authority has major generation facilities on the islands of St. Thomas and St. Croix, and has limited backup generating facilitie s on the island of St. John. Except for emergency situations, the electric power and energy requirements of the island of St. John are generated on the island of St. Thomas and transmitted to the island of St. John by means of two underwater cable s. Because of the extrem e water depth between them,

the islands of St. Thomas and St. Croi x are not interconnected electrically.

The Authority's generating facilities on the island of St. Thomas are located at the Randolph E. Harley Generating Station at Kr um Bay, which is on the southwestern end of the island. All electric ge neration for the islands of St . Thomas and St. John, and the two smaller islands, Hassel Island and Water Is land, are located at this site, except for an emergency diesel-generating unit located on the island of St. John. In addition to generation facilities, the Krum Bay site includes water produ ction, fuel oil unloading and storage, transportation, and warehouse facilities.

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### All of the existing generation f acilities on the island of St. Croix are located at the Estate

Richmond site on the north shore of the is land near Christiansted. In addition to generation facilities, the Es tate Richmond site includes water production, fuel oil unloading and storage a nd warehouse facilities.

As a part of its plan to pr ovide for increased demand for el ectricity and to improve the reliability of service, the Authority ha s acquired and installed a 41 MW combustion turbine generating unit which has been designated as Un it No. 23 on the island of St. Thomas, and which became operational in December 2004.

To provide, among other things, an additi onal source of steam for water production on the island of St. Thomas, the Authority insta lled a waste heat recovery steam generator (HRSG), sometimes referred to as a “waste he at boiler.” The HRSG was constructed in 1997 to utilize the exhaust gases from either or both combustion turbine Units No. 15 and No. 18 for the production of steam for electric generation and as an additional source of steam production on the island of St. Thom as for the desalination of water.

The Authority is proceeding with the in stallation of a second HRSG to convert

Combustion Turbine Unit No. 16 and No. 20 at the Estate Richm ond Generating Station from simple-cycle operation to combined-cyc le operation. The installation of the second waste heat boiler is projected to reduce fuel costs through the improved efficiencies and improve the overall generating reliability by increasing the amount of generation

available for reserves.

To improve generation efficiencies and to con tinue to lower system-wide fuel costs, the Authority is contemplating the installation of an additional HRSG on the island of St.

Thomas as a retrofit to Unit 23.

As shown below, the Authority's existing oil- fueled production facilitie s consist of steam, combustion turbine, and diesel generating units.

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### St. Thomas/St. John – Randolph E. Harley Power Plant

Unit No. Technology Fue l Type Rated Capacity (MW) In Service

Date



### 7 (St. John) Reciprocating E ngine Generator # 2 Oil 2.5 1985

11 Fired Boiler/STG [1] 

### # 6 Oil 18.5 1968

12 Simple Cycle CTG # 2 Oil 12.5 1970

14 Simple Cycle CTG # 2 Oil 12.5 1972

13 Fired Boiler/STG [1] 

### #6 Oil 36.9 1973

15 Combined Cycle CTG/HRSG [1] 

### # 2 Oil 20.9 [2] 

### 1981

18 Combined Cycle CTG/HRSG [1] 

### # 2 Oil 23.5 [2] 

### 1993

22 Simple Cycle CTG # 2 Oil 24.0 2001

23 Simple Cycle CTG # 2 Oil 39.5 2004

Total 190.8

[1] Fired boilers and HRSGs provide steam to steam headers to supply STGs 11 and 12 and four multi-effect distillation water pr oduction units. [2] Capacity shows CTG output only.



### St. Croix – Estate Richmond Plant

Unit No. Technology Fue l Type Rated Capacity (MW) In Service

Date



### 10 Fired Boiler/STG [3] 

### # 6 Oil 10.0 1967

11 Fired Boiler/STG [3] 

### # 6 Oil 19.1 1970

16 Combined Cycle CTG/HRSG [3] 

### # 2 Oil 20.9 [4] 

### 1981

17 Combined Cycle CTG/HRSG [3] 

### # 2 Oil 21.9 [4] 

### 1988

19 Simple Cycle CTG # 2 Oil 22.5 1994

20 Simple Cycle CTG # 2 Oil 22.5 1994

Total 116.9

[3] Fired boilers and HRSGs deliver steam to steam headers to s upply STGs 10 and 11 and four multi-effect distillation water pr oduction units. [4] Capacity shows CTG output only.

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 5 of 42

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### The Authority’s four steam generating units range in age from 33 to 39 years. The Authority’s ten combustion turbine units range in age from three to 36 years. Although some of the generating units have exceeded their normal life expectancy, the Authority has refurbished or reconditioned many of its units to extend their useful life. At this time, the Authority has not established expected retirement dates for its existing steam and combustion turbine generating facilities. Howe ver, based on the findings of the initial “Condition Assessment Study” performed by the Harris Group dated October 31, 2005, the Harris Group found, among other things, th at Combustion Turbines Unit No. 12 and No. 14 and boiler No. 11 on the island of St. Thomas should be dispatched on an emergency basis only and ev entually retired when repl acement generating resources become available. Furthermore, with the addition of a second HRSG at the Estate Richmond Generating Station, the Harris Group recommended that boiler No. 10 on the

island of St. Croix should be used as a standby unit.

As a part of the Authority’s maintenance and refurbishment program, the Authority has scheduled major maintenance on certain units including Unit No. 13 (37 MW steam) on the island of St. Thomas, one of the Authority ’s largest units, that has been temporarily derated to 25 MW. Following the rewinding of the turbine generator, Unit No. 13 is planned to return to service at its norma l rating of 37 MW. In addition, combustion

turbine Unit No. 22 on the island of St. Thomas has been remove d from service. Both of these units are assumed to be fully operational over the study period.

Given that the Authority ope rates two isolated electric generation and distribution systems, and the Authority's demand and energy requirements do not deviate significantly by season, the Authority, like other is olated electric systems, is required to maintain a higher level of generating reserves to provide for scheduled maintenance and forced outages, and to minimize interruptions in service. To reduce the potential for service interruptions and to improve the quality of service, the Authority’s established planning criteria for generating reserves ca lls for the Authority to have sufficient generating capacity on each island to meet its respective electric load requirements with its two largest un its out of service. In April 1991, in Docket No. 345, the PSC found, among other things, that the use of this pl anning criteria for gene rating reserves was prudent and in the best interest of the Aut hority's customers. The use of this planning criterion has been affirmed by the PSC in subsequent orders.

On the island of St. Thomas, the two larg est units are Unit No. 13, a steam turbine generator with a reported ne t continuous capacity rating of approximately 37 MW, and Unit No. 23, a combustion turbine generator w ith a reported net continuous rating of approximately 40 MW. The two largest units on the island of St. Croix are Unit No. 19 and Unit No. 20, two combustion turbine genera tors, each with a reported net continuous capacity rating of approximately 22.5 MW.



## Load and Capabilities

In connection with the Consulting Engineer ’s Report on the Virgin Islands Water and Power Authority, dated June 2007, projections of future power requirements by island were prepared for the period 2007 through 2011. These projections were based on an abbreviated heuristic analysis of historical demand and en ergy requirements, sales and

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### customer growth, usage patterns and ot her economic parameters, together with adjustments to reflect record levels of high fuel costs.

The projections also reflect a decrease in una ccounted-for losses over time resulting from implementation of the Authority’s loss reduc tion program. For purposes of the Power Supply Study the projected annu al average growth for the is lands of St. Thomas and St. Croix is projected to be 1.2 percent and 0.5 percent, respectively from 2012 through 2027

based on an extension of this forecast. It has been assumed that the Authority will continue to perform normal maintenance and re pairs of its existing plant in accordance with normal prudent utility practice.

To reflect the potential for a higher than e xpected load, a “Higher Requirements” load forecast was prepared as a sensitivity case. This load forecast assumed no reduction in unaccounted-for losses and growth rates of 3 percent and 1.5 percent for St. Thomas and St. Croix, respectively.

Based on the previously mentioned resources an d load projections for St. Thomas and St. Croix a summary of projected loads and resources for each island is shown on Table 1. Lines 10 and 26 show the total existing gene ration for St. Thomas – St. John, and St. Croix, respectively. The projected peak dema nd for St. Thomas – St. John, and St. Croix is shown on line 13 and 27, respectively. Capac ity available from reserves, which is the total capacity less peak demand is shown on lines 14 and 28. A comparison of the capacity available for reserves less the two largest units s hown on lines 17 and 31

indicates that under the base assumptions, no additional cap acity is required over the period 2007 through 2027 on either island.

Under the “High Requirement” load scenario shown on Table 2, it is assumed that Units

12 and 14 on St. Thomas will be retired in 2016, the first year that additional capacity would be required due to load growth without retiring these units. Under this sensitivity scenario, St. Thomas is projected to need approximately 26 MW in 2016 and 70 MW by 2027. No additional capacity is required on St. Croix under this “High Requirements” sensitivity scenario.

These cases indicate that while the Authority may not need additional capacity over the period 2007 through 2027 under the Base Case assumptions, additional capacity, particularly on St. Thomas, coul d be beneficial to meet higher than expected load growth and replace aging capacity.



## Resource Options

The following resource options were selected for screening by R. W. Beck based on the practicality of installing and operating them and their suitability for the Authority’s electric system:

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 7 of 42

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### Generation Resources

 

### Option 1 – 20 MW Circulating Fluidized Bed Plant

 

### Option 2 – 10 MW Wind Turbine Generator Farm

 

### Option 3 – 20 MW Combined Cycle Retr ofit of existing 40 MW Combustion

Turbine

 

### Option 4 – 10 MW Municipal Solid Waste Generating Plant

 

### Option 5 – 10 MW Reciprocating Slow Speed Diesel Engine Generator

 

### Option 6 – 10 MW Photovoltaic Cell Array



### Fuel Supply Options

 

### Option 8 – Liquefied Natural Gas

 

### Option 9 – Methanol from Gasification of Petroleum Coke

In addition to the resources listed above, Ocean Thermal Energy Conversion (OTEC) is considered to be a potential pow er generating source. OTEC is an ener gy technology that converts solar energy collected by the ocean to electric power. The OTEC process can also be applied to pr oduce large quantities of desalinated water. OTEC Systems use the ocean’s natural thermal gradient to drive an open or closed power producing cycle.

About a 20 o 

### C temperature difference, which would be found in very deep water, is required for OTEC operation. Tropi cal islands that are situated in close proximity to very deep ocean locations are considered to be typical candidate sites for the application of

OTEC. Based on research conducte d in the 1990’s, the vicinity of Rust Up Twist on the island of St Croix was determined to be a good location for such a facility as it is located less than one mile from a very d eep area of the Atlantic Ocean.

While there are small sized demonstration plan ts operating in India, Japan and Hawaii,

there are no installations that demonstrate the technical and economic viability of this technology on a commercial ba sis. According to the National Renewable Energy Laboratory (NREL), to accelerate the developm ent of OTEC systems, researchers need

to:



##  Obtain data on OTEC plant operation with appropriately sized demonstration plants,



##  Develop and characterize co ld-water pipe technology an d create a database of information on materials, desi gn, deployment, and installation,



##  Conduct further research in the areas of innovative turbine con cepts for the large machines required for open-cycle systems, and



##  Identify and evaluate advanced concepts for ocean thermal energy extraction.

Since OTEC technology is still in the demonstrat ion phase with plant sizes no larger than

1 MW and since there are t echnical challenges to be overcome in applying this technology to larger plants, we do not consider it as an option that is ready for direct use

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### as a commercially proven resource to meet th e Authority’s needs at this time. However, based on the potential of this technology, it may be prudent for the Authority to participate in a research oriented OTEC project.



## Methodology and Assumptions

Under the Base Case assumptions, a new generating resource will be an economic option for the Authority if the all-in cost including debt service on capital investment, fixed and variable production operation and maintenance expenses, and fuel is less on a dollar per

MWh basis than the incremental cost of th e generation it displaces on the Authority’s

system.

The generating systems on St. Thomas and St . Croix involve multi-unit configurations operating in combined cycle operation. Based on HGI’s Condition Assessment Study, the recommended configuration on St. Thom as that meets rec ognized reliability

constraints 1 

### assumes that combustion turbine units 15 and 18 are supplying waste heat to the heat recovery steam generators (HRSG) . Steam turbine gene rators 11 and 13 are driven by steam from the HR SG and boilers 11 and 13. Units 22 and 23 are brought on

as needed. Units 12 and 14 are in reserve st atus. Steam is supplied to the desalination plant on a continuous basis.

HGI’s recommended configuration on St. Croi x that meets recognized reliability

constraints 1 

### assumes that combustion turbine units 16 and 20 supply waste heat to the new HRSG. Steam turbine generators 10 and 11 are driven by steam from the HRSG and boilers 10 and 11. As a backup, Unit 17 can suppl y waste heat to the old HRSG to drive the steam turbines. Unit 19 is brought in as needed. Steam is supplied to the desalination plant on a continuous basis.

Based on these configurations displaced energy costs were calculated for the Authority’s system assuming the maximum displacement of energy that would maintain a reliable system operation. Average system energy cost s were also calculated. These projected displaced energy costs and average system energy costs are used as a benchmark to compare various new generation alternatives. These projected displaced energy costs and average system energy costs are shown on Table 6.

As a part of this Fatal Flaw Analysis, a busbar screening of gene rating technologies was conducted. Cost projections were prepared for each potential ge nerating technology and compared to each other to reduce the num ber of options to the most economic alternatives for further detailed analysis.

The busbar screening was based on preliminary planning level cost and performance data for the various technologies su mmarized on Table 4. The busbar screeni ng curves on Exhibit 1 show the all-in average costs per MWh, including debt service on capital investment, fixed and variable projected ope rations and maintenance expenses, and fuel expense (if applicable), levelized over a 25-y ear period for a range of capacity factors. Also shown on this graph are the projected displaced energy costs and average system energy costs of the existing resources for each respective island.

1 The plant must be capable of handling steam and electrical demand over a full range of demand with the largest unit down for maintenance concurrent with the trip of the next largest unit.

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### All of the Authority’s generati ng units are fueled by oil. Hi storically, the Authority has purchased its fuel oil supply from Hess O il Virgin Islands Corporation (HOVIC), an affiliate of the Amerada Hess Corporation. As a result of a joint venture between HOVIC and Petroleos de Venezuela, S.A. the present entity HOVENSA was formed. HOVENSA has an obligation to supply fuel oil to the Authority for a period of 20 years from the declared commercial operation date of the new coking facili ties which occurred in 2002. For purposes of this Fatal Flaw Analysis, fuel oil assumptions were based on escalation rates for average crude oil as reported in the U.S. Department of Energy, Energy Information Administration (EIA), Annual Energy Outlook for 2007, (AEO 2007) and a starting fuel price based on the forward pr ices for crude oil in 2008 and 2009 plus $3.75/Bbl for transportation, as supplied by the Authority’s fuel consultant. Based on recent discussions with the Authority, deliver ed fuel prices were approximately $90.00 per barrel for December 2007 deliveries.

Certain options considered in this evaluati on involve the use of petroleum coke (petcoke) fuel and coal fuel. Prices for pet-coke fuel have generally increased at a higher rate over the last few years relative to coal prices. Based on a meeting with HOVENSA, approximately 3,300 – 3,500 tons of pet-coke is produced per day on the island of St. Croix as a by-product of the refining proces s. Pet-coke from HOVENSA would be priced at a market index. The current pr ice reported by HOVENSA is $40-$45 per metric ton, which is equivalent to approximately $1.43 per MMBtu based on a reported heat content of 14,276 BTU per lb rece ived. We have assumed this price will escalate at 2.65 percent annually in nominal terms based on escalation rates for average U.S. coal fuel as reported in the EIA AEO 2007.

Coal Fuel was assumed to be priced at $2.90 per MMBtu based on recent market quotes for delivered 0.7 percent sulfur coal from Columbia as report ed by a representative of St.

Croix Renaissance Inc. Escalation for deliver ed coal was based on escalation rates for average U.S. coal fuel as previously assumed for pet-coke.

The cost estimates in this report are intended to allow various plant configurations to be evaluated at a conceptual or very initial planning level. A great deal of additional analysis and due diligence would be required to establis h capital and operating cost estimates for a specific plant at a level of detail and precision to support i nvestment decisions. However, these planning level cost estimates are considered to be appropriate for purposes of screening alternative power supply plans.

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## Environmental Considerations

Any of the generation options li sted above must be designed, constructed, a nd operated in compliance with applicable federal, territorial , and local regulations, guidelines, policies, codes, standards, and laws. Some of the ke y permits and approvals that may be required from various agencies are presented in the tabl e below. The list is not exhaustive, but is intended to provide a general idea of the types of permits that may be required for construction of a generating facility. We note that permitting requirements will vary based on the technology se lected and design of the facility, as well as site specific conditions. Thus, the actual permits require d for a specific technology and design will likely vary from another tec hnology and design. For the U.S. Virgin Islands, regulatory programs fall under the jurisdiction of seve ral different agencies and the agency identifiers below are intended to be generic in nature, particularly at the territorial-level.

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### Listing of Key Permits and Approvals

Approval Responsible Ag ency Timing Comments

“No Hazard”

Determination Federal Aviation Administration (FAA)

Obstruction Evaluation Services (OES) To be obtained prior to

start of construction. Required to demonstrate no

hazards to aviation if stack or buildings exceed certain height thresholds

Hazardous Waste

Identification Number United States

Environmental Protection Agency (USEPA) To be obtained prior to start of operation. Required if the Project is to use, manage, and dispose material categorized as hazardous waste. Disposal must follow manifest tracking system.

Oil Spill Prevention

Control and

Countermeasure Plan USEPA To be prepared prior to start of operation Required as per 40 CAR 112,

Oil Pollution Prevention regulations, if the Project stores more than 1,320 gallons at the site (including electrical equipment, transformer oil). Plan must be prepared before start of operation.

Clean Water Act

Section 404 Wetland

Permit U. S. Army Corps of Engineers (USCOE) To be obtained prior to

start of construction. Required if discharge of dredge or fill material into

wetlands and waters of the US is necessary for project construction. Also triggered by other actions.

Section 10 Permit USCOE To be obtained prior to

start of construction Required for construction of facilities in navigable waters

and shoreline facilities

Threatened and Endangered (T&E) Species Determination US Fish and Wildlife

Service Determination required

before start of

construction May be required to assess impact of project if a federal permit, such as a Section 404, is required

Air Quality

Construction Permit USEPA To be obtained prior to

start of construction. Required to construct an air emissions source if permitting

falls under federal Prevention of Significant Deterioration (PSD) rules. Sets forth air emission limits, monitoring, and reporting requirements.

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TERRITORIAL/LOCAL

Title V Permit to Operate Virgin Islands Department of Planning

and Natural Resources (VIDPNR) To be applied for within

12 months after start of operation Will incorporate all air quality permit requirements into one

document

Coastal Zone Management Approval VIDPNR Required prior to start

of construction Approval requires the preparation of an

Environmental Assessment for

all facilities in the coast zone

Territorial Pollutant Discharge Elimination System (TPDES) Permit for Discharges

of Storm water

Associated with

Construction Activities VIDPNR To be obtained prior to

start of construction. Required for storm water management during

construction.

TPDES Permit for Discharge of Process

Wastewater VIDPNR To be obtained prior to start of operation. Required for wastewater discharges. May include storm water discharges.

TPDES General Permit

for storm water Discharges Associated

with Industrial

Activities VIDPNR To be obtained prior to start of operation. May be a general permit.

Could also be included in TPDES permit for wastewater discharge.

Zoning/Land Use Approvals Local Municipality To be obtained as necessary in the development process May be required depending on

location



### Emission rates and the net increase in emissions from a particular site will determine whether a proposed emissions source will be able to be permitted as a minor source under air quality regulations or will be defined as a major source and require permitting under the federal PSD rules. At this time, it a ppears the most significant obstacle that will affect permitting of a generating facil ity, based on technology using combustion, is related to air quality. NOx and SO 2 

### emissions from such a facility would be the primary concern. A recent study performed for the Authority by MACTEC (February 22, 2005)

indicates that the PSD increment for NOx is virtually exhausted at or near the existing Authority’s sites. This means that any new major source construction at or adjacent to the existing sites would likely have difficu lty in securing a PSD permit, without offsetting NOx emission reductions from the ex isting units, which would have to be in sufficient amounts to classify the new addition as a minor source. There were also various scenarios evaluated by MACTEC in which the National Ambient Air Quality Standard (NAAQS) for NOx was pr edicted to be exceeded. Ag ain, in these scenarios, an air quality permit for construction w ould not be issued to a project.

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### There is also information to indicate that SO 2 

### emissions, and possibl y NOx emissions, are

a concern on the south shore of St. Croix near the HOVENSA refinery. For generation options that include combustion sources, the best strategy will likely be to design the facility such that modeled emissions result in impacts below the deminimis levels for each pollutant of concern. We note that th e deminimis levels do not apply for Class I areas, the nearest of which is the Virgin Islands National Park located on St. John. Impacts from St. Thomas or St. Croix would not be expected to impact the National Park on St. John due to the separation distance of the islands and the prevailing winds.

As noted above the VIDPNR’s Coastal Zone Management Approval re quires preparation of an Environmental Assessment (EA). The EA includes, among other things, analyses of impacts to air quality, we tlands, cultural and historical resources, and threatened and endangered species. As part of this approval public notice and a public hearing would be required allowing comments from interested parties. The EA and public involvement process could be initiated for any of the proposed options at the existing power plant sites or at the new sites. Public support for any ne w site development would need to be strong, to overcome public opposition.



## Option 1 – Circulating Fluidized Bed Boiler with Steam Turbine

Generator

Circulating fluidized bed (CFB) boilers along with accompanying steam turbine generators have been in widespread use in the U.S. and overseas since the mid-1980s for small independent power and electric utility applications. The boiler is similar to a pulverized coal (PC)-fired boiler in many ch aracteristics, but is typically smaller (available in size range from 20 to 300 MW) and has always been a sub-critical design. The operation of a CFB boiler involves the in jection of a portion of the combustion air through a bed of fuel, ash and limestone on th e boiler floor. The upward flow of air

fluidizes the material and allows the use of a diversity of possible solid fuel types and mixtures. However, a CFB boiler has much higher maintenance costs than a PC-fired boiler as a result of high ma terial wear rates caused by er osion in the combustion zone and is also more difficult to operate and requ ires more operators than other comparably

sized solid fuel boilers.

In recent years, the CFB boilers have included both atmospheric pressure designs, which are successfully operating in several commer cial power plant locations, and pressurized designs, which operate at several atmosphe res of pressure, and have higher thermal

efficiencies. Pressurized CFB boilers are considered a developmental technology and

therefore are not bei ng included for the Authority’s consideration.

The most notable CFB achievements lie in the ability to burn less de sirable fuels such as pet-coke and satisfy current environmental em issions restrictions without the need for additional and costly NO X 

### and SO 2 

### control systems. This feature is achieved through lower combustion temperatures to minimize NO x emissions and the ability to introduce limestone directly into the combustion area to remove SO 2



### . As sufficient pet-coke is available from th e HOVENSA Refinery in St. Croix to more than meet the Authority’s current and futu re power generation needs on both islands and

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### the price is attractive in terms of its current level and volatility, it is logical for the Authority to consider the use of CFB tec hnology as a means of utilizing the readily available fuel. The CFB technology would provi de the Authority with the flexibility to burn a wide range of types and grades of solid fuel with the ultimate choice being made primarily on the basis of economics and availabi lity of fuel that is capable of meeting the

environmental emissions criteria.

A major challenge that will face the Authority in operating a CFB facility is the storage and disposal of the large qua ntity of solid waste (CaSO 4 

### ) produced from the limestone

that is used for removal of SO 2 

### . While there is a market for this waste in the mainland United States for use in concrete, wall board a nd other associated products, the sale of the waste is generally coordinated to minimize disposal expenses and typically does not provide a significant revenue st ream to CFB plants. Locally, there may be opportunities

to utilize the waste as a road base or as land fill material. No revenues are assumed from the disposal of solid waste.



### Operating Constraints

Solid fuel fired generating units are best ope rated in baseload mode at or near full capacity as much as possible. Cycling and load-following opera tions are typically

detrimental to both the technical and economic performance, causing an increase in the frequency and cost of plant maintenance.



### Siting Alternatives

CFB power plants require considerable acreage for their location in order to accommodate the required plant and ancillary equipment and fuel, limestone and waste storage and handling facilities. We estimat e that a CFB plant with a site build-out capacity of 3 x 20 MW units w ould ideally require approximate ly 25 – 35 acres of usable land. Approximately 10 acres would be used for the main power plant and short term fuel storage; approximately 5 – 10 acres woul d be required for the long term fuel and limestone storage; and approximately 10 – 15 acres would be needed for long term waste storage and disposal facilities. Additional acreage may be requi red in future if the waste material cannot be used locally and has to be stored for shipment off-island. The longterm storage area for waste material may be located remotely from the generating plant site, if necessary.

In addition to meeting the size requirements, the following criteria was also applied in the assessment of a potential CFB generating plant site:

 

### Availability of sufficient wate r for cooling and boiler make-up

 

### Proximity to deep water harbor for fuel a nd limestone deliveries and ash collection if

necessary

 

### Property rezoning and pl ant siting requirements

 

### Proximity of nearby residences and othe r potentially sensi tive noise receptors

 

### Ability to meet environmenta l permitting requirements

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### Proximity of suitable point of interc onnection to the electric system

 

### Access to site for construction and long-term operation

 

### Limitations and restrictions caused by the ope ration of other facili ties in the vicinity, such as airports

On the island of St. Croix, the Authority ow ns approximately 7.5 acres of property in the

South Shore area near the HOVENS A refinery that can be made available as the site for a power generating plant. In addition, the Author ity reports that the pr operty situated to the north of and adjacent to the Authority’s pr operty is owned by the Virgin Islands Port Authority (Port Authority) and could be made available to the Authority to satisfy the property size requirement for a CFB facility.

This site was previously planne d to be used by the Authority for the construction of an oil fired steam generating plant which was cancelled in early development in the l970’s. The site is flat and would require minimal prepar ation for construction. A portion of the site appears to be low lying and pr one to flooding. This area woul d require filling to raise the

level.

The South Shore site is ideally situated to faci litate the delivery of pet-coke fuel from the HOVENSA refinery by conveyor belt or by ship, since a deep water dock operated by the Port Authority is located only several hundred feet from the site. Similarly, limestone may be delivered to, and waste collected from, the site by ocean going ships with relative

ease.

A major permitting issue for the South Shore site is the current air quality issues as a result of the HOVENSA refinery. This re finery has gone through several upgrades and the EPA has reported that potential emissions from the refinery and the near-by St. Croix Renaissance facility, consume all of the PSD increment for SO 2 

### . As a result, any new emissions from a new generation site would have to be very small (deminimus) to avoid the PSD permitting process. Demonstration of compliance with National Air Quality

Standards for both SO 2 

### and NOx would also be a concern.

An abundant supply of sea water is available in close proximity to the site for use in a once-through cooling water system and for conversion to high quality boiler make-up

water.

The site is located in an area that is populated by businesse s that operate heavy industrial processes including power gene ration, so property zoning should not present any issues for the Authority. There are no nearby sensitive noise receptors.

Interconnection to the electric system can be achieved by installing duplicate express 24.9 kV ties from the CFB generating plant substation to the substation at the existing Estate Richmond Generating Station which is approximately six miles away. Other

radial distribution circuits th at presently originate from the Estate Richmond Generating Station (such as Feeders 3, 8 and 9) may be rearranged as necessary to be fed from the CFB Generating Station.

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### The island’s Henry E. Rohlsen Airport is located approximately three miles from the site and the FAA height limitation for structures in the vicinity of airports are not expected to impact the power plant design or operation.

A second potential site on the island of St. Croi x is located in the ar ea of Hams Bluff near

the National Guard Station. This site is covered by heavy vegetation and access to the area is limited to an unpaved road several mile s long. This site is situated on the coast in an area of deep water, but no docking facilities are present.

It appears that sufficient vacant acreage is available in the Hams Bluff area for a CFB power plant but rezoning is likely to be requi red since there are no industrial facilities in the general area. No re sidences or hotels were observed in the area of this site. It is believed that the government owns the property of interest, but this would have to be confirmed and the Authority would have to commence the acquisition process if it

decided to use this site.

Permitting approval of this site would probably be easier for air emissions, but the Coastal Zone Approval and the associated EA requirements (i.e. public approval) may be

more difficult.

On the island of St. Thomas, potential sites for the location of a CFB facility are very limited because of the developed nature of th e island and the potential for residential or tourism related development in those areas where fairly large tracts of land still exist. The potential site that appears to be most appealing when assessed using the major site

selection criteria is Grambokola Hill which is located adjacent to the existing power plant and desalination water facility at Krum Bay. The Grambokola Hi ll site is reported to be owned by the Federal Government. It once cont ained residences that were destroyed by a major hurricane several years ago and were ne ver repaired or rebu ilt. The area is overgrown by dense bush and access is restricted by a gate across the entrance road. The Authority is not aware of any plans by the Federal government to develop the area and believes it could be made available for development as a power plant site.

The total area of interest is estimated to be about 35 acres. The hill is located on a peninsula and slopes toward the sea. Extensive cutting and grad ing of the hillside will be required in order to create a site that make s maximum use of the av ailable space. Similar excavation of the hillside was performed to cr eate the adjacent Krum Bay site. This site

satisfies the site selection criteria with re gards to: availability of sufficient water; proximity to deep water harbor; property zoning; distance from residences; close proximity of electric interconnection point; a nd ease of access for plant construction and operation. There is uncertainty with respect to the ability to secure a new major air emission source permit for this site. Its proxi mity to the existing Krum Bay site could pose compliance problems for meeting National Ambient Air Quality Standards and PSD standards that may apply to the site. Furthe r investigations of th ese issues would be necessary if this site warrants further consid eration. Also, the western end of the runway at the Cyril E. King International Airport is located less than a mile from the Grambokola

Hill site. Because of the elev ation of the site and its close proximity to the aircraft landing and takeoff path, it wi ll be prudent to submit an application to the FAA as early in the process as possible to obtain a ruling on this potential fatal flaw.

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### Other potential issues that are likely to be pr esented by this site are related to aesthetics and acceptance by the community since the site is very near to the cruise ship berths and its high elevation will increase its visibility. Features such as covered pet-coke storage and other aspects of the plant design can be incorporated specifically to enhance the aesthetics of the facility.

Another potential site for consideration on St . Thomas is the undeveloped property in the Bovoni area at Stalley Bay near the island’s solid waste landfill facility. This location appears to have sufficient unused area to hou se a CFB facility. However, like the Grambokola Hill site, it will require significant excavation and grading to create a usable

site. It is also assumed that the landfill s ite will not expand be yond its current footprint and that all of the unused land on the Stalley Bay peninsula will be ma de available to the Authority for development of a power plant. The current owner of the property at Stalley Bay is reported to be the Government of the Virgin Islands.

The Stalley Bay site is on the ocean front and the water appears to be sufficiently deep to accommodate ships and barges for fuel deliveri es. There are no docking facilities in the vicinity of the site. Access to the site from Bovoni Road is pr ovided by one mile of unpaved road through the landfill facility.

An abundant supply of sea water is available in close proximity to the site for use in a once-through cooling water system and for conversion to high quality boiler make-up water. There are no nearby sensitive noise receptors.

Interconnection to the electric system can be achieved by installing 34.5 kV subtransmission ties from the CFB generating plant substation to the Tutu and East End

substations which are both a pproximately three miles away.

Similar to the Grambokola Hill site, this site is situated at a location that will afford the CFB plant fairly high visibility from hotels and upscale residences on the South Coast.

Air permitting of a new generation facility at th is site would be easier as compared to the existing Krum Bay site and the Grambokola Hill site. However, VIDPNR’s Coastal Zone Approval and the associated EA a pproval requirements could be difficult.



### Fuel Supply and Pricing

Under normal operation, the HOVENSA refinery produces up to 3,500 tons of pet-coke per day. A 20 MW unit operating at full outpu t is projected to burn approximately 158 tons of pet-coke per day. According to HOVE NSA, the pet-coke produced at the refinery is sold primarily to the Jacksonville Electri c Authority’s North End Generating Plant. However, HOVENSA anticipates no difficulty entering into a long term supply arrangement with the Authority to supply sufficient pet-coke for three 20 MW units on

St. Croix and three 20 MW units on St. Thomas with a total fuel consumption of up to 948 tons per day.

The sulfur content of the HOVENSA pet-coke is reported by HOVENSA to be stable at 3.5 percent to 4.5 percent.

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### Pet-coke deliveries to the St. Croix site can be made by an enclosed conveyor system or by barge and deliveries to the St. Thomas site can be made by barge or by ship.

HOVENSA reports that the recent FOB selling pr ice for its pet-coke has been between $40 and $45 per metric ton which equates to $1.27 - $1.43 per MMBtu at a heat content which is reported to be 14,276 Bt u/lb. The estimated cost to transport pet-coke from St. Croix to St. Thomas is approximately $4 per ton.

Limestone for sulfur removal during combustion is estimated to cost approximately $19 per ton delivered and can be sourced from the U.S. and South America.



### Environmental Permitability

As noted above, in the Virgin Is lands there are significant concerns

, 

### both at the existing Authority power plant sites and near the existing HOVENSA Refiner y, with respect to

NOx and SO 2 

### emissions and their resulting impact on air quality. For this reason, it could reasonably be expected that the air quality permit would be the key permit for a proposed

CFB installation. On a lb/MMB tu basis, NOx emissions from a CFB are considerably lower than from the slow speed diesel reci procating engines eval uated in the MACTEC report. However, the characteristics of the em issions, such as a difference in temperature, flow rate, and pound per hour emission rate, do not a llow a simple ratioing or extrapolation from the slow speed diesel an alysis to estimate what a modeled impact might be.

Although CFBs can achieve high levels of control with respect to SO 2 

### emissions, the high sulfur content of the pet-coke could cause SO 2 

### emissions to be a concern, particularly in

an area such as the south shore of St. Cr oix. As discussed above since the existing HOVENSA Refinery and the St. Croix Renaissa nce facility near the south shore site, consume the existing PSD increment for SO 2 

### , any new emission source would have to be permitted as a deminimus emission source (non- PSD) or emission off-sets would have to

be secured from HOVENSA or from St. Croix Renaissance. Even with these hypothetical off-sets, demonstration of comp liance with National Ambient Air Quality Standards may be difficult. Due to these air permitting issues, air permitting of a CFB facility at the south shore St. Croix site is somewhat uncertain without further air compliance evaluations, which would likely include a screening-level modeling of estimated emission rates and investigation of th e availability of emission off-sets and the feasibility of obtaining them.



### Capital and Non-Fuel Operating Costs

The estimated total capital cost to install a 20 MW CFB unit on the islands of St. Croix and St. Thomas is approximately $160 million or $8,000 per kW. This estimate is based on the assumption that the project will inco rporate the installation of sufficient

infrastructure at the site to accommodate an ultimate build out of three 20 MW units. Preliminary estimates of the non-fuel fixed and variable O&M expenses for the 20 MW CFB unit which is expected to operate at a capac ity factor of 85 pe rcent are $100.00/ kWyr and $8.18/MWh (including limestone supply a nd solid waste disposal), respectively as

shown on Table 4.

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## Option 2 – Wind Turbine Generators

In April 2006, a report titled “A Detailed Wi nd Energy Case Study for Point Udall on St. Croix, Crown Mountain on St. Thomas and Esta te Concordia on St. John” was prepared for the Virgin Islands Energy Office, a di vision of the Department of Planning and Natural Resources, Government of the U. S. Virgin Islands by Energy Answers Corporation of Puerto Rico (the “2006 Wind Energy Report”). Analyses of the data

collected from the three sites studied lead to the conclusion that the sites are considered acceptable for wind energy applications. For pur poses of this Fatal Flaw Analysis, it has been assumed that wind turbine generation ca n achieve an average annual capacity factor in the range of 20 – 30 percent. Howeve r, the report recommends additional data monitoring at the oper ational height of the selected wind turbine over a twelve month period in order to better pr edict the performance of the wind turbine generator.

Because of the difficulty in transporting comp onents of the wind turbine generators to suitable locations in the Virgin Islands, the report recommends that the 800 kW sized unit be considered rather than the larger 1.5 MW and 2.0 MW units.



### Operating Constraints

Energy generated by wind turbin e generators is “non-dispatch able” and must be absorbed by the electric system as and when it is pr oduced. As a result, such generating resources cannot be relied on as capacity and serve in the role of producers of energy only. In addition, because of the inconsistency and su dden variations in the level of the wind resource, sufficient spinning reserve must always be available to the system to maintain the overall system performance

.


### Siting Alternatives

Several areas have been identified on the Isla nd of St. Croix as potential sites for wind energy projects as follows:

 

### East end where the island is less than two miles wide and has a spine of hills running

east to west in the Point Uda ll area. Most of the land in this area is reportedly owned by the Virgin Islands Government and Th e Nature Conservancy. There are no residential developments in the area. The Authority’s Feeder No. 2 may be used to connect the wind turbine genera tors to the electric system.

 

### Various potential locations exist on the h ills along the southern coast towards the HOVENSA Refinery. Most of the land in this area is reportedly owned by a relatively small number of private owners and residential development is sparse to moderate along this stretch.

 

### The island’s north coast from Teague Bay to Christiansted Harbor. Development in this area is sparse to moderate with uppe r middle to high-end residences and several hotels and it is anticipated that property owners would object to any plans to site wind turbine generators in this area.

 

### The range of hills along the island’s northwest coastline. This area is very mountainous and is lightly developed. Acces s to potential sites is poor and the

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### Authority’s electric system would have to be extended to these areas for interconnection purposes.

 

### South Coast offshore. The potential exists to site wind turbine generators offshore on the coastal shelf that extends along the island’s south coast. Selection of this siting option would require a detailed assessment of the environmental and other impacts compared with land based sites.

The island of St. Thomas is very heavily de veloped, providing very few areas that would be favorable for wind energy installations. The siting opportunities identified in the 2006 Wind Study Report are as follows:

 

### Sites of existing communication tower in stallations. Where sufficient space is available, consideration can be given to locating wind energy units adjacent to existing communication towers since these towers have already been accepted from a visual perspective.

 

### Near the solid waste landfill in the Bovoni area. This is the same area described earlier in this letter report as a potential site for a CFB project. While there are no nearby residents, the wind turbine units w ould be clearly visibl e by residents along the southeast coast and the surrounding hills.



### Environmental Permitability

It is expected that under this technology option, permits re lated to local zoning and special use would be the key pe rmits for construction. There could be impacts related to aesthetics and noise and local oppo sition to such an installati on is not known. Therefore, the difficulty of obtaining the required permits , authorizations, and/or variances cannot be estimated with any degree of certainty. Due to the amount of land disturbance required for a facility of this type, a storm water pe rmit for construction activities would need to

be obtained.



### Capital and Non-Fuel Operating Costs

The estimated total capital cost to install 10 MW of wind turbine generators on the islands of St. Croix and St. Thomas (on-shor e installation) is a pproximately $30 million or $3,000 per kW. All of the O&M costs associ ated with the units are assumed to be fixed costs at an estimated $50/kW-yr. The wind turbine generator farm is projected to operate at a capacity factor of 25 percent.

A recent review of information regarding off- shore wind turbine projects indicates that the cost of construction and permitting impacts for off-shore installations is significantly higher (as much as 100 percent) than on-shor e installations. Recognizing this cost

differential between off-shore and on-shore wind turbine projects , the on-shore wind turbine project was selected as the candidate for the busbar analysis.

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## Option 3 – Combined Cycle Retrofit

As an initiative to improve its overall system efficiency, the Authority is considering the implementation of a project that would a dd a waste heat recovery steam generator (HRSG) at the Randolph E. Harley Generatin g Station to capture exhaust heat from combustion turbine unit 23 and generate high pressure (HP) steam at 900 psig and low pressure (LP) steam at 30 psig, with integral deaerator and feedwate r system. The steam will be used for power generation and wate r production and will replace steam that is currently being produced by oil-fired boilers.

The GE Frame 6B units have been in si mple cycle and combined cycle operation commercially for more than 20 years and are considered to be a proven technology.



### Operating Constraints

This unit can be operated as a base load or inte rmediate unit. Efficiency decreases at part

load and turndown is limited to about 60 percent by the steam cycle equipment and emissions constraints. Maintenance outage frequency, duration and costs are adversely impacted by frequent start/st op cycles. Start-up times can be up to 6 hours if the unit is

cold.

A major issue for consideration in assessing the feasibility of this option for the Authority is the impact on the system when such a large resource trips off the system when operating at or near maximum electri c power and steam production capacity.



### Siting Alternatives

The HRSG and associated auxiliary equipmen t would be installed in available space adjacent to combustion turbine Unit 23 at the Randolph E. Harley Generating Station.



### Environmental Permitability

Of the generation options involving a combus tion resource, a combined cycle option may be the most attractive from a permitting st andpoint. The combined cycle technology

lends itself well to the use of selective ca talytic reduction (SCR) fo r the control of NOx emissions, and the ability to use fuels such as natural gas, methanol, or ultra low sulfur diesel can lead to virtually insignificant SO 2 

### emissions. However, without further evaluation, which would likely include a scr eening-level modeling of estimated emission rates, a definitive answer as to the permitability of such a unit cannot be determined.



### Capital and Non-Fuel Operating Costs

The estimated capital cost to retrofit the St. Thomas 40 MW com bustion turbine with a HRSG and 20 MW steam turbine generato r is $44 million or $1,233/kW for the total capacity when a $30 million allowance for the existing CT is taken into account. Preliminary estimates of the non-fuel fixed and variable O&M expenses for the 60 MW combined cycle unit which is expected to ope rate at a capacity factor of 50 percent are $41.25/ kW-yr and $4.03/MWh, respectively.

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## Option 4 – Municipal Solid Waste Steam Turbine Generator

The Authority reports that in discussions w ith the Government Department responsible

for solid waste collection and di sposal, it was disclosed that the Department is interested in installing a single facility to incinera te the municipal solid waste (MSW) from the entire group of islands. Th e incineration would take pla ce in a boiler, producing steam that then would be used to produce electric ity in a steam turbine generator. Such a process would have the benefit of significantly reducing the required landfill area (this is important on small islands where space for landfills is very limited). The major challenge is to make the operation work fina ncially since traditiona lly MSW plants cost more to build and operate that standard fossil fueled plants.

The two main MSW power generating designs that are found in the United States are mass burn and refuse derived fuel (RDF) facilit ies. In mass burn facilities, which are the most common type, MSW is burned directly in a similar way to solid fossil fuels in other direct combustion technologies. In RDF fac ilities, the MSW is processed prior to direct combustion. The level of pre-combustion processing varies among facilities, but generally involves shredding of the MSW and removal of meta ls and other bulky items.

The shredded MSW is then used in the same manner as at mass burn plants.



### Operating Constraints

Solid fuel fired generating units are best operated in base load mode at or near full capacity as much as possible. Typically the units are operated as a “must-take facility” and as such are not considered dispatchable resources.



### Siting Alternatives

The area adjacent to the St. Thomas landfill in the Bovoni area appears to be ideally suited for a MSW facility. The same siting attr ibutes as discussed previously for the CFB option would be applicable to a MSW plant located at that site.



### Fuel Supply and Pricing

Fuel supply for the plant would be the MS W collected on St. Thomas, St. John and St. Croix, which consists of everyday items such as product packagi ng, grass clippings, furniture, clothing, bottles, food scraps, news papers, appliances, pa int and batteries.

MSW from St. John and St. Thomas would be transported by barge to the St. Thomas plant site. The 10MW facility operating at an 80 percent capacity factor, and burning

MSW with an assumed heat content of 9.6MMBtu/ton would require about 128,000 tons of MSW annually. Based on information from the 2004 Annual Report by the USVI Division of Environmental Protection, th e MSW production on St. Croix alone was estimated at 130,000 tons in the year 2000. Thus, the MSW production for the Territory appears to be sufficient to meet the needs of a 10MW facility.

A “tipping fee” is normally paid by trash ha ulers to the MSW facility owner for the disposal of waste materials. No tipping fees are assumed for the base case busbar analysis. However, we did perform an analys is to determine the required tipping fee or fuel subsidy on a dollar per ton basis that would be required to render the dollar per

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### megawatt hour cost of the MSW plant option eq ual to the cost of the CFB option burning 50% pet coke and 50% coal. The requi red tipping fee or subsidy ranges from approximately $64.00 per ton in 2012 to $97.00 per ton in 2036. As a reference point, such tipping fees are comparable to those typi cally seen in Florida for MSW facilities.



### Environmental Permitability

MSW units lend themselves well to the contro l of emissions generated from combustion

of the waste in a boiler. The inclusion of S CR, a dry scrubber, and fabric filter in the design can allow the unit to achieve fairly low emission rates for NOx, SO 2 

### , and particulate matter The federal New Sour ce Performance Standards (NSPS) contain emission limits for various pollutants from both large and small MSW units. As with the

above discussions related to the other techno logies involving combustion, without further evaluation, which would likely include a scr eening-level modeling of estimated emission rates, a definitive answer as to the permitab ility of a such a unit cannot be determined.



### Capital and Non-Fuel Operating Costs

The estimated capital cost for a 10 MW MSW generating facility lo cated at the landfill site on St. Thomas is $105 million or $10,500/kW of installed capacity. Preliminary

estimates of the non-fuel fixed and variable O&M expenses for the facility which is projected to operate at a capacity factor of 75 percen t are $375/ kW-yr and $75/MWh, respectively.



## Option 5 –Reciprocating Engine Generator

Reciprocating engine ge nerators burning No. 6 heavy fuel oil are a proven technology for power generation and are in use in island sy stems similar to the Virgin Islands.



### Operating Constraints

These units are generally operated as base lo ad generating resources. The performance of the engines is typically guaranteed for opera tion down to 50 percent of rated capacity.



### Siting Alternatives

On both St. Thomas and St. Croix, the alte rnative sites for a reciprocating engine generator power plant would be similar to those discussed earlier in this report for the CFB option.



### Fuel Supply and Pricing

No. 6 heavy fuel oil for the reciprocating engi nes would continue to be supplied from the HOVENSA refinery. While this technology will not lessen the Authority’s dependence on oil, it would provide substant ial benefits in the form of lower fuel consumption as a result of the efficient heat rate. Projected price for No. 6 heavy fuel oil is shown on

Table 3.

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### Environmental Permitability

Based on the MACTEC report of February 2005, slow speed diesel reciprocating engines operating without a SCR, would not be permitable on St. Croix, nor on St. Thomas

, 

### due to the high rate of NOx emissions. Other te chnologies, such as medium speed and high speed options may be permitable, but a definiti ve conclusion cannot be reached until site specific emission rates are modeled and compared to the applicable air quality standards.



### Capital and Non-Fuel Operating Costs

The estimated capital cost for a 20 MW slow sp eed diesel engine generator power plant is $40 million or $2,000/kW of installed capacity. Preliminary estimates of the non-fuel fixed and variable O&M expenses for the facility which is projected to operate at a capacity factor of 85 percent are $75/ kW-yr and $7.5/MWh, respectively



## Option 6 – Photovoltaic Systems

Photovoltaic (PV) type systems are based on solid-state semi-conduc tor devices with no moving parts that convert sunlight directly to electricity. Their first major application was to power satellites in the 1950s. To date , PV systems have been used primarily in distributed applications and for off-grid use. The installations generally consist of a rooftop unit where the rooftop provides the space and support for the array of cells. Apart from the cost of the equipment, the ma jor challenge associated with utilizing PV technology for a central plant application is the space requirement of approximately 6 acres per megawatt for a central PV power generating facility.



### Operating Constraints

Energy generated by PV systems is “non-disp atchable” and must be absorbed by the electric system as and when it is produced. As a result, such gene rating resources cannot be relied on as capacity and serve in the ro le of suppliers of energy only. Of course, energy can only be generated by PV units dur ing the daytime and the quantity of energy produced is highly dependent on the amount of cloud cover. It is estimated that a PV system in the Virgin Islands would operate at an average capacity factor of approximately 15 percent.



### Siting Alternatives

As discussed previously, the island of St. Thomas presents very limited opportunities for locating central generating pl ant facilities because of the extensive residential development. On the island of St. Croix, good potential exists on some of the properties that previously served as farmlands. A 10 MW array of PV cells would require approximately sixty acres of space.



### Environmental Permitability

This activity could require a significant envi ronmental effort in order to obtain the permits and approvals necessary for cons truction. Depending on the interconnection circuit routing, an EIS may be required.

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### Capital and Non-Fuel Operating Costs

At approximately $8,500 per kilowatt, the estimat ed installed cost of a central PV system in the Virgin Islands is among the highest on a per kilowatt basis for a commercially available electric power generating unit. Fi xed operating cost is estimated at $31.25 per kilowatt year and variable operating cost is estimated at $12.50 per megawatt hour.



## Option 7 – Interconnection of St. Thomas and St. Croix Electric Systems

The distance between the existing St. Cr oix and St. Thomas pow er plant sites is approximately 45 miles as the cr ow flies. However, the dire ct route passes through water that is approximately 12,000 to 18,000 feet deep. In order to avoid such depths, and limit

the route to water that is no more than a pproximately 6,000 feet d eep, a route length of about 100 miles would be required for submar ine cable to interconne ct the two island electric systems. Because of the consid erably long route length and the associated limitations of AC cable transmission, we have assumed that the link would be provided by a DC circuit operating at 150 kV between the substations of the two power plants.

Potential savings from this option would be in the form of the use of larger size generators with associated economies of scale, less planning reserves and reduced spinning reserves. As stated previously, th e planning reserve margin is based on the two largest units on each island. The interconnect ion could reduce this planning margin to the two largest units on the two islands collect ively. Another potential advantage of an interconnection would be the ability to repla ce smaller generating units with larger units that have lower capital cost s per kW. Without the interc onnection, each island must operate its system to be able to withstand the sudden loss of its largest unit due to a forced outage. On St. Croix, due to it s smaller load and ex isting generation unit configuration, the size of its generating units are limited to approximately 20 MW each,

in order to maintain a reliable system. With interconnected sy stems, larger units could be installed on either island without reducing the systems reliability.

Also with an interconnected system the amou nt of spinning reserves could be shared between the islands and reduced, allowing the Authority’s generating resources to operate more closely to their most efficient full load output.

The bulk of these potential cost reductions a ssociated with the interconnection may not be realized until the Authority adds new capacity or replaces existing capacity on its

system.



### Operating Constraints

The interconnection would not impose any operating constraints on the interconnected system. In fact, it would enable the combined resources to operate at optimum efficiency to the extent that they can while maintaini ng their local production of steam to drive the

desalination units on th e individual islands.

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### Environmental Permitability

This activity could require a significant envi ronmental effort in order to obtain the permits and approvals necessary for constr uction. Depending on the routing, an EIS may be required



### Capital and Non-Fuel Operating Costs

The cost estimate to connect the islands of St. Thomas and St. Croix using a 100 mile long 150 kV DC interconnection with two HVDC terminals with a transmission capacity of 150 MW is in the range of $300 - $350 million. This is a very preliminary planning level estimate as there are sign ificant unknowns related to the in stallation of cable in very deep open waters.



## Option 8 – Liquefied Natural Gas Fuel Supply

R. W. Beck prepared a report titled “Feasibility of the Conversion of Fuel Oil to Natural Gas Fired Generation” and dated July 10, 2007 for the Authority (the “Beck 2007 Fuel Conversion Report). The report examines the technical feasibility and develops preliminary costs for operating the existing ge nerating plants at St. Thomas and St. Croix on natural gas instead of oil.

The scenario that appears to be most attractive for the Virgin Islands is to have liquefied natural gas (LNG) supplied to the islands from the Ecoelectrica LNG facility in Puerto Rico by a small ship that could be owned and operated by the Au thority or hired on a long term basis to make deli veries exclusively to the Au thority. To accommodate the LNG deliveries, the Authority would have to construct a re ceiving port, storage and regasification facilities at St . Thomas and St. Croix.



### Operating Constraints

Conversion to natural gas woul d not be expected to impose any significant constraints on the operation of the existing generating plant a nd the cost of necessa ry modifications to the plant fuel systems and equipment combustion and control systems would be very minimal compared to the cost of the ship, por t, storage and re-gasification facilities.



### Siting Alternatives

The location of the gas receiving port and the storage and re-gasific ation facilities would be at or adjacent to the existing power plants. The St. Thomas site should not pose any significant issues as the Grambokola Hill property may satisfy any requirement for additional space. Because of the close pr oximity of residents and a school to the St. Croix power plant, there may be some oppo sition to any plan to locate a gas storage and re-gasification facility at that site.



### Fuel Supply and Pricing

LNG could be supplied primarily from Puerto Rico, with Trinidad serving as an alternate regional supplier The Authority could maintain the genera ting units as dual fired and

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### retain on-site fuel oil storage as back-up. Projected cost of LNG delivered to the Authority’s generating pl ants is shown Table 3.



### Environmental Permitability

Depending on the facility design and location, a significant e nvironmental effort may be required to obtain the approvals necessary for construction and operation. The construction of pipelines and loading term inals would trigger EA requirements under VIDPNR’s Coastal Zone Management approval. The permitting of combustion sources, if utilized for vaporization of the LNG and compression of the natural gas, could be problematic due to the exis ting air quality concerns.



### Capital and Non-Fuel Operating Costs

See Discussion of Results.



## Option 9 – Methanol Produced from Gasification of Petroleum
Coke

As an alternative to burning the locally av ailable and low cost pet-coke in new CFB boilers as described in Option 1 above, the Authority may also consider converting the pet-coke to a fuel that can be burned in its existing generators with minimal combustion system conversion costs. Such a fuel is me thanol which can be produced from pet-coke by a gasification process that is well tested and proven. The gasification process converts the pet-coke into synthetic gas, or syngas wh ich is then used to produce liquid methanol. In addition to producing a fairly user-fri endly and easily transportable fuel, the gasification process also convert s 99 percent of the feed sulf ur into hydrogen sulfide gas

and results in minimal formation of SO 2 

### , NOx and volatile organic compounds (VOCs). The gasification process is exothermic, hence the process does not require a furnace. As a result of these characteristics, extensive emission treatment systems are not required for the gasifier and produces fuel th at generates minimal NOx and SO 2 

### when burned.

In a position paper prepared in 2001, GE stat es that tests have s hown that, with fuel system and combustor modifications, liquid metha nol is readily fired and is fully feasible as a fuel for combustion turbines. According to GE, relative to No. 2 distillate, methanol can achieve an improved heat rate, higher pow er output due to the higher mass flow, and

lower NOx emissions due to the lower flame te mperature. Since methanol contains no Sulfur, there are no SO 2 

### emissions. Also, the clean burni ng characteristics of methanol are expected to lead to clean hot gas path components and lower maintenance than with

distillate fuel.

Relative to distillate fuel, methanol has three main characteristics that make fuel system and turbine combustor modifications necessary: low heating value, low lubricity and low flash point. The low heating value means higher fuel flow rate, and therefore redesign of the fuel system components (including sizi ng of the fuel storage tanks). The low lubricity of methanol requires changes in the main fuel pump/flow divider system and use of a pressure flow divider or optional additi on of a lubricity agent. The low flash point necessitates precautions to eliminate possible sources of ignition. Floating roof storage

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### tanks and explosion proof components are re quired. In addition, unit startup must be performed on distillate or natural gas.

Applicable fuel system modifications are re quired for oil-fired boilers of the type operated by the Authority.

GE reports that in a 12-hour test conducte d on a 20 MW combustion turbine, the NOx emissions when firing methanol were 74 percen t less than the NOx emissions when firing

distillate.

Based on the Authority’s total fuel requi rement for St. Thomas and St. John, a gasification plant with a methanol production capacity of one milli on gallons per day is required. Such a plant would require appr oximately 40 MW of dedicated generating capacity to serve the plant auxiliaries.



### Operating Constraints

Using methanol as the main fuel for firing its existing generating pl ants would not impose any significant operating constraints on the Authority beyond those that are experienced when operating on distillate or heavy fuel o il. However, changes in plant operations would have to be implemented to address the explosion hazard in troduced by methanol and the requirement for unit startups to be performed on distillate.



### Siting Alternatives

Since the pet-coke supply exists on the island of St. Croix that island has been selected as the preferred location for the gasification plant. The South Shore site which was discussed previously as a potential site for th e CFB plant would be the ideal site for this facility. In order to accommodate the plan t and storage capacity, the Authority would need to secure additional property from the Port Authority. Also to address

environmental concerns at the South Shore site, it may be ne cessary to locate the 40 MW of dedicated generation for the gasificati on plant at the existin g power plant site.

An alternative to the South Shore site woul d be the Hams Bluff area. As discussed earlier, locating a facility in this area would require the installation of all new infrastructure including docks and an extensi on of the electric distri bution system to serve as an interconnection to the facility on the site . It would also require the transportation of pet-coke from the HOVENSA refinery to the site.

From either site, methanol would be tran sported by ocean to the Authority’s existing power plant facilities on St . Croix and St. Thomas.



### Fuel Supply and Pricing

Pet-coke for the gasification plant would be supplied under a long term contract with the HOVENSA refinery as discussed previously for the CFB plant option. Since this option does not involve firing the pet-coke in a boiler, no limestone would be required for sulfur removal and no large amounts of solid waste will be generated as a by-product. Project costs for pet-coke are shown on Table 3.

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### Environmental Permitability

This alternative would require the construction and operation of a gasification unit to produce methanol from pet-coke. With a gasification unit, the ability to capture problematic compounds such as SO 2 

### with a high efficiency is a distinct advantage. The permitting requirements and challenges for th is option would vary depending on whether a combined cycle unit, which would utilize the methanol as fuel, was constructed in conjunction with the gasificati on plant at the south shore site or at another site. The primary considerations for this option woul d be the need for deminimus air quality permitting considering the current air permitting issues associated with the HOVENSA

and St. Croix Renaissan ce facilities near-by.



### Capital and Non-Fuel Operating Costs

See Discussion of Results.



## Water Production by Reverse Osmosis

Membrane processes are well-established tech nologies for seawater desalination. The membrane processes included for seawater desalination is generally Reverse Osmosis (RO). RO uses pressure as a motive fo rce for the separation process and a semipermeable membrane. An RO desalination pl ant to produce drinking water generally is composed of six major components:

 

### Seawater Intake

 

### Pretreatment

 

### RO Desalination

 

### Concentrate Disposal

 

### Post-Treatment

 

### Product Water Storage and/or Pumping

In any consideration of cost estimate it is impor tant to be assured that all of the requisite

facilities have been included th at will be necessary to produce water of the quality desired for the customers. A concept design is typica lly developed to identify the site specific unique requirements and process options neede d. This concept design is then typically used to produce an engineer’s preliminary planning level estimate of cost. This cost estimate has been prepared in the absence of detailed information of many of the site specific requirements needed to prepare a pr eliminary planning level estimate of cost, but is intended to provide a useful basis for di scussion of potential co sts alternatives.

The purpose of this of this section of the repo rt is to provide the Au thority with high level overview of available RO plant cost information to consider in a fatal flaw evaluation and as a possible prelude to a plan ning effort to assess needs, develop a concept design and a planning level estimate of probable costs or to develop propo sal requirements.

R. W. Beck has been provided certain in formation regarding pr oposals from vendors that would supply an assortment of different components for skid mounted RO equipment

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### and/or turnkey supply of components for skid mounted RO equipment, operation and sale

of water. In addition we ha ve reviewed water demand proj ections and historic water usage data. The evaluation to develop the costs estimates included a review of the following:

 

### Average Daily Production (2002-2007), Virg in Islands Water and Power Authority

 

### Projected Water Sales and Requirements (2008-2017), Virgin Islands Water and Power Authority

 

### Richmond Desalination Proposal Detail, Seven Seas Water

 

### Offer NO: SWRO 4000/06, IDE SWRO Technologies, LTD

 

### Budgetary Water Treatment System Proposal, GE

 

### Water Analysis Report, GE

 

### Water Analysis Report, Ashland



### Operating Constraints

While an RO desalination plant could be co-located at the same site as an electric power generating plant, its operation is completely independent and does not inhibit the power plant from operating at its optimum efficiency level. The RO process would allow the Authority to focus on maximizing the performa nce of its power generating plant without considering the steam requirements of the existing multi-effect distillation (MED)

desalination units.



### Siting Alternatives

Locating the RO units at the existing locati ons of the MED units on St. Croix and St.

Thomas would enable the installations to ut ilize existing seawater intake and discharge infrastructure at potentially significant cost savings to the project. Both sites appear to have sufficient space to accommodate RO un its as replacements for the MED units.

The advantages of collocation of a desalination facility using an RO process with a power plant are very dependent upon the configuratio n of the power plant cooling systems, and operation of the power plant. The advantag es of collocation include the following:

 

### avoided costs due to use of the power plant’s existing intake infrastructure;

 

### lower energy use due to a heated sour ce of raw seawater for SWRO process;

 

### avoided costs due to use of the power plant’s cooling water discharge to

blend the concentrate from the desalina tion process with ambient seawater.

 

### reduced intake and discharge permitting costs

However, only certain power facilities are suitable as candidates for collocation. A power plant with a once through cooling configuration may provide an optimal cooling water system for collocation. With this type of configuration, the power plant circulates cooling water through a power plant’s condenser once and discharges the heated water to the sea. Since the allowable cooling water temperature rise is typically limited as a

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### condition of the power plant’s National Po llutant Discharge Elimination System (NPDES) permit, a large amount of cooling water is typically needed for cooling purposes. As a result, this conf iguration allows heated water to be reused as raw intake water for a desalination facility after the coo ling water exits the power plant’s condenser.

The warmer water can reduce the energy require d for the RO process. Additionally, the since the raw water supply for the desalination f acility is water that has already been used by the power plant, it does not require a new supply of ambient seawater so that there are essentially no additional a quatic impingement and entrai nment impacts due to the desalination facility. In addi tion, if the flow of power plan t cooling water is sufficient, the concentrate from the desalination proces s may be blended with power plant’s cooling water discharge and mixed with the ambien t seawater without significant discernable environmental impacts. Since the power f acilities generally use substantial amounts of water, the flow of power plant cooling water is often sufficient to accommodate concentrate blending without then need for pumping and diffusers.

SWRO membranes are sensitive to heat over a certain temperature and require that the pretreated water applied to the membranes mu st be below the manuf acturer’s temperature for the RO element’s warranty. Typically, th is requires seawater below 40 to 45 degrees

Celsius. In collocated desali nation plants, this fact may require the need for cooler seawater to control the temp erature of the post condenser seawater. This is often accomplished by intercepting a small amount of the power plant’s post screening intake

seawater or construction of a new ambient temperature seawat er intake and pumping this into the warm post condenser seawater supp ly. This consideration may impact the facility’s permitting requirements and cost.

In addition to the cooling syst em configuration, a power pl ant’s operating regime should also be evaluated to determine if the regi me is suitable for co-location. Power plant operating regimes may be classifi ed in three categories: (1) base-load; (2) peaking; and (3) base-load/peaking. A power plant with multiple base-load electric generating units typically offers the most co -location advantages. A base -load electric generating unit generates power more or less c ontinuously. Consequently, this type of electric generating unit rarely goes offline and provides a consta nt source of power and a consistent cooling water flow. A power plant with multiple base -load electric generating units improves the reliability of the power and cooling water so urces, as multiple electric generating units help prevent interruptions due to scheduled or unscheduled outages of any of the individual electric generating units at the pow er plant. At a peaking power plant, power generation is normally restrict ed to operation duri ng the periods of hi ghest daily, weekly, or seasonal loads. Therefore, electric generation and coo ling water usage are intermittent, being based upon the need for power . As a result, a power station with a peaking type of operating regime will not pr ovide a continuous or reliable source of electricity or cooling water for an RO desa lination facility. A base-load/peaking power plant is usually generating some power. Ho wever, the plant may operate on a reduced or low power production basis for the majority of time. If it is a power plant with multiple electric generating units typically, some ge nerating units would be shut down during

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### periods of reduced electric de mand. Since the individual elec tric generating units may be operated intermittently, this type of facility may not provide a consistent cooling water flow or electric generation output to support the SWRO facility.

Due to its operating regime, a power plant with multiple base-load electric generating units and once-through cooling offers the mo st advantages for co-location, since it provides a consistent and reliable cooling water flow that can be used as raw water for an RO process and for blending concentrate. Co-l ocation with power plants that consist of one or two electric generati ng units or other operating regimes may limit desalination facility availability, if an insufficient amount of raw water or cooling water for potable water production or for concentr ate blending is available.

While co-location with these facilities ma y be economically feasible, each situation should be carefully evaluated on an individua l basis. Reduced SWRO facility production will increase water production costs ($/1,000 gall ons), as the debt service for the facility would be distributed over a reduced product water quantity. Therefore, it is most economical to operate the desalination facility on a full-time basis and near its production design to minimize the cost of product water, du e to the economic effect of debt service for the facility.

In addition to the existing sites, the Authority is also considering locating an RO unit in the vicinity of Red Hook Po int to serve the Island of St . John and the east end of St.

Thomas. RO units are well suited for distri buted locations where seawater intake and discharge infrastructu re are permitable.



### Capital and Operating Costs

This cost overview is intended to allow various plant configurations to be evaluated at a conceptual or very initial pl anning level. A gr eat deal of additiona l analysis and due diligence would be required to establish capita l cost estimates for a specific plant at a level of detail and precision to support investment decisions. However, these tools will assist the Authority in initial planning regarding capital costs of facilities, operation and maintenance costs, annual production, water price and estimated revenues based on production for a wide variety of scenarios.

As shown in the table below, the capital co st per unit of water production decreases due to economies of scale as facilities get larger:

Beck prepared a life cycle cost analysis to develop preliminary estimates of the overall production cost as shown in the following tables:

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### Project Cost Estimate for a S eawater RO Desalination Facility Co-Located with Power Plant

0.5 MGD 1 MGD 1.5 MGD 3 MGD

Estimated Project Capital

Cost $4.9 M $9.3 M $13.3 M $24.8 M

Estimated

Annual O&M

Cost $1.2 M $2.2 M $3.0 M $5.2 M

Estimated Water Cost, $/1000 gal $8.9 $7.8 $7.5 $6.5

Annual Water Production, 1,000 gal/yr 178,850 357,700 536,550 1,073,100

Annual

Revenue Requirement (Pretax) $1.6 M $2.8 M $4.0 M $7.0 M



### Project Cost Estimate for a S eawater RO Desalination Facility Not Co-Located with Power

Plant

0.5 MGD 1 MGD 1.5 MGD 3 MGD

Estimated Project Capital

Cost $6.4 M $11.8 M $16.8 M $30.6 M

Estimated

Annual O&M

Cost $1.2 M $2.2 M $3.0 M $5.2 M

Estimated Water Cost, $/1000 gal $9.5 $8.4 $7.8 $6.9

Annual Water Production, 1,000 gal/yr 78,850 357,700 536,550 1,073,100

Annual Revenue Requirement (Pretax) $1.7 M $3.0 M $4.2 M $7.4 M

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 34 of 42

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### To place the costs estimates prepared by Beck into the context of the proposals received by the Authority, we have summarized some of the information from the GE and Seven Seas proposals, respectively in the Tables belo w. While they may be an apple to oranges comparison, they highlight so me major differences.

GE Proposal Summary

3 Train 4 Train 5 Train 6 Train

Normal Operating Conditions 40 0 GPM 600 GPM 800 GPM 1000 GPM

MGD 0.576 0.864 1.152 1.440
$ / 1000 gal year $ 6.08 $ 4.82 $ 4.19 $3.80



### The GE proposal excludes all utility and power costs, it assumes use of (VIWPA supplied) existing pipes, wires, cables, and instrument air and the RO Permeate is not remineralized (no Post treatment). The cost of water produced under the GE proposal can be compared to the estimated costs fo r the 0.5, 1.0 and 1.5 MGD facilities in the co

located costs table above. These values are for a completely installed and functioning plant per the estimate at $8.9/1,000 (kga ls) gallons, $7.8/kgals and $7.5/kgals.

Seven Seas Proposal Summary

Capacity in MGD $ / Kgal yr 1&2 $ / Kgal yr 3+

0.5 12 10.25

1 9.25 8.25

1.5 8.75 7.98



### The Seven Seas proposal is a turn key proposal for installation and operation, but excludes any distribution piping and connectio ns. Also, there is no discussion of how they will index of adjust cost for power cost. The cost of water produced under the Seven Seas proposal can also be compared to th e estimated costs for the 0.5, 1.0 and 1.5 MGD

facilities in the co located co st table above. These values are for a completely installed and functioning plant per th e estimate at $8.9/1,000 (kgals) gallons, $7.8/kgals and $7.5/kgals.



## Discussion of Results

Busbar Analysis

A graphical presentation of bus bar costs for the six (6) options evaluated as part of the Fatal Flow Analysis is shown on Exhibit 1. Th is graph shows the all-in levelized cost in dollars per MWh for each option at various capacity factor s over each option’s typical range of operation. The all-in levelized cost s is the average NPV cost per MWh over a twenty-five year period at a given capacity factor. Also shown in the graph are the projected levelized displaced energy costs a nd average system costs for each island. As shown on Exhibit 1, Option 6 the Photovoltaic solar resource, and Option 4 the MSW

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 35 of 42

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### resource are projected to be well above the Authority’s average system and displaced energy costs. Exhibit 2 is the same as Exhi bit 1 except that the vertical scale has been reduced to focus on the remaining Options, 1, 2, 3 and 5. As shown on Exhibit 2, the wind option at a 20 to 30 per cent capacity factor is project ed to be lower than the Authority’s displaced energy costs. This i ndicates that energy associated with the wind option is projected to be produced at a co st lower that the energy displaced on the Authority’s system, thereby representing an opportunity for reducing the Authority’s average system costs. None of the other alte rnatives are projected to be lower than the Authority’s displaced en ergy costs in the 40 – 60 percent cap acity factor range. At the 70 percent capacity factor the CFB unit fueled w ith 50 percent coal / 50 percent pet-coke is projected to be lower than the Authority’s di splaced energy costs. At the upper end, in the 80 – 90 percent capacity factor range, both the combined cycle retrofit with No. 2 oil and the CFB unit fueled with 50 percent coal / 50 percent pet-coke are projected to be lower than the Authority’s displaced energy costs. To the extent a resource is projected to be lower than the Authority’s displaced energy cost at a given capacity factor, the Authority is projected to benefit from adding that resource to its existing system if the resource is capable of producing energy at the given capacity factor a nd if the Authority’s system is capable of accepting the amount of en ergy at the given capacity factors. To the extent a resource is projected to be lower than the Authority’s average systems cost, the Authority may be able to achieve some be nefit, but it would ha ve to replace major portions of its generating system with the ne w resources to achieve lower costs, and the impacts on reliability, and water production would need to be taken into account.

At the present time there are a number of Federal Bills that have been proposed in Congress calling for limitation on CO 2 

### emissions. Some of these Bills call for mandatory caps on CO 2 

### emissions with an emissions trading program. These programs will result in a regulatory regime that will require the purchase of CO 2 

### allowances by CO 2 

### producers. At this time, the schedule for enactment of such a program and the cost of CO 2 

### allowance

are uncertain. Allowance costs have generally been projected to be in the range of $10 to $30 per ton by the year 2020. For purposes of th is fatal flaw analys is, we have assumed an average levelized CO 2 

### allowance price of $15 per ton starting in 2012. The graphical presentations of busbar costs with assumed CO 2 

### allowances are s hown on Exhibits 1b and 2b. Under the assumptions of CO 2 

### allowance, wind power, CFB, and combined cycle retrofit generation t echnology options, are still proj ected to be lower than the Authority’s displaced energy cost starting at capacity factors of 20 percent, 70 percent, and 80 percent respectively.



### Qualitative Assessment

A qualitative assessment of the generating options is summarized on Table 8. This assessment compares six potential generating options with respect to several key areas including cost related factor s, whether the resource is re newable, permitability, siting, dispatchability and fuel di versity. As shown on Table 8, two of the options, MSW generation (with no tipping fee) and PV cells ar e projected to have costs that are clearly higher than both the Authority’s displaced energy costs and average system energy costs. These resources, if installed would likely result in an increase in the Authority’s average

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### system costs. With the appropriate tipping fee, the MSW option may become competitive with the Authority’s lowest cost alternatives.

With respect to permitability and siting feasibility issues which are summarized on the table below, all of the options appear to be potentially pe rmitable at some sites. The slow speed reciprocating engines are considered to be the least likely perm itable of the options at the sites considered. The other options ar e considered more likel y to be permitable at certain sites, but will require further evalua tion. With respect to the CFB and combined cycle retrofit, additional air quality monitori ng will be required to determine the potential environmental impacts. The availability of suitable sites for the wind powered and photovoltaic resources will require identifying locations where objections due to noise

and aesthetics can be minimized.

Three of the resources, wind powered, PV a nd MSW resources are generally considered renewable resources. The output from thes e resources can sometimes be sold at a premium to certain customers as “Green” en ergy, which could help offset some of the higher costs associated with these type resources.

Because the source of the energy associat ed with wind powered and PV resources is intermittent, these resources are not dispatch able, nor are they considered dependable capacity. MSW resources are also considered “must take” facilities, and as such are not dispatchable. All of the res ources provide fuel diversity to the Authority except the combined cycle retrofit and the slow speed reciprocating engine s. Since one of the main goals for the Authority is to reduce its dependenc e on fuels that are tied to the price of oil, fuel diversity should be a high priori ty for any new resource considered.

There are certain assumptions made in the ev aluation of these options and to the extent these assumptions are different, the projected costs for these options could be higher or lower than projected. These key assumptions have been discussed in this report. Generally, the CFB coal unit, wind resource , MSW resources and PV resources involve relatively high capital investment and therefor e are sensitive to changes in investment cost assumptions. The combined cycle retrof it and slow speed reciprocating engines are fueled by relatively high pri ced No. 2 oil and No. 6 oil resp ectively, so would be more sensitive to fuel price variations than the ot her alternatives. The CFB unit and slow speed reciprocating engines have the highest CO 2 

### emissions compared to the other options and therefore would be most impacted by a carbon tax or CO 2 

### cap and trade program that requires the purchase of CO 2 

### allowances. The relative sens itivity to the various types of costs discussed above are summarized on Table 8 for each option.

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### Environmental Permitting Comparison of Alternate Sites and Technologies

Technology Sites

St. Croix St. Thomas

Existing

Estate
Richmond South Shore Hams Bluff Existing Krum Bay (Randolph E. Harley Plant) Grambokola Bovoni

CFB Not considered;

insufficient

space Uncertain, requires

further

evaluation of

NOx and SO 2 off-sets Likely; no apparent impediments Not considered,

insufficient

space Uncertain; will

need off-sets from existing plant at Krum Bay Likely; no apparent impediments

Combined-Cycle Likely; using existing CTs Uncertain; requires

further

evaluation of

NOx and SO 2 off-sets Likely; no apparent impediments Likely; using existing CTs Uncertain; will

need off-sets from existing plant at Krum Bay Likely; no apparent impediments

Slow Speed Diesel Unlikely; NOx

control issues regarding #6 oil operation Unlikely; NOx

control issues regarding #6 oil operation Uncertain; requires

detailed air modeling Unlikely; NOx

control issues regarding #6 oil operation Unlikely; NOx

control issues regarding #6 oil operation Uncertain; requires

detailed air modeling

Liquified NG (used for existing generation) Likely; no apparent impediments Not applicable Not applicable Likely; no apparent impediments Not applicable Not applicable

Gasification to Methanol (at South

Shore site for use in existing generating plant) Likely; no apparent impediments Uncertain, requires

further

evaluation of

NOx and SO 2 off-sets for auxiliary generation Not applicable Likely; no apparent impediments Not applicable Not applicable



### Interconnection of St. Thomas an d St. Croix Electric Systems

As stated previously the major savings associ ated with the interconnection is the ability to utilize larger sized units, reduced planni ng reserves, and reduced spinning reserves. Since no capacity is projected to be needed over the study peri od, under the base case

there is no immediate cost reduc tion associated with reduci ng planning reserves or being able to install larger units. The major cost reduction would be associated with a reduction in spinning reserves and the abil ity to operate units closer to the most efficient full load capacity. The current recommended spinni ng reserve practice is to operate the combustion turbine at no greater than 80 perc ent of the maximum rating. Based on the assumed heat rates for the combined cycle configuration on St. Thomas and St. Croix as

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### previously described, a reduction of 20 percen t in output on St. Thomas and St. Croix is projected to result in an increase in the heat rate of approximately three percent and 3.5 percent respectively. Using th is information, it was projected that reducing the spinning reserves from 20 percent to ten percent of the maximum rating would increase overall plant efficiency by 1.5 to 1.75 percent.

In 2012 total system fuel cost is projected to be approximately $217 million per year and is projected to increase up to approximat ely $393 million per year by 2030. An increase in efficiency of 1.75 percent would be equi valent to approximately $3.8 million per year and $6.9 million per year in 2012 and 2030 respectively. Based on these annual savings an investment of $300 to $350 million for an interconnection does not appear to be justified.

This option may be considered further in the event the Authority is adding new or replacement generating capacity. This interc onnection could allow the installation of fewer and larger new generating units wh ich may possibly justify the investment

associated with the interconnection.

In particular, if it is determin ed that the Authority should install a base load power plant

on the island of St. Croix using CFB technology and pet-coke fuel, then the

interconnection would allow the installation of a single large plant on St. Croix that would supply both St. Croix and St. Thomas. Thus, the electric system would benefit

from the economies of scale in the reduced cost per unit in both capital and operating costs. In such a scenario, the power need s of St. Thomas would normally be supplied from the generating plant located on St. Cr oix via the DC interconnection and suitable existing units at the Krum Bay facility can be retained for back- up and peaking duty on an as-required basis.



### Liquefied Natura l Gas Fuel Supply

Based on the Beck 2007 Fuel Conversion Repo rt, which was a preliminary high level analysis of the feasibility of converting from fuel oil to LNG fuel, the most attractive scenario involves supplying LNG to the islands from Ecoelectrica LNG facility in Puerto Rico by a small ship owned and operated by th e Authority or hired on a long-term basis to make deliveries exclusively to the Authority.

The capital costs associated with this scenar io including purchasing the LNG ship, on-site storage and regasification facilities for each island, dock improvements and

interconnection facilities fo r each island was projected to be between $134 to $158 million with an estimated $5.3 million per year for the ship operations and maintenance contract. The lower end of the range is ba sed on receiving LNG from Puerto Rico. In addition to the capital costs associated with adding infrastructure for the LNG facilities, additional capital costs of $5 million per gene ration site are assumed for conversion of existing fuel oil fired steam generation a nd combustion turbines to natural gas and provide the required fuel interconnection. In addition, fixed O&M costs are projected to change for current fuel oil fixed O&M.

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### Based on the Beck 2007 Fuel Conversion Re port, the conversion to LNG fuel could provide a potential savings, based on July 2007 market condition, of approximately $19 million per year. Based on the forecasted gas and oil prices the annual cost reduction was projected to be approximately $12 million per ye ar. As also stated in the Beck 2007 Fuel Conversion Report, the actual benefit will depend on the price diffe rential between the volatile oil and gas commodities. A differentia l of at least $2.20 per MMBtu (price of oil less price of gas) was projected to be required to have a break-even for the LNG conversion. The potential down-si de associated with this alte rnative is the infrastructure investment of $134 - $158 million and the risk that the differential between oil and natural gas prices will decrease in the futu re to less than the break-even differential, eliminating the potential cost reduction associ ated with this proj ect and providing no reduction in revenue requirements to offset the debt service associated with the

infrastructure investment.

The Beck 2007 Fuel Conversion Report conclu ded, among other things, that considering the possible savings indicated from the feasibi lity analysis, further re search is warranted.



### Methanol Production from Gasification of Pet-coke.

As part of the Fatal Flaw Analysis, a preliminary high level economic feasibility evaluation was prepared to determine whether this option should be further considered.

This evaluation is summarized on Table 9. Th e evaluation compares the fuel savings of replacing fuel oil with methanol in the Aut hority’s existing generating units versus the costs of constructing and ope rating a methanol production plant, providing additional electric generation to supply the plant, me thanol storage and tr ansportation to St. Thomas, and conversion of existing genera ting plants to accomm odate the use of methanol fuel. Based on very preliminary projection, the methanol plant and associated capital and operating costs are assumed to be the following:

Capital Costs

Methanol Plant $800,000,000
Fuel storage Tanks $14,000,000

Combustion Turbine Conversion $2,000,000
New Combine Cycle Unit $70,000,000

Annual O&M Costs

Methanol Plant – Fixed O&M $12,500,000
Combined Cycle Plant – Fixed O&M $4,500,000
Combined Cycle Plant Varied O&M $830,000

Fuel [1] $3,700,000

[1]

Assumed to be Methanol

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### As shown on Table 9, line 3, the total oper ating and capital carrying costs for the methanol plant, additional generation and associated equipment is projected to be approximately $112 million annually starting in 2012. Also shown on Table 9 based on the projected fuel prices for N o. 2 oil and No. 6 oil versus th e projected cost of pet-coke, replacing all of the Authority’s fuel in 2012 with methanol is projected to represent an annual reduction in fuel costs of approxi mately $187 million as shown on line 12. The net annual cost reduction is projected to be approximately $75 million in year 2012 and $134 million per year on a levelized basis over a 25 year life of the plant.

Similar to the LNG fuel supply option, this fuel supply option is dependent on the price differential between two fuels, in this case, pet-coke versus No. 2 and No. 6 oil. The difference with this fuel suppl y option is the readily available nearby supply of pet-coke

from HOVENSA on the island of St. Croix. Although pet-coke has increased in price significantly on a percentage basis over the last few years, it has only increased by approximately $1.00 per MMBtu, whereas oil prices are significantly higher and have the potential to change more than pet-coke in terms of dollars per MMBtu. Pet-coke prices are also limited by coal prices for which pet-coke has been used as a lower cost substitute. With more stringent environmen tal regulation being considered, there should be continued pressure on coal prices to remain relatively low compared to other fuels such as gas and oil.

Another significant difference between the methanol fuel supply option and the LNG Option is the capital cost investment. As stated previously, the methanol plant and associated equipment are projected to represent an investment of nearly on bil lion dollars. It is not clear whether the Authority or a deve loper will be able to finance this level of

investment.



### Seawater RO Desa lination Facility

As previously described, and summarized belo w, projected water co sts for various sized facilities are the following:

Summary of Projected Water Cost ($/1,000 gal)

0.5 MGD 1 MGD 1.5 MGD 3 MGD

Co-located at power plant $8.9 $7.8 $7.5 $6.5

Not co-located at power plant $9.5 $8.4 $7.8 $6.9

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 41 of 42

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### As shown on Table 5, recent historical wa ter costs in 2006 and 2007 for the Authority have been approximately $9/1,000 gal [we are evaluating this cost to determine what portion, if any, contains fixed costs]. Ba sed on the replacement of the Authority’s existing water system with similarly sized units, a potential decr ease of $1.5/1,000 gal is

indicated. This assumes that the additional electric load associated with the new RO facilities can be supplied from existing generati ng resources. It is further assumed that the Authority’s historical water production co st is an incremental cost and all costs allocated to the production of wa ter from the electric system will be eliminated with the installation of the RO system. Based on the annual water producti on of approximately 2,200 million gallons, a decrease of $1.5/1,000 ga l would result in an annual cost reduction of $3.3 million or approximately 17 percent of the current water costs.



## Conclusions

Based on the results of our analysis and re view of reports prep ared by or for the Authority and information provided by the Aut hority and others which is summarized or referred to in this Fatal Flaw Letter Report, wh ich report should be read in its entirety in conjunction with the following, we are of the opinion that:

1. The power generation technologies that are projected to reduce costs and dependence on oil for the Authority are:

a.) CFB units burning pet-coke from th e HOVENSA St. Croix refinery and Columbian coal, and

b.) Wind Power units.

2. Retrofitting CT Unit No. 23 at St. Thom as with a HRSG for combined cycle operation is projected to re sult in reduced costs but th is option does not improve the system’s fuel diversity and the capacity of the combined cycle unit is likely to present system operation reliability issues.

3. The slow speed diesel, the municipa l solid waste and the photovoltaic cell technology options are less attractive than th e other alternatives. In addition, the slow speed diesel option presents signi ficant environmental permitting challenges that are potentially fatal flaws.

4. The use of methanol (produced by processing pet-coke from the HOVENSA St. Croix refinery) as a fuel in existing gene rating plants, appears to be economically feasible. However, at the projected cap ital investment of $900 million this option presents a significant financial risk to the Authority.

5. At the current $/MMBtu price differential between oil and gas, LNG is feasible as an alternative fuel for the existing generating units. However, there is a risk that

in the future this differential will be eroded and the projected economic benefits from the high capital investment may not be realized.

### February 25, 2008 Mr. Glenn Rothgeb Virgin Islands Water and Power Authority Page 42 of 42

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### 6. Feasible sites have been identified fo r locating generating pl ants utilizing the various technologies as follows:

a. CFB Plant – St. Thomas: at Grambokola Hill and near the Bovoni

landfill. St. Croix: at the Author ity’s south shore site (with some additional adjacent Port Authority property) and in the area of

Hams Bluff on the west coast.

b. Wind Power – St. Thomas: in the area of the Bovoni landfill. St. Croix: on hills that are situated along the islands south coast and

northwest coast.

c. Combined Cycle Retrofit of CT Unit No. 23 – at the existing Krum Bay Power Plant site.

7. Further emission assessments are re quired in order to determine the environmental permitability of the CFB units at the candidate sites.

8. Reverse Osmosis water production units are a feasible alternative to the existing

MED units.

9. A high-voltage interconnection between th e islands of St. Thomas and St. Croix does not appear to be feasible for the continued operation of the existing power plants. However, it may prove to be feasible for the scenario where a large portion of the existing generation is repl aced or a single new power plant is

installed on one island to supply the total Authority electric system needs. A detailed technical feasibility study is required to addr ess unknowns related to the

installation of the submarine cable.

10. The Authority may want to consider issuing Request for Proposals (RFP) to solicit offers for the more capital intensive options such as the methanol and LNG fuel supply and interconnectio n/CFB plant alternatives to reduce the financial risk

of these alternatives.

Sincerely,
R. W. BECK, INC.

AttachmentsVIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemProjected Loads and Capicity Resources (MW)Base CaseTable 1Fiscal Year Ending June 30Line Description200720082009201020112012201320142015201620172018201920202021202220232024202520262027No.(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t) (u) (v)ISLANDS OF ST. THOMAS AND ST. JOHNGenerating Units [1]1 Unit 7 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.52 Unit 11 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.53 Unit 12 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.54 Unit 13 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.95 Unit 14 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.56 Unit 15 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.97 Unit 18 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.58 Unit 22 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 249 Unit 23 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.510 Existing Generating Capability 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.811 Planned Additional Capability 0 0 0 0 0 0 0 0 000000000000012 Total Generating Capability 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.813 Projected Maximum Demand [3] 88.2 88.5 88.5 89.5 90.6 91.7 92.8 93.9 95.0 96.2 97.3 98.5 99.7 100.9 102.1 103.3 104.5 105.8 107.1 108.4 109.714 Capacity Available For Reserves [4] 102.6 102.3 102.3 101.3 100.2 99.1 98.0 96.9 95.8 94.6 93.5 92.3 91.1 89.9 88.7 87.5 86.3 85.0 83.7 82.4 81.115 As a % of Projected Maximum Demand 116 116 116 113 111 108 106 103 101 98 96 94 91 89 87 85 83 80 78 76 7416 Less: Two Largest Units Out of Service [5] 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4Capacity Available For Reserves With Two17 Largest Units Out of Service 26.2 25.9 25.9 24.9 23.8 22.7 21.6 20.5 19.4 18.2 17.1 15.9 14.7 13.5 12.3 11.1 9.9 8.6 7.3 6.0 4.718 As a % of Projected Maximum Demand 30% 29% 29% 28% 26% 25% 23% 22% 20% 19% 18% 16% 15% 13% 12% 11% 9% 8% 7% 6% 4%19 Gross Energy Requirements 563,867 565,597 565,614 572,164 578,796 585,742 592,770 599,884 607,082 614,367 621,740 629,201 636,751 644,392 652,125 659,950 667,870 675,884 683,995 692,203 700,509ISLAND OF ST. CROIXGenerating Units [1]20 Unit 10 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.021 Unit 11 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.122 Unit 16 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.923 Unit 17 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.924 Unit 19 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.525 Unit 20 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.526 Existing Generating Capability 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.927 Projected Maximum Demand [3] 53.7 53.1 52.2 52.4 52.7 53.0 53.2 53.5 53.8 54.0 54.3 54.6 54.8 55.1 55.4 55.7 56.0 56.2 56.5 56.8 57.128 Capacity Available For Reserves [4] 63.2 63.8 64.7 64.5 64.2 63.9 63.7 63.4 63.1 62.9 62.6 62.3 62.1 61.8 61.5 61.2 60.9 60.7 60.4 60.1 59.829 As a % of Projected Maximum Demand 118% 120% 124% 123% 122% 121% 120% 119% 117% 116% 115% 114% 113% 112% 111% 110% 109% 108% 107% 106% 105%30 Less: Two Largest Units Out of Service [6] 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0Capacity Available For Reserves With Two31 Largest Units Out of Service 18 19 20 20 19 19 19 18 18 18 18 17 17 17 17 16 16 16 15 15 1532 As a % of Projected Maximum Demand 34% 35% 38% 37% 36% 36% 35% 34% 34% 33% 32% 32% 31% 30% 30% 29% 29% 28% 27% 27% 26%33 Gross Energy Requirements 360,407 356,091 350,189 351,828 353,472 355,239 357,016 358,801 360,595 362,398 364,210 366,031 367,861 369,700 371,549 373,406 375,273 377,150 379,035 380,931 382,835NOTES:[1] BASED ON CAPACITY RATINGS FROM PREVIOUS CONDITION ASSESSMENT AND DISCUSSIONS WITH AUTHORITY.[2] ASSUMES UNITS 12 AND 14 WILL BE USED AS RESERVE UNITS.[3] PROJECTED LOSS REDUCTIONS MEET GOALS AND GROWTH OF ELECTRIC DEMAND ASSUMED TO BE 1.2 AND 0.5 PERCENT PER YEAR FOR ST. THOMAS AND ST. CROIX RESPECTIVELY[4] CAPACITY IS NOT AVAILABLE YEAR ROUND DUE TO MAINTENANCE AND OTHER OPERATIONAL RESTRICTIONS[5] UNIT 13 (36.9 MW), UNIT 23 (39.5 MW) ARE LARGEST UNITS[6] CT 19 (22.5 MW), CT 20 (22.5 MW) ARE LARGEST UNITSB-56VIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemProjected Loads and Capicity Resources (MW)High Requirements CaseTable 2Fiscal Year Ending June 30Line Description200720082009201020112012201320142015201620172018201920202021202220232024202520262027No.(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t) (u) (v)ISLANDS OF ST. THOMAS AND ST. JOHNGenerating Units [1]1 Unit 7 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.52 Unit 11 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.5 18.53 Unit 12 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 0 0 0 0000000004 Unit 13 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.9 36.95 Unit 14 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 0 0 0 0000000006 Unit 15 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.97 Unit 18 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.5 23.58 Unit 22 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 249 Unit 23 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.5 39.510 Existing Generating Capability 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.811 Planned Additional Capability 0 0 0 0 0 0 0 0 000000000000012 Total Generating Capability 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 190.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.8 165.813 Projected Maximum Demand [3] 88.2 90.8 93.6 96.4 99.3 102.2 105.3 108.5 111.7 115.1 118.5 122.1 125.8 129.5 133.4 137.4 141.5 145.8 150.2 154.7 159.314 Capacity Available For Reserves [4] 102.6 100.0 97.2 94.4 91.5 88.6 85.5 82.3 79.1 50.7 47.3 43.7 40.0 36.3 32.4 28.4 24.3 20.0 15.6 11.1 6.515 As a % of Projected Maximum Demand 116 110 104 98 92 87 81 76 71 44 40 36 32 28 24 21 17 14 10 7 416 Less: Two Largest Units Out of Service [5] 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4 76.4Capacity Available For Reserves With Two17 Largest Units Out of Service 26.2 23.6 20.8 18.0 15.1 12.2 9.1 5.9 2.7 -25.7 -29.1 -32.7 -36.4 -40.1 -44.0 -48.0 -52.1 -56.4 -60.8 -65.3 -69.918 As a % of Projected Maximum Demand 30% 26% 22% 19% 15% 12% 9% 5% 2% -22% -25% -27% -29% -31% -33% -35% -37% -39% -40% -42% -44%19 Gross Energy Requirements 563,867 580,783 598,207 616,153 634,637 653,676 673,287 693,485 714,290 735,719 757,790 780,524 803,940 828,058 852,899 878,486 904,841 931,986 959,946 988,744 1,018,407ISLAND OF ST. CROIXGenerating Units [1]20 Unit 10 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.021 Unit 11 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.122 Unit 16 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.923 Unit 17 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.9 21.924 Unit 19 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.525 Unit 20 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.526 Existing Generating Capability 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.927 Projected Maximum Demand [3] 53.7 54.5 55.3 56.2 57.0 57.9 58.7 59.6 60.5 61.4 62.3 63.3 64.2 65.2 66.1 67.1 68.1 69.2 70.2 71.3 72.328 Capacity Available For Reserves [4] 63.2 62.4 61.6 60.7 59.9 59.0 58.2 57.3 56.4 55.5 54.6 53.6 52.7 51.7 50.8 49.8 48.8 47.7 46.7 45.6 44.629 As a % of Projected Maximum Demand 118% 114% 111% 108% 105% 102% 99% 96% 93% 90% 88% 85% 82% 79% 77% 74% 72% 69% 67% 64% 62%30 Less: Two Largest Units Out of Service [6] 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0Capacity Available For Reserves With Two31 Largest Units Out of Service 18 17 17 16 15 14 13 12 11 10 10987654321032 As a % of Projected Maximum Demand 34% 32% 30% 28% 26% 24% 22% 21% 19% 17% 15% 14% 12% 10% 9% 7% 6% 4% 2% 1% -1%33 Gross Energy Requirements 360,407 365,813 371,300 376,870 382,523 388,261 394,085 399,996 405,996 412,086 418,267 424,541 430,909 437,373 443,933 450,592 457,351 464,212 471,175 478,242 485,416NOTES:[1] BASED ON CAPACITY RATINGS FROM PREVIOUS CONDITION ASSESSMENT AND DISCUSSIONS WITH AUTHORITY.[2] ASSUMES UNITS 12 AND 14 WILL BE RETIRED WHEN CAPACITY NEEDED.[3] NO LOSS REDUCTIONS AND GROWTH OF ELECTRIC DEMAND ASSUMED TO BE 3 AND 1.5 PERCENT PER YEAR FOR ST. THOMAS AND ST CROIX RESPECTIVELY.[4] CAPACITY IS NOT AVAILABLE YEAR ROUND DUE TO MAINTENANCE AND OTHER OPERATIONAL RESTRICTIONS[5] UNIT 13 (36.9 MW), UNIT 23 (39.5 MW) ARE LARGEST UNITS[6] CT 19 (22.5 MW) CT 20 (22.5 MW) ARE LARGEST UNITSB-56VIRGIN ISLANDS WATER AND POWER AUTHORITY
Electric System

Projected Fuel Prices ($/MMBtu) Table 3

Line Fuel Oil [1] Solid Fuel Natural Gas

No. Year No. 2 No. 6 PET Coke [2] Coal [3] LNG [4] (a) (b) (c) (e) (f) (g)

1 2007 13.13 11.40 1.43 2.90 9.15

2 2008 16.55 15.36 1.50 3.04 9.25

3 2009 15.92 14.77 1.57 3.18 8.84

4 2010 16.42 15.23 1.64 3.33 8.66

5 2011 16.34 15.16 1.66 3.36 8.33

6 2012 16.26 15.09 1.68 3.40 8.29

7 2013 16.18 15.02 1.70 3.43 8.25

8 2014 16.10 14.94 1.71 3.47 8.42

9 2015 16.03 14.87 1.73 3.51 8.49

10 2016 16.53 15.34 1.77 3.58 8.76

11 2017 17.05 15.82 1.81 3.66 9.17

12 2018 17.58 16.32 1.85 3.74 9.21

13 2019 18.13 16.83 1.89 3.82 9.30

14 2020 18.70 17.36 1.93 3.90 9.58

15 2021 19.38 17.99 1.98 4.02 9.74

16 2022 20.09 18.64 2.05 4.14 10.10

17 2023 20.82 19.32 2.11 4.27 10.47

18 2024 21.57 20.02 2.17 4.40 10.89

19 2025 22.35 20.74 2.24 4.53 11.08

20 2026 23.05 21.40 2.31 4.67 11.32

21 2027 23.78 22.07 2.38 4.82 11.66

22 2028 24.52 22.76 2.46 4.97 12.09

23 2029 25.29 23.47 2.53 5.13 12.46

24 2030 26.09 24.21 2.61 5.29 12.75

25 2031 26.90 24.97 2.69 5.45 13.13

26 2032 27.75 25.75 2.78 5.62 13.51

27 2033 28.62 26.56 2.87 5.80 13.91

28 2034 29.52 27.39 2.96 5.98 14.32

29 2035 30.44 28.25 3.05 6.17 14.75

30 2036 31.40 29.14 3.14 6.37 15.19

NOTES:

[1] Fuel Oil Prices for 2007 based on delivered fuel costs for the Authority for the period june through October 2007. Fuel Oil Prices for 2008-2009 based on forward prices for crude oil plus $3.75/mmBtu, as supplied by the authority's
fuel consultant. Future prices based on 2009 forward price escalated at rates based on AEO 2007 for
Crude Oil. Inflation assumed to be 2.3% per year. Escalation from 2031-2036 based on the combined annual average of the last 5 years of growth for Crude Oil. [2] Pet Coke price based on a plant operating at the St. Croix south shore site. [3] Columbian Coal; 11,600 Btu/lb; 0.7% sulfur; Recent price for June 2007 $2.85-$2.90 based on note from Mr. Zakaria
of Rennaissance. Escalation 2007-2030 Based on AEO 2007 Table A-15 Coal Supply Disposition and Prices.
Escalation 2030-2036 Based on AEO 2007 Table A-15 Coal Supply Dispostion and Prices forecast from 2025-2030. [4] Data from Page 7 of Letter Report to Glenn Rothgeb from Ivan Clark dated July 10, 2007 and titled
"Report - Feasibility of the Conversion of Fuel oil to Natural Gas Generation".

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\ Table 3_fuel prices_rev.xls Page 1 of 1; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation ScreeningResource Assumptions without CO2 Allowance CostTable 4AResource Options1 2 3 4 56LnNo. Item Option 1 - CFB Option 2 - WindOption 3 - CCRetrofit Option 4 - MSW Option 5 - RecipOption 6 - PVSolar(a) (b) (c) (d) (e) (f) (g)1 Plant Type CFB/Steam On-Shore Wind Unit 23 CC Retrofit MSW/Steam Slow Speed Recip PV Solar2 Location ST/SC ST/SC ST ST ST/SC ST/SC3 VIWAPA Ownership %100 100 100 100 1004 Nominal Capacity MW20 10 60 10 20 105 Fuel TypePET Coke/Coal #N/A #2 oil MSW #6 oil #N/A6 Capital Cost $000160,000$ 30,000$ 73,980$ 105,000$ 40,000$ 85,000$7 Capital Cost $/kW8,000$ 3,000$ 1,233$ 10,500$ 2,000$ 8,500$8 Start of Eng to CO Months36 9 18 30 18 249 HR Average Btu/kWh12000 #N/A 7900 17500 8750 #N/A10 HR Average MMBtu/MWh 12.000 #N/A 7.900 17.500 8.750 #N/A11 Mature FOR %5.0% 5.0% 5.0% 6.9% 6.3% 5.0%12 Scheduled Maintenance %6.3% 1.3% 2.5% 12.5% 6.3% 2.0%13 Capacity Factor %85% 25% 50% 75% 85% 15%14 CO2 Emissions Rate lb/MMBtu 204 #N/A 159 92 174 #N/A15 CO2 Emissions Charge $/ton 0 #N/A 0 0 0 #N/A16 FOM $ 2,000,000$ 500,000$ 2,475,000$ 3,750,000$ 1,500,000$ 312,500$17 FOM $/kW-yr100.00$ 50.00$ 41.25$ 375.00$ 75.00$ 31.25$18 Limestone for PET Coke $/MWh1.03$-$ -$ -$ -$ -$19 Solid Waste Disposal for PET Coke $/MWh1.53$-$ -$ -$ -$ -$20 VOM $/MWh5.63$ #N/A 4.03$ 75.00$ 7.50$ 12.50$21 VOM Total $/MWh 8.18$ #N/A 4.03$ 75.00$ 7.50$ 12.50$22 Total O&M $ 3,218,625$ 500,000$ 3,533,164$ 8,677,500$ 2,616,900$ 476,750$23 Total O&M $/MWh 21.61$ 22.83$ 13.44$ 132.08$ 17.57$ 36.28$R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 4_resource assumptions_noCO2.xlsPage 1 of 2; 2/22/2008;RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation ScreeningResource Assumptions without CO2 Allowance CostTable 4AResource Options1 2 3 4 56LnNo. Item Option 1 - CFB Option 2 - WindOption 3 - CCRetrofit Option 4 - MSW Option 5 - RecipOption 6 - PVSolar(a) (b) (c) (d) (e) (f) (g)Other Assumptions24 Capital Payment Period (yrs)25 25 25 25 25 2525 Annual carrying cost factor 7.82% 7.82% 7.82% 7.82% 7.82% 7.82%26 Bond Factor 1.1237 1.0541 1.0773 1.1082 1.0773 1.092827 Annual Interest Rate6.00% 6.00% 6.00% 6.00% 6.00% 6.00%28 Issuance Expenses3.00% 3.00% 3.00% 3.00% 3.00% 3.00%29 Inflation2.30% 2.30% 2.30% 2.30% 2.30% 2.30%NOTES:All costs in $2007FOM does NOT include property taxes, insurance, or debt serviceFOM includes Capital ExpenseInvestment Tax Credits not included for Wind and Solar optionsCapital costs for CC retrofit is comprised of $44 million for new equipment and a $30 million allowance for the existing CT formodeling purposeLimestone and solid waste disposal expenses are based on 85% capacity factor operation or 50% PET Coke and 50% coal.Estimated limestone consumption is 8,000 tons per year at $19 per ton delivered. Estimated volume of waste for disposal in 12,250 tons per year at a cot of $19 per ton.ST/SC - St Thu / Str CroixR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 4_resource assumptions_noCO2.xlsPage 2 of 2; 2/22/2008;RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemScreening Curves for Generation without CO2 Allowance CostExhibit 1AR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Ex1&2_noCO2_rev.xlsPage 1 of 1; 2/25/2008;RWBeck, Inc.01002003004005006000.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9Capacity Factor

$/MWhOption 1 - CFB Coal/PET CokeOption 2 - WindOption 3 - Retrofit w/No. 2 OilOption 4 - MSW Stoker/CFBOption 5 - Recip w/No. 6 OilOption 6 - PV SolarApproximate Displaced Energy Cost for St. ThomasApproximate Displaced Energy Cost for St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixPV SolarWindCFBApproximate Displaced EnergyCost for St. Thomas and St. CroixMSWRecipRetrofitVIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemScreening Curves for Generation without CO2 Allowance CostExhibit 2AR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Ex1&2_noCO2_rev.xlsPage 1 of 1; 2/25/2008;RWBeck, Inc.0501001502002503003500.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9Capacity Factor

$/MWhOption 1 - CFB Coal/PET CokeOption 2 - WindOption 3 - Retrofit w/No. 2 OilOption 5 - Recip w/No. 6 OilApproximate Displaced Energy Cost for St. ThomasApproximate Displaced Energy Cost for St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixWindCFBApproximate Displaced EnergyCost for St. Thomas and St. CroixRecipRetrofitVIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation ScreeningResource Assumptions with CO2 Allowance CostTable 4BResource Options1 2 3 4 56LnNo. Item Option 1 - CFB Option 2 - WindOption 3 - CCRetrofit Option 4 - MSW Option 5 - RecipOption 6 - PVSolar(a) (b) (c) (d) (e) (f) (g)1 Plant Type CFB/Steam On-Shore Wind Unit 23 CC Retrofit MSW/Steam Slow Speed Recip PV Solar2 Location ST/SC ST/SC ST ST ST/SC ST/SC3 VIWAPA Ownership %100 100 100 100 1004 Nominal Capacity MW20 10 60 10 20 105 Fuel TypePET Coke/Coal #N/A #2 oil MSW #6 oil #N/A6 Capital Cost $000160,000$ 30,000$ 73,980$ 105,000$ 40,000$ 85,000$7 Capital Cost $/kW8,000$ 3,000$ 1,233$ 10,500$ 2,000$ 8,500$8 Start of Eng to CO Months36 9 18 30 18 249 HR Average Btu/kWh12000 #N/A 7900 17500 8750 #N/A10 HR Average MMBtu/MWh 12.000 #N/A 7.900 17.500 8.750 #N/A11 Mature FOR %5.0% 5.0% 5.0% 6.9% 6.3% 5.0%12 Scheduled Maintenance %6.3% 1.3% 2.5% 12.5% 6.3% 2.0%13 Capacity Factor %85% 25% 50% 75% 85% 15%14 CO2 Emissions Rate lb/MMBtu 204 #N/A 159 92 174 #N/A15 CO2 Emissions Charge $/ton 15 #N/A 15 15 15 #N/A16 FOM $ 2,000,000$ 500,000$ 2,475,000$ 3,750,000$ 1,500,000$ 312,500$17 FOM $/kW-yr100.00$ 50.00$ 41.25$ 375.00$ 75.00$ 31.25$18 Limestone for PET Coke $/MWh1.03$-$ -$ -$ -$ -$19 Solid Waste Disposal for PET Coke $/MWh1.53$-$ -$ -$ -$ -$20 VOM $/MWh5.63$ #N/A 4.03$ 75.00$ 7.50$ 12.50$21 VOM Total $/MWh 8.18$ #N/A 4.03$ 75.00$ 7.50$ 12.50$22 Total O&M $ 3,218,625$ 500,000$ 3,533,164$ 8,677,500$ 2,616,900$ 476,750$23 Total O&M $/MWh 21.61$ 22.83$ 13.44$ 132.08$ 17.57$ 36.28$R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 4_resource assumptions_withCO2.xlsPage 1 of 2; 2/22/2008;RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation ScreeningResource Assumptions with CO2 Allowance CostTable 4BResource Options1 2 3 4 56LnNo. Item Option 1 - CFB Option 2 - WindOption 3 - CCRetrofit Option 4 - MSW Option 5 - RecipOption 6 - PVSolar(a) (b) (c) (d) (e) (f) (g)Other Assumptions24 Capital Payment Period (yrs)25 25 25 25 25 2525 Annual carrying cost factor 7.82% 7.82% 7.82% 7.82% 7.82% 7.82%26 Bond Factor 1.1237 1.0541 1.0773 1.1082 1.0773 1.092827 Annual Interest Rate6.00% 6.00% 6.00% 6.00% 6.00% 6.00%28 Issuance Expenses3.00% 3.00% 3.00% 3.00% 3.00% 3.00%29 Inflation2.30% 2.30% 2.30% 2.30% 2.30% 2.30%NOTES:All costs in $2007FOM does NOT include property taxes, insurance, or debt serviceFOM includes Capital ExpenseInvestment Tax Credits not included for Wind and Solar optionsCapital costs for CC retrofit is comprised of $44 million for new equipment and a $30 million allowance for the existing CT formodeling purposeLimestone and solid waste disposal expenses are based on 85% capacity factor operation or 50% PET Coke and 50% coal.Estimated limestone consumption is 8,000 tons per year at $19 per ton delivered. Estimated volume of waste for disposal in 12,250 tons per year at a cot of $19 per ton.ST/SC - St Thu / Str CroixR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 4_resource assumptions_withCO2.xlsPage 2 of 2; 2/22/2008;RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemScreening Curves for Generation with CO2 Allowance CostExhibit 1BR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Ex1&2_withCO2_rev.xlsPage 1 of 1; 2/25/2008;RWBeck, Inc.01002003004005006000.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9Capacity Factor

$/MWhOption 1 - CFB Coal/PET CokeOption 2 - WindOption 3 - Retrofit w/No. 2 OilOption 4 - MSW Stoker/CFBOption 5 - Recip w/No. 6 OilOption 6 - PV SolarApproximate Displaced Energy Cost for St. ThomasApproximate Displaced Energy Cost for St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixApproximate Displaced EnergyCost for St. Thomas and St. CroixPV SolarWindCFBRetrofitMSWRecipVIRGIN ISLANDS WATER AND POWER AUTHORITYElectric SystemScreening Curves for Generation with CO2 Allowance CostExhibit 2BR:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Ex1&2_withCO2_rev.xlsPage 1 of 1; 2/25/2008;RWBeck, Inc.0501001502002503003500.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9Capacity Factor

$/MWhOption 1 - CFB Coal/PET CokeOption 2 - WindOption 3 - Retrofit w/No. 2 OilOption 5 - Recip w/No. 6 OilApproximate Displaced Energy Cost for St. ThomasApproximate Displaced Energy Cost for St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixAverage System Cost - St. ThomasAverage System Cost - St. CroixApproximate Displaced EnergyCost for St. Thomas and St. CroixWindRetrofitRecipCFBVIRGIN ISLANDS WATER AND POWER AUTHORITY Water System

Historical Water Sales and Requirements [1],[2]

L in e Fiscal Year Ended June 30 No. Description 2002 2003 2004 2005 2006 2007

(a) (b) (c) (d) (e) (f) (g)

ISLANDS OF ST. THOMAS

AND ST. JOHN

Sales of Water (000 Gallons)

1 Residential 114,281 118,397 122,733 124,934 127,958 136,755

2 Commercial 239,675 203,039 238,523 254,485 223,465 279,665

3 Virgin Islands Government 282,287 284,746 285,346 239,037 105,662 102,670

4 Incentive 5,935 36,236 43,772 42,316 44,240 37,599

5 Other Government 4,562 6,657 6,779 42,225 166,569 182,759

6 Standpipe 42,450 39,355 27,628 24,727 28,450 39,665

7 Subtotal Sales 689,190 688,430 724,781 727,724 696,344 779,113

8 Station Use and Steam Production 151,405 161,360 95,033 119,215 122,577 113,196

9 Change in Inventory (5,872) (5,357) (1,386) 566 0 (15,396)

10 Losses and Unaccounted For Water 144,481 119,937 135,405 131,816 151,930 131,615

11 Total Production 979,204 964,370 953,833 979,321 970,851 1,008,528

ISLAND OF ST. CROIX

Sales of Water (000 Gallons)

12 Residential 148,170 154,909 154,984 163,616 158,975 151,691

13 Commercial 164,064 156,941 160,011 176,193 188,245 170,430

14 Virgin Islands Government 400,079 392,492 381,044 362,810 164,699 180,005

15 Incentive 5,090 (398) 0000

16 Other Government 12,939 58,990 42,855 40,680 256,728 254,901

17 Standpipe 14,489 23,753 11,712 13,937 14,975 11,042

18 Subtotal Sales 744,831 786,687 750,606 757,236 783,622 768,069

19 Station Use and Steam Production 37,063 37,228 46,111 54,601 67,178 75,207

20 Change in Inventory (2,296) (4,025) (1,568) 5,298 0 938

21 Losses and Unaccounted For Water 423,314 339,511 350,051 272,226 370,777 350,834

22 Total Requirements 1,202,912 1,159,401 1,145,200 1,089,361 1,221,577 1,195,048

Sources of Supply

23 Desalinization Plant 1,135,852 1,089,116 1,078,400 1,070,431 1,026,911 1,012,800

24 Wells 67,060 70,285 66,800 18,930 194,666 182,248

25 Total Production & Well Su pp l

y 1,202,912 1,159,401 1,145,200 1,089,361 1,221,577 1,195,048

TOTAL SYSTEM

Sales of Water (000 Gallons)

26 Residential 262,451 273,306 277,717 288,550 286,933 288,446

27 Commercial 403,739 359,980 398,534 430,678 411,710 450,095

28 Virgin Islands Government 682,366 677,238 666,390 601,847 270,361 282,675

29 Incentive 11,025 35,838 43,772 42,316 44,240 37,599

30 Other Government 17,501 65,647 49,634 82,905 423,297 437,660

31 Standpipe 56,939 63,108 39,340 38,664 43,425 50,707

32 Subtotal Sales 1,434,021 1,475,117 1,475,387 1,484,960 1,479,966 1,547,182

33 Station Use and Steam Production 188,468 198,588 141,144 173,816 189,755 188,403

34 Change in Inventory (8,168) (9,382) (2,954) 5,864 0 (14,458)

35 Losses and Unaccounted For Water 567,795 459,448 485,456 404,042 522,707 482,449

36 Total Requirements 2,182,116 2,123,771 2,099,033 2,068,682 2,192,428 2,203,576

Sources of Supply

37 Desalinization Plant 2,115,056 2,053,486 2,032,233 2,049,752 1,997,762 2,021,328

38 Wells 67,060 70,285 66,800 18,930 194,666 182,248

39 Total Production & Well Su pp l

y 2,182,116 2,123,771 2,099,033 2,068,682 2,192,428 2,203,576

O p eratin g Ex p enses [3]

Production Ex p enses ($)

40 Total Production Ex p enses 10,928,468 11,103,855 11,597,540 14,085,280 19,909,213 19,708,554

Avera g e Production Ex p enses ($/1000 g al)

41 Total Avera g e O p eratin g Ex p enses 5.01 5.23 5.53 6.81 9.08 8.94

[ 1 ] Amounts obtained from the Authorit y 's June Monthl y Financial Re p orts, Production and O p eratin g Data b y Island and Q uarter l

Re p ort and Statistical Data

. [ 2 ] Total S y stem q uantities mi g ht not match Monthl y Financial Re p orts due to roundin g [ 3 ] O p eratin g Ex p enses taken from Table III-1

. Table 5A

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Table 5_prod exp water&elec.xls Page 1 of1; 2/22/2008; RWBeck, Inc.Table 5B

Ln. No. Description 2002 2003 2004 2005 2006 2007

(a) (b) (c) (d) (e) (d) (e)

Island of St. Thomas Randolph E. Harley

1 Steam Unit No. 11 $203,085 $266,267 $245,540 $165,867 $239,091 $230,933

2 Steam Unit No. 13 649,377 636,937 181,082 242,697 292,829 165,997

3 Total Steam 852,462 903,205 426,622 408,564 531,920 396,931

4 Combustion Turbine Unit No. 12 59,579 197,266 23,557 27,987 141,800 79,088

5 Combustion Turbine Unit No. 14 118,755 86,078 15,692 274,693 52,920 33,021

6 Combustion Turbine Unit No. 15 204,153 490,913 178,102 167,177 418,103 123,322

7 Combustion Turbine Unit No. 18 89,889 247,082 211,977 39,409 181,839 128,752

8 Combustion Turbine Unit No. 22 165,996 378,797 374,340 30,872 46,952 63,343

9 Total CT 638,371 1,400,136 803,669 540,139 841,612 427,526

10 Waste Heat Boiler No. 21 (23) 0 54,844 15,781 46,599 20,566 82,778

11 Total Island of St. Thomas 1,490,833 2,358,185 1,246,072 995,302 1,394,098 907,235

Island of St. John

12 Diesel Unit No. 7J 83,784 89,656 9,876 11,689 12,078 17,266

13 Total Island of St. John 83,784 89,656 9,876 11,689 12,078 17,266

14 Total Islands of St. Thomas & St. John 1,574,617 2,447,841 1,255,947 1,006,990 1,406,176 924,501

Island of St. Croix Estate Richmond Generating Station

15 Steam Unit No. 10 28,482 630,636 312,316 230,356 26,980 1,036,235

16 Steam Unit No. 11 727,307 452,814 627,494 233,453 431,948 407,652

17 Total Steam 755,789 1,083,450 939,811 463,809 458,928 1,443,886

18 Combustion Turbine Unit No. 16 342,347 132,956 196,552 171,115 172,754 126,606

19 Combustion Turbine Unit No. 17 209,256 376,946 226,484 112,995 119,411 1,411,457

20 Combustion Turbine Unit No. 19 188,260 248,913 222,302 178,230 126,101 164,766

21 Combustion Turbine Unit No. 20 184,163 475,664 243,246 180,604

Total CT 924,026 1,234,479 888,584 642,944 418,267 1,702,830

22 Waste Heat Boiler No. 21 0 95,366 98,595 79,084 81,841 52,843

23 Total Island of St. Croix 1,679,815 2,413,295 1,926,989 1,185,836 959,036 3,199,559

Other Production Maintenance

24 Miscellaneous Steam Units 7,518,267 8,096,478 8,038,299 6,880,055 7,293,135 6,165,723

25 Miscellaneous CT's 48 26,020 32,521 6,456

26 Total Other Production Maintenance 7,518,315 8,122,498 8,070,820 6,886,511 7,293,135 6,165,723

27 TOTAL COMBINED ISLANDS $10,772,747 $12,983,634 $11,253,756 $9,079,337 $9,658,348 $10,289,783

TOTAL COMBINED ISLANDS

Steam

28 Island of St. Thomas 852,462 903,205 426,622 408,564 531,920 396,931

29 Island of St. Croix 755,789 1,083,450 939,811 463,809 458,928 1,443,886

30 Miscellaneous Steam 7,518,267 8,096,478 8,038,299 6,880,055 7,293,135 6,165,723

Waste Heat Boiler

31 Island of St. Thomas 0 54,844 15,781 46,599 20,566 82,778

32 Island of St. Croix 0 95,366 98,595 79,084 81,841 52,843

33 Total Steam 9,126,518 10,233,343 9,519,107 7,878,110 8,386,390 8,142,161

Combustion Turbine

34 Island of St. Thomas 638,371 1,400,136 803,669 540,139 841,612 427,526

35 Island of St. Croix 924,026 1,234,479 888,584 642,944 418,267 1,702,830

36 Miscellaneous CT 48 26,020 32,521 6,456 0 0

37 Total CT 1,562,445 2,660,635 1,724,774 1,189,538 1,259,879 2,130,356

Diesel

38 Island of St. John 83,784 89,656 9,876 11,689 12,078 17,266

39 TOTAL COMBINED ISLANDS $10,772,747 $12,983,634 $11,253,756 $9,079,337 $9,658,348 $10,289,783

TOTAL COMBINED SYSTEM PRODUCTION

Generation (MWh) [2] 855,639 888,905 908,559 920,814 926,502 932,551

System Cost ($/MWh) 12.59 14.61 12.39 9.86 10.42 11.03

[1] Detail data provided by the Authority.

[2] Data taken from Table III of VIWAPA OS 2007. Fiscal Year Ended June 30 VIRGIN ISLANDS WATER AND POWER AUTHORITY Electric System

Schedule of Historical Maintenance Expense *

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Table 5_prod exp water&elec.xls; Page 1 of 1; 2/22/2008; RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITY
Generation Screening

Displaced and Average System Energy Costs Table 6

Without CO2 Allowance Cost

Displaced Energy Costs St. Thomas St. Croix Average System Energy Cost

Line All Hours

Benchmark All Hours

Benchmark St. Thomas St. Croix No. Year ($/MWh) ($/MWh) ($/MWh) ($/MWh) (a) (b) (d) (f) (g)

1 2012 158 165 237 219

2 2013 156 164 236 217

3 2014 157 163 235 214

4 2015 157 162 234 212

5 2016 160 167 241 219

6 2017 168 172 249 225

7 2018 174 177 257 232

8 2019 181 183 265 239

9 2020 188 188 273 246

10 2021 197 196 283 254

11 2022 204 203 293 262

12 2023 212 209 303 271

13 2024 221 217 314 280

14 2025 230 225 326 290

15 2026 239 233 336 299

16 2027 249 241 346 309

17 2028 255 249 357 318

18 2029 264 256 367 329

19 2030 276 264 375 339

Levelized Payment 20 2012-2030 $190.55 $191.68 $276.64 $249.62

With CO2 Allowance Cost

Displaced Energy Costs St. Thomas St. Croix Average System Energy Cost

Line All Hours

Benchmark All Hours

Benchmark St. Thomas St. Croix No. Year ($/MWh) ($/MWh) ($/MWh) ($/MWh) (a) (b) (d) (f) (g)

1 2012 170 177 239 223

2 2013 168 176 236 222

3 2014 169 175 235 221

4 2015 169 174 234 219

5 2016 172 179 239 226

6 2017 180 184 246 232

7 2018 186 190 253 239

8 2019 194 195 261 245

9 2020 200 200 268 252

10 2021 210 208 277 261

11 2022 217 215 286 269

12 2023 225 222 295 278

13 2024 234 230 305 288

14 2025 243 238 315 297

15 2026 252 245 324 306

16 2027 262 253 334 315

17 2028 268 261 343 324

18 2029 278 268 353 333

19 2030 289 276 364 343

Levelized Payment 20 2012-2030 $203.26 $203.87 $271.96 $255.86

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 6_avoide&average cost_rev.xls Page 1 of 1; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20251Option 1 - CFB Coal/PET CokePlant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 20 20 20MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520Annual Capital Carrying Cost ($) 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680Fixed Annual O&M Cost ($) 2,240,826 2,292,365 2,345,090 2,399,027 2,454,204 2,510,651 2,568,396 2,627,469 2,687,901 2,749,723 2,812,966 2,877,664 2,943,851 3,011,559CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 160,631 164,325 168,105 171,971 175,927 179,973 184,112 188,347 192,679 197,111 201,644 206,282 211,026 215,880Average Heat Rate (MMBtu/MWh) 12 12 12 12 12 12 12 12 12 12 12 12 12 12Annual Fuel Consumed (MMBtu) 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240Total Annual Fuel Operating Cost ($) 533,808 539,399 545,048 550,756 562,558 574,612 586,924 599,500 612,345 630,961 650,143 669,907 690,273711,257Total Annual Operating cost ($) 16,999,946 17,060,770 17,122,923 17,186,434 17,257,369 17,329,916 17,404,112 17,479,996 17,557,605 17,642,474 17,729,433 17,818,534 17,909,830 18,003,377Total Annual Operating cost ($/MWh) 970 974 977 981 985 989 993 998 1,002 1,007 1,012 1,017 1,022 1,028PV Total Annual Operating cost ($) 16,037,684 15,184,024 14,376,736 13,613,266 12,895,710 12,216,907 11,574,729 10,967,166 10,392,320 9,851,465 9,339,644 8,855,265 8,396,827 7,962,911Levelized Annual Operating Cost ($/MWh)2Option 2 - CC w/LNGPlant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115Fixed Annual O&M Cost ($) 4,369,611 4,470,112 4,572,925 4,678,102 4,785,698 4,895,769 5,008,372 5,123,565 5,241,407 5,361,959 5,485,284 5,611,445 5,740,509 5,872,540CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4Annual Fuel Consumed (MMBtu) 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944Total Annual Fuel Operating Cost ($) 3,224,853 3,206,887 3,275,565 3,302,622 3,407,870 3,565,928 3,584,000 3,615,856 3,724,840 3,789,546 3,929,198 4,072,153 4,234,635 4,308,533Total Annual Operating cost ($) 31,471,801 31,557,723 31,732,677 31,868,455 32,084,925 32,356,763 32,491,231 32,642,161 32,872,957 33,062,277 33,329,409 33,602,777 33,898,670 34,109,048Total Annual Operating cost ($/MWh) 599 600 604 606 610 616 618 621 625 629 634 639 645 649PV Total Annual Operating cost ($) 29,690,379 28,086,261 26,643,367 25,242,802 23,975,723 22,810,241 21,608,524 20,480,096 19,457,453 18,461,803 17,557,517 16,699,551 15,893,019 15,086,465Levelized Annual Operating Cost ($/MWh)3Option 3 - WindPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819Fixed Annual O&M Cost ($) 560,207 573,091 586,272 599,757 613,551 627,663 642,099 656,867 671,975 687,431 703,242 719,416 735,963 752,890CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AVariable Annual O&M ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAverage Heat Rate (MMBtu/MWh) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAnnual Fuel Consumed (MMBtu) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 3,034,026 3,046,910 3,060,092 3,073,576 3,087,370 3,101,482 3,115,918 3,130,686 3,145,794 3,161,250 3,177,061 3,193,235 3,209,782 3,226,709Total Annual Operating cost ($/MWh) 346 348 349 351 352 354 356 357 359 361 363 365 366 368PV Total Annual Operating cost ($) 2,862,288 2,711,739 2,569,312 2,434,560 2,307,063 2,186,422 2,072,264 1,964,231 1,861,991 1,765,225 1,673,636 1,586,940 1,504,871 1,427,176Levelized Annual Operating Cost ($/MWh)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 1 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20254Option 4 - Retrofit w/No. 2 OilPlant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678Fixed Annual O&M Cost ($) 2,773,022 2,836,802 2,902,048 2,968,795 3,037,078 3,106,931 3,178,390 3,251,493 3,326,277 3,402,782 3,481,046 3,561,110 3,643,015 3,726,804CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 237,116 242,570 248,149 253,856 259,695 265,668 271,778 278,029 284,424 290,966 297,658 304,504 311,508 318,672Average Heat Rate (MMBtu/MWh) 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9Annual Fuel Consumed (MMBtu) 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224Total Annual Fuel Operating Cost ($) 6,750,994 6,718,554 6,686,270 6,654,141 6,863,027 7,078,471 7,300,677 7,529,860 7,766,236 8,048,139 8,340,275 8,643,015 8,956,743 9,281,860Total Annual Operating cost ($) 15,995,810 16,032,603 16,071,145 16,111,470 16,394,477 16,685,747 16,985,523 17,294,059 17,611,615 17,976,564 18,353,656 18,743,306 19,145,944 19,562,014Total Annual Operating cost ($/MWh) 304 305 306 307 312 317 323 329 335 342 349 357 364 372PV Total Annual Operating cost ($) 15,090,387 14,268,960 13,493,643 12,761,793 12,250,907 11,762,793 11,296,343 10,850,507 10,424,288 10,038,020 9,668,477 9,314,849 8,976,366 8,652,298Levelized Annual Operating Cost ($/MWh)5Option 5 - MSW Stoker/CFBPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929Fixed Annual O&M Cost ($) 4,201,549 4,298,185 4,397,043 4,498,175 4,601,633 4,707,470 4,815,742 4,926,504 5,039,814 5,155,730 5,274,311 5,395,621 5,519,720 5,646,673CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 736,111 753,042 770,362 788,080 806,206 824,749 843,718 863,124 882,975 903,284 924,059 945,313 967,055 989,297Average Heat Rate (MMBtu/MWh) 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5Annual Fuel Consumed (MMBtu) 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 14,040,589 14,154,155 14,270,334 14,389,184 14,510,768 14,635,148 14,762,389 14,892,557 15,025,718 15,161,942 15,301,300 15,443,862 15,589,704 15,738,899Total Annual Operating cost ($/MWh) 1,603 1,616 1,629 1,643 1,656 1,671 1,685 1,700 1,715 1,731 1,747 1,763 1,780 1,797PV Total Annual Operating cost ($) 13,245,839 12,597,148 11,981,647 11,397,581 10,843,290 10,317,202 9,817,832 9,343,774 8,893,699 8,466,349 8,060,534 7,675,126 7,309,061 6,961,330Levelized Annual Operating Cost ($/MWh)6Option 6 - Recip w/No. 6 OilPlant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 20 20 20MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520Annual Capital Carrying Cost ($) 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007Fixed Annual O&M Cost ($) 1,680,620 1,719,274 1,758,817 1,799,270 1,840,653 1,882,988 1,926,297 1,970,602 2,015,926 2,062,292 2,109,725 2,158,248 2,207,888 2,258,669CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75Annual Fuel Consumed (MMBtu) 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300Total Annual Fuel Operating Cost ($) 2,312,999 2,301,884 2,290,823 2,279,815 2,351,383 2,425,198 2,501,329 2,579,851 2,660,837 2,757,422 2,857,512 2,961,235 3,068,724 3,180,114Total Annual Operating cost ($) 7,511,848 7,542,774 7,574,720 7,607,708 7,724,284 7,844,142 7,967,377 8,094,084 8,224,365 8,371,377 8,523,055 8,679,553 8,841,030 9,007,650Total Annual Operating cost ($/MWh) 429 431 432 434 441 448 455 462 469 478 486 495 505 514PV Total Annual Operating cost ($) 7,086,649 6,713,042 6,359,881 6,026,018 5,772,035 5,529,811 5,298,761 5,078,329 4,867,989 4,674,533 4,489,839 4,313,472 4,145,020 3,984,092Levelized Annual Operating Cost ($/MWh)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 2 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20257Option 7 - PV SolarPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214Fixed Annual O&M Cost ($) 350,129 358,182 366,420 374,848 383,469 392,289 401,312 410,542 419,984 429,644 439,526 449,635 459,977 470,556CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AVariable Annual O&M ($) 122,685 125,507 128,394 131,347 134,368 137,458 140,620 143,854 147,163 150,547 154,010 157,552 161,176 164,883Average Heat Rate (MMBtu/MWh) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAnnual Fuel Consumed (MMBtu) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 7,739,028 7,749,903 7,761,028 7,772,408 7,784,051 7,795,961 7,808,145 7,820,610 7,833,361 7,846,405 7,859,750 7,873,401 7,887,366 7,901,653Total Annual Operating cost ($/MWh) 883 885 886 887 889 890 891 893 894 896 897 899 900 902PV Total Annual Operating cost ($) 7,300,970 6,897,386 6,516,308 6,156,475 5,816,696 5,495,845 5,192,863 4,906,747 4,636,554 4,381,392 4,140,418 3,912,839 3,697,905 3,494,909Levelized Annual Operating Cost ($/MWh)8Option 8 - CC w/No.2Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684Fixed Annual O&M Cost ($) 4,369,611 4,470,112 4,572,925 4,678,102 4,785,698 4,895,769 5,008,372 5,123,565 5,241,407 5,361,959 5,485,284 5,611,445 5,740,509 5,872,540CO2 Allowance Cost ($)00000000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4Annual Fuel Consumed (MMBtu) 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944Total Annual Fuel Operating Cost ($) 5,296,517 5,170,295 5,047,081 4,926,803 5,102,163 5,283,765 5,471,831 5,666,591 5,868,282 6,052,573 6,242,651 6,438,698 6,640,902 6,849,457Total Annual Operating cost ($) 15,940,035 15,917,700 15,900,762 15,889,205 16,175,787 16,471,169 16,775,631 17,089,464 17,412,968 17,721,873 18,039,431 18,365,891 18,701,506 19,046,541Total Annual Operating cost ($/MWh) 303 303 303 302 308 313 319 325 331 337 343 349 356 362PV Total Annual Operating cost ($) 15,037,769 14,166,696 13,350,587 12,585,739 12,087,489 11,611,524 11,156,753 10,722,141 10,306,709 9,895,801 9,502,947 9,127,285 8,767,996 8,424,303Levelized Annual Operating Cost ($/MWh)Adjusted Avoided CostsAll Hours Benchmark for St. Thomas ($/M157.64 156.07 157.12 156.89 160.05 167.85 173.57 181.02 187.61 196.86 204.08 212.40 221.19 230.00Check $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55All Hours Benchmark for St. Croix ($/MWh164.57 163.86 163.26 161.70 166.77 171.63 177.37 182.62 188.20 195.75 202.57 209.42 217.50 225.45Check $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68Adjust Average System Energy CostSt. Thomas ($/MWh)237.31 236.38 234.91 233.80 241.25 248.62 256.56 264.76 273.09 283.01 293.08 303.40 314.11 325.81$276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64St. Croix ($/MWh)218.71 216.62 214.36 212.38 218.86 225.11 231.79 238.62 245.81 253.87 262.41 271.22 280.30 289.66$249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 3 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%)Year1Option 1 - CFB Coal/PET CokePlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)2Option 2 - CC w/LNGPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)3Option 3 - WindPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)10% No CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg20 20 20 20 20 20 20 20 20 20 2017,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 223,964 17,52014,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,6803,080,825 3,151,684 3,224,173 3,298,329 3,374,190 3,451,797 3,531,188 3,612,405 3,695,491 3,780,487 3,867,43800000000000220,845 225,925 231,121 236,437 241,875 247,438 253,129 258,951 264,907 271,000 277,23312 12 12 12 12 12 12 12 12 12 12210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240733,612 756,670 780,452 804,981 830,282 856,378 883,294 911,056 939,690 969,225 999,68818,099,963 18,198,958 18,300,426 18,404,427 18,511,027 18,620,293 18,732,291 18,847,092 18,964,768 19,085,392 19,209,039 226,443,7771,033 1,039 1,045 1,050 1,057 1,063 1,069 1,076 1,082 1,089 1,096 1,026.207,552,482 7,163,952 6,796,127 6,447,877 6,118,135 5,805,895 5,510,205 5,230,164 4,964,924 4,713,682 4,475,680 226,443,7771,01160 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,56023,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,1156,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,206,207 7,371,949 7,541,50400000000000202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0917.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,9444,403,554 4,536,434 4,701,641 4,846,019 4,960,647 5,105,272 5,255,001 5,410,015 5,570,501 5,736,650 5,908,66434,343,689 34,619,399 34,930,721 35,224,576 35,492,117 35,793,174 36,102,932 36,421,656 36,749,617 37,087,093 37,434,374 426,085,135653 659 665 670 675 681 687 693 699 706 712 647.8514,330,421 13,627,798 12,972,027 12,340,711 11,730,607 11,160,481 10,619,873 10,107,195 9,620,949 9,159,716 8,722,158 426,085,13563410 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7602,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819770,206 787,921 806,043 824,582 843,548 862,949 882,797 903,101 923,873 945,122 966,860#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A3,244,025 3,261,740 3,279,862 3,298,401 3,317,367 3,336,768 3,356,616 3,376,920 3,397,692 3,418,941 3,440,679 40,535,825370 372 374 377 379 381 383 385 388 390 393 367.551,353,618 1,283,972 1,218,024 1,155,574 1,096,433 1,040,420 987,367 937,113 889,506 844,405 801,673 40,535,825362R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 4 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%)Year4Option 4 - Retrofit w/No. 2 OilPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)5Option 5 - MSW Stoker/CFBPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)6Option 6 - Recip w/No. 6 OilPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)10% No CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg60 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,5606,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,6783,812,521 3,900,209 3,989,914 4,081,682 4,175,560 4,271,598 4,369,845 4,470,352 4,573,170 4,678,353 4,785,95500000000000326,002 333,500 341,170 349,017 357,045 365,257 373,658 382,252 391,044 400,038 409,2387.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,2249,572,983 9,873,237 10,182,908 10,502,293 10,831,694 11,171,427 11,521,816 11,883,195 12,255,908 12,640,311 13,036,77119,946,183 20,341,623 20,748,670 21,167,669 21,598,977 22,042,960 22,499,996 22,970,476 23,454,799 23,953,379 24,466,642 235,062,987379 387 395 403 411 419 428 437 446 456 465 369.988,322,845 8,007,404 7,705,318 7,415,961 7,138,743 6,873,099 6,618,496 6,374,424 6,140,402 5,915,971 5,700,694 235,062,98735010 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7609,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,9295,776,547 5,909,408 6,045,324 6,184,366 6,326,607 6,472,119 6,620,977 6,773,260 6,929,045 7,088,413 7,251,446000000000001,012,051 1,035,328 1,059,141 1,083,501 1,108,422 1,133,915 1,159,995 1,186,675 1,213,969 1,241,890 1,270,45317.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A15,891,527 16,047,664 16,207,393 16,370,796 16,537,957 16,708,963 16,883,901 17,062,864 17,245,942 17,433,232 17,624,829 194,917,3531,814 1,832 1,850 1,869 1,888 1,907 1,927 1,948 1,969 1,990 2,012 1,789.646,630,979 6,317,103 6,018,849 5,735,407 5,466,010 5,209,934 4,966,491 4,735,032 4,514,940 4,305,634 4,106,561 194,917,3531,74120 20 20 20 20 20 20 20 20 20 2017,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 223,964 17,5203,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,0072,310,619 2,363,763 2,418,130 2,473,747 2,530,643 2,588,847 2,648,391 2,709,304 2,771,618 2,835,365 2,900,57900000000000202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0918.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,3003,279,857 3,382,729 3,488,828 3,598,254 3,711,112 3,827,510 3,947,559 4,071,373 4,199,071 4,330,773 4,466,6079,163,894 9,324,565 9,489,792 9,659,708 9,834,446 10,014,148 10,198,956 10,389,019 10,584,489 10,785,523 10,992,283 108,994,137523 532 542 551 561 572 582 593 604 616 627 511.303,823,773 3,670,580 3,524,171 3,384,219 3,250,412 3,122,459 3,000,078 2,883,006 2,770,990 2,663,793 2,561,187 108,994,137487R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 5 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening without CO2 Allowance CostSelected CalculationsTable 7ACapacity Factor (%)Year7Option 7 - PV SolarPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)8Option 8 - CC w/No.2Plant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)Adjusted Avoided CostsAll Hours Benchmark for St. Thomas ($/MCheckAll Hours Benchmark for St. Croix ($/MWhCheckAdjust Average System Energy CostSt. Thomas ($/MWh)St. Croix ($/MWh)10% No CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg10 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7607,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214481,379 492,451 503,777 515,364 527,217 539,343 551,748 564,438 577,420 590,701 604,287#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A168,675 172,555 176,523 180,583 184,737 188,986 193,333 197,779 202,328 206,982 211,742#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A7,916,268 7,931,219 7,946,514 7,962,161 7,978,168 7,994,543 8,011,294 8,028,431 8,045,962 8,063,896 8,082,243 100,408,422904 905 907 909 911 913 915 916 918 921 923 901.343,303,182 3,122,095 2,951,053 2,789,494 2,636,888 2,492,736 2,356,566 2,227,931 2,106,411 1,991,609 1,883,152 100,408,42289760 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,5606,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,6846,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,206,207 7,371,949 7,541,50400000000000202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0917.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,9447,078,450 7,315,099 7,559,659 7,812,396 8,073,582 8,326,808 8,587,976 8,857,336 9,135,144 9,421,665 9,717,17319,415,153 19,794,632 20,185,309 20,587,522 21,001,622 21,411,279 21,832,476 22,265,546 22,710,829 23,168,677 23,639,452 230,740,054369 377 384 392 400 407 415 424 432 441 450 361.848,101,265 7,792,083 7,496,105 7,212,710 6,941,309 6,676,138 6,422,141 6,178,802 5,945,633 5,722,166 5,507,960 230,740,054343238.79 248.54 255.06 264.32 275.862,126($190.55)$190.55 $190.55 $190.55 $190.55 $190.552,126232.66 241.09 248.76 256.11 263.702,139($191.68)$191.68 $191.68 $191.68 $191.68 $191.682,139335.84 345.76 357.17 367.22 375.263,087($276.64)$276.64 $276.64 $276.64 $276.64 $276.643,087299.13 308.68 318.28 329.39 339.072,785($249.62)$249.62 $249.62 $249.62 $249.62 $249.622,785R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xlsPage 6 of 6; 2/22/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%) 10% with CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20251Option 1 - CFB Coal/PET CokePlant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 20 20 20MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520Annual Capital Carrying Cost ($) 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680Fixed Annual O&M Cost ($) 2,240,826 2,292,365 2,345,090 2,399,027 2,454,204 2,510,651 2,568,396 2,627,469 2,687,901 2,749,723 2,812,966 2,877,664 2,943,851 3,011,559CO2 Allowance Cost ($) 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983Variable Annual O&M ($) 160,631 164,325 168,105 171,971 175,927 179,973 184,112 188,347 192,679 197,111 201,644 206,282 211,026 215,880Average Heat Rate (MMBtu/MWh) 12 12 12 12 12 12 12 12 12 12 12 12 12 12Annual Fuel Consumed (MMBtu) 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240Total Annual Fuel Operating Cost ($) 533,808 539,399 545,048 550,756 562,558 574,612 586,924 599,500 612,345 630,961 650,143 669,907 690,273711,257Total Annual Operating cost ($) 17,320,928 17,381,753 17,443,906 17,507,417 17,578,351 17,650,898 17,725,095 17,800,979 17,878,588 17,963,457 18,050,416 18,139,516 18,230,813 18,324,360Total Annual Operating cost ($/MWh) 989 992 996 999 1,003 1,007 1,012 1,016 1,020 1,025 1,030 1,035 1,041 1,046PV Total Annual Operating cost ($) 16,340,499 15,469,698 14,646,239 13,867,514 13,135,567 12,443,187 11,788,201 11,168,554 10,582,309 10,030,701 9,508,734 9,014,784 8,547,316 8,104,882Levelized Annual Operating Cost ($/MWh)2Option 2 - CC w/LNGPlant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115Fixed Annual O&M Cost ($) 4,369,611 4,470,112 4,572,925 4,678,102 4,785,698 4,895,769 5,008,372 5,123,565 5,241,407 5,361,959 5,485,284 5,611,445 5,740,509 5,872,540CO2 Allowance Cost ($) 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4Annual Fuel Consumed (MMBtu) 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944Total Annual Fuel Operating Cost ($) 3,015,932 2,992,991 3,080,687 3,115,238 3,249,632 3,451,462 3,474,538 3,515,217 3,654,381 3,737,006 3,915,332 4,097,877 4,305,355 4,399,717Total Annual Operating cost ($) 31,605,039 31,685,986 31,879,958 32,023,230 32,268,846 32,584,455 32,723,927 32,883,680 33,144,657 33,351,896 33,657,702 33,970,659 34,311,549 34,542,391Total Annual Operating cost ($/MWh) 601 603 607 609 614 620 623 626 631 635 640 646 653 657PV Total Annual Operating cost ($) 29,816,075 28,200,414 26,767,028 25,365,397 24,113,159 22,970,755 21,763,281 20,631,628 19,618,271 18,623,525 17,730,458 16,882,377 16,086,593 15,278,133Levelized Annual Operating Cost ($/MWh)3Option 3 - WindPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819Fixed Annual O&M Cost ($) 560,207 573,091 586,272 599,757 613,551 627,663 642,099 656,867 671,975 687,431 703,242 719,416 735,963 752,890CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AVariable Annual O&M ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAverage Heat Rate (MMBtu/MWh) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAnnual Fuel Consumed (MMBtu) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 3,034,026 3,046,910 3,060,092 3,073,576 3,087,370 3,101,482 3,115,918 3,130,686 3,145,794 3,161,250 3,177,061 3,193,235 3,209,782 3,226,709Total Annual Operating cost ($/MWh) 346 348 349 351 352 354 356 357 359 361 363 365 366 368PV Total Annual Operating cost ($) 2,862,288 2,711,739 2,569,312 2,434,560 2,307,063 2,186,422 2,072,264 1,964,231 1,861,991 1,765,225 1,673,636 1,586,940 1,504,871 1,427,176Levelized Annual Operating Cost ($/MWh)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 1 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%) 10% with CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20254Option 4 - Retrofit w/No. 2 OilPlant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678Fixed Annual O&M Cost ($) 2,773,022 2,836,802 2,902,048 2,968,795 3,037,078 3,106,931 3,178,390 3,251,493 3,326,277 3,402,782 3,481,046 3,561,110 3,643,015 3,726,804CO2 Allowance Cost ($) 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605Variable Annual O&M ($) 237,116 242,570 248,149 253,856 259,695 265,668 271,778 278,029 284,424 290,966 297,658 304,504 311,508 318,672Average Heat Rate (MMBtu/MWh) 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9Annual Fuel Consumed (MMBtu) 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224Total Annual Fuel Operating Cost ($) 6,750,994 6,718,554 6,686,270 6,654,141 6,863,027 7,078,471 7,300,677 7,529,860 7,766,236 8,048,139 8,340,275 8,643,015 8,956,743 9,281,860Total Annual Operating cost ($) 16,492,415 16,529,208 16,567,749 16,608,075 16,891,082 17,182,351 17,482,128 17,790,664 18,108,220 18,473,169 18,850,261 19,239,910 19,642,548 20,058,619Total Annual Operating cost ($/MWh) 314 314 315 316 321 327 333 338 345 351 359 366 374 382PV Total Annual Operating cost ($) 15,558,882 14,710,936 13,910,602 13,155,151 12,621,999 12,112,880 11,626,613 11,162,083 10,718,227 10,315,321 9,930,082 9,561,646 9,209,193 8,871,947Levelized Annual Operating Cost ($/MWh)5Option 5 - MSW Stoker/CFBPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929Fixed Annual O&M Cost ($) 4,201,549 4,298,185 4,397,043 4,498,175 4,601,633 4,707,470 4,815,742 4,926,504 5,039,814 5,155,730 5,274,311 5,395,621 5,519,720 5,646,673CO2 Allowance Cost ($) 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777Variable Annual O&M ($) 736,111 753,042 770,362 788,080 806,206 824,749 843,718 863,124 882,975 903,284 924,059 945,313 967,055 989,297Average Heat Rate (MMBtu/MWh) 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5Annual Fuel Consumed (MMBtu) 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 14,146,366 14,259,932 14,376,111 14,494,961 14,616,545 14,740,925 14,868,166 14,998,334 15,131,495 15,267,719 15,407,077 15,549,639 15,695,481 15,844,676Total Annual Operating cost ($/MWh) 1,615 1,628 1,641 1,655 1,669 1,683 1,697 1,712 1,727 1,743 1,759 1,775 1,792 1,809PV Total Annual Operating cost ($) 13,345,628 12,691,289 12,070,460 11,481,367 10,922,332 10,391,770 9,888,180 9,410,140 8,956,309 8,525,415 8,116,256 7,727,694 7,358,654 7,008,116Levelized Annual Operating Cost ($/MWh)6Option 6 - Recip w/No. 6 OilPlant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 20 20 20MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520Annual Capital Carrying Cost ($) 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007Fixed Annual O&M Cost ($) 1,680,620 1,719,274 1,758,817 1,799,270 1,840,653 1,882,988 1,926,297 1,970,602 2,015,926 2,062,292 2,109,725 2,158,248 2,207,888 2,258,669CO2 Allowance Cost ($) 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75Annual Fuel Consumed (MMBtu) 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300Total Annual Fuel Operating Cost ($) 2,312,999 2,301,884 2,290,823 2,279,815 2,351,383 2,425,198 2,501,329 2,579,851 2,660,837 2,757,422 2,857,512 2,961,235 3,068,724 3,180,114Total Annual Operating cost ($) 7,711,621 7,742,547 7,774,493 7,807,482 7,924,058 8,043,916 8,167,150 8,293,858 8,424,138 8,571,151 8,722,829 8,879,327 9,040,804 9,207,424Total Annual Operating cost ($/MWh) 440 442 444 446 452 459 466 473 481 489 498 507 516 526PV Total Annual Operating cost ($) 7,275,115 6,890,839 6,527,615 6,184,257 5,921,317 5,670,643 5,431,621 5,203,669 4,986,235 4,786,086 4,595,078 4,412,753 4,238,681 4,072,452Levelized Annual Operating Cost ($/MWh)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 2 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%) 10% with CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20257Option 7 - PV SolarPlant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 10 10 10MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760Annual Capital Carrying Cost ($) 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214Fixed Annual O&M Cost ($) 350,129 358,182 366,420 374,848 383,469 392,289 401,312 410,542 419,984 429,644 439,526 449,635 459,977 470,556CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AVariable Annual O&M ($) 122,685 125,507 128,394 131,347 134,368 137,458 140,620 143,854 147,163 150,547 154,010 157,552 161,176 164,883Average Heat Rate (MMBtu/MWh) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/AAnnual Fuel Consumed (MMBtu) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/ATotal Annual Operating cost ($) 7,739,028 7,749,903 7,761,028 7,772,408 7,784,051 7,795,961 7,808,145 7,820,610 7,833,361 7,846,405 7,859,750 7,873,401 7,887,366 7,901,653Total Annual Operating cost ($/MWh) 883 885 886 887 889 890 891 893 894 896 897 899 900 902PV Total Annual Operating cost ($) 7,300,970 6,897,386 6,516,308 6,156,475 5,816,696 5,495,845 5,192,863 4,906,747 4,636,554 4,381,392 4,140,418 3,912,839 3,697,905 3,494,909Levelized Annual Operating Cost ($/MWh)8Option 8 - CC w/No.2Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 60 60 60MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560Annual Capital Carrying Cost ($) 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684Fixed Annual O&M Cost ($) 4,369,611 4,470,112 4,572,925 4,678,102 4,785,698 4,895,769 5,008,372 5,123,565 5,241,407 5,361,959 5,485,284 5,611,445 5,740,509 5,872,540CO2 Allowance Cost ($) 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 189,063 193,411 197,859Average Heat Rate (MMBtu/MWh) 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4Annual Fuel Consumed (MMBtu) 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944Total Annual Fuel Operating Cost ($) 5,296,517 5,170,295 5,047,081 4,926,803 5,102,163 5,283,765 5,471,831 5,666,591 5,868,282 6,052,573 6,242,651 6,438,698 6,640,902 6,849,457Total Annual Operating cost ($) 16,405,209 16,382,874 16,365,936 16,354,379 16,640,961 16,936,343 17,240,805 17,554,638 17,878,142 18,187,047 18,504,605 18,831,065 19,166,680 19,511,715Total Annual Operating cost ($/MWh) 312 312 311 311 317 322 328 334 340 346 352 358 365 371PV Total Annual Operating cost ($) 15,476,612 14,580,699 13,741,156 12,954,200 12,435,094 11,939,453 11,466,120 11,013,997 10,582,045 10,155,552 9,747,995 9,358,462 8,986,088 8,630,050Levelized Annual Operating Cost ($/MWh)Adjusted Displaced Energy CostsAll Hours Benchmark for St. Thomas ($/M169.94 168.31 169.50 169.28 172.29 180.35 186.10 193.68 200.33 209.75 216.98 225.44 234.29 243.16Check $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26All Hours Benchmark for St. Croix ($/MWh176.96 176.08 175.48 173.92 178.90 183.78 189.51 194.77 200.32 207.84 214.72 221.57 229.64 237.61Check $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87Adjusted Average System Energy CostSt. Thomas ($/MWh)238.87 236.44 235.39 233.80 239.16 246.45 253.05 260.58 268.03 277.32 285.96 295.36 305.35 315.15$271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96St. Croix ($/MWh)223.48 222.12 220.96 219.46 225.75 231.84 238.53 245.14 252.15 260.65 269.17 277.90 287.50 296.95$255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 3 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%)Year1Option 1 - CFB Coal/PET CokePlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)2Option 2 - CC w/LNGPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)3Option 3 - WindPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)10% with CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg20 20 20 20 20 20 20 20 20 20 2017,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 223,964 17,52014,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,6803,080,825 3,151,684 3,224,173 3,298,329 3,374,190 3,451,797 3,531,188 3,612,405 3,695,491 3,780,487 3,867,438320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983220,845 225,925 231,121 236,437 241,875 247,438 253,129 258,951 264,907 271,000 277,23312 12 12 12 12 12 12 12 12 12 12210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240733,612 756,670 780,452 804,981 830,282 856,378 883,294 911,056 939,690 969,225 999,68818,420,945 18,519,941 18,621,409 18,725,410 18,832,010 18,941,275 19,053,274 19,168,075 19,285,751 19,406,374 19,530,021 230,547,0161,051 1,057 1,063 1,069 1,075 1,081 1,088 1,094 1,101 1,108 1,115 1,044.527,686,417 7,290,306 6,915,329 6,560,331 6,224,224 5,905,979 5,604,623 5,319,239 5,048,957 4,792,958 4,550,468 230,547,0161,02960 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,56023,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,1156,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,206,207 7,371,949 7,541,504342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0917.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,9444,521,053 4,690,731 4,901,689 5,086,050 5,232,422 5,417,098 5,608,292 5,806,235 6,011,164 6,223,325 6,442,97534,803,346 35,115,855 35,472,928 35,806,766 36,106,051 36,447,159 36,798,382 37,160,034 37,532,438 37,915,927 38,310,844 430,461,742662 668 675 681 687 693 700 707 714 721 729 656.0914,522,220 13,823,226 13,173,383 12,544,678 11,933,520 11,364,396 10,824,443 10,312,099 9,825,890 9,364,421 8,926,374 430,461,74264110 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7602,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819770,206 787,921 806,043 824,582 843,548 862,949 882,797 903,101 923,873 945,122 966,860#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A3,244,025 3,261,740 3,279,862 3,298,401 3,317,367 3,336,768 3,356,616 3,376,920 3,397,692 3,418,941 3,440,679 40,535,825370 372 374 377 379 381 383 385 388 390 393 367.551,353,618 1,283,972 1,218,024 1,155,574 1,096,433 1,040,420 987,367 937,113 889,506 844,405 801,673 40,535,825362R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 4 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%)Year4Option 4 - Retrofit w/No. 2 OilPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)5Option 5 - MSW Stoker/CFBPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)6Option 6 - Recip w/No. 6 OilPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)10% with CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg60 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,5606,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,6783,812,521 3,900,209 3,989,914 4,081,682 4,175,560 4,271,598 4,369,845 4,470,352 4,573,170 4,678,353 4,785,955496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605326,002 333,500 341,170 349,017 357,045 365,257 373,658 382,252 391,044 400,038 409,2387.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,2249,572,983 9,873,237 10,182,908 10,502,293 10,831,694 11,171,427 11,521,816 11,883,195 12,255,908 12,640,311 13,036,77120,442,788 20,838,228 21,245,275 21,664,274 22,095,581 22,539,565 22,996,601 23,467,080 23,951,403 24,449,983 24,963,246 241,411,260389 396 404 412 420 429 438 446 456 465 475 379.438,530,061 8,202,891 7,889,739 7,589,944 7,302,877 7,027,943 6,764,574 6,512,234 6,270,412 6,038,621 5,816,402 241,411,26035910 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7609,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,9295,776,547 5,909,408 6,045,324 6,184,366 6,326,607 6,472,119 6,620,977 6,773,260 6,929,045 7,088,413 7,251,446105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,7771,012,051 1,035,328 1,059,141 1,083,501 1,108,422 1,133,915 1,159,995 1,186,675 1,213,969 1,241,890 1,270,45317.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A15,997,304 16,153,441 16,313,170 16,476,573 16,643,734 16,814,740 16,989,678 17,168,641 17,351,719 17,539,009 17,730,606 196,269,5381,826 1,844 1,862 1,881 1,900 1,919 1,939 1,960 1,981 2,002 2,024 1,801.726,675,116 6,358,742 6,058,131 5,772,465 5,500,971 5,242,915 4,997,606 4,764,385 4,542,633 4,331,759 4,131,207 196,269,5381,75320 20 20 20 20 20 20 20 20 20 2017,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 223,964 17,5203,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,0072,310,619 2,363,763 2,418,130 2,473,747 2,530,643 2,588,847 2,648,391 2,709,304 2,771,618 2,835,365 2,900,579199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0918.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,3003,279,857 3,382,729 3,488,828 3,598,254 3,711,112 3,827,510 3,947,559 4,071,373 4,199,071 4,330,773 4,466,6079,363,667 9,524,339 9,689,566 9,859,481 10,034,220 10,213,921 10,398,730 10,588,793 10,784,263 10,985,297 11,192,057 111,547,915534 544 553 563 573 583 594 604 616 627 639 522.713,907,131 3,749,221 3,598,360 3,454,208 3,316,440 3,184,749 3,058,843 2,938,444 2,823,291 2,713,133 2,607,734 111,547,915498R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 5 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISANDS WATER AND POWER AUTHORITYPower Supply StudyNovember 2007 - Generation Screening with CO2 Allowance CostSelected CalculationsTable 7BTOCapacity Factor (%)Year7Option 7 - PV SolarPlant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)8Option 8 - CC w/No.2Plant Rating (MW)MWh Generated (MWh)Annual Capital Carrying Cost ($)Fixed Annual O&M Cost ($)CO2 Allowance Cost ($)Variable Annual O&M ($)Average Heat Rate (MMBtu/MWh)Annual Fuel Consumed (MMBtu)Total Annual Fuel Operating Cost ($)Total Annual Operating cost ($)Total Annual Operating cost ($/MWh)PV Total Annual Operating cost ($)Levelized Annual Operating Cost ($/MWh)Adjusted Displaced Energy CostsAll Hours Benchmark for St. Thomas ($/MCheckAll Hours Benchmark for St. Croix ($/MWhCheckAdjusted Average System Energy CostSt. Thomas ($/MWh)St. Croix ($/MWh)10% with CO22026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 NPVAvg10 10 10 10 10 10 10 10 10 10 108,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 111,982 8,7607,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214481,379 492,451 503,777 515,364 527,217 539,343 551,748 564,438 577,420 590,701 604,287#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A168,675 172,555 176,523 180,583 184,737 188,986 193,333 197,779 202,328 206,982 211,742#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A7,916,268 7,931,219 7,946,514 7,962,161 7,978,168 7,994,543 8,011,294 8,028,431 8,045,962 8,063,896 8,082,243 100,408,422904 905 907 909 911 913 915 916 918 921 923 901.343,303,182 3,122,095 2,951,053 2,789,494 2,636,888 2,492,736 2,356,566 2,227,931 2,106,411 1,991,609 1,883,152 100,408,42289760 60 60 60 60 60 60 60 60 60 6052,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 671,893 52,5606,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,6846,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,206,207 7,371,949 7,541,504465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,0917.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,9447,078,450 7,315,099 7,559,659 7,812,396 8,073,582 8,326,808 8,587,976 8,857,336 9,135,144 9,421,665 9,717,17319,880,327 20,259,806 20,650,482 21,052,695 21,466,796 21,876,453 22,297,650 22,730,719 23,176,002 23,633,851 24,104,626 236,686,538378 385 393 401 408 416 424 432 441 450 459 370.698,295,366 7,975,197 7,668,854 7,375,681 7,095,055 6,821,181 6,558,974 6,307,890 6,067,414 5,837,054 5,616,345 236,686,538352252.02 261.90 268.40 277.74 289.482,268($203.26)$203.26 $203.26 $203.26 $203.26 $203.262,268244.81 253.25 261.01 268.37 275.952,275($203.87)$203.87 $203.87 $203.87 $203.87 $203.872,275324.43 334.40 342.61 352.78 364.173,035($271.96)$271.96 $271.96 $271.96 $271.96 $271.963,035305.55 314.82 323.76 333.14 342.622,855($255.86)$255.86 $255.86 $255.86 $255.86 $255.862,855R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xlsPage 6 of 6; 2/25/2008; RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYGeneration ScreeningFatal Flaw AnalysisQualitative AssessmentTable 8LineOptionNo. Description 1 2 3 4 5 61Name of Option:CirculatingFluidized BedWindTurbine GeneratorsCombinedCycle RetrofitMunicipal Solid Waste Steam TurbineGeneratorSlow Speed ReciprocatingEngine GeneratorPhotovoltaicCells2Plant Size (MW) 20 20 20 10 20 103Expected Capacity Factor 85% 25% 50% 85% 85% 15%4Lower than Average System Cost atExpected Capacity FactorYes Yes Yes No [2] Yes No5Lower than Avoided Cost atExpected Capacity FactorYes Yes Yes No [2] No No6Permittability/Siting Feasibility Yes[1] Yes [1] Yes Yes No[3] Yes [1]7Renewable No Yes No Yes No Yes8Dispatchable Yes No Yes No Yes No9Fuel Diversity Yes Yes No Yes No YesSensitivity to:10Capital Costs High High Medium High Medium High11O&M Costs Medium Medium Medium High Medium Low12Fuel Costs Medium None High None [2] High None13CO2CostsHigh None Medium None High None[1] Permitability is feasible but site dependent.[2] No tipping fee assumed.R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 8_fatal flaw.xlsPage 1 of 1; 2/25/2008;RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply StudyProjected Cost of Methanol Plant versus Fuel Cost ReductionTable 9LineNo. Description NPV(a) (b)PV Total Annual Operating Cost [1]1CC @ 40MW [2]229,096,6162Methanol Plant [3]1,278,439,8823 Total 1,507,536,497Fuel Cost [4]St. Croix4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost DifferenceSt. Thomas7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost DifferenceTotal System10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13Net Total Cost Difference(1,720,945,829)14Levelized Cost Difference(134,623,944)2012 2013 2014 2015 2016 2017 2018 2019(c) (d) (e) (f) (g) (h) (i) (j)15,769,382 15,927,833 16,089,443 16,254,278 16,464,239 16,678,900 16,898,367 17,122,74796,584,184 96,906,303 97,235,830 97,572,937 97,917,797 98,270,589 98,631,495 99,000,702112,353,566 112,834,136 113,325,273 113,827,215 114,382,036 114,949,489 115,529,861 116,123,44873,197,312 73,132,508 72,994,119 72,911,935 75,513,775 78,138,001 80,882,972 83,723,3857,784,247 7,896,754 8,002,813 8,116,523 8,324,943 8,531,021 8,745,396 8,965,052(65,413,065) (65,235,754) (64,991,307) (64,795,412) (67,188,832) (69,606,980) (72,137,576) (74,758,333)138,194,287 139,152,233 139,848,589 140,663,564 146,726,243 152,945,954 159,581,425 166,483,16816,190,165 16,570,210 16,926,913 17,305,669 17,879,582 18,459,946 19,077,335 19,712,819(122,004,122) (122,582,023) (122,921,676) (123,357,894) (128,846,661) (134,486,008) (140,504,090) (146,770,349)211,391,599 212,284,740 212,842,708 213,575,499 222,240,018 231,083,955 240,464,397 250,206,55323,974,412 24,466,964 24,929,726 25,422,193 26,204,525 26,990,967 27,822,731 28,677,871(187,417,186) (187,817,777) (187,912,983) (188,153,306) (196,035,494) (204,092,988) (212,641,665) (221,528,682)(75,063,620) (74,983,641) (74,587,710) (74,326,091) (81,653,458) (89,143,500) (97,111,804) (105,405,234)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xlsPage 1 of 4; 2/25/2008;RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply StudyProjected Cost of Methanol Plant versus Fuel Cost ReductionTable 9LineNo. Description NPV(a) (b)PV Total Annual Operating Cost [1]1CC @ 40MW [2]229,096,6162Methanol Plant [3]1,278,439,8823 Total 1,507,536,497Fuel Cost [4]St. Croix4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost DifferenceSt. Thomas7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost DifferenceTotal System10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13Net Total Cost Difference(1,720,945,829)14Levelized Cost Difference(134,623,944)2020 2021 2022 2023 2024 2025 2026 2027 2028(k) (l) (m) (n) (o) (p) (q) (r) (s)17,352,151 17,624,788 17,904,652 18,191,936 18,486,842 18,789,576 19,105,427 19,429,849 19,763,08099,378,400 99,764,786 100,160,059 100,564,423 100,978,087 101,401,265 101,834,177 102,277,046 102,730,100116,730,551 117,389,574 118,064,710 118,756,359 119,464,929 120,190,841 120,939,604 121,706,894 122,493,18086,678,526 90,093,163 93,734,985 97,552,059 101,462,767 105,525,386 109,342,947 113,181,323 116,731,2249,191,814 9,499,543 9,827,290 10,169,267 10,516,739 10,875,582 11,269,739 11,666,091 12,032,756(77,486,713) (80,593,620) (83,907,696) (87,382,792) (90,946,028) (94,649,803) (98,073,208) (101,515,232) (104,698,468)173,563,500 181,844,352 190,405,348 199,387,751 208,713,690 218,814,338 228,078,552 237,445,409 244,892,81920,355,413 21,191,646 22,049,015 22,943,281 23,864,743 24,861,778 25,897,773 26,944,219 27,771,799(153,208,087) (160,652,706) (168,356,333) (176,444,471) (184,848,946) (193,952,560) (202,180,779) (210,501,189) (217,121,021)260,242,026 271,937,515 284,140,334 296,939,811 310,176,456 324,339,724 337,421,499 350,626,731 361,624,04429,547,226 30,691,189 31,876,305 33,112,548 34,381,482 35,737,360 37,167,512 38,610,310 39,804,555(230,694,800) (241,246,326) (252,264,029) (263,827,263) (275,794,974) (288,602,364) (300,253,987) (312,016,421) (321,819,489)(113,964,249) (123,856,752) (134,199,319) (145,070,904) (156,330,045) (168,411,522) (179,314,383) (190,309,527) (199,326,308)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xlsPage 2 of 4; 2/25/2008;RWBeck, Inc.VIRGIN ISLANDS WATER AND POWER AUTHORITYPower Supply StudyProjected Cost of Methanol Plant versus Fuel Cost ReductionTable 9LineNo. Description NPV(a) (b)PV Total Annual Operating Cost [1]1CC @ 40MW [2]229,096,6162Methanol Plant [3]1,278,439,8823 Total 1,507,536,497Fuel Cost [4]St. Croix4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost DifferenceSt. Thomas7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost DifferenceTotal System10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13Net Total Cost Difference(1,720,945,829)14Levelized Cost Difference(134,623,944)2029 2030 2031 2032 2033 2034 2035 2036(t) (u) (v) (w) (x) (y) (z) (aa)20,105,366 20,456,957 20,818,115 21,189,104 21,570,199 21,961,682 22,363,843 22,776,979103,193,575 103,667,710 104,152,750 104,648,945 105,156,554 105,675,837 106,207,064 106,750,509123,298,941 124,124,667 124,970,864 125,838,049 126,726,753 127,637,519 128,570,906 129,527,488120,392,467 124,168,544 128,063,057 132,079,720 136,222,365 140,494,942 144,901,528 149,446,32512,410,946 12,801,023 13,203,360 13,618,342 14,046,367 14,487,845 14,943,198 15,412,864(107,981,521) (111,367,522) (114,859,698) (118,461,378) (122,175,998) (126,007,098) (129,958,330) (134,033,461)252,573,816 260,495,725 268,666,103 277,092,742 285,783,681 294,747,209 303,991,875 313,526,49728,624,946 29,504,453 30,411,140 31,345,849 32,309,450 33,302,841 34,326,945 35,382,718(223,948,871) (230,991,272) (238,254,963) (245,746,894) (253,474,231) (261,444,368) (269,664,929) (278,143,780)372,966,284 384,664,270 396,729,160 409,172,463 422,006,046 435,242,151 448,893,403 462,972,82241,035,892 42,305,476 43,614,499 44,964,190 46,355,817 47,790,685 49,270,144 50,795,581(331,930,392) (342,358,794) (353,114,661) (364,208,272) (375,650,229) (387,451,465) (399,623,259) (412,177,241)(208,631,451) (218,234,126) (228,143,796) (238,370,223) (248,923,476) (259,813,946) (271,052,353) (282,649,753)R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xlsPage 3 of 4; 2/25/2008;RWBeck, Inc.

### VIRGIN ISLANDS WATER AND POWER AUTHORITY
Power Supply Study

Projected Cost of Methanol Plant versus Fuel Cost Reduction

FOOTNOTES: Table 9

[1] Operating cost based on a 25 year capital payment period, 6% annual interest rate, 3% issuance expenses, 2.3% inflation, 7.82% annual carrying cost, and a 1.1546 bond factor. [2] Based on a unit with a 7.4 MMBtu/MWh heat rate, a capital cost of $1,183/kW using methanol fuel

converted from PET coke. [3] Based on a capital cost of $800 Million, two $6 Million fuel storage tanks, converting 10 CT's at $0.2 Million each. Also based on a 4 year construction period, $12.5 Million FOM and $0 VOM. [4] Based on current approximate MMBtu required per Island. [5] Based on 100% No. 2 fuel oil for St. Croix. [6] Based on a fuel oil mixture of 50% No. 2 and 50% No. 6 for St. Thomas. [7] Includes a $4/ton ($2007) transportation cost for St. Thomas.

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\ Table 9_methanol conversion_rev.xls Page 4 of 4; 2/25/2008; RWBeck, Inc.

# Appendix C Wind Project Financing Structures: A Review and Comparative Analysis

### LBNL-63434



# E RNEST 

# O RLANDO 

# L AWRENCE


# B ERKELEY 

# N ATIONAL 

# L ABORATORY



# Wind Project Financing Structures:
A Review & Comparative Analysis

John P. Harper, Birch Tree Capital, LLC

Matthew D. Karcher, Deacon Harbor Financial, L.P.
Mark Bolinger, Lawrence Berk eley National Laboratory

Environmental Energy Technologies Division

September 2007

Download from http://eetd.lbl.gov/ea/emp

The work described in this report was funded by the Office of Energy Efficiency and Renewable Energy, Wind & Hydropower Technologies Program of the U.S. Department of Ener gy under Contract No. DE-AC02-05CH11231.

### Disclaimer

This document was prepared as an account of work sponsored by the United States

Government. While this document is believed to contain correct information, neither the United States Government nor any ag ency thereof, nor The Regents of the University of California, nor any of thei r employees, makes any warranty, express or implied, or assumes any legal responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disc losed, or represents that its use would not infringe privately ow ned rights. Reference herein to any specific commercial product, process, or service by it s trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof, or The Regents of the University of California. The views a nd opinions of authors expressed herein do not necessarily state or reflect those of th e United States Government or any agency thereof, or The Regents of the University of California.

Ernest Orlando Lawrence Berkeley Nationa l Laboratory is an equal opportunity employer.

## Acknowledgements

The work described in this report was funded by the Office of Energy Efficiency and Renewable Energy, Wind & Hydropower Technologies Program of the U.S. Department of Energy under

Contract No. DE-AC02-05CH11231. The authors would particularly like to thank Steve Lindenberg, Alejandro Moreno, and Jack Cadogan (retired) of the U.S. Department of Energy for their support of this work. For contributing information and revi ewing earlier vers ions of this manuscript, the authors thank (in alphabetical orde r, by last name): Jeff Chester (Kaye Scholer LLP), Karlynn Cory (NREL), Mike Davies (FreeS tream Capital LLP), Ed Ing (Law Offices of Edwin T.C. Ing), Tim MacDonald (Meridian I nvestments), Alejandro Moreno (U.S. DOE), Ric O’Connell (Black & Veatch), Kevin Pearson (S toel Rives LLP), Liz Salerno (AWEA), Ryan Wiser (LBNL), and one anonymous reviewer. Of c ourse, any remaining errors or omissions are the sole responsibility of the authors.

## Table of Contents

Executive Summary ....................................................................................................................... i

1. Introduction .............................................................................................................................. 1 2. A Recent History of Modern Wind Project Finance ............................................................ 5 2.1 1998-2002: Strategic Inve stors Dominate the Market ........................................................ 6

2.2 2003-2006: Rise of the Institutional Investor ..................................................................... 7 2.3 Recent Equity Financing Developments .............................................................................. 9 2.4 Recent Debt Financing Developments ............................................................................... 11 2.5 Summary ............................................................................................................................ 13 3. Description of Current Financing Structures ..................................................................... 14 3.1 Corporate Structure ............................................................................................................ 15 3.2 Strategic Investor Flip ........................................................................................................ 18 3.3 Institutional Investor Flip ................................................................................................... 22 3.4 Pay-As-You-Go ................................................................................................................. 25 3.5 Cash Leveraged .................................................................................................................. 28 3.6 Cash & PTC Leveraged ..................................................................................................... 31 3.7 Back Leveraged ................................................................................................................. 34 3.8 Summary: Choosing a Structure ....................................................................................... 36 4. The Impact of Financing Structure on the Levelized Cost of Wind Energy .................... 39

4.1 Overview of Pro Forma Financial Model .......................................................................... 39 4.2 Levelized Cost of Energy Comparisons ............................................................................ 40

5. Conclusions – Observations & Future Trends .................................................................... 48

References

............................................................................................................................... ..... 52 Appendix A: Glossary ............................................................................................................... 54 Appendix B: Description of Pro Fo rma Financial Model and Assumptions ........................ 57 Appendix C: Overview of Part nership Tax Accounting Issues ............................................. 69

## Executive Summary

Wind power capacity in the United States has grown substantially in recent years. From 1998 through 2006, almost 9,900 megawatts (“MW”) of new wind capacity was added, accounting for 85% of the 11,575 MW cumulative total capacity as of the end of 2006. In 2006 alone, 2,454 MW of new wind capacity was installed, represen ting a 27% increase in cumulative capacity.

This rapid expansion has required the mobilizati on of a tremendous amount of capital to finance wind project costs. Roughly $18 billion (in real 2006 dollars) has been inve sted in wind project

installation in the U.S. since the 1980s, with more than $3.7 bi llion invested in 2006 alone. Looking ahead, wind project developers will need to raise close to $6 billion in 2007 in order to finance the expansion projected by the Americ an Wind Energy Association (“AWEA”), and the required amount of capital will lik ely continue to increase in fu ture years if market growth

continues.

The financing of new wind projects varies from that of fossil-fuel ed power projects due to the different cost characteristics of each. Specifica lly, wind projects are capital-intensive to build but have no ongoing fuel costs, while fossil-fueled power projects are less capital-intensive (per unit of production) but have higher operating (e.g., fuel) costs. Furthermore, whereas Federal tax incentives for fossil-fueled power plants can be (and generally are) distributed throughout the entire fuel cycle (e.g., from exploration and ex traction to transportation, power production, and emissions controls), tax incentives for wind projects are instead ta rgeted almost exclusively at the power production stage. The two principal Fe deral tax incentives ava ilable to wind projects are the production tax credit (“PTC”) and acceler ated depreciation deducti ons (togethe r with the PTC, the “Tax Benefits”). These Tax Benefits pr ovide a significant value to wind projects, but also complicate wind project finance, since most wind project developers lack sufficient Federal income tax liability to use the Tax Benefits efficiently.

In response, the wind sector has developed multip le financing structures to attract various investors to projects, manage pr oject risk, and allocate Tax Benef its to entities that can use the Tax Benefits most efficiently. Some of these st ructures are intended to attract actively involved large equity investors with a strategic interest in the wind sector, labeled here as “Strategic

Investors.” Others are designed to tap into more-passive equity capital from “Institutional Investors,” which are primarily interested in the Tax Benefits. Still others enable developers and equity investors to layer on de bt financing to leverage thei r equity exposure and returns.

This report surveys the seven principal financin g structures through which most new utility-scale wind projects in the United Stat es have been financed from 1999 to the present, excluding projects owned by investor-owned and publicly-owned utilities wh ere the project becomes part

of the utilities’ internal generating portfolio and rate base. The report defines utility-scale wind projects as those designed to sell electricity directly to utilities or into power markets on a wholesale basis. The report do es not cover financing structur es used for smaller communitybased wind power projects, though it may have some indirect utility for parties considering such projects, as several financing op tions used for smaller projects are derived from structures first conceived for larger projects. Fi nally, this report is relevant onl y to the U.S. market, since the

i

### presence and structure of the Tax Benefits have dr iven the development of financing structures in ways not applicable for ot her national markets.

The report has three primary objectives: (1) to su rvey recent trends in the financing of utilityscale wind projects in the United States, (2) to describe the seve n principal financing structures through which most utility-scale wind projects have been financed from 1999 to the present, and (3) to explain each structure’s relative impact on the levelized cost of wind energy. The year 1999 is used as a starting point because it marks the recent upsurge in wind power growth in the

United States.

The seven structures, summarized briefly in Table ES-1, feature varying combinations of equity capital from project developers, third-party tax-oriented investor s (both Strategic and Institutional Investors, jointly known as “Tax I nvestors”), and commercial debt. Their origins

stem from variations in the fina ncial capacity and strength, as we ll as the business objectives, of wind project developers. The stru ctures have received various names in the industry. The names given in this report are intended to reflect a defining characteristic. For the first three structures in Table ES-1, it is the nature of the Tax Investor. The Pay-As-You-Go (“PAYGO”) structure name reflects the delayed timing of the Tax Inve stor contribution. For the three structures involving leverage, the name refers to the type of debt financing provided. Other names are feasible and in use; care should therefore be taken to specify st ructures other than solely by

name.

Table ES-1. Description of Seven Financing Structures

Financing
Structure

Name Project Capital
Structure Likely Equity

Investors Brief Description of Structure Mechanics

Corporate All equity Developer (corporate entity) Corporate entity develops project and finances all costs. No other investor or lender capital is involved. Corporate entity is able to utilize Tax Benefits (no flip).
Strategic

Investor

Flip All equity Developer and Strategic Investor Strategic Investor contributes almost all of the equity

and receives a pro rata percentage of the cash & Tax Benefits prior to a return-based flip in the allocations.

Institutional

Investor

Flip All equity Developer and

Institutional Investor Institutional Investor contri butes most of the equity and

receives all of the Tax Benefits and, after the developer has recouped its investment, all of the cash benefits, until a return-based flip in the allocations.

Pay-As-You-Go

(“PAYGO”) All equity Developer and

Institutional Investor Institutional Investor financ es much of the project, injecting some equity up-front and additional equity over time as the PTCs are generated. Includes a return-based flip in the allocations.

Cash Leveraged Equity and debt Developer and

Institutional Investor Based on the Strategic Invest or Flip structure, but adds debt financing. Likely involv es Institutional Investors, rather than Strategic Investors. Loan size/amortization based on the amount of cash flow from power sales.

Cash & PTC Leveraged Equity and debt Developer and

Institutional Investor Similar to the Cash Levera ged structure, but the loan size and amortization profile are based on the cash flow from power sales plus a monetization of the projected PTCs from the project.

Back Leveraged All equity (but developer uses

debt outside of the project) Developer and

Institutional Investor Virtually identical to the Institutional Investor Flip, but with the developer leveraging its equity stake in the project using debt financing.



### ii

### The list of financing structures s hown in Table ES-1 and covered in this report is not intended to be exhaustive. Various permutations of these st ructures, as well as othe r structures altogether, are possible. That said, the initial construc tion costs of most new utility-scale wind projects in

the United States from 1999 to th e present have been financed using one or another of these

structures.

To compare the levelized cost of wind energy under each structure, a simplified Excel-based pro forma financial model of an indicative or temp late wind power project was constructed. The template project is based on a set of assumpti ons intended to reflect market conditions for projects coming on-line in 2007 and 2008 for items such as non-financing ca pital costs, operating costs, energy production, taxes, and re venue flows. The template project is then customized to reflect each financing structure. For the six financing st ructure involving thirdparty equity or debt capital, the analysis includes assumptions for: (1) the cost and terms of debt (if any); (2) the cost and terms of equity from Tax Investors; and (3 ) any financing-related transaction, or “soft” costs. Th e model then estimates the power prices needed to comply with those terms. For these six structures (i.e., all but the Corporate structure), the model calculates the minimum 20-year levelized cost of energy (“LCOE ”) that yields the 10-y ear internal rate of return (“IRR”) requirement for the Tax Investors in each structure, while not violating any lender

constraints. i 

### For these structures, the 10-year Tax Invest or IRR is used as a key metric, as it is a key negotiating point between developers and investors. ii 

### For the Corporate structure, the model calculates the minimum LCOE that yields the de veloper’s 20-year IRR target. Using a 20-year target for the Corporate structure is consistent with the assumption that the developer, as sole project participant, evaluates th e project on a longer-term basis th an do pure Tax Investors. The use of a standardized template project enables the observed variations in LCOE to reflect the impact of the different financing structures.

Table ES-2 summarizes key inputs and outputs from the model for each structure. The key inputs listed are the project costs, the Tax Investor’s 10- year IRR target (ex cept for the Corporate structure, where the relevant input is the de veloper’s 20-year IRR target), and the assumed

interest rates and tenor of debt for the three structures using debt financing. Discussion of these and other debt and equity fina ncing input assumptions are desc ribed in Chapter 4 and Appendix B. The outputs are the 20-year LCOE, the Tax I nvestor’s 20-year IRR, and the developer’s 10- year and 20-year IRR (again, except for the Cor porate structure, where the developer’s 20-year IRR target is a model input). In practice, ne gotiations with Tax Invest ors focus principally on

the Tax Investor’s IRR. The de veloper’s return calculations ar e presented (in both IRR and NPV terms) primarily for informational purposes, though some Tax Investor s will monitor the developer’s return to ensure a reasonable allocation of project returns between the parties.

i In turn, for each structure involving third-party Tax Invest or capital, the developer’s return in the model (and in actual negotiations) is the residual, or what is left after satis fying the Tax Investor’s return requirements. In practice, developer returns also reflect relative project attri butes, e.g., capacity factors, power prices, etc.,

ii To simplify the modeling task, the model treats the 20-year Tax Investor IRR as an output. In reality, the Tax Investor’s 20-year IRR is linked to its 10-year IRR and both IRR targets are highly negotiated between the Tax Investor and the developer and will reflect market conditions.



### iii

### As shown in Table ES-2, our analysis finds significant variation – ranging from $48 per megawatt hour (“MWh”) to $63/MWh – in th e 20-year LCOE required under the various financing structures. This varia tion is principally a function of: (1) financing-related transaction costs (s hown in Table ES-2 as “soft costs”); (2) assumed 10-year Tax Investor IRR target rates, and Corporate 20 -year IRR target; and (3) the relative terms of each structure (not s hown in Table ES-2, but discussed in Chapter 3 and Appendix B), including the level of equ ity contributions and pre- and post-flip

allocations of both cash and Tax Benefits.

Table ES-2. Project Costs, Investor Re turns, and LCOE by Financing Structure

Cash & PTC Leveraged Cash Leveraged Institutional

Investor

Flip Back Leveraged PAYGO Strategic

Investor

Flip Corporate

Assumed Installed Project Costs

Hard Cost ($/kW) 1,600 1,600 1,600 1, 600 1,600 1,600 1,600

Soft Cost ($/kW) 229 215 183 183 183 183 125

Total Cost ($/kW) 1,829 1,815 1,783 1, 783 1,783 1,783 1,725

Tax Investor After-Tax Return (The 10-year target IRR is a model inpu t, while the 20-year IRR is a model output)

10-Year Target IRR 9.25% 9.00% 6.50% 6.50% 6.50% 6.50% N/A

20-Year IRR 9.67% 9.29% 7.12% 7.12% 7.02% 7.02% N/A

Assumed Loan Terms (For those structures using leverage; Table B3 has details)

All-in Interest Rate 6.70% 6.70% N/A 6.70% N/A N/A N/A

Tenor (maturity) 15 years 15 year s N/A calculated N/A N/A N/A

Developer After-Tax Return (Except for the Corporate 20-year IRR, the developer returns are all model outputs)

10-Year IRR 9.25% 9.00% 0.00% -10.08% 5.75% 6.50% 6.64%

20-Year IRR 33.15% 30.58% 10.44 % 11.91% 11.52% 37.44% 10.00%

20-Year NPV ($000 @ 10%) 7,208 7,540 1,578 4, 673 7,811 20,745 0

20-Year Levelized Cost of Energy (LCOE)

Nominal $/MWh 48 50 53 53 59 61 63



### Although these results are intended to be illustrative of current ma rket conditions, they are, of course, a function of the modeling assumptions. These assumptions, which are merely indicative and do not reflect a specific project, are detail ed in Chapter 4 and in Appendix B. Using a different set of input parameters will generate different results. iii 

### Finally, the model does not undertake detailed tax-oriented partnership accoun ting analysis. Accordingly, the returns should not be assumed as likely for speci fic projects using the various fina ncing structures. Instead, the comparative nature of the analysis means that thes e LCOE results are best considered relative to

iii For example, the template wind project assumes a 36% net capacity factor (as described further in Appendix B). Capacity factor, a measure of energy production, is an important determinant in the profitability of a wind project, as it drives both revenue and PTC generation. Reducing th e capacity factor to 32% causes the calculated LCOEs to rise anywhere from 13% to 20% to compensate for the lower wind production. The relative relationships among the LCOE for the individual financing structures, however, do not change.



### iv

### one another – i.e., to illustrate the relative im pact of financing structures – rather than individually or on an absolute basis.

Table ES-2 suggests that leverage at the project level provides th e lowest required LCOE, with the Cash & PTC Leveraged structure coming in at $48/MWh. In other words, given the assumptions used in the analysis, our template project – when financed using this structure – requires a flat $48/MWh for the next twenty year s of operation to cover its capital and operating costs, and to meet the return requirements of the Tax Investor as well as the financing terms of the debt provider. The next-l owest LCOE is found with the Ca sh Leveraged structure, at $50/MWh (with the slightly higher LCOE reflecting slightly less le verage, due to the absence of PTC-backed debt).

The fact that the two structures with the lowest LCOEs have project debt is not unexpected, and suggests that leveraged structures should be popular in the market. Debt has a cheaper cost of capital than does equity. Other matters held equa l, the more debt a project can secure, the lower the LCOE. This is true despite the fact that, as reflected in Table ES-2, required equity returns are higher when leverage is involved, to account for the extra risk that is imposed on equity providers when debt is used. Moreover, the in vestors still receive th e full amount of the Tax Benefits as if the project had been financed with all equity and no debt. Additionally, the interest payments on debt are tax-deductible, so they increase the tax loss (which equates to tax benefits for the Tax Investor) in the early years of the project.

Interestingly, this finding is not consistent with actual market practice. Most new wind projects have not featured project-level debt. In 2006, for example, only about 20% of the deals in the market appeared to include project-level debt. Many developers and Tax Investors prefer other structures. The reasons given vary, but include both factors in favor of other structures (perceived simplicity, standardization, speed) and factors against using debt (perceived cost, complexity, loss of control, little-improved IRR). This divergence in th e implications of our LCOE results from market practice suggests that while the generic cost assumptions used for the model may reflect general market conditions, project -specific cost assumptions are central in the decision on financing stru cture. Factors not easily quantifia ble in a financial model, e.g., a parent company’s corporate financing strategy and project risk considerat ions, also play major

roles.

The Institutional Investor Flip and Back Leveraged structures ha ve the next lowest LCOE at $53/MWh. These all-equity structures are iden tical with the excepti on of the developer’s company-level debt in the Back Leveraged structur e. Because this debt is not at the project level, the project returns, Tax Investor returns, and required LCOEs do not differ between these two structures. The only variation is in the deve loper’s returns. For th e Institutional Investor Flip structure, the developer has no return on its capital prior to the flip point due to the

allocation of cash under the structure. In the Back Leveraged structure, the developer has a negative 10-year IRR (reflecting repayment of the company-level debt). Twenty years out, the developer under the Back Leveraged structure ha s a 20-year IRR (11.9%) that is about 150 basis points higher than the developer’s 20-year IRR (10.4%) using the Institutional Investor Flip structure. This reflects the positive impact of leverage on returns.

v

### The PAYGO structure – where the Tax Investor pa ys the developer an annual amount equal to a fixed percentage of the PTCs generated – is f ound to be the next-cheapest, with a LCOE of $59/MWh. This LCOE, as well as the develope r’s own return, are greatly affected by the assumed PTC payment percentage (in reality, the specific payment rate is set to achieve the negotiated respective return requirements).

The Strategic Investor Flip structure has the next highest LCOE, at $61/MWh. The LCOE is highly dependent on the Strategic Inve stor’s target return requirement. As the Strategic Investor does not take development-stage risks, and only contributes funds when the project is operational, the return requireme nts should be lower than requir ed for a Corporate structure investment (in which the Corporat e entity takes development risks) . The equity return to the developer under the Strategic Investor Flip struct ure is artificially magnified by the small amount of capital contributed. Fi nally, the Strategic Investor Flip structure results in a higher LCOE than does the Institutional Investor Flip structur e because the former provides the developer with a pre-flip pro rata return on investment, whereas the latter only provides the developer with a pre-flip return of its investment.

The highest LCOE of $63/MWh resu lting from the analysis is as sociated with the Corporate structure, and is largely a function of the fact that the model assumes a 20-year target return for the developer/Corporate entity of 10%. A devel oper’s return requirement is used under this structure in part because there is no involvement by a separate Tax Investor. A single owner bears all of the project risks – i.e., there is no separation of th e risks (and return s) between two equity parties, with one party havi ng lower risks and, hence, lower retu rns, than the other. In this way, the 10% developer’s target return might be thought of as a blende d equity hurdle rate, reflecting a melding of the typical returns to Ta x Investors and developers in other all-equity structures. The single return figure also can be viewed as a blend of developer’s equity and

lower-cost debt sourced at the co rporate level. Other things held equal, a decrease in the developer’s required return w ill reduce the corresponding LCOE.

Variations in the LCOE across financial stru ctures (assuming the same underlying template project) reflect the different as sumptions made about the equity returns and debt financing costs required by Tax Investors and lenders in the mark etplace. Investors and lenders require higher returns to invest in wind projects that use st ructures deemed more risky, e.g., those that defer returns until later in the life of the project, or th at use leverage. Thus, assuming all other cost and operating parameters are held equal, iv 

### the LCOE for a given financi ng structure is a proxy for the relative cost of equity and, if used, debt financ ing for the project. As with other maturing sectors, the cost of financing becomes a comp etitive differentiator am ong project developers. Those with access to cheaper money will be able to offer lower-cost power to their customers.

The variation in LCOE across stru ctures also indirectly touche s upon an apparent contradiction of the wind financing marketplace. Financial theory suggests that an efficient market will eliminate differences in net financing costs, returns, and LCOE acro ss different financing structures, once all risks and costs are taken into account. However, the U.S. wind sector has seen an expansion in the types of wind financing structures avai lable to project developers, as

iv This assumption is important: variations in other assumptions about the underlying template project – including turbine and balance-of-plant costs, capacity factors, and operating costs – will also impact the resulting LCOE.



### vi

### well as variations in the rela tive popularity across structures over time and among different developers and capital providers. These attributes suggest that inefficiencies and differing risk perceptions remain in fina ncing wind projects.

More broadly, this analysis highlights the fact th at developers decide wh ich financing structure best meets their needs for a given project based on multiple considerations. The decision reflects both the developer’s own relative ability to us e the Tax Benefits and to provide the capital funding, as well as the financial ro bustness of the project itself, e.g., whether debt leverage is needed to boost projected returns to satisfy return requirements. The amount of time before the next expiration date of the PTC has also played a role: pending PTC e xpiration dates led some developers earlier in the decade to adjust their financing strategies and shy away from debt so as to avoid transaction delays and increase the prospects of meeti ng in-service deadlines for the PTC. Secondary factors also influence the de cision, e.g., the relative pr eference for realizing value up-front via a development f ee or capital gain on the sale of the project, or over time from the net cash flows from operations. The relativ e importance of these various considerations, however, differs from developer to developer and from project to project. Furthermore, some developers’ preferred financing structures have evolved over ti me, especially as their own financial situations have changed. In short, there is no single “correct” structure for all developers for all proj ects for all time.

That said, the varying rationales for each financing structure can be illustrated by looking at the decision process faced by wind developers in c hoosing a financing structure. Table ES-3 provides a list of several key corporate and proj ect-level considerations. Depending on a given developer’s views on each consider ation, one or more financing stru ctures are likely to be more

suitable than other structures to meet the needs of the developer. Tabl e ES-3 lists several nonexhaustive scenarios with differing combinati ons of these developer considerations. The financing structure(s) most typically used for e ach scenario is identified in the final column.

Section 3.8 describes the s cenarios in more detail.

Table ES-3. Wind Developer Financing Structure Decision Matrix

Scenario Developer

can use Tax Benefits Developer
can fund project costs Developer wants

to retain stake in project ownership / ongoing cash flows Developer wants early

cash

distributions Project

has low projected

IRR Project already exists (refinancing / acquisition) Most suitable financing strategy or structure:

1 No No No Yes N/A No Sell project to a Strategic Investor

2 Yes Yes Yes No No No Corporate

3 No Limited Yes No No No Strategic Investor Flip

4 No Limited Yes Yes No No Institutional Investor Flip

5 No Limited Yes No Yes No Cash Leveraged or Cash & PTC Leveraged

6 No Limited Yes Yes No Yes Institutional Investor Flip

7 No Yes Yes Yes N/A Yes Pay-As-You-Go

8 No Limited Yes Yes Yes No Back Leveraged



### vii

### For example, a developer that cannot use a project ’s Tax Benefits, does not have the financial resources to carry the project th rough construction, and prefers an early return rather than an ongoing stake in the project will likely find it most convenient to sell the entire project to a Strategic Investor (Scenario 1). A second developer in a similar position but more interested in retaining a long-term stake in the project than in an early cash-out might instead pursue the Strategic Investor Flip structur e (Scenario 3) or, if the project returns look low, the Cash Leveraged or Cash & PTC Levera ged structures (Scenario 5). Which of these two leveraged structures is used will genera lly reflect project economics (i.e ., whether the incremental PTC monetization is needed to achieve requisite equity returns), as well as the relative interest of Tax Investors in taking on the incremental contingent fi nancial obligations associated with PTC debt. A developer lacking the ability to use the Tax Benefits, but w ith more cash to invest and interested in both a long-term stake and early cash returns, instead might opt for the Institutional Investor Flip or the Back Leveraged structur es (Scenarios 4 and 8), with Back Leverage employed to reduce the developer’s stake and/or to boost the devel oper’s return. Those developers that own existing projects but are seek ing Tax Investors to monetize the Tax Benefits might opt for the Institutional Investor Flip or Pay-As-You-Go structures (Scenarios 6 and 7), with the choice depending in part upon how quickly the developer wants to recoup its investment in the project. Finally, for a developer (or its corporate parent) willing to commit the cash

resources and able to use the Tax Benefits efficiently on its own, the Corporate structure (Scenario 2) may prove to be most advantageous.

This interplay of a variety of considerations , both monetary and qualitative, underscores the value of ongoing monitoring of wind project financ ing trends. Even in the short period since 1999, financing structures have ri sen and declined in their rela tive popularity among developers

and investors. The current divers ity of financing structures is in response to the evolving needs of developers and new investors in the wind sect or. Existing financing structures will continue to evolve, and new structures wi ll be developed to meet the emerging needs of the market. This ongoing evolution, combined with the prospect of external developments – e.g., Congressional changes to the structure or existe nce of the PTC – and the fact that choice of financing structure can, as demonstrated in this report, have a si gnificant impact on LCOE, suggests that it will be useful for the U.S. Department of Energy to st ay abreast of changes in the market and to periodically review the imp act of financing structures on the cost of wind energy.

viii

## 1. Introduction

After a long period of relative stag nation that began in the late 1980s and lasted throughout much of the 1990s, the U.S. wind power market has grow n rapidly in recent year s (Figure 1). From 1998 through 2006, almost 9,900 MW of new wind cap acity was added, accounting for 85% of the 11,575 MW cumulative total at the end of 2006. In 2006 alone, 2,454 MW of new wind capacity was installed, representing a 27% increase in cumulative capacity.

igure 1. Annual and Cumulative Grow th in U.S. Wind Power Capacity

he boom in this segment of the renewable energy market shows no signs of slowing in the near

he rapid expansion in U.S. wind power capacity in recent years has required the mobilization of 0 500 1,000 1,500 2,000 2,500 3,0001982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006Annual Capacity (MW)

0 2,000 4,000 6,000 8,000 10,000 12,000Cumulative Capacity (MW) Annual US Capacity (left scale)

Cumulative US Capacity (right scale)



### F

T term. AWEA’s August 2007 forecast projects r ecord growth of more than 3,000 MW of new wind capacity in 2007. 1 

### Furthermore, anecdotal evidence indicates that the major wind turbine manufacturers have sold much, if not all, of their production capacity through early 2009, suggesting that 2008 could be another record year for U.S. wind power installations.

T a tremendous amount of capital to finance pr oject costs. Roughly $18 billion (in real 2006 dollars) has been invested in new wind projects in the U.S. since the 1980s, with more than $3.7

billion invested in 2006 alone. 2 

### Looking ahead, wind project devel opers will need to raise close to $6 billion in 2007 in order to finance the expansion proj ected by AWEA, a nd the required amount of capital will likely continue to increase in future year s if market growth continues. Moreover, these figures do not include financing ra ised to support acquisitions or refinancings of existing wind turbine assets.

1 AWEA Quarterly Market Report dated August 8, 2007, available at http://www.awea.org/newsroom /releases/AWEA_Quarterly_Market_Report_080807.html

2 See Ryan Wiser and Mark Bolinger (2007), Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2006 , available at http://eetd.lbl.gov/ea/ems/reports/ann-rpt-wind-06.pdf



### 1

### Accessing sufficient am ounts of capital to finance the build-out of wind project pipelines has historically been a challenge for many wind developers, due in large part to the importance of Federal tax incentives to the project’s return. Specifically, qualifying commercial wind projects are eligible to receive a 10-year stream of Federal production tax credits (“PTCs”), and can also depreciate (for tax purposes) the vast majority of project assets using an accelerated 5-year schedule. These two major Federal tax incentives, described in more detail in Text Boxes 1 and 2, are collectively referred to in this report as the project’s “Tax Benefits.” As a general rule of thumb, investor returns from a wind project often derive as much or more from

these combined Tax Benefits than from cash revenue from the sale of power and renewable energy credits (“RECs”). 3



### Historically, most wi nd project developers

have been small si ngle-purpose entities

without a tax base of sufficient size to make

efficient use of the Tax Benefits generated by a wind project. As a result, for several years, one of the few options available to such developers was to develop a project up to the point of construction and then sell it to a larger entity wi th not only access to the capital required to build the project, but also a tax base large enough to efficiently us e the project’s Tax Benefits. Text Box 1. The Federal Production Tax Credit

As authorized by the Energy Policy Act of 1992 and amended over time, Section 45 of the Inte rnal Revenue Code provides a production tax credit for power generated by certain types of renewable energy projects, in cluding wind power. For wind power, the PTC provides an inflation-adjusted 1.5¢ per kilowatt hour (“kWh”) credit for a 10-year period. The credit amounts vary for other renewable power technologies. For 2007, the IRS announced the inflation-adjusted PTC rate at 2.0¢/kWh, or $20/MWh. To qualify to receive th e credit, a project must meet

several factors to dem onstrate that the turbines have been placed

in service. Certain limitations exist on use of the PTC in combination with other public sector incentives. There are also ongoing requirements, including that power from the project must be sold to an unrelated party.

Together with state-level renewa ble portfolio standards, the PTC has been a key driver of wind power development in the United States. The PTC enhances equity returns to owners of wind and other qualifying projects by providing an additional financial benefit not directly tied to power prices. In practice, however, competitive pressures have led de velopers to pass most of the benefits of the PTC though to utility customers by charging less for the project’s power output.

Since its original expiration in mid-1999, the PTC has subsequently expired and been extended several times. In recent years, the Energy Policy Act of 2005 modified the credit and extended it through December 31, 2007. In December 2006, the credit was extended for another year through December 31, 2008 by Section 207 of the Tax Relief and Health Care Act of 2006.



### More recently, as the market has grown and matured, multiple financing structures have been developed in order to attract various investors to projects, manage project risk, and allocate Tax

Benefits to entities that can use them most ef ficiently. These structures balance the varying needs for financial return, risk, and operati ng control presented by wind power project developers, tax-oriented investors, and, where utilize d, debt providers.

While these new financial structures have enable d more wind power project s to attract capital, the diversity in the purpose, framework, and econo mics of such financing structures has made comparing the cost of energy from wind projects more opaque. Traditional tools for assessing relative costs across projects include comparing the price per MWh of the electricity sold or the IRR of the investors in the projects. These new wind financing structures, however, feature varying allocations of investment obligations , risk, and cash and Tax Benefits, both among the owners and over time. As a consequence, the stru ctures effectively create different returns for

3 As wind project installed costs have increased in recent years, the return s coming from accelerated tax depreciation – which is tied to installed costs – have become a larger proportion of the overall Tax Benefits relative to the PTC benefits, which are tied to electricity outpu t and are independent of installed costs.



### 2

### the various investors. In turn, this creates uncertainty over what structure is being assumed in the presentation of any given return or cost of energy figure. The different risk and timing profiles for a project’s cash return s and Tax Benefits further complicates these assessments.

The purpose of this report is three-fold: (1) to survey recent trends in the financing of utility-scale wind projects in the United States, (2) to describe in some detail the seven principal financing structures through which most utility-scale wind projects (excluding ut ility-owned projects)

have been financed from 1999 to the present, and (3) to help understand the potential impact of these seven structures on the effective cost of energy from wind

power. 4 

### The year 1999 is used as a starting point because it marks the advent of the recent expansion in wind power growth in the U.S. (see Figure 1).

The remainder of this report is organized as follows. Chapter 2 provides a historical overview of the recent evolution of wind project financing in the U.S., providing a broader context for the financing structures examined in this report. Chapter 3 describes the seven structures principally used in the market. The chapter reviews the impetus for and application of each st ructure, and presents a schematic diagram of

the mechanics of each structure and of the flow of key benefits streams. Chapter 4 introduces an Excel-based pro forma financial model (described in more detail in Appendix B), and presents the results of using the model to compare the levelized cost of energy under each structure. Chapter 5 concludes the report with some broader assessments of the financial model review and

of current trends in the deve lopment of wind power projects th at may affect how future wind projects are financed. Text Box 2. Accelerated Depreciation

Section 168 of the Internal Revenue Code provides a Modified Accelerated Cost Recovery System (“MACRS”) through which certain investments in wind (and other types of) projects can be recovered through accelerated income tax deductions for depreciation. Under this provisi on, which has no expiration date, certain wind project equipment – including the turbines, generators, power conditioning e quipment, transfer equipment, and related parts up to the electrical transmission stage – may qualify for 5-year, 200 percent (i.e., double) declining-balance depreciation. A typical rule of thumb is that 90% - 95% of the total costs of a wind project qualify for 5-year MACRS depreciation, with much of th e remaining amount depreciated over 15 years.

Along with the PTC, this Federal depreciation incentive enhances equity returns to owners of wind and other qualifying projects by providing an additional financial benefit. This value – equal to

between one-third and one-half the amount of revenue that can be earned through a long-term power purchase agreement – enables wind developers to charge less for power, while still generating competitive returns for equity investors.

Depreciation deductions in excess of net income generated by a project can be carried forward to future years under certain circumstances. However, due to the time value of money and the fact that a significant share of overall project returns come from accelerated tax depreciation and PTCs, it is important for an investor to be able to utilize such Tax Benefits in the years in which they are generated.



### Before proceeding, three not es on the scope of this work merit mention:

1) This report is focused on the financing of larg e utility-scale wind proj ects designed to sell electricity directly to utilities or into power markets on a whol esale basis. As such, it does

not review how investor-owned or publicly-owned utilities finance their own wind projects, where the project becomes part of the utilities’ internal generating portfolio and rate base.

4 This report is intended – in part – to assist policy makers in the U.S. Department of Energy (“DOE”) in understanding how financi ng structures used in the wind power marketplace a ffect the cost of wind energy. It is not intended to replace the DOE’s ongoing in ternal evaluations of the cost of energy from vari ous electric power generation technologies, though the authors hope that this report will help to inform that work.



### 3

### 2) This report also does not cover financing stru ctures used for smaller community-based wind power projects, or for distributed generati on or behind-the-meter wind power projects. Several reports have been rel eased that profile the financin g options – which are typically simpler than those presented here – available to these smaller projects. 5 

### Still, this report may have some indirect utility for parties c onsidering such projects, as several financing options used for smaller projects are derived from structures first conceived for larger projects.

3) Finally, this report is relevant only to the U. S. market, since the pres ence and structure of the Tax Benefits have driven the development of financing structures in ways not applicable

to other national markets.

5 For example, see http://www.energytrust.org/RR/wind/OR_Community_Wind_Report.pdf and http://www.elpc.org/docum ents/WindHandbook2004.pdf



### 4

## 2. A Recent History of Modern Wind Project Finance

The financing of utility-scale wind power projects in the United States has evolved significantly in the last ten years, reflectin g a widening and deepen ing of the capital markets for wind power. Prior to roughly 1999, the financing community ge nerally perceived the wi nd market as exotic, i.e., complex, small, and risky. Earlier difficul ties and financial losses experienced by projects

and manufacturers had soured the market for se veral years. Few financial institutions were interested in the sector. There were relatively few financing transactions, the structures were simple, and debt and equity terms were expensive. In contrast, the market now features multiple new equity and debt sources, offers developers and capital providers a variety of tested financing structures from the simple to the highly comple x, includes more and larger transactions, and has

recorded a marked reduction in th e cost of equity and (to a lesse r extent) debt. Overall, these changes mark the transition of the wind industry from one perceived to be essentially a niche sector by the capital markets to a substantive, in creasingly mature, market. These changes have reinforced the growth of the U.S. wind market and are likely to endure, absent unforeseen technical problems or broader financial market changes.

There have been three principal de velopments in financing trends a nd structures in the U.S. wind market since the burst of wind project de velopment in the 1998/1999 time period. These developments, along with variations on these them es, have fostered the creation of the multiple financing structures profiled in th is report. Two concer n the equity side: (i) the entrance of large companies with strong balance sh eets interested in actively developing and owning wind power projects (“Strategic Investors”) a nd, (ii) the entry of large, but mo re-passive investors principally interested in investing in wind projects for the Tax Benefits (“Institutional Investors”). 6 

### The third development has been the entry of multip le European commercial banks to compete for wind project debt financing opportuniti es in the United States market.

While these developments cannot be tied to a part icular moment in time, two distinct phases in wind project financing practices from 1998 to the present can be described. The first phase was from 1998 through 2002, when Strategic Investors dominated the market. The year 2003 was somewhat of a transition year, while 2004 th rough 2006 saw the second and third developments described above – i.e., the entry of Institutional Investors and the expansion of debt offerings –

come into full force.

This chapter describes the evolution of modern wind project financing with in these two distinct periods, followed by more detailed observations on specific developments within the equity and debt markets. The purpose is to provide the context required to bett er understand the seven specific financing structures desc ribed in detail in Chapter 3.

6 Typically (but not always), both Institutional and Strategic Investors can use the Tax Benefits. The primary differences between the two groups of investors concern thei r relative level of control and participation in project management and the integration of the wind project investments with their main business activities.



### 5

## 2.1 1998-2002: Strategic Inve stors Dominate the Market

The 1998/1999 time period marked the beginning of th e current era of substantial new growth in U.S. wind power capacity (see Figure 1). Fo r the ten years prior to 1998, annual capacity additions had been modest, averaging around 40 MW per year. Driven in part by the thenscheduled expiration of the PTC on June 30, 1999, however, the wind sector added more than 800 MW of new capacity in 1998 and 1999. Half of this increase was concentrated in the four Lake Benton and Storm Lake pr ojects in Minnesota and Iowa, re spectively. All were developed by a single independent developer (Enron Wind). Averaging 100 MW each, these transactions were among the largest in the world at the time. The remaining capacity additions in that period were through much smaller projects. Utilities su ch as PacifiCorp, Public Service Company of Colorado, Platte River Power Authority, and Madis on Gas & Electric installe d projects for their own account. A few private inde pendent developers (“developers” or “sponsors”) and utility subsidiaries developed the remaining utility-sca le projects. Little capacity came on line after

June 30 th 

### , 1999 through the end of 2000, as the Congre ss did not renew the PTC until late in 1999, and developers needed time to develop a new round of projects.

The financing structures for mo st wind projects during this pe riod were not complex. Although the PTC was available to projects coming on line prior to June 30, 1999, mo st developers lacked the financial strength to fund a proj ect or to make efficient use of the Tax Benefits. As a result, their main financing option was simply to sell th e project to those few unregulated subsidiaries of electric power utilities that were entering the wind market during this time as Strategic Investors – i.e., investors with e xperience in the power sector who in tended to take an active, if not controlling, management role in wind project s. Although only a handful of such entities were in the market during this period, e.g., FPL Energy, Edison Mission Energy, and Cinergy, the equity market was dominated primarily by thes e Strategic Investors, w ho used their internal financial resources to fund the equity share of cap ital costs (and all of the costs if no project-level debt was used). Institutional Investors – i.e., th ose entities interested in passively investing in wind projects primarily for the Ta x Benefits – had not yet entere d the market to any significant degree. Indeed, GE Capital was the only major Institutional Investor in the market during this period.

While a few projects used debt financing to fund a portion of the capital costs, there were only a small number of debt providers interested in th e sector. One institution, Fortis Capital, drew upon its success in financing European wind project s to dominate wind sect or debt financing in the United States. Plain-vanilla, uncomplicate d, construction and senior term debt financing were the principal offerings. A few deals includ ed PTC loan monetizations. This new type of debt allowed a project to borrow against PTCs generated by the project. Such monetizations require the owner receiving the PTCs to commit to make periodic equity contributions for the term of the PTC loan, if needed to support the related debt serv ice obligations. While PTC loan

monetizations can be at tractive in boosting the amount of debt that a project can support, the number of PTC loan monetizations completed in this period was limited by the few developers and Strategic Investors with the requisite financ ial strength and willingness to provide the related

6

### guarantees. 7 

### Overall, much of the new capacity a dded from 1998-2000 was financed on balance sheet, with no project debt (i.e., using the Corpor ate structure described later in Section 3.1).

New capacity additions surged in 2001, as develope rs raced again to complete projects prior to the new December 31, 2001 expiration date of the PTC. A major equity-related development occurred in this year. Shell, a multi-nationa l petroleum company, entered the U.S. wind market as a Strategic Investor. A few el ectric utilities also made their firs t acquisitions of wind projects as investors (rather than for internal genera tion purposes). These included American Electric Power and Entergy. Equity financing structures did not change significan tly, however. In each case, these new investors typi cally acquired wind projects de veloped initially by smaller, independent developers unable to utilize the Tax Benefits. In most cases, the larger Strategic Investor acquired the projects outright. Joint venture collabo rations involving two larger companies were used for some projects, but this st ructure was the exception rather than the rule. Also in 2001, bond market financing was used for th e first time to finance a large wind project. A group of public utility districts in Washingt on State sourced $70 million in non-recourse taxexempt bond financing to pay for the costs of the Nine Canyon wind project. 8 

### The bond was notable in that the procee ds directly financed construction cost s, rather than being merely a takeout of other construction debt.

There was little new project activ ity in 2002, as the PTC was not av ailable for part of the year and the electric sector grappled with problems of overcapacity and financial strains from the previous excess in thermal capacity, as well as disenchantment with power sector financings related to the Enron collapse. Several utility-bas ed Strategic Investors and some early European lenders withdrew from the market in reaction to these financial strains. These power sector issues, the uncertain prospects for extension of the PTC, and the perceived complexity of wind projects relative to other tax credit investme nt opportunities (e.g., tax credits supporting affordable housing) all restrained intere st by potential Institutional Investors.



## 2.2 2003-2006: Rise of the Institutional Investor

The burst of new capacity additions in 2003 fostered paradigm shifts in the debt and equity markets for wind projects. New projects grew in average size, requiring mo re capital. Several new, independent developers ente red the sector around th is time. With littl e or no ability to make efficient use of the Tax Benefits, some of these developers nonethel ess sought structures that allowed them to finance their projects in a tax-efficient manner, while retaining an ownership stake. With many of the earlier util ity-based Strategic Inve stors still financially constrained due to the difficulties in the merchant power sector, developers of larger projects sought tax-oriented Instituti onal Investor capital.

Three developments assisted in this effort. First, from September 11, 2001 through the end of 2004, the Federal Government offered a temporar y bonus depreciation option for certain assets, including wind projects, first placed in service during that period. This incentive was put in place to boost economic growth af ter the 9/11 terrorist attacks. By boosting the n ear-term return to investors, this incentive enhanced the attract iveness of wind and other capital investments.

7 Section 3.6 provides more background on the PTC loan monetization concept.

8 See the Energy Northwest Nine Canyon project: www.energy-northwest.com/generation/nine_canyon.php



### 7

### Second, private letter rulings issued by the Intern al Revenue Service (“IRS”), while officially only pertinent to specific transactions and not intended to set precedents, nevertheless also helped to resolve investor questions regarding ambiguities in the interaction of the PTC with state incentives, as well as the viability of some of the tax-oriented financing structures being implemented. Finally, financial intermediary firms such as Babcock & Brown and Meridian Investments, with experience in mobilizing tax-orie nted equity, entered the wind sector to assist in sourcing capital for new projects. As a re sult of this confluence of events, 2003 and 2004 saw the closing of the first large transactions involving simple pa rtnership flip structures.

Institutional Investors remained fe w in number, however. Most proj ects in these years were still financed using the simplest equity structures, i.e. , via internal corporate funds, or by sale of the project outright to a larg er Strategic Investor.

Debt-financing structures also deepened and matured beginning in 2003. The entry of additional commercial banks at both the arranging and participant levels facilitated new transactions and loan facilities, and pushed interest rate margins lo wer. Lenders began to offer bridge financing, such as turbine supply loans and construction loans, as means to compete for term-lending opportunities. Debt arrangers devised different loan facilities to enable single projects to attract capital from both commercial banks and instit utional lenders (e.g., insurance companies).

The year 2003 also saw the first debt financing of a portfolio of new wind projects. In this type of structure a holding company houses the interests in se veral wind projects, a nd the financing is obtained at the holding company level (rather than for each project indi vidually). Portfolio financings can offer developers several benefits. These include potential transaction cost savings by negotiating a single set of financing documenta tion, more favorable financing terms due to perceived lower aggregate risks of the portfolio, and the enabli ng of financing of projects otherwise too small or risky to at tract financing on their own.

In addition, a transaction in 2003 combined two different fina ncing sources for the first time: PTC debt financing and Institutiona l Investor equity capital. The transaction required the three parties contributing funds to the project – the developer, the Inst itutional Investor, and the lender – to identify and allocate project risks. In part icular, the lender and the Tax Investor had to craft their respective rights and risks w ith respect to the PTC debt financing. Previous transactions had involved simpler, bilateral negotiations betw een just two entities, e .g., between a buyer and a seller of a project, or between an owner and a lender.

Since 2003, these financing trends have continue d, stimulated by the broader expansion of the overall wind sector and the focus of project de velopers on developing larger and more-costly projects. While a 100 MW wind project was stunning in 1998/99 and still unusual in 2003, such projects were commonplace by 2006. The evoluti on towards larger projects reflects multiple factors, including economies of scale in develo pment costs and an up-scaling of turbine size. 9


### Most importantly, the effort, cost, and time to deve lop wind projects do not increase in step with project size; thus, developers ha ve been able to reduce costs on a per-MW basis by focusing on

9 According to Wiser and Bolinger (2007), the average tu rbine size installed in 2006 was 1.6 MW (with turbines exceeding 2 MW used for many projects), which is more th an double the 0.7 MW averag e turbine size installed in

1998/99.



### 8

### larger projects. For their part, Tax Investors also have been ab le to achieve economies of scale in financing by deploying larger blocks of capital in single transactions.

Increased project development activ ity has put upward pressure on tu rbine prices in the last few years. The demand for turbines both nationally and globally has led to a scarcity of supply. At the same time, the cost of building a turbine has increased due to hi gher global prices for manufacturing inputs such as steel . In response, turbine manufact urers have raised prices and required developers to make ear ly turbine commitments and cas h down-payments in order to

secure access to turbines. In addition to turbin e price increases, interconnection costs have risen for projects being sited further away from transm ission lines. All of thes e factors have raised wind project financing requirements substantia lly since 1999. AWEA estimated that the 663 MW of capacity installed in 1999 represented so me $700 million in investment, resulting in an average cost of $1,056 pe r kilowatt of capacity. 10 

### By contrast, AWEA estimated that $4 billion in investment capital was mobilized to fina nce the 2,454 MW installed in 2006, yielding an average cost of $1,630 per kilowatt of capacity. 11 

### Anecdotal information suggests that installed costs for some projects in 2007 and 2008 could r each or exceed $2,000 per kilowatt of capacity.



## 2.3 Recent Equity Financing Developments

Wind developers have responded to this increased development pace and associated increase in capital requirements in various ways. Changes ha ve taken place both at the project level and at the corporate level. Most directly, fewer devel opers have the internal capital to cover their project capital expenses. Instead, more third-party equity is being tapped, and at earlier points in the development life-cycle, to finance projects than in earlier years. Separately, companies seeking to enter the wind sector in the U.S. are using their financial strength either to offer development financing directly to smalle r developers or to buy them outright.

A key method for financing new construction has c ontinued to be the singl e-entity, all-equity financing structure, referred to herein as the “Corporate” structure. This reflects both a continuing pattern and two newer trends. The largest investor in the U.S. wind market, FPL Energy, continues to finance the in itial construction costs of its projects using internal funds. 12 

### At the same time, several other large developers that have entered the market in the last few years also have used internal funds to cover at least the initial capital co sts of their projects. These large developers include foreign companie s, e.g., BP, Iberdrola, Acciona, and Enel, as well as domestic entities such as PPM Energy a nd Horizon Wind Energy. The ability to finance new construction without having to tap third-part y capital has emerged as a useful competitive advantage by reducing transaction costs and time to operation.

The continued use of this form of financi ng structure has been accentuated by the marked consolidation in the industry since 2002. Large entities, including especi ally foreign entities,

10 See www.awea.org/news/news000430w2k.html

11 See www.awea.org/newsroom/releases/W ind_Power_Capacity_012307.html

12 In the last few years, FPL Energy has closed several pr ivately-placed long-term debt re financings of portfolios of its existing and new projects. The refinancings appear princi pally to be limited-recourse in nature, but include credit support from FPL Energy on certain as pects. In August, the company was re ported as considering a tax equity monetization for five projects, including one under construction.



### 9

### have forged alliances with, or acquired outright, several smaller de velopers as a way of obtaining a pipeline of project investment opportunities. Previously, these smaller developers had either sold their projects outright to Strategic Investors, or partnere d with Tax Investors. This consolidation trend has accelerated in the last few y ears: at least thirteen mergers or acquisitions totaling 35,000 MW of wind projec t pipeline were announced in 2006, compared to nine such transactions totaling 12,000 MW in 2005 and just four transactions totaling 4,000 MW from 2002 through 2004. 13 

### In July 2007, Goldman Sachs sold its 100% share interests in Horizon Wind Energy to EDP-Energias de Portugal SA, the largest utility in Portugal, in a transaction valued at $2.7 billion. 14 

### One of the largest wind developers in the U.S., Horizon expects to have over 1,500 MW gross installed wind capacity by the end of 2007.

Separately, some investor-owned utilities such as MidAmerican Energy and Puget Sound Energy have become interested in directly owning wind power generation capac ity, and have acquired several projects from developers. Their motives vary, but include an ability to use the Tax Benefits, and a willingne ss to use their own internal corporate funds to finance capital costs. In addition, some utilities are seeking outright proj ect ownership in part because their state regulators allow them to earn a re turn on the investments. Anothe r incentive is a desire to avoid potential complications with rati ng agencies wanting to reflect cr edit risks of buying power from unrated project entities by establishing a de bt equivalency value for power purchases.

At the same time, Institutional Investor capital sources have increasingly been asked to finance new construction. In 2006, thir teen companies developed 99% of the 2,454 MW of new wind projects. 15 

### Of these thirteen companies, only five had the tax appetite to retain ownership of their projects; 16 

### the remaining eight partnered with Tax Investors to make efficient use of the projects’ Tax Benefits. JPMorgan Capital Corpor ation, a leading Institut ional Investor in wind projects, estimates that thir d-party Tax Investor financing was tapped for 1,291 MW of new construction in 13 transactions from 2003 through 2005. 17 

### By contrast, the firm has estimated that 15 tax equity transactions were closed in 2006 alone, with an aggr egate value of about $3.1

billion. 18



### Along with deal flow, the number and capacity of Institutional Investors also have expanded since 2003. Whereas there were only three prominen t Institutional Investors in 2003, tax equity

transactions in 2006 involved 13 participants. Moreover, more participants are showing a willingness and capacity to structure and lead a tr ansaction. Of the thirteen participants, six

firms acted as lead investor in transactions, up from only one or tw o just three years earlier.

The increases in the number and quality of Institutional Investors reflect several factors either specific to the wind sector or broader in nature . Wind sector-specific factors include greater familiarity with wind technology, the implicit comf ort of seeing major multinational corporations

13 Wiser and Bolinger (2007), op. cit.

14 See: http://www.edp.pt/EDPI/Internet/EN/Group/Investors/News/2007/Com02072007.htm

. 15 These figures focus on the project owner at the point at which projects are financed and built; they do not reflect sales by smaller developers to the final owners that may have occurred at earlier stages of project development.

16 See “The Tax Equity Market” in Chadbourne & Parke, LLP’s April 2007 Project Finance Newswire , available online at http://www.chadbourne.com.

17 JPMorgan Capital Corporation presentation, AWEA Wind Power Finance & Investment Workshop, April 2006.

18 See Chadbourne & Parke, LLP, op. cit.



### 10

### such as GE, Siemens, and Goldman Sachs assume leading roles in manufacturing and/or project development, the creation of more tools for analyzing wind resour ce risk, and a standardization of financing structures. Broader market factors in the rise of Institutio nal Investors include an increasing comfort that Federal and state tax and other incentives for renewable power will remain in place or be expanded, Congressional acti on in 2003 that granted i nvestors the ability to use the PTC against alternative minimum tax oblig ations during the first four years of a wind project, and declining attractiv eness of alternate ta x-oriented investme nt opportunities for Institutional Investors (e.g., in the low-income housing sector).

Such broadening of the investor pool has added to the competitiveness of th e market for capital. Developers have been able to secure equity financ ing from Tax Investors at steadily lower rates. At the AWEA wind power conference in May 2003, Meridian Investments estimated that

Institutional Investor returns woul d need to be in the range of 12-13% in order to attract capital for wind projects. Currently, the requisite ten- year equity hurdle rates for high-quality, wellstructured transactions has declined to less than 7% for all-equity deal s and less than 10% for leveraged deals. 19 

### This decline is not likely to be reversed, absent the emergence of a previously-unforeseen material technical issue with wind technology, a major project default with implications for other proj ects, broader capital market changes, or the like. At the same time, further material declines may be limited as project returns approach rates of alternate investments such as low-income housing a nd even risk-free Treas ury securities.



## 2.4 Recent Debt Financing Developments

Debt has remained mostly a sec ondary consideration in the financ ing activity of recent years. When developers have sought third-party capital, securing a Tax Investor typically has been the primary, if not only, goal. While there have been a few debt-leveraged projects each year, these transactions have represented the minority of the financings.

Several factors account for this. A key factor has been the reluctance of leading Institutional Investors to invest in projects that include limited-recourse debt at the project level. Specifically, they have been uneasy with the allocation of ca sh flow and control betw een project lenders and

the Institutional Investors in loan default situatio ns. The concern is the po tential risk of their upfront equity investment being squ eezed out by lenders seeking to rec over the value of their loans. Additionally, some Institu tional Investors fear that the increased transaction costs associated with debt may erode much of the value associated with leverage. There is also a timing issue associated with debt. Debt leverage not only co sts more up-front, it also takes more time to close the financing transaction. The repeated expirati ons in the PTC, and short-term renewals of several of the PTC extensions, have given a comp etitive advantage to developers not needing to obtain debt financing as a condition of comm encing construction.

With term debt not in high demand, the debt market has expanded principally in the type s of loan financing made available to proj ect developers. Several devel opers, for example, have accessed shorter-term turbine supply loans, construction financing, and letter of cred it support from

19 See Chadbourne & Parke, LLP, op.cit.



### 11

### several commercial banks in support of their new wind projects. 20 

### Additionally, lenders committed to limited-recourse financing for se veral transactions in 2006 using the Back Leveraged structure. The Back Leveraged fina ncing structure – with debt incurred by the developer, rather than at the project level (des cribed in more detail later in Section 3.7) – balances developer interest in using leverage with reticence by Institutional Investors in seeing debt at the project level. The Back Leveraged structure does not affect project-level returns or risks, since the debt only finan ces a portion of the developer’s e quity contribution to the project company. These debt facilities principally assist the developer by stretchi ng its capital, thereby enhancing its ability to expand ope rations. Developers and investors are also beginning to tap debt financing to refinance existing projects. FPL Energy has issued private limited-recourse

secured bonds and notes for two portfolios of existing projects. 21



### While term debt financing has not been the prim ary financing tool, the nu mber of institutions providing debt financing of all type s, as well as the average size of loan transactions, has risen in recent years. Eleven financial institutions acted as lead arranging lender fo r debt transactions in

the wind sector that closed in 2006. This wa s up from earlier years when only two or three lenders were willing and able to assume such lead-arranging functions. Transaction loan commitment amounts in 2006 routinely were in the hundreds of millions of dollars; one developer secured $1 billion in co nstruction loan facilities to s upport a portfolio of projects. Anecdotal information by loan arrangers at indus try conferences indicate that the number of banks participating in loan syndica tions and average loan participa tion levels have both risen as well since 1998/1999. Overall, the expanding pool of debt arrangers competing to arrange debt financing for projects suggests a continuation of current trends. Banks are competing to provide debt capital at competitive rate s and are innovating in terms and st ructures in order to win such competitions.

European commercial banks have dominated lending activity in the U.S. wind sector. One bank, Fortis, virtually originated the term cash flow a nd PTC monetization debt fi nancing structures in the U.S. market during the 1998-2001 time period. Since then, the informal mantle of mostactive lead arranger has always b een held by one or another Eur opean bank such as Dexia Crédit

Local or HSH Nordbank. Of the eleven institu tions that led one or more debt financing syndications in 2006, only three were U.S. financia l institutions, and one of those three only acted as a lead arranger for a transaction develo ped by an affiliate. A few insurance companies also have provided institutional debt financing, but the majority of project leve rage has come

from commercial banks.

Relative to the dramatic decrease in equity return s, debt terms have not changed as significantly. The typical loan term (or duration) remains a fu nction of the length of the underlying power and REC purchase agreements. For projects with lo ng-term power purchase ag reements (e.g., twenty years) with creditworthy utility buyers, commercial bank lenders are willing to extend loans with

20 Jeff Chester presentation (“Wind Power Ma rket Overview 2006 ”) at Infocast’s Wind Power Finance & Investment

Summit 2007 , La Jolla, CA, February 7-9, 2007.

21 http://www.fplenergy.com/news/contents/05020.shtml

, http://findarticles.com/p/articles/ mi_m0EIN/is_2005_Feb_9/ai_n9509206 . Also, see Form 8-K filing by FPL Group, Inc. to the U.S. Securities & Exchange Commission, June 26, 2006, http://www.psc.state.fl.us/library /filings/06/05916-06/05916-06.pdf

.



### 12

### a term of up to fifteen years. Institutional le nders, e.g., insurance companies, have been willing to go as long as nineteen years for comparable transactions. For projec ts involving shorter term power purchase agreements (“PPAs”) or utilizing power marketing contracts in lieu of power purchase agreements, loan terms are shorter an d/or involve mandatory prepayments using any

excess cash flow.

The standard debt service coverage ratio (“DSCR”) 22 

### has widened slightly from 1.40:1 in 1998/99 to 1.45:1 more recently. The increased DSCR reduces default risk by lowering the borrowing capacity of the project. Anecdotal info rmation suggests that co mmercial bank interest rate margins over their cost of funds have dec lined by approximately 50 ba sis points (0.5%) from 2003 through 2006. Commercial banks currently quote interest rate spreads for high-quality projects of 110-125 basis points over the London InterBank Offer Rate (“LIBOR”) in the early years of a loan. Some lenders raise these margin s gradually in later years, e.g., up to 200 basis points over LIBOR for the final y ears of a fifteen-year loan. Institutional lenders such as insurance companies sometimes quote spreads over U.S. Treasuries, but most debt discussions

are LIBOR-based.



## 2.5 Summary

The increased depth and richness of equity and debt financing capacity available to the wind sector is likely to continue. Br oadly stated, equity and debt capita l now is more readily available than the supply of new high-quality wind projects able to utilize such capital. In contrast with market conditions of barely a decade earlier, capit al is now chasing projects. This upheaval has fostered the development of the va rious financing structures profiled in the next chapter. To the

extent that this situation endur es, capital providers will continue to innovate financing terms and financing structures as means to se cure new financing opportunities.

22 Calculation of the DSCR may vary across projects, but as a general rule it is operating cash divided by total debt service (i.e., principal and interest).



### 13

## 3. Description of Curr ent Financing Structures

Financing structures currently used in the U.S. wind sector can be distinguished by five principal

characteristics. 23 

### These include the following:

• Tax Appetite : ability of the project developer to make efficient use of the Tax Benefits.

• Capital Strength : ability of the project developer to fund the in itial construc tion costs.

• Leverage : whether project-oriented limited-reco urse debt financing is utilized.

• Timing of Funds : whether equity funds provided under the structure are provided by a

Tax Investor at the outset or on an instal lment (i.e., “pay-as-you-go”) basis tied to generation of PTCs by a project.

• Management : the division of management respons ibilities among the se veral investors.

These principal characteristics or considerations manifest themselves in various combinations among different wind projects, which give rise to a variety of financing structures.

In the United States, most new utility-scale wind projects constructed since 1998 (and not directly owned by a local electric ut ility) have used one of seven st ructures to finance the capital costs. This chapter describes each of these structures in detail. The simplest structure is a single investor, all-equity approach dubbe d the Corporate structure. Thr ee other all-equity structures – the Strategic Investor Flip, the Institutional Investor Flip, and Pay-As-You-Go – are more complex, in that they make use of equity from bo th the developer and one or more Tax Investors. The final three structures – Cash Leveraged, Cash & PTC Leveraged, and Back Leveraged – build upon previous structures by introducing debt financing at e ither the project or developer

level. 24 

### In addition to describing each of these stru ctures both textually and schematically, this chapter discusses each structure’s rationale for us e, the types of investors that find it appealing (and why), and its relative frequency of use in the market. The chapter concludes with a generalized summary of how a developer might choose one structure over another.

The financing structures identified in this report are not intended as a comprehensive list. Various permutations of these structures, 25 

### as well as other financing mechanisms altogether, 26


### are possible. That said, the initial construc tion costs of most new utility-scale wind projects in

the United States from 1999 to th e present have been financed using one or another of these

structures.

23 Adapted from a Milbank, Tweed, Hadley & McCloy LLP presentation, AWEA Wind Power Finance & Investment Workshop, September 2004.

24 It is worth noting that some of these structures have been called various names in the industry. The names given in this report are intended to reflect a defining characteristic. For three of th e four all-equity structures, it is the nature of the Tax Investor (i.e., Corporate, Strategic, In stitutional). The Pay-As-You-Go structure name reflects the delayed timing of the Tax Investor contribution. For the three structures involving leverage, the name refers to the type of debt financing provided. Other names are feasible and in use; care should therefore be taken to specify structures other than solely by name.

25 For example, developers continually explore different wa ys of using debt financing. Also, some developers initially finance a project using one structure, then refinance it via another structure at a later date.

26 For example, given the report’s focus on project-level financing structures, financings by companies tapping external debt financing at the corporate level or portfolio financing structures are beyond the scope of this report.



### 14

### Before proceeding, it should be noted that the desc riptions and re views of the various financing structures presented here do not include formal legal analys es of their ta x and accounting implications. The authors are not attorneys or accountants, and the info rmation presented here should not be considered as formal legal or accounting advice. Instead, the information presented here is at a general le vel and is not specific to a particular project or investment. Though the report identifies certain important aspects re lating to partnership issues associated with the financing structures described here, project develope rs, investors, and others are strongly encouraged to seek ta x and accounting counsel prior to undertaking a particular project

or investment.



## 3.1 Corporate Structure

Description

The Corporate structure is characterized by a single developer/investor with the financial strength to fund all of the projec t costs and sufficient tax appetite to use all of the project’s Tax Benefits. The Corporate parent developer/invest or typically establishes a special purpose entity to house the assets of the project. This structure, which continue s to be one of the most widely used in the wind sector, represents the simplest way to own and operate a project. All of the initial capital costs are funded by the parent comp any using internally generated funds from other operations, and all of the project’s net cash flows and Tax Benef its flow back to the parent. The parent provides the funds in the form of equity to the project company. No additional investors

or limited-recourse debt financi ng are involved (at least initially) at the project leve l. The parent exercises full management control over the proj ect (although it is not uncommon even for this type of developer/investor to engage an outside firm to perf orm day-to-day operational and maintenance duties).

Figure 2 provides a schematic representation of the Corporate structure. Entities are identified by bold print. Shaded boxes represent the three types of financial benefits accruing from the wind project: distributable cas h, taxable losses/gains, and PT Cs. The underlying boxes with percentages show how the respectiv e financial benefit is allocated to the investors (in this case, there is only one developer/investor). The project company generates both cash revenue and

PTCs from the sale of electric power. It may also generate cash revenues from REC sales, though this analysis assumes that the PPA price includes the purchase of both the electricity and any RECs. Operating expenses are deducted from revenues to generate cash available for distribution. Non-cash tax-deductible expenses (p rincipally depreciation in this structure, though

interest on debt also falls into this category) generate taxable losses. In this structure, there is just one investor. Accordingly, the schematic shows the Corporate parent funding 100% of the costs of the project as equity in the project company. In turn, 100% of each of the distributable cash, taxable losses & gains, and PTCs fl ows back to the Corporate parent.

15

### Corporate Parent (100% of equity)

Project Company (100% equity)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses less Tax-Deductible Expenses (including MACRS)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 100% Æ

100% Æ Å 100%



### Figure 2. Schematic of Corporate Structure

Rationale for Use

The advantage of this structure relative to othe r structures is its simplicity. Funding, accounting, and management issues are not complicated by the need to inform or seek approval from lenders

or other investors. All of the financial and other benefits of ownership flow to the single owner.

This structure is the most time-efficient and in curs the least amount of out-of-pocket transaction costs. In the wind sector, these aspects have b ecome key ways in which large developers have secured several competitive advantages. The repeated expirations and extensions of the PTC earlier in the decade forced developers to focu s their efforts on project s most likely to be completed prior to the next expiration date, as they had no guarantees that the PTC would be

renewed. Without the need to identify and negotiate for third-party capital, such companies enjoy more flexibility and time to fini sh development of their projects.

Earlier in the decade, some corporate investors le veraged their financial st rength still further. The ability to internally develop and finance entire projects provides a significant negotiating advantage when acquiring projects from smaller de velopers lacking the internal wherewithal or

16

### time to mobilize the capital to finish projects pr ior to the next PTC expi ration date. Under time pressure from the pending PTC expiration date, and not wanting to face the risk that the PTC will not be renewed, some smaller deve lopers opted to accept a discounted price for sel ling the rights to their projects. This type of market pow er was more pronounced in the 1998-2003 time period when there were few such buyers and the PTC lapsed three times (before subsequently being extended retroactively in each instance). This market dynamic is less apparent in recent years, as

more investors have entered the market and conf idence has grown that the PTC will be extended.

Other Strategic Investors have us ed their financial strength to fa shion on-going relationships with smaller developers as a means of securing a pipe line of future investment opportunities, rather than acquiring potential projects one at a time. The larger company will offer to provide financial support to the smaller de veloper to finish the developmen t of one or more projects in exchange for a first right of refusal to acquire or invest in the projects. The multiple outright acquisitions in the last few years of smalle r development companies by larger companies entering the sector are further examples of the use of financial strength to competitive advantage.

Lastly, the larger, financially st rong developers have placed down -payments to acquire rights for

deliveries of wind turbines from turbine manufacture rs. With a scarcity of wind turbines in the marketplace, the advance payments to secure de liveries prior to the next PTC expiration date have been another means by which larger developers have used th eir financial strength to enable their projects to be completed on schedule. In some cases, large turbine orders have enabled developers to acquire turbines at lower cost s than competitors, which has provided a further competitive advantage in competing for utility purchase contracts.

Investor Type

The companies using this structure most comm only are large, financially strong, and have significant and predictably recurr ing income tax obligations. They have the cash flow to undertake the full investment and the ability to util ize the Tax Benefits in the years in which they are generated by the project. Companies using th e Corporate structure typically have strategic reasons to be investing in the wi nd sector. They view it as a co re part of their business plan, rather than simply a convenient means to reduce tax obligations. In eff ect, they are Strategic Investors that prefer to maintain full ownership without any other investors. FPL Energy is the most prominent example, as it has used this struct ure to finance the initial costs of most of its wind projects. 27



### Use of the Corporate financing st ructure often reflects a broader, corporate-wide decision to fund all corporate investments at the pa rent level, rather than individually at a project level. This financing strategy reduces financing costs, e.g., rate s and transaction costs, to the lowest levels available to the Corporate parent investor, since the risk s of any single inve stment, be it in a wind project or other uses of corporate cash flow , are aggregated with all other company-wide investments and are supported by the company’s a ggregate cash flow from current and future operations. Electric utilitie s and petroleum companies historica lly have taken th is approach for

27 Section 2.4 notes FPL Energy’s use of debt financing and portfolio financings to refinance portfolios of existing and planned projects and reported current consideration of tax-equity financing for a portfolio of existing and new projects.



### 17

### all but their most risky investments. The Co rporate financing struct ure enables decisions on project development to be separa te from decisions about the best means to finance the project; it allows the parent investor to time the financing based on broader financial market conditions. In particular, the Corporate financing structure can be used as an interim measure, as the company retains the flexibility of a later partial refinanc ing via the capital market s using other financing structures such as the Pay-As-You-Go or le veraged portfolio financing structures.

Frequency

The Corporate financing structure is the most co mmonly utilized structure in the U.S. In large part, this reflects the use of this structure by FPL Energy, which alone has accounted for a major portion of all wind projects br ought on-line in recent years. 28 

### A few other developers have initially used this structure for some projects, but then shifted to other financing structures after their ability to make efficient use of the Tax Be nefits changed. For one reason or another, most other developers have found it useful or necessary to tap third-party equ ity or debt capital to finance their projects. The recent entry of severa l large foreign developers into the U.S. market and the related consolidation of the sector by la rge financially strong pl ayers suggest that the Corporate structure will continue to be widely utilized going fo rward. At the same time, it will increasingly be employed not as the final structur e, but rather as an interim means to get wind projects built and into operation pending later refi nancings. To the extent that the foreign entities have insufficient U.S. tax appetite, such re financings likely will involve Tax Investors.



## 3.2 Strategic Investor Flip

Description

The Strategic Investor Flip financing structure is the simplest version of the structures involving capital from Tax Investors (“Tax Equity”). The na me of the structure reflects the fact that it has been used primarily by Strategic Investors seeking an active role in wind projects. The project developer negotiates a percenta ge ownership share by the Stra tegic Investor. Under this structure, the initial funding of project costs and allocations of project cash flows and Tax Benefits are shared on the same percentage basis, or pro rata, as the respective ownership of the parties. In effect, this partners hip structure is similar to a basi c 50/50 joint venture structure. However, three key elaborations set it ap art from a conventiona l joint venture.

The first key difference is that the Tax Investor provides almost all of the project equity, and in turn is initially allocated almost all of the cash and Tax Benefits. For example, with an undercapitalized developer, the Tax Investor might contribute funds for up to 99% of the total project cost, while the develope r provides the remaining 1%. U nder this structure, the Tax Investor and developer are initially allocated the same respective 99% and 1% shares of the

distributable cash and Tax Benefits. There have been transactions where the Tax Investor’s

initial contribution and allocation has been as high as 99.9%; there is speculation that pending guidance from the IRS may address the acceptability of such high ratios for future transactions.

28 See http://www.fplenergy.com/portfolio/wind/map.shtml for a map of FPL Energy’s wind facilities.



### 18

### The second elaboration, relative to a traditional joint venture, involves the concept of a “flip” in the percentage allocations of the project cash fl ows and Tax Benefits after a certain point in the life of the project. This point (the “Flip Point” ) typically is expressed as the point at which the

Tax Investor has received sufficient cash flows a nd Tax Benefits to reach a pre-negotiated IRR on its investment. After the Flip Point, the perc entage allocations of pr oject cash flow and Tax Benefits change to a second set of numbers that allocate most project flows away from the Tax Investor in favor of the developer. The Flip Point and the pre- and post-flip allocations are negotiated by the two parties. Th e Flip Point is usually projected to be reached on or shortly after the tenth anniversary of the project’s comm ercial operation date. The tenth anniversary is used as a marker date, since the PTC is availabl e only during the first ten years of operations. As developers utilizing this structure typically do not have the ability to utilize Tax Benefits efficiently, they do not want the fl ip to occur prior to year ten. 29 

### A common post-flip sharing amount is simply to invert the original percentage allocations. It may, however, be necessary to allocate more of the post-flip flows to the Tax Investor to achieve the overall twenty-year IRR targets required by the Tax Investor. 30 

### It is also possible to have a second, late r, Flip Po int and to have the inversion of the percen tage allocations be staged acr oss the two Flip Points. For example, a transaction could include an initial 99%/1% allocation that flips to 20%/80% on the first Flip Point and then to 5%/95% at the se cond Flip Point. A minimum 5% retention by the Tax Investor is increasingly seen as important to avoid a potential IRS challenge to the allocation

of Tax Benefits.

The third difference is that the Strategic Investor Flip structure often includes an option for the project developer to purchase th e ownership interests held by th e Tax Investor after the Flip Point. In order to comply with tax code requirements, for the Tax Investor to record the investment as a true equity i nvestment (and to recognize the co nsequent Tax Benefits), most projects set the purchase price on at least a “f air market value” basis. The purchase option typically is structured to first be available on or after the Flip Point has been reached. The

reduction in the allocations of cas h flow thereafter and the exhaus tion of the Tax Benefits serve

to reduce the fair market value of the Tax Investor’s ownership interests after th at point and, consequently, the price that must be paid by the project developer for such interests.

Under this structure, no limited-re course debt financing is sought either at the project level or outside of the project company. Management control over the project is negotiated. In transactions using this structur e, the project develope r usually retains broa d management control prior to the Flip Point. Howeve r, it is not uncommon for the Tax Investor to exercise majority control pro rata with its owne rship and funding percentages. The partnership agreement typically provides for certain limited rights for the owner with the lower percentage allocation, e.g., veto rights with respect to major corporate decisions.

Figure 3 provides a schematic repr esentation of the Strategic Investor Flip structure. Specifically, the schematic shows the relative per centage equity contributions from the project developer and the Tax Investor into the project company to fund initial construction costs. The

29 Note that after the Flip Point, most of the Tax Benef its – i.e., all of the PTCs and most of the depreciation deductions – have been utilized, which means that the developer is really being allocated cash and tax liabilities

. 30 These 20-year IRR targets are typically only slightly higher (e.g., less than 100 basis points or 1% higher) than the 10-year targets.



### 19

### shaded percentage boxes show the pre- and post-flip allocations of cash flow and the various TaxBenefits back to the developer and the Tax Investor. The first percentage in each box is the preflip allocation to the associated investor, while the percentage after the forward slash represents

the allocation to the associated investor after the Flip Point. Although th e equity contribution and pre- and post-flip allocation percentages s hown in Figures 2-8 match those used in the modeling analysis presented later in Chapter 4, in actual practice these percentages will vary from project to project and should th erefore be considered illustrative.

Strategic Tax Investor ( 99% of e q uit y ) Developer ( 1% of e q uit y )

Project Company (100% equity)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses less Tax-Deductible Expenses (including MACRS)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 99% Æ

99% / 10% Æ Å 1% / 90%

Å 1% / 90% 99% / 10% Æ Å 1%



### Figure 3. Schematic of Strategic Investor Flip Structure 31

31 Figures 3, 4, 6, and 7 are adapted from a June 2006 Meridian Clean Fuels presentation titled Comparing Alternative Structures for Tax Equ ity Investments in Wind Projects

.



### 20

### Rationale for Use

The Strategic Investor Flip structure was one of the first structures to be developed to attract third-party equity able to utilize the Tax Benefits, while allowing the developer to retain an interest in the project. Its virtue is its relativ e simplicity. All financial flows prior to the Flip Point, both in and out of the project company, are on the same pro rata basi s as ownership. The structure is useful for those proj ect developers lacking both the fi nancial strength to fund initial capital costs and the appetite for the Tax Bene fits, but who are nonetheless unwilling to simply sell the project outright. In e ffect, the Tax Investor buys the majority of the project and gets the lion’s share of the aggregate Ta x Benefits during roughly the firs t decade of operation, when most of the Tax Benefits are generated. The proj ect developer receives most of the cash and the remaining Tax Benefits generated thereafter; th e developer also typical ly has an option to repurchase the shares held by the Tax Investor at that point. The investor is made comfortable that the project developer has the incentive to ma nage the project capably during this first period, as the project’s success is key to the Flip Poin t occurring on schedule and the developer realizing the long-term value thereafter. The Flip Point hi storically has been designed to occur near the end of the ten-year period during which the PTCs are generated. The rise in turbine and other capital costs may be leading the Flip Point for so me transactions to be extended by a few years to enable the Tax Investor to reach its negotiated ta rget return. Changes in negotiated power prices and underlying interest rates also wi ll affect the relative positioni ng of the Flip Point by affecting the residual amount of cash flow, and taxable income or loss, distributed to the Tax Investor.

Investor Type

Project developers opting to use th is structure typically have a busin ess plan that calls for them to evolve into larger entities over time. They are not content simply to re ceive a single up-front development fee, but wish to develop a pool of pr ojects that will generate cash flow over time. Some closely-held developers vi ew the structure as a means to develop cash flows that will support their families in later years. Other privately-held developers look toward the possibility of listing their companies on a pub lic stock exchange and note that market valuations tend to favor ongoing contractually-based revenue streams over irregular, one-time development fees.

For their part, Tax Investors can be attracted to th is structure as it enables them to partner with capable, if cash-poor, project de velopers. Some Tax Investors believe that making the project developer wait for its returns unt il after the Flip Point motivates good project management. The structure gives preferred return ri ghts to the Tax Investor and, in so doing, allocates much of the risks of a wind project to the developer. If th e wind resource proves weaker than first thought, if turbine technical availability proves less than promised, or if maintena nce costs are higher than projected, the effect on the Tax Investor is mitigated by the fact that it is receiving virtually all of

the cash flows and Tax Benefits that are generated by the project until the Flip Point, and the Flip Point will be delayed until the Tax Investor reache s its IRR target. This structural risk mitigant can be very attractive to potential Tax Investors just entering the market and desiring to reduce the risk of solitary investments. Though primarily used by Strategic Inve stors, this financing structure can also be of interest to more-passive Institutional Investors (acting as Tax Investors) seeking to maximize their initial investments and to lock in a particular return. For example,

21

### some life insurance companies, with their need to match investments with future year policy payment obligations, favor this st ructure for these reasons.

Frequency

The Strategic Investor Flip fina ncing structure was employed for a few transactions early in the decade, but does not appear to be in frequent use currently. 32 

### Though it has elements of interest to both Tax Investors and develope rs, there are limitations. At l east one Tax Investor currently

in the market discounts the struct ure’s utility, considering it to be little different from the Corporate structure. For devel opers, this structure obliges them to wait ten or more years to receive any substantive cash flow (other than through whatever up-front development fee is feasible given the project economics and any ongoing management fees charged by the developer for overseeing project operations). Other financing structures have since been developed that meet the developer’s needs more effectively. In particular, the Institutional Investor Flip financing structure (described next) has proven more attractive to developers with capital to invest, as it enables such developers to put more of their capital to work and also recoup their investment more qui ckly, without being saddled w ith unwanted Tax Benefits. Separately, several of the medium-scale wind pr oject developers that might otherwise have utilized the Strategic Investor Fl ip structure have instead solved their project financing needs by agreeing either to sell their projec ts or to be acquired outright by larger Strategic Investors.



## 3.3 Institutional Investor Flip

Description

The Institutional Investor Flip Structure is also known as the “PAPS” structure (Pre-tax, Aftertax Partnership Structure), the “A/B” structure (after the two classes of investors in the partnership agreement for such transactions), or the “Babcock & Brown” structure (in recognition that this investment firm often has utilized this structur e for its many transactions). It is similar to the Strategic Investor Flip structure, in that the project develo per brings in a separate

Tax Investor to use the Tax Benefits, and there is a Flip Point at which the allocations of cash and Tax Benefits change.

Beyond these similarities, there are several impor tant differences. First, the name of the

structure reflects the fact that it was devised to bring in less-active, more-passive equity capital from Institutional Investors. Second, in contrast to the Strategic Investor Flip, the cash and Tax Benefits are initially allocated in different pe rcentages than each investor’s respective equity contributions. In other words, the allocations are not pro rata with the initial capital contributions. Specifically, in exchange for th e developer contributing a greater portion of the initial equity capital (e.g. , 30% - 40% of the total), all of the distributable cas h from the project is initially allocated to the developer until it recovers its capital. This typically takes place over the first four to six years of the project. Note that this initial allocation does not provide the developer any return on its investment, but only a return of its investment. After the developer has recouped its initial investment , 100% of the cash is then allocat ed to the Tax Investor until

32 Some developers of smaller community wind projects are using versions of this structure.



### 22

### the Flip Point is reached. Separately, the Tax I nvestor is allocated 100% of the Tax Benefits from the outset of project opera tions. The two parties adjust the initial contributions and the project allocations so that the Flip Point – the point at which the Institutional Investor achieves its targeted IRR – is projected to be reached on or shortly after the end of year ten. The initial contributions also will vary across projects, de pending on the relative returns generated from

cash flows versus PTCs. 33 

### Once the Flip Point has been reach ed, a majority of the cash and Tax Benefits, typically around 90%, are allocated to the developer. Th e post-flip sharing percentages are sized to provide the Tax Investor with a ta rgeted 20-year return, so they vary depending on the specifics of the project. The general assumpti on is that the 20-year re turn is, at a minimum, slightly higher than the 10-year return (e.g., by 50 - 70 basis points).

This structure does not include any limited-recourse debt financ ing at either the project or company level. The developer usually maintain s broad management control over routine project operations. The Tax Investor has voting rights or veto power with respect to major decisions. After the Flip Point has occurred, it is not uncommon for the Tax Investor’s right to be limited

still further.

Figure 4 provides a schematic representation of the Institutional Investor Flip structure. Specifically, the schematic shows the relative cont ributions from the project developer and the Tax Investor into the project company to fund ini tial construction costs, as well as allocations of cash flows and Tax Benefits to each party. As di scussed above, this structure features two Flip Points for cash allocations (though ju st one Flip Point for Tax Benefits ): initially all cash goes to the developer until it recoups its investment in th e project company; thereafter, all cash goes to

the Tax Investor until it reaches its target return, at which point the second flip (in the allocation of both cash and Tax Benefits) occurs.

Rationale for Use

The Institutional Investor Flip structure was deve loped to address limitations of the Strategic Investor Flip for various types of developers and investors. Sp ecifically, some developers have capital to invest and the interest in doing so, but lack the ability to use the Tax Benefits. For such investors, the Strategic In vestor Flip, with its pro rata link between the percentage amount of capital invested and receipt of cash and Tax Be nefits, does not give them the means to invest capital without being saddled w ith unwanted Tax Benefits.

Another more recent driver has been the entry of cash-based investors (“Ca sh Investors”) into the wind sector. These are typically Strategic Investors but can be Institutional Investors or even ratepayer-funded state clean ener gy funds; the distinct ion is their preference for a cash-based return as opposed to one comprised primarily of Tax Benefits. Foreign-owned utilities entering the U.S. market are examples of this group. In some cases, these Cash Investors team with undercapitalized developers to jo intly act as the project sponsor . In other cases, the Cash

33 A wind project with a robust capacity factor (enabling the developer to offer a lower power purchase price) will generate more PTCs and less cash. In comparison, the sa me size project, but in a lower wind region (obliging the developer to seek a higher power purchase price), will generate fewer PTCs but more cash. Since the cash and PTCs are allocated differently in this financing structure, the parties adjust their initial contributions to compensate

as needed.



### 23

### Investors have acquired either the project deve lopment rights or simply acquired the smaller developer outright so as to become the sole pr oject sponsor. For such Cash Investors, the Strategic Investor Flip structur e is not suitable, si nce it would require only a small amount of capital and not provide a substantive share of the cash flow until after the Flip Point. The Institutional Investor Flip struct ure enables a Cash Investor to put more capital to work. At the same time, the structure enables the Cash Investor to receive a preferred cash flow early in the project, thereby both lessening its longer-term exposure, while also recycling funds to support new wind projects. For their part, many Instit utional Investors like the structure because it obliges the project developer to invest more capital than with the Strategic Investor Flip, thereby becoming more vested in the success of the project. As an all-equity structure, it also allows developers and Institutional Inve stors to avoid the time, expense, governance, and cash flow allocation issues of debt financing.

Institutional Tax Investor ( 60% of e q uit y ) Developer ( 40% of e q uit y )

Project Company (100% equity)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses less Tax-Deductible Expenses (including MACRS)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 100% Æ

100% / 10% Æ Å 0% / 90%

Å 100% / 0% / 90% 0% / 100% / 10% Æ Å 0%



### Figure 4. Schematic of Institut ional Investor Flip Structure

24

### Investor Types

The Institutional Investor Flip is designed to enable developers to attract passive equity investment from large corporate entities with large, recurring, and reas onably predictable tax obligations. To date, these have been comprised primarily of ba nks and insurance companies.

Tax-oriented Institutional Investors active in the wind sector have in cluded JPMorgan Capital Corporation, GE Financial Services, Wells Farg o, Morgan Stanley, Union Bank of California, New York Life, Prudential, Wachovia Securities , and U.S. affiliates of AEGON, NV, among others. These investors have experience with other tax-oriented investments, and seek the additional return offered by wind projects.

As mentioned, Cash Investors are making targeted investments in wind, but do not want to base their return primarily on Tax Benefits. This financing structure enables these entities to participate in this sector. Some Cash Investors have similar strate gic goals as Strategic Investors, but lack the tax capacity to use all of the Tax Bene fits. Examples include foreign utilities such as

Enel and Iberdrola. 34 

### Alternatively, some Cash Investors are more akin to Institutional Investors, but lack tax appetite; examples include Babcock & Br own Wind Partners and ArcLight Capital.

Frequency

For the last several years, thos e developers seeking third-party financing (and not simply selling their projects outright) have most commonly used th e Institutional Investor F lip structure. Of the 13 transactions involving tax e quity investors reported closed from 2003 through 2005, ten used

this structure. It remained a popular structure in 2006. Such repeated use has spurred increasing comfort with this structure, as well as so me standardization of transaction documentation.



## 3.4 Pay-As-You-Go

Description

The underlying structure for Pa y-As-You-Go (“PAYGO”) is very loosely based on the Strategic Investor Flip Structure, with three main di fferences. Under the PAYGO structure, (i) the developer contributes roughly half (40%-60%) of the in itial capital required (compared to the much lower percentages in the Stra tegic Investor Flip st ructure), (ii) the al location of pre-flip cash and Tax Benefits do not match the percentage of equity contributions, and (iii) in addition to its up-front equity contributions of 40-60% (i.e., the amount not covered by the developer’s investment), the Tax Investor makes annual paym ents equal to a pre-determined value of the PTCs generated (e.g., 80–90 cents per dollar of PTCs generated), thereby e ffectively increasing its equity contributions over time. Actual per centage equity contributions both initially and over time will vary by the relative value of individual pr ojects, as well as the associated depreciation

treatment.

34 In July, 2007, Iberdrola announced an agreement to acqui re a utility in the Northeast. The acquisition may enable Iberdrola to use some Tax Benefits internally and thereby enable its wind project subsidiaries to use the Corporate financing structure for more projects for longer periods.



### 25

### The structure allows the Tax Investor to defer a portion of its equity investment over time and reduce risk by only paying for actual PTCs generated. 35 

### The PTC payments can be structured as incremental equity injections in to the project company. More co mmonly, they are structured as delayed payments for the ownership interests re ceived from the outset in the project company, with the payments made directly to the develope r outside of the project company. In some cases, there are two ongoing payments, with one being a fixed annual obligation, and the other varying in amount according to the level of PTCs generate d. In all cases, an important tax consideration

is to structure PAYGO transacti ons to avoid any doubt that the Tax Investor acquires its full ownership interests upon its initial investment in the project, so as to minimize later challenges to

the allocations of the Tax Benefits between th e developer and the Tax Investor. Some IRS private letter rulings in connection with similarly structured transactions involving the Section 29 non-conventional fuels credit suggest that the IRS may want the net present value of the up-front cash plus the fixed annual cont ributions to exceed 50% of the net present value of the Tax

Investor’s total invest ment in the project.

The pre-flip cash and Tax Benefit allocation percentages under the PAYGO structure are not pro-rata with the equity contributed and are not aligned with each other. The Tax Investor initially receives 100% of the Tax Benefits, but only a majority of the distributable cash, e.g., 70%-80%. The developer receives the balance of th e distributable cash prior to the Flip Point. As with the other structures, the terms are structur ed to cause the Flip Point to be met soon after the first ten years of operations . The periodic deferred equity payments are included in the calculation of the Tax Investor’s net IRR, even though they most often occur outside of the project company. After the Flip Point, the cash and Tax Benefit allocation ratios are realigned, with the developer receiving almost all (e.g., 90%-95%) of both the cash and Tax Benefits.

This structure contains no limited- recourse debt financing at eith er the project or the equity holding company level. The developer usuall y maintains management control over routine project operations. The Tax Investor has voting rights or veto power with respect to major decisions. After the Flip Point has occurred, the Tax Investor’s rights t ypically are limited still

further.

Figure 5 provides a schematic representation of the PAYGO structure. The schematic shows the relative equity contributi ons of the project developer and the Ta x Investor, as well as allocations of cash flows and Tax Benefits to each party. As discussed above, some portion of the PTC value (85% in Figure 5) flows – most often outside of the pr oject company, as shown here –

from the Tax Investor to the de veloper in the form of delayed payments for the Tax Investor’s initial equity interest in the project company.

35 Note that the PAYGO structure is distinct from a PTC monetization to support debt service under the Cash & PTC Leveraged structure (described in more detail in Section 3.6).



### 26

### Tax Investor ( 55% of e q uit y ) Developer ( 45% of e q uit y )

Project Company (100% equity)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses less Tax-Deductible Expenses (including MACRS)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 100% Æ

100% / 5% Æ Å 0% / 95%

Å 30% / 95% 70% / 5% Æ Å 0% Å 85% of

PTC value



### Figure 5. Schematic of Pay-As-You-Go Structure

Rationale for Use

The PAYGO structure typically ha s not been used in connection with the initial financing of projects, as other structures can generate higher initial per centage contributions from Tax Investors and, if used, lenders. The structure instead is findi ng use in connection with the refinancing of existing wind project s. Several such scenarios have emerged. For developers that initially financed their projects using the Co rporate structure, refi nancing with the PAYGO structure can raise capital for other corporate pu rposes or reduce the investment stake in the projects. The structure also en ables developers to maintain a significant amount of capital at work in their projects, while focusing their re turn on the cash flows (including the monetized PTC payments), rather than the Tax Benefits. Another use has been by existing wind project

owners whose tax situation has ch anged (e.g., via a corporate divest iture) such that they are no longer able to use the Tax Benefits efficiently. The PAYGO structure enab les them to maintain ownership and control, rather than being forced to sell the projects outright. Lastly, Cash

27

### Investors desiring to ac quire existing wind project assets but lacking ta x appetite can use the structure to tap Tax Investor capital to finance a portion of the acquisition costs.

Investor Types

This structure works best for developers with the capital available to invest, but who need a cashbased return as they do not have tax liabilities to offset. Th is structure allows the developers to maintain a long-term ownership interest in their projects. In these situ ations, the developers desire to remain active owners of their projec ts and thus typically l ook for an Institutional Investor, i.e., a passive financial partner, to ac t as the Tax Investor for the project. Foreign companies entering the market also may find it usef ul. For example, Energias de Portugal, S.A. initially considered using a form of this struct ure to finance a portion of the costs to acquire Horizon Wind Energy, LLC from Goldman Sachs earlier this year. 36



### Tax Investors can find the PAYGO structure useful if they are uncertain about the amount of PTCs projected to be generated. Such uncertainty might rise from insufficient wind resource data, new turbine technology, an inexperienced opera tor, or some other pr oject risk. In each case, the PAYGO structure reduces the exposure of the Tax Investor s to the risk that the PTCs ultimately generated will prove less than projected at the time of their initial investment. A developer comfortable with such risks can fund initial construction, wh ile still achieving an

efficient use of the Tax Benefits. These structur al risk mitigants also might be attractive to potential Tax Investors just ente ring the market and desiring to re duce the risk of investing in a single project.

Frequency

To date, the structure has not been used to finance a new project. PPM Energy has used a version of the structure to refinance existing projec ts after the sale of a corporate affiliate that previously had used the Tax Benefits. Aside from this example, the structure likely will see use mostly in connection with the acquisition of ex isting assets by foreign or other Cash Investors

unable to use the Tax Benefits.



## 3.5 Cash Leveraged

Description

The Cash Leveraged structure is based on the same underlying structure as the Strategic Investor Flip structure, but features a layer of debt added at the project level. 37 

### The loan is provided on a limited-recourse, i.e., project financ e, basis. Accordingly, it is sized to be repaid from the cash flow generated by the project and secured by the project’s assets. The initial percentage equity

36 See “EDP Enters U.S. Market with Acquisition of Horizon Wind Energy,” March 27, 2007, Renewable Energy
Access.com, www.renewableenergyaccess.com/rea/news/story?id=47894

. 37 The Strategic Investor Flip has been the basis for most leveraged wind transactions closed since 1999. A few transactions have used a basic joint venture structure (withou t a flip) or the Corporate stru cture as the base structure, i.e., they have not used third-party Tax Investor capital. The sponsor of a large transaction that closed financing this year reportedly initially considered combining leverage with a version of the Institutional Investor Flip structure.



### 28

### funding contributions by the develo per and the Tax Investor are the same as with the all-equity Strategic Investor Flip, but the am ount of the initial equity capit al required is decreased by the amount of the debt. In turn, th e loan principal and interest payments decrease the amount of

distributable cash availabl e to the investors. Th e overall project capital costs rise by the amount of initial closing costs associated with the loan f acility such as legal fees, technical consultants, etc., and with any lender-required cash reserves su ch as debt service or maintenance reserves.

The percentage of debt varies across projects , but is commonly around 40-60% of total project

costs. 38 

### For any given project, the size of the loan is a function of the projected cash flows and loan terms. The most important loan terms are the tenor (i.e., the number of years the loan is scheduled to be outstanding), th e interest rate, and the DSCR. Section 2.4 provides background

on current market levels for these loan terms. Table B3 in Appendix B describes the debt assumptions used in the template model of this report.

The management and control issues between the e quity investors are consis tent with those found in the Strategic Investor Flip structure, with one important difference: the impact of the customary lender covenants on proj ect governance. Specifically, the lender will have a first lien on the assets, first rights to cash generated, a nd approval rights with respect to major operating

decisions. This measure of control afforded the de bt provider is a direct result of the lower cost associated with these funds. A ge neral rule of finance is the lower the risk, the lower the return. In this case the lender is providing low-cost capital, so to reduce its risk, a priority position and increased rights are required.

Figure 6 provides a schematic repr esentation of the Cash Leveraged structure. Specifically, the

schematic shows the relative contributions from th e project developer, the Tax Investor, and the lender into the project company to fund initial construc tion costs, as well as pre- and post-flip

allocations of cash flows and Tax Benefits to each party. Debt service payments are deducted from the cash flows, with the residual distributed to the developer and Ta x Investor. In addition, interest payments on the debt are tax-deductible, thereby increasing taxable losses (or, in later years, reducing taxable gains).

Rationale for Use

Developers seek limited recourse project debt for two principal r easons: to boost equity returns and to reduce required equity contributions. All ot her things held equal, adding debt to a project will increase equity returns (because debt is t ypically cheaper than equity). This may be important for some projects where the returns otherwise are marginal or unattractive. This might occur, for example, if a project is in a marginal wind regime, ha s higher interconnection costs, or has been obliged by local market conditions to accept a lower-than-desired power purchase price. 39 

### Developers also use this structure to reduce the amount of equity required under the Strategic Investor Flip structure.

38 For example, as presented in Chapter 4, our analysis of this structure finds that, given our modeling assumptions, the template project is able to support 45% debt financ ing (compared to 61% debt for the Cash & PTC Leveraged structure, described next).

39 Note, however, that a lower-than-desir ed power purchase price will not be able to support as much debt as would a higher power purchase price. Even so, any leverage that can be added to the project may boost returns.



### 29

### Senior Lender ( PPA/cash d eb t )

Tax Investor ( 99% of e q uit y ) Developer ( 1% of e q uit y )

Project Company (equity + PPA/cash debt)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses

less

Debt Service less Tax-Deductible Expenses (including MACRS and interest on debt)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 99% Æ

99% / 10% Æ Å 1% / 90%

Å 1% / 90% 99% / 10% Æ Å 1%



### Figure 6. Schematic of Cash Leveraged Structure

Investor Type

Developers seeking project debt often have a general corporat e strategy of minimizing their capital investments in individual transactions. They are comfortable in their ability to access debt efficiently and to work thr ough Tax Investor concerns, such that they are comfortable that they can realize the promise of the improved proj ect returns possible with leverage. These are typically developers with prior e xperience in using debt, perhaps in conventional po wer projects.

30

### Developers who have tapped term debt incl ude Invenergy Wind, UPC Wind, enXco, and Noble

Environmental Power.

While the structure itself is an adaptation of the St rategic Investor Flip (at least in a mechanical sense, with pro rata allocations ), developers using the structure typically seek to retain substantive control of their projec ts and are not looking for an activ e Strategic Investor. Instead, more passive Institutional Invest ors are typically the t ype of Tax Investors sought by developers. The use of debt on a project can, however, limit th e pool of Tax Investors that are willing to

invest. Some Tax Investors are mo re comfortable with all-equity structures. Such investors do

not want to have to contend with a lender in case a project encount ers financial stress. They do not want to worry about being squeezed out of a transaction, i.e., losing their equity investment,

if lenders elect to foreclose on the project company. The potentia l for such an “equity squeeze” can arise since their share interests in the proj ect company usually are pledged to the lender as part of the collateral security for the loan. Such Tax Investors prefer to retain the flexibility of contributing additional funds to support a project in distress without having to coordinate such support with a lender. For these entities, the additional up-front costs and controls associated with debt outweigh the lower cost of capital. Ti ming may also be an issu e for some investors: closing on debt financing not onl y costs more up-front, it also ta kes additional time to close relative to an all-equity deal. In contrast, othe r Tax Investors are comfortable with having debt at the project level, believing that the lender’s initial due diligence and on-going monitoring of project operations are likely to result in bette r-structured deals and th ereby reduce their own

risks. Tax Investors who have invested in wind transactions involving leverage include the Union Bank of California, AEGON-affiliated life insurance companies, and JP Morgan.

Frequency

Although term debt is used in the market, levere d structures are currently in the minority for financing wind projects. All-e quity structures are more common. Short-term turbine supply

loans and construction loans have been used more frequently, but these are replaced by equity upon the project commencing operations.



## 3.6 Cash & PTC Leveraged

Description

The Cash & PTC Leveraged structure is the same as the Cash Leveraged struct ure but with an additional layer of debt – based on expected PTCs – at the project level. In this structure, both the cash-based loan and the PTC-based loan are secured by the project assets and assignments of contract rights. The term of th e PTC loan is ten years, corres ponding to the period in which the PTC can be claimed. As a tax credit used by th e project owners, the PTCs do not generate cash at the project level that can be used to repay pr oject-level debt. Thus, the debt service payments

of the additional debt will eat into (and sometimes exceed) the cash flow cushion created by the DSCR for the cash-based loan. In response, lende rs typically require that the Tax Investor provide a contingent guarantee to make periodic additional equity investments into the project company on an as-needed basis. The amount of such injections for any period is capped at the amount of PTCs actually generated in that period. In some cases, the obligation is capped at the

31

### lower of either the PTCs received by the Tax I nvestor or the actual debt service payment shortfall. Lenders usually focus on the credit-w orthiness of the guarantee by the Tax Investor,

since the Tax Investor makes the lion’s share of the equity contributions (e.g., 99%) under this structure. On occasion, lenders will seek such commitments from the developer as well as the

Tax Investor. 40 

### Such injections essentially create a second contingent cash flow stream that lenders are willing to rely upon to support an in cremental PTC loan. With this incremental source of project-level cash fl ow, projects using the Cash & PTC Leveraged structure can support debt for up to 50% to 65% of total project costs, compared with the 40% to 60% levels under the Cash Leveraged structure.

This structure differs from the PAYGO struct ure described in Sect ion 3.4. Even though both involve periodic equity payments whose amounts are linked to the amount of PTCs actually generated, the source and role of such period ic injections vary. Under the Cash & PTC Leveraged structure, the lender pr ovides a PTC loan to complete the initial f unding, and both owners (albeit mostly the Tax Investor) make peri odic equity contributions directly to the project company to help repay the PTC-based loan, if necessary. In c ontrast, under the PAYGO structure, no debt is involved, so the developer provides more in itial funding. Further, just the Tax Investor makes incremental periodic equity contributions based on the PTCs received, and such payments go directly to the developer.

In the analysis of this structure presented in Chapter 4, the cash and PTC-based loans are treated separately, in the interest of transparency. In practice, rather than having two separate loans, most lenders create a single, customized loan amortization schedule that aggregates the cash flows and the PTC-related equity contributions. The aggregate de bt service payments are sized during the first ten years to be supported by both the project’s cash flow and the incremental contingent equity contributions from the Tax I nvestor. The subsequent debt service payments are sized to be covered just by the project’s cash flow. As with the Cash Leveraged structure,

there are lender covenants and re strictions on the project. The additional PTC-based loan amount generally does not lead lenders to tighten these rest rictions, other than imposing covenants related to the periodic contingent equity contribution obligations. These incremental covenants can be difficult to negotiate, however, as the Tax Investor and the lender reconcile competing interests in the even t of project financial stress.

Figure 7 provides a schematic representation of the Cash & PTC Leveraged structure. Specifically, the schematic shows the relative contributions from the project developer, the Tax Investor, and the lender into the project company to fund initial construction costs, as well as pre- and post-flip allocations of cash flows and Tax Benefits to each party. Debt service payments – for both the Cash and PTC tranches – are paid from project cash flows prior to allocating the residual cash flow to the developer and Tax Investor. In addition, interest payments on the debt are tax deductible, thereby increasing taxable losses (or, in later years, reducing taxable gains). To the extent that th ere is not enough cash to repay the PTC debt, the Tax Investor (and sometimes) the developer make pr o rata equity contributions into the project company sufficient to support the PTC debt; thes e incremental contingent contributions are shown as dotted arrows parallel to thei r original equity contribution arrows.

40 For tax reasons, the developer may want to contribute its small percentage share regardless of the lender’s requirements so as to preserve the relative allocations of the cash flows and Tax Benefits between the owners.



### 32

### Senior Lender ( PPA/cash d ebt + PTC d eb t )

Tax Investor ( 99% of e q uit y ) Developer ( 1% of e q uit y )

Project Company (equity + PPA debt + PTC debt)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses

less

Debt Service less Tax-Deductible Expenses (including MACRS and interest on debt)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 99% Æ

99% / 10% Æ Å 1% / 90%

Å 1% / 90% 99% / 10% Æ Å 1% contingent equity contingent equity



### Figure 7. Schematic of Cash & PTC Leveraged Structure

Rationale for Use

The general rationale for use of debt has been pr eviously discussed. Namely, the lower cost of debt capital boosts project return s and requires less up-front investme nt from equity participants. This structure maximizes the use of leverage by including a PTC-based tran che of debt that is supported by a pledge of ongoing contingent equity infusions.

33

### Investor Type

Developers considering the Cash & PTC Leverage d structure are especially comfortable with using debt to leverage their equity investment and believe that the IRR boost from the incremental PTC debt merits the added complexity. As with the Cash Leve raged structure, they usually have prior experience in us ing debt, want to retain substa ntive control of their projects, and seek passive Inst itutional Investors to be the Tax Investor in the transactions. However, the

inclusion of a PTC tranche of de bt limits the pool of potentially interested Tax Investors still further, because few Tax Investors have been willing to assume the contingent obligation surrounding future capital contributions.

When judging a project opportunity, an investor will compare the expe cted rate of return against its cost of capital. This evaluation becomes pr oblematic with an obligation to fund uncertain amounts at unknown dates in the future, as far out as ten years from the present. Because there is generally great uncertainty about future cost of capital and even availab ility of funds, many Tax Investors prefer the certainty of making just one in itial investment ove r making an initial

investment and a series of potential future contributi ons. As a result, few Tax Investors are willing to guarantee to provide ongoing equity contributions in support of a PTC loan

monetization. In addition to the concerns about a lender squeezing out their equity interest in the event of project difficulties, they dislike the obligation to potentially make ongoing contributions in support of a loan – particul arly if the project is not pe rforming well (i.e., when such contributions are most likely). Given such i ssues, relatively few Tax Investors have proved willing to sign up for this structure.

Frequency

This type of structure, involvi ng both a Tax Investor separate from the developer, and a PTC loan, is rarely seen in the market. Two different developers each used this structure to finance a project in 2002 and 2004. Invene rgy Wind also used a version of the structure to finance a portfolio of three projects in 2005. 41 

### No other such tran sactions are believed to have been done.

As loan documentation and terms are worked out that address Tax Invest or concerns, however,

there are indications that this structure ma y be utilized for some projects in 2007-08.



## 3.7 Back Leveraged

Description

The Back Leveraged structure is the same as the Institutional Investor Flip structure, but with a layer of debt outside of the project company at the level of a holding company for the interests of the developer. The developer pledges its owners hip interests in the project company to secure the debt, and uses the debt to f und part of its initial capital contribution. As the debt is at the developer level, it does not have an impact on the economics at the level of the project company. The debt provider has no recourse to the project company, other than via the pledge of the developer’s equity share interests. The underlying structure and allocations to each party remain the same as in the Institutional Investor Flip structure. Loan covenants typically include provisions to sweep excess developer cash flow to make loan prepayments. As a result, while

41 Presentation by Jim Murphy, Invenergy Wind Finance Company, Renewable Energy Finance Forum, June 2005.



### 34

### the nominal loan maturity may be comparable to the 15-year maturity under the other debt structures, the effective maturity of ten is significantly shorter, e.g., as short as four to six years.

Figure 8 provides a schematic representation of th e Back Leveraged structure. Specifically, the schematic shows the relative equity contributions from the project developer (which in turn, is partly financed by back leverage) and from the Tax Investor into the project company to fund initial construction costs, as well as pre- and pos t-flip allocations of cas h flows and Tax Benefits to each party. The developer repays its borrowed e quity stake out of the cash flow allocated to it.

igure 8. Schematic of Back Leveraged Structure Senior Lender ( back levera g e )

Institutional Tax Investor ( 60% of e q uit y ) Developer ( 40% of e q uit y )

Project Company (100% equity)

Power ( and REC ) Sales

Cash Revenue Production Tax Credits ( PTCs )

less Operating Expenses less Tax-Deductible Expenses (including MACRS)

equals

Taxable Losses/Gains (which result in Tax Benefits/Liabilities) equals

Distributable Cash 100% Æ

100% / 10% Æ Å 0% / 90% Å 0%

Å 100% / 0% / 90% 0% / 100% / 10% Æ



### F

35

### R ationale for Use

The Back Leveraged structure allows the develo per to increase its long-term IRR by securing lower cost capital with which to fund its in itial equity contribution. It also allows undercapitalized developers to increase their equity participation in a project. Lastly, it has been used by developers interested in using debt, but desi ring to keep the direct project assets unencumbered. For example, a developer might use the structure as an interim measure to finance initial construction costs, pending a la ter refinancing as part of a portfolio.

Investor Type

This structure is used by developers that eith er have limited capital or who have the financial

resources to invest but that wa nt to reduce their co st of funds. The Ta x Investors are not impacted by this type of financ ial engineering at th e developer level. Indeed, they may not participate in or even see the loan documentation. Developers using this structure typically seek passive Institutional Investors to be th e Tax Investor for their transactions.

Frequency

This structure is becoming more common in the ma rket. It allows developers to increase their ownership in a project and capture the relative ec onomic benefits of debt. It also satisfies the Tax Investor market preference for all-equity projects.



## 3.8 Summary: Choosing a Structure

The seven financing structures profiled in this chapter are the princi pal means by which most large-scale wind projects (excludi ng utility-owned projects) are currently financed in the United States. These structures vary in several respects, including th e contractual flow of funds and obligations among the financing parties, their relative utility for different types of project developers and investors, the tim ing of funding, their frequency of use, and (as will be shown in the next chapter) their impact on th e project’s cost of energy.

Project developers typically make the decision on which financing structure best meets their needs for a given project based on a number of c onsiderations. The decision reflects both the developer’s own relative ability to use the Tax Benefits and to provide the capital funding, as

well as the financial robustness of the project itself, e.g., whethe r debt leverage is needed to boost projected returns to satisfy return requirements. Earlier in the decade, the amount of time before the next expiration date of the PTC al so played a role; pending PTC expiration dates led some developers to adjust their project developmen t and financing strategies so as to increase the prospects of meeting PTC deadlines. As this pr essure has abated more recently, the number of financing options being created and used has increased. Developers have become more confident that the PTC will be renewed, and have increased their financial ability to support more and longer lead-time development projects. Secondary factors also influence the financing decision, e.g., the relative preferen ce for realizing value up-front via a development fee or capital gain on sale of the project, or over time from the net cash flows from operations.

36

### The relative impor tance of these various consider ations differs from developer to developer and om project to project. Furthermore, some de velopers’ preferred fina ncing structures have

project-level onsiderations. Depending on a given develope r’s views on each consideration, one or more tures are likely to be more suitable than other stru ctures to meet the needs of the eveloper. The table provides se veral scenarios that represent differing combinations of these

able 1. Wind Developer Financing Structure Decision Matrix

Scenario oper

can use Developer
can fund Developer wants

to retain stake in Developer wants early Project

has low Project already exists 

### fr evolved over time, especially as their own financial situations have changed. In short, there is no single “correct” structure for all develope rs for all projects for all time.

Notwithstanding the above, one can illustrate, in general, the varied rationales for each financing structure by looking at the (hypothe tical) decision process facing wind developers in choosing a financing structure. Table 1 below provides a list of several key corporate and

c financing struc

d developer considerations. The financing structur e(s) most typically used for each scenario is identified in the final column. It is important to note that the table is generalized and focuses on just a few key considerations. Ot her factors can lead a developer to opt for a different financing structure than that suggested in the table.

T

Devel Most suitable financing

Tax Benefits project costs project ownership / ongoing cash flows cash

distributions projected

IRR (refinancing / acquisition) strategy or structure:

1 No No No Yes N/A No Sell project to a Strategic Investor

2 Yes Yes Yes No No No Corporate

3 No Limited Yes No No No Strategic Investor Flip

4 No Limited Yes Yes No No Institutional Investor Flip

5 No Limited Yes No Yes No Cash Leveraged or Cash & PTC Leveraged

6 No Limited Yes Yes No Yes Institutional Investor Flip

7 No Yes Yes Yes N/A Yes Pay-As-You-Go

8 No Limited Yes Yes Yes No Back Leveraged



### Scenario 1 typifies smaller deve lopers lacking the financial or technical wherewithal to carry a project through construction in to operation. Such develope rs commonly adopt a business strategy that focuses on early project development, with the goal being to sell their projects to larger entities prior to construc tion. Earlier in the decade, this was the only real alternative for developers unable to carry thei r own projects into operation. Larger developers on occasion have taken this approach as well as a means of maintaining business team s, generating cash flow to support operations, or to meet the requirement s of key utility client s desiring to own wind projects outright. Purchasers of these projects – which are often Strategic Investor s – might then use one of the other financing structures discussed in this report to finance the project.

Scenario 2 portrays a simple Corporate structure, where the developer has the financial resources

fund the project, efficiently use the Tax Benefits, and desires a long-term ownership stake for to strategic reasons. This is the most common wind project financi ng structure in the United States

37

### (in terms of installed cap acity), though only a handful of large de velopers are able to make use of

it.

Scenarios 3 and 4 pertain to all- equity flip structur es, where the develop er cannot fully fund the

roject or use its Tax Benefits , but nevertheless desires a long- term ownership stake in the

quity sources often prefer a shorter investment cycle nd have a higher requisite retu rn than investors focused on l ong-term returns from project

able to use the Tax Benefits pro ati on ight also like this structure, to the extent

c s a t to t ri e a Strateg r tu d e finance a portion investmen ither to p erve cash oost retur sing k lever ,” then S e Back Leveraged structure – is a relevant structure.

Scenario 5 represents a leveraged version of S cenario 3, where the intent is to boost project

IRRs. The use generally reflects the relative project economics, i.e., whether the increm l PTC m iz ation is needed to ach ie returns. It can also reflect other factors, such as the relative interest of Tax Investors in the s cific p ct and cremental contingent f ncial o ations ociate F reaso already ssed, th e of lev e at t project el h uncommon over the past few years, but may become more common in the future.

Finally, Scenarios 6 and 7 refer to a developer t owns
Investor to monetize the Tax Bene change in the developer’s tax

redit appetite, or simply to free up cash. Such a developer might opt eith er for the Institutional

tations of

e various considerations identi fied here also are possible. p project. The Strategic Investor Flip structure (Scenario 3) may be useful for developers with limited or no long-term capital to invest and no t needing significant earl y cash flows. This structure has been used by some of the “community wind” projects in the Mi dwest, in addition to some larger projects earlier in the decade.

If instead the developer has some cash to invest but would like to recoup its investment, in cash, sooner than possible under the Strategic Investor Flip structur e, then the Institutional Investor Flip structure (Scenario 4) may be more useful. This scenario also may make sense if the developer has received developm ent-stage financing from an equity source focused more on financing developers than projects; such e

a operations. Developers receiving equity financing from sources un generated from

e ject oper on, e. g., pensi funds, m

that su h sourc lso wan see significa n cash dist butions arlier than vailable under the

ic Investo Flip struc re. If such a eveloper d s to ires of its capital t (e res or b n s) u “bac age cenario 8 – th

choice of which leverage structure to

enta onet ve requisite equity

pe roje the in i na blig ass d with PTC debt.

or ns discu e us era g he lev as been relatively

tha an existing project but seeks a Tax fits, e.g., due to a detrimental

c Investor Flip or the Pay-As-You- Go structure, with the choice depending in part upon how much cash the developer wants to receive at the outset a nd in part on the percei ved relative transaction costs and complexity of the two structures. The us e of these structures for refinancing projects is becoming more common as developer consolida tion, often involving foreign entities without U.S. tax liability, increases.

As noted, these scenarios are simplified to illust rate key differences. Sp ecific developers likely will have additional or other considerations in connection with specific pr ojects or with their overall corporate goals that will impact the choice of financing stru cture. Other permu

th

38

## 4. The Impact of Financing Struct ure on the Levelized Cost of Wind

n E ergy

the pro forma financial model used for the LCOE

ortray how th e agreed-upon allocations of the ax Benefits may be adjusted to comply w ith IRS tax partnership accounting requirements

y virtually all utility-scale wind projects developed and financed in the la st several years. For example,

sumptions are those that vary among the financing structures and therefore differentially impact the LCOE for each structure. These assumptions relate

rates of return and debt terms are indicative of current market conditions; they are not reflective of particular projects. In addition to describing the m echanics of each of the seven financing structures, a principal purpose of this report is to analyze the levelized cost of energy (“LCOE”) from each structure, on a relative basis. For this report, the LCOE is defined as the minimum required nominal 20- year power purchase price (with no escalation) that enables the project to cover its operating costs while also satisfying the requirements of le nders (if any) and equity providers. This

hapter begins with a brief overview of c analysis. More detail on the model is provided in Appendix B. The chapter then presents and discusses the results of the LCOE analysis.



## 4.1 Overview of Pro Forma Financial Model

To facilitate comparisons of th e impact of each financing structure on the cost of wind energy, the authors developed a simplifie d Excel-based pro forma financia l model. The model uses a template of an indicative wind project as the co mmon basis for illustrati ng the effects of each financing structure. The purpose of the model is to understand the principal differences across financing structures. The model is not derived from an actual wind projec t financial model (such models are considerably more de tailed), nor does it attempt to po rtray a specific project in a particular region of the country. It also does not p

T (Appendix C provides an introduction to these requirements). Instead, the model simply provides a platform to compare the structures to each other.

The authors developed three sets of assumptions to first define the template wind project and

then to differentiate between the financing structures:

(1) Market assumptions reflect the broad market conditi ons experienced b

it is assumed that the template project uses proven technology to ge nerate electricity for sale on a long-term, wholesale basis to a creditw orthy utility, and that the project owners make full use of the project’s Tax Be nefits in the year they are earned. (2) Common assumptions are those that are project-speci fic – i.e., narrower than market assumptions – yet nevertheless common to a ll seven financing stru ctures analyzed. These include assumptions about turbine and other “hard” project costs, net capacity factor, O&M costs, marginal income ta x rates, and depreciation schedules. (3) Structure-specific as

primarily to the cost of financing (equity and, if used, debt, as well as any transaction or “soft” costs associated with the financing) as well as the relative e quity contributions and pre- and post-flip allo cations of the project’s cash and Tax Benefits among the relevant investors. The specific assumptions about eq uity

39

### Appendix B describes the market, common, and st ructure-specific assumptions used in the template model, and lists the specific values used for these input assumptions.

T he model itself consists of a single Excel workbook. Each financing structure is housed in its own worksheet. Based on the assumptions describe d above and in Appendix B, the model solves for the levelized cost of energy for each structure involving third-party equity that yields the specified Tax Investor after-tax re turn target at the end of ten y ears, while not violating minimum DSCRs or other lender constraints (for t hose structures also employing leverage). 42 

### The use of a 10-year term for the Tax Investor’s return target is industry standard, since that term also

coincides with the duration of the PTC. For the Corporate structure, which does not use external financing, the model solves for the levelized cost of energy that yields the developer’s after-tax return target at the end of twenty years. A twen ty-year period is used in this case, as it matches

dard in the industry, given the tax-oriented ature of the equity investment.

be attained by varying (within the onfines of tax law) the equity contribution ratios and pre- and pos t-flip cash and tax allocations.

the first approach.

For



## 4.2 L

Tab

The Corpor

assume

are
IRR

model th e industry’s default assumption for the life of a wind project. For all of the structures, measuring investor returns on an af ter-tax basis is stan

n

The modeling process adopted for this report st arts with assumed retu rn targets, equity contribution ratios, and cash and Tax Benefit allocations and then solves for the power sales price required to satisfy these targets and constr aints. Developers initially follow a similar approach (i.e., starting with assump tions about the cost of financing) to evaluate the viability of potential projects and to arrive at a starting point for power price ne gotiations. However, this is the reverse of the process that actually occurs wh en external financing is arranged. By that time, the developer typically already has negotiated a PPA. In such cases, the developer seeks to maximize its residual return in the negotiations with financiers. Tax Invest or return targets are negotiated based on the set PPA price, subject to what can

c Since, however, the purpose of this report is, in part, to analyze th e potential impact of financing structures on the cost of wind energ y, this report takes

more details on the structure of the mode l and on the input assumptions, see Appendix B.



## evelized Cost of Energy Comparisons

summarizes the highlights of the modeling analysis, including key inputs and results. le 2 key inputs listed are the project costs, the Ta x Investor’s 10-year IRR target (except for the ate structure, where the relevant input is the developer’s 20-year IRR target), and the

d debt interest rates and tenor for the th ree structures using debt financing. The outputs 20-year LCOE, the Tax Investor’s 20-year IRR, 43 

### the developer’s 10-yea the r and 20-year (again, except for the Corporate structure, where the developer’s 20-year IRR target is a input), and the de veloper’s 20-year NPV. For thos e financing structures involving

, the developer’s return is the residual, or what is left after satisfying the Tax Investor’s return requirements gotiations between the developer and the Tax Investor. In practice, developer returns also reflect relative ttributes, e.g., capacity factors, power prices, etc. plify the modeling task, the model treats the 20-year Tax Investor IRR as an output. In reality, the Tax 42 In turn

in the ne project a

To sim vestor’s 20-year IRR is linked to its 10-year IRR and both IRR targets are highly negotiated between the Tax Investor and the developer, and will reflect market conditions. 43

In



### 40

### independent Tax Investors, the negotiations focus principally on the Tax Investor’s IRR. The developer’s return calculations are presented for informati onal purposes, t hough some Tax

vestors also assess the developer’s returns to ensure a reasonable alloca tion of project returns

• For the six structures other than the Corporate structure, the Tax Inve stors’ 10-year target

• The template project’s 20-year LCOE under the seven structures ranges from $48/MWh

act

lthough the modeling results are intended to be illustrative of current market conditions, they In between the parties.

Key inputs and results include:

• Total project costs are assumed to be relatively similar across all structures, with roughly $100/kW difference between the most expensiv e and least expensiv e structures. The leveraged structures are the most expensive – assumed to be nearly $1,830/kW – due to the closing costs and reserve ac counts associated with debt. 44 

### Conversely, the Corporate structure is assumed to be the cheapest – at $1,725/kW – as it in curs no debt-related transaction costs and, unlike the all-equity st ructures involving third- party Tax Investors,

does not utilize construction debt or incur equity closing costs.

IRR (which our analysis assumes is al ways met on schedule) reflects the input assumptions, while the 20-year Tax Investor IRR is an output from the model, and is generally only slightly (i.e., 30-50 basis points) higher than the 10-year targ et, illustrating the degree to which Tax Investor returns are front-loaded and the post-flip reallocation of

most cash and Tax Benefit flows to the deve loper. The develope r’s IRR (both 10- and 20-year) is an output of the model (except fo r the Corporate structure), and varies across

structures as well as over time.

• For the Corporate structure, the developer’s 20-year IRR target is the input assumption, while its 10-year IRR is derived. Unlike in the other structures, the developer in the Corporate structure receives all of the benefits thr oughout the 20-year period.

to $63/MWh, suggesting that choice of financ ing structure can have a significant imp on a wind project’s LCOE.

A are, of course, a function of the modeling assumptions. These a ssumptions are merely indicative and do not reflect a specific projec t. Using a different set of i nput parameters will generate

different results. 45 

### Finally, the model does not undertake de tailed tax-oriented analysis with respect to partnership accounting issues, as intr oduced in Appendix C. A ccordingly, the returns should not be assumed as likely for specific proj ects using the various financing structures. Instead, the comparative nature of the analys is means that these LCOE results are best

44 However, the depreciable basis for th ese structures is not as high as the capital cost might suggest, because the

lity of a wind project, as it drives both revenue and PTC debt service reserve account is non-depreciable.

45 For example, this analysis assumes a 36% net capacity f actor for the template wind pr oject. Capacity factor, a measure of energy production, greatly affects the profitabi generation. Reducing the capacity factor assumption to 32% forces the projected LCOEs to rise. While the percentage increase varies from 13% to 20%, the relative differences between the LCOEs for the financing structures do not change.



### 41

### considered relative to one another – i.e., to illust rate the relative impact of financing structures – rather than individually or on an absolute basis.

Table 2. Project Cos ts, Investor Retu rns, and LCOE by Financing Structure

Leveraged Cash Leveraged Institutional

Investor

Flip Back Leveraged PAYGO Strategic

Investor

Flip Corporate Cash & PTC

Assum ed Installed Project Costs

Hard C ost ($/kW) 1,600 1,600 1,600 1, 600 1,600 1,600 1,600

Soft C ost ($/kW) 229 215 183 183 183 183 125

Total C ost ($/kW) 1,829 1,815 1,783 1, 783 1,783 1,783 1,725

Tax Inves tor After-Tax Return (The 10-year target IRR is a model inpu t, while the 20-year IRR is a model output)

10-Ye 6.50% 6.50% N/A ar Target IRR 9.25% 9.00% 6.50% 6.50%

20-Year IRR 9.67% 9.29% 7.12% 7.12% 7.02% 7.02% N/A

Assumed Loan Terms (For those structures using leverage; Table B3 has details)

All-in I nterest Rate 6.70% 6.70% N/A 6.70% N/A N/A N/A

Tenor (maturity) 15 years 15 year s N/A calculated N/A N/A N/A

Developer After-Tax Return (Except for the Corporate 20-year IRR, the developer returns are all model outputs)

10-Yea r IRR 9.25% 9.00% 0.00% -10.08% 5.75% 6.50% 6.64%

20-Yea r IRR 33.15% 30.58% 10.44 % 11.91% 11.52% 37.44% 10.00%

20-Ye ($000 @ 7,208 7,540 1,578 4, 673 7,811 20,745 0 ar NPV 10%)

20-Year L evelized Cost of Energy (LCOE)

Nomin 63 al $/MWh 48 50 53 53 59 61



### The a key dif 10-year

rget re ll as the relative relationships of these assumptions among

strong projects securing a sligh tly lower rate and ot her, less-strong project s needing to offer a higher rate. This hurdle rate of 6.50% is used as the benchmark for the other all-equity structures T x Investor’s 10-year IRR targets for each of the six structures accessing Tax Equity are

ferentiators of the resul ting LCOE. Since there is no public registry of the Tax Investor IRR agreed upon between the developer and the Tax Invest or for individual projects, the

turns assumed here, as we ta structures, are based on anecdotal industry inform ation. Nonetheless, so me discussion of these assumptions relative to each other is of use, if only to distinguish the results of this report from actual projects.

The prominence of the Institutional Investor Flip structure in recent years makes its associated 10-year Tax Investor IRR assumption a benchmark for comparison with ot her structures. The 6.50% rate is in the rang e of projects closing fi nancing in the last year , with some especially

utilizing Tax Investors.

The Tax Investor’s 10-year IRR targets for th e Cash Leveraged and Cash & PTC Leveraged

structures are assumed to be 250 and 275 basis points, respectively, a bove the Tax Investor return for the Institutional Investor Flip structure. The target returns are set higher to reflect both

42

### the incremental risk 46 

### and the mechanical impact of debt on equity returns. 47 

### The study sets the 10-year Tax Investor IRR targ et for the PAYGO structure at the 6.50% industry benchmark.

rguments that the rate should be reduced to reflect the fact that Tax Investors only pay for the

e Tax Investor reserve just as much tax capacity for ructures as it doe s for ctures. Also, some Tax Investors say th at eate ty o GO structures and, in some cases, th high initial , e ot a h o .

The 6.50% IRR for the Tax Investor under the Strate gic Investor F lip is the m fficu assess, as there have been few deals using this cture in ent ye One

curren gues that the assum d 6.50% rate should be higher since the required investment amount is litt le different from that required fo

he Institutional Investor Flip stru cture, since that ure re les ron al to contributed by the Tax Investor. On the other ha like th ora ctur Strate Investor Flip structure protects the Tax Investor from the development and construction risks of active project management.

M red w Insti l Inves Flip structure, th e Inve under Strategic Investor Flip e re th ca d Ta s fr he ou of pro

and needs of the Tax Investor and the developer.

The developer’s 10%, 20-year I RR et assu for th porate structure is based on anecdotal industry information of returns sought by entities directly able to use the Tax Benefits ip of wind proj ects. There is little data available on the IRR

re develop using structur hough F Energ has pr ded so

dications of its internal valuation metrics to stock analysts. 48 

### The Corporate structure return

mbined with an inability to do so directly. A PTC benefits if and as they are generated are counter-balanced by the view that th

needs to P AYGO st

r i other stru the gr complex f PAY

e investment justify the sam , if n igher, rate f return

ost di lt to

stru rec ars. Tax Investor tly active in the m arket ar e r the Corporate stru cture. This investor also argues th at it should be higher th an the required Tax Investor return under t

struct qui res s up-f t capit be nd, un e Corp te st ru e, the gic

the project, and does not requir e the Tax Investor to assume

oreover, compa ith the tutiona t or Tax stor the

structur ceives bo sh an x Benefit om t tset ject operations and forces the developer to wait for a decade or more to start receiving the bulk of its return. In practice, rates negotiated for specific projects will balance th e relative strengths

targ med e Cor

and interested in long-term ownersh

quirements of ers this e, t PL y ovi me in target figure does not reflect the risk and reward calculations of either Tax Investor or pure developers unable or unwilling to i nvest in long-term ownership, but rather it is a hybrid of the two. While the 10%, 20-year IRR assumption a nd the calculated 6.64% ten-year IRR can be compared to the developer returns under the ot her structures, such comparisons may not be germane, as comparison implies a choice. More typically, the reason a developer seeks Tax Investor capital is based less on relative returns than simply the need to make efficient use of the Tax Benefits, co

46 The incremental risk comes from the lender having a fi rst call on all project cash flows to meet debt service obligations and a priority lien on the project assets in the event of a loan default; thus, poor operating performance will magnify the impact on the equity investor.

47 Some of this basis point premium is to reflect the mechanics of leverage. If debt costs less than equity, then the use of debt to partially finance a project results in a higher equity return than if no debt were used – regardless of

sk considerations – since the incremental operating cash flow after servicing the cheaper debt (relative to the cost ri of equity) flows to the equity investors.

48 FPL Energy has advised that it seeks wind projects yielding an IRR of 10% or better ( http://seekingalpha.com/article/34007-fpl -group-q1-2007-earnings-call-transcript ) and that it factors in a 50/50 debt-equity ratio when assessing the accretive imp act of new wind projects on its corporate results ( http://seekingalpha.com/article/42882-fpl -group-q2-2007-earnings-call-transcript ).



### 43

### Each individual structure’s modeling resu lts are discussed in more detail below.

As shown in Table 2, the financing structure w ith the lowest LCOE is Cash & PTC Leveraged, which has a 20-year LCOE of $48/MWh. In othe r words, given the assumptions used in the analysis, the template project – wh en financed using this structur e – requires a flat $48/MWh for the first twenty years of operation to cover its ca pital and operating costs, and to meet the return requirements of the Tax Investor as well as the financing terms of the debt provi der. The nextwest LCOE is found with the Cash Leveraged structure, at $50/MWh (with the slightly higher

ct level would be widely used. However, this has ot been the case in recent years. Indeed, it is estimated that only 20% of the deals in the market

he effect of leverage and the increased risks associated with debt from a Tax Investor’s standpoint are reflected in their eq uity return requirements. In th is analysis, the Tax Investor’s target returns are 9.00% and 9.25% for the Cash Leveraged and Cash & PTC lo LCOE reflecting slightly less leverage, due to the absence of PTC-backed debt).

The fact that the two structures with the lowest LCOEs have project debt is not unexpected. Debt has a cheaper cost of capital than does equ ity, so the more debt a project can secure, the lower the LCOE (assuming no other changes). This is true despite the fact that, as reflected in Table 2, required equity returns are higher when leverage is involved, to account for the extra risk imposed on equity providers when debt is us ed. Moreover, the investors still receive the full amount of the Tax Benefits as if the project ha d been financed with all equity and no debt. Additionally, debt interest payments are tax-deductible, so th ey increase the tax loss in the early years of the project (a potentially counter-intuit ive characteristic unique to tax-based investments is that greater tax losses enhance the returns to Tax Investors).

If the developer’s goal is to create the lowest LCOE, then the LCOE results reported here

indicate that some form of levera ge at the proje

n in 2006 included project level debt. 49 

### In a perfect market, economi c theory suggests that no one structure would generate higher returns than another, in which case there should not be such disparities in usage levels. Chapters 2 and 3, however, have described several reasons why developers and Tax Investors have preferred not to us e debt, including con cerns about up-front transaction costs, increased defa ult risk, and additional time to cl ose. As discussed, up-front fees, reserve accounts, and transactional expenses w ill reduce the net IRR gain from using debt. Many Tax Investors prefer not to have a bank holding a first clai m on the project assets, in the event the project underperforms ma terially. While the indicative cost assumptions used for the

model are meant to reflect current market condi tions, they may nonetheless not be incorporating all perceived market costs or ri sks when developers and investor s structure financing for actual projects.

T

10-year after-tax Leveraged structures, respectively. These ta rgets are 250-275 basis poi nts higher than the comparable Tax Investor returns in the all-equity structures. The developer’s IRR projected for the leveraged structures, as well as for the St rategic Investor Flip structure (the underlying structure for the leveraged cases), are also among the highest of all those examined. Indeed, the developer’s projected after-tax re turns for the two leveraged structures are about 9% (for the 10-

ear return) and over 30% (for y the 20-year return). This is because in these scenarios the developer contributes very little initial capital, ye t receives almost all of the project allocations

49 See Chadbourne & Parke, LLP, op. cit.



### 44

### after the Flip Point. However, the increased cost and risks associated with lever age makes these rojected returns more uncertain. Lower-than- projected wind production will disproportionately

bt is not at the roject level, the Back-Leveraged structure us es the same 6.50% IRR assumption and these two

he PAYGO structure – where the Tax Investor pa ys the developer an annual amount equal to a

of PTCs produced. If that amount d ecreases to 80 cents the LCOE decreases from 59 to $56, and the developer return decreases to 10.5%. In practic e, the developer and the Tax p reduce or delay cash flow dist ributions to the developer, since the annual debt service requirements do not change. This significant volatili ty, i.e., the risk that the developer’s return will prove substantially lower, is not captured in the single-point forecast of the model.

The Institutional Investor Flip and Back Leveraged structures ha ve the next lowest LCOE at $53/MWh. As noted earlier, these all-equity structures are identi cal with the exception of the developer’s company-level debt in the Back Leverage d structure. Because th is de

p structures show the same project returns, Tax Investor 20-year returns, and required LCOEs. The only variation is in the developer’s returns. For the Institutional Investor Flip structure, the developer has no 10-year return on its capital due to the allocation of cash and Tax Benefits

under the structure. In the Back Leveraged structure, the developer has a negative 10-year IRR (reflecting repayment of the company-level debt), but has a 20-year IRR (11.9%) that is about 150 basis points higher than the developer’s 20-y ear IRR (10.4%) using the Institutional Investor Flip structure. The developer’s higher 20-year IRR reflects the lower cash investment enabled by the use of debt in the Back Leveraged structure.

T fixed percentage of the PTCs generated – is found to be next cheapest, with a LCOE of $59/MWh. This structure allows the developer to make a signifi cant capital contribution (45% in this analysis) and secure a cash-based return in the form of cash distributions from the project and Tax Investor PTC payments. The model assu mes that the Tax Investor receives a 10-year target return of 6.5%, inclusiv e of the PTC monetization paymen ts; in turn, this yields a projected 20-year IRR to the Tax Investor that is roughly 50 basis points higher, at 7.02%. The developer’s return in the PAYGO structure is among the lowe st of the structures involving Tax Investor equity, with a 20-year after-tax IRR of 11.5%. This retu rn is a function of the amount of capital contribu ted up-front (the most of any structure, at 45% of to tal equity) and the receipt of a majority of the return, via the PTC payments, over time.

The LCOE and developer return for the PAY GO structure are affected greatly by the PTC payment percentage. This analysis assumes th e Tax Investor pays th e developer 85 cents for

each dollar $ Investor negotiate a PTC payment rate at a le vel that will achieve th eir respective return requirements.

The Strategic Investor Flip structure ha s the second-highest LCOE, at $61/MWh. The developer’s 20-year return in this structure is proj ected to be the highest of all the structures. This is because (i) the developer contributes ju st 1% of the up-front cap ital and receives a prorata share of the cash and Tax Benefits prior to the Flip Point and (ii) after the Flip Point it

receives 90% of all allocations . Therefore, it contributes virtually no capital up-front yet

receives almost all of the allo cations after year ten. The LCOE of this structure is highly dependent on the Tax Investor’s target return requirement. As the Tax Investor does not take

45

### development-stage risks, and only contributes funds when the proj ect is operational, the 10-year return requirement is assumed to be lower than required for a Corporate structure investment.

In this analysis, the Tax Investor’s (whether Stra tegic or Institutional) 10-year target return for the all-equity partnership structur es is uniformly set at 6.5%. As a result, one might ex pect that

e Strategic Investor Flip and Institutional Inve stor Flip structures would generate the same

he highest LCOE resulting from our analysis is a ssociated with the Corporate structure, and is

usin g this structure have a lower eighted-average cost of capital than assumed for this study, then the LC OE would be reduced.

required by Tax I nvestors and lenders in the marketplace. Investors and lenders quire higher returns to invest in wind projects that use structures deemed more risky, e.g., those th LCOE. However, the calculated LCOE in the form er is $8/MWh greater than in the latter. The difference is due to the developer’s capital cont ribution and return prof ile. In the Strategic Investor Flip structure, the de veloper contributes almost no cas h, but nevertheless receives a pro rata return on its investment for the first ten years prior to the Flip Point, yielding a positive return at the end of year ten. In contrast, the developer in th e Institutional Investor Flip structure invests a larger amount of cap ital but receives only a return of capital in the first ten years (0% IRR). In other words, under the Institutional Invest or flip structure, the developer recovers its capital in the first four to six y ears of operation (six ye ars in this analysis), but receives nothing from that point through year ten. Because the deve loper is not receiving a return in the first ten years of operation, the project is essentially using a large percenta ge of zero-cost capital, which allows the Tax Investor to reach its 10-year return target through a lower cost of energy.

T largely a function of the fact that the mode l sets the 20-year target return for the developer/Corporate entity at 10%. A developer’s return requirement is used, as there is no involvement by a separate Tax Invest or. Although this is technically an all-eq uity structure, the

structure differs from the other structures in that a single owner bears all of the project risks, i.e., there is no separation of the risks (and returns) between two equity parties, with one party having lower risks and, hence, lower return s, than the other. In other wo rds, the target return might be thought of as a blended equity hurdle rate, reflec ting a melding of the returns to the Tax Investor and the developer in other all-equ ity structures. Alternatively, it could be considered the blended rate of a higher equity return requirement, aver aged with cheaper debt financing obtained at a corporate level above the project. In either case, this higher return requirement and the lack of leverage yields a comparatively high LCOE. If developers

w For example, if the 20-year 10% return assumpti on is reduced to a 9% bl ended return, then the

calculated LCOE would d ecrease to $58/MWh.

In sum, variations in the LCOE across financ ial structures (assumi ng the same underlying template project) reflect the different assumpti ons made about the equity returns and debt financing costs

re that defer returns until later in the life of the pr oject, or that use leverage. Thus, assuming all other cost and operating parameters are held equal, 50 

### the LCOE for a given financing structure is a proxy for the relative cost of equity and, if used , debt financing for the project. As with other maturing sectors, the cost of financing beco mes a competitive differentiator among project developers. Those with access to cheaper money will be able to offer lower-cost power to their

customers.

50 This assumption is important: variations in assumptions about the underlying template project itself – including turbine and balance-of-plant costs, capacity factors, and operating costs – will also impact the resulting LCOE.



### 46

### In the economists’ perfect world, no one financing structure should generate higher returns th an nother, LCOEs would not differ substantially among structures, and there should be little a difference in the degree of usage of these structur es. This analysis suggests that the economists’ perfect world does not exist in the wind financin g marketplace. Additi onally, the divergence of the presumed attractiveness of each structure (as measured by LCOE) from actual market practice suggests that developers considering financing structures take multiple factors into account in addition to the projected LCOE. Most obviously, their financial analyses consider project-specific costs and revenues, and not simply generic assumptions. Non-monetary considerations also play an important role. In formation flows, access to equity and debt capital, and experience levels are not uniform across the sector. Given these realities, developers and investors likely will continue to find value in optimizing the fi nancing structure for their wind projects.

47

## 5 . Conclusions – Obser vations & Future Trends

nancing structures will change in popularity fr om year to year. As an example, the use f leveraged structures increased in 2006 and may do so again in 2007, compared with less frequent use earlier in the decade. A key driver for this increased use is the rise in turbine costs in the last two years. Commensurate increases in power prices have not occurred, which has put pressure on developer and investor returns and s purred efforts to boost returns through the use of leveraged financing structures . The extension of the PTC through the end of 2008 also has afforded developers more time to craft levera ged financing structures. Finally, lenders are devising loan forbearance terms to accommodate Tax Investor needs in potential default situations, such that some Tax Investors are becoming less worried about the participation of lenders in wind financings. On the other hand, debt financings may become less attractive iflenders tighten credit standards and loan terms as a reaction to the recent difficulties in the subprime mortgage financing market.

Rising turbine and other capital costs in the last few years have additional implications. Prior to 2004, the average cost of wi nd projects was declining. 51 

### This enabled developers to offer lower power prices to their utility customers. The lower prices, along with several other factors, accelerated utility acceptance of wi nd as a viable power source. Since then, project costs have been rising, and developers have offset a sign ificant amount of the cost increase with the financial gains from reductions in third-party equity and debt re turn requirements, such that prices offered to utilities do not appear to have climbed as much as might otherwise be expected. 52 

### Some Tax Investors are accepting Flip Po int dates later than ten years, which provides more time for projects to reach the inve stors’ targeted returns. However, further material reductions in return requirements are unlikely. Separately, a rise in interest rates or more cautious views by capital sources about wind resource assessments could push direct financing costs higher. Absent finding savings elsewhere, developers may be obliged to pass on such increases by charging more for the power from new projects.

The significant developer consolidation in the la st three years also will affect the choice of financing structures for future pr ojects. Larger, well-capitalized developers have more financing options than do small developers. Such compan ies have the opportunity to use their financial strength to absorb perceived project risks and to structure and schedule financings to take The U.S. wind power sector has grown significantly in the last decade. The pace of sector development has outstripped the ability of most developers to fund project capital costs and to

make efficient use of the Federal Tax Benefits. In response, the sector has been successful in creating novel project financing st ructures to attract both Instit utional Investors and Strategic Investors wanting to enter the se ctor. Different financing stru ctures have evolved to meet specific developer and investor needs, and this evolution will continue so long as the sector attracts new investment capital. This chapter concludes this report by making some observations about the potential direction of this evoluti on and the potential impact on the cost of wind

energy.

Specific fi

o

51 Wiser and Bolinger (2007), op. cit.

52 Diane Bailey, “Cheaper Finance Help s Offset Rising Turbine Costs,” Windpower Monthly, May 2007, pp. 58-62.



### 48

### advantage of market conditions. By de-linki ng financings from project deadlines and by roviding more corporate support in the financings, la rger developers will foster new or p differentiated financing structures and also put pressure on capit al providers to improve their financing terms and conditions. At the same time, the entry of foreign utilities into the U.S. wind market via purchases of mid-sized and smaller U.S. developers suggests a continued, if not expanded, need for domestic institutional equity sources able to use the Tax Benefits.

Financial sector comfort with wi nd power technology and markets is enabling some transactions to be able to handle risks previously consider ed unfinanceable, i.e., risk s that lenders and Tax Investors historically required pr oject developers to absorb. Earlier in the decade, lenders and Tax Investors only financed wind projects with l ong-term PPAs with stipulated prices in place.

his wa T s based on the belief that variances in bo th production (to be expe cted in wind projects)

projects in other states.

rovide benefits to the utility

independent project-specific entities selling power on a contract basis. For utilities directly of more-expensive and elaborate project-specific financing and prices created too much uncerta inty in the level of cash flow available to service the debt. Additionally, many banks had suffered huge losse s in having financed conventional power projects without such contracts (known as merchant plants), a nd had become increasingly more stringent with their underwriting requirements. In the last two years, however, several wind projects in Texas and earlier this year, a large transaction in New York, have closed on financing arrangements using shorter-term PPAs followed by financial hedge contracts to reduce marketprice risk in the later years. Some lenders an d Tax Investors have beco me comfortable with the ability of hedge contracts to provide sufficient (if not perfectly comparable) price risk reduction compared with a traditional PPA during the term of the hedge contracts. The addition of hedge counterparties as credit provide rs to wind project financings is obliging lenders and Tax Investors to craft intercreditor arrangements with the hedge providers. More such transactions are likely to close in Te xas and New York in the next year ; developers and bankers also are

xploring if such hedge contract s are feasible in financing wind e

Separately, lenders and Tax Investors are becomi ng more willing to finance projects using new wind turbine technology from companies such as Suzlon En ergy Limited and Clipper Windpower. Their willingness stems in part from the increased supply of lenders and Tax

Investors relative to availabl e wind financing opportunities. Potential capital providers are competing by assuming greater risks and by easing terms and costs.. That said, until the new turbines accumulate a significant operating history, their comfort likely will come with tighter investment terms and conditions, including highl y-negotiated incremental support offered by the developer and the turbine manufacturer to mitigate perceived incremental risks.

Investor-owned utilities also are showing renewe d interest in acquiring wind projects outright to add to their internal generating portfolio. This di ffers from unregulated de veloper subsidiaries of utilities (such as FPL Energy) buyi ng projects where the power is so ld to other utilities. Such

irect acquisitions to a utility’s internal generation portfolio can p d compared with entering into long-term power purchase agreements with stand-alone projectspecific entities. The Tax Benef its of ownership of wind projec ts are attractive to utilities enjoying profitability, and therefor e with enough tax liab ility to benefit from the Tax Benefits of wind projects. The effective price of power may al so be somewhat lower, to the extent that the utilities are able to fund proj ect costs with lower-cost corpor ate funds than can be accessed by

purchasing projects, the use

49

### structures will be unnecessary. Direct owners hip also obviates increasing pressure by credit rating agencies to treat long -term power purchase agreements as forms of contingent indebtedness, and provides utilities a di rect return on their rate base.

At the same time, expanding interest in dir ect ownership by publicly owned (e.g., municipal and cooperative) utilities is fosteri ng development of different financ ing structures. For example,

ur cooperatives and public util ity districts in Wash ington State desired to develop and own a

r larger rojects.

pting to devise nancing structures that incorporate contingent insurance or bank letters of credit to mobilize fo wind project, but were unable to use the Tax Bene fits because of their tax-exempt status. They devised a financing structure th at involves pre-paying some of their projected power purchases. 53 

### The prepayments will be used, along with Tax Investor equity and debt financing, to finance

initial construction costs. The fi nancial closing of the White Creek project, as it is named, was announced in January 2007. To date, this project is the only one to close financing using this

structure. Whether this structure becomes more widely employed will depend on the relative

interest of other credit-worthy publicly-owned utilities and other entiti es becoming increasingly comfortable with wind power technology to be willing to make such pre-payments.

Publicly owned utilities and cooperatives separa tely are beginning to tap a new tax credit bond financing program known as Clean Renewabl e Energy Bonds (“CREBs”). CREBs were established by the Energy Policy Act of 2005 to encourage public sector entities and cooperatives that are unable to use Tax Benefits to invest in renewable power projects. The program is just beginning, however, and the firs t CREBs are likely to be issued this year. Currently, wind project financing structures incorporating CREBs are still being devised, and their utility for large projects currently is lim ited. The IRS, which administers the program, currently allocates CREBs mostly to small proj ects. Congress is cons idering changes in the program that would expand the amount of CREBs and make them more available fo

p

The continuing use of the PTC as a key Federa l incentive for wind power projects also has implications on future financing structures. As the sector expands, so does the impact of the PTC on Federal tax receipts. Lengthening the pe riod of the next extension to provide more stability to the sector and thereby spur a higher rate of new capacity additions will increase the expected budgetary impact still further. Nonetheless, a longe r-term PTC extension may lead Tax Investors not currently participating in the wind s ector due to the temporar y nature of the PTC to commence financing projects. Separately, some investment bankers are attem

fi

hitherto reluctant Tax Investors by fine-tuning their proj ected exposure to proj ect downside risks. While such structures may be commercially feasible allocations of project risks, they are being hampered by IRS requirements that Tax Investors be exposed to equity risk s if they are to be

allocated the Tax Benefits.

On the other hand, if the PTC framework is not re newed or is changed substantively to limit its cost to the Treasury, wind power financing struct ures designed to attract Tax Investors may no longer be attractive absent changes in the structur es and/or terms. Such a change would be a

53 See Brian Skeehan, “Cowlitz PUD’s Post 2011 Power Supply and the White Creek Wind Project,” presentation at Northwest Public Power Association Power Supply Workshop, April 11, 2006. www.nwppa.org/web/presentations/Skeehan_presentation.ppt

.



### 50

### paradigm shift in the U.S. industr y, as the current structures deve loped to attract and utilize taxbased equity investment would become obsolete. The market would ultimately adapt, but there would be a transition period as new structures are developed or existin g ones are modified.

structure or
ad to modified versions of other financing structures. Portfolio financings are increasing in usage and are being considered by both project developers and financial institutions. Such portfolio financ ings are being stimulated by the increasing pace of development. Several inve stment banking firms have estab lished or are developing pools or funds of institutional investor cap ital to invest in projects. Funds being set up by financial institutions vary in targeting ne w projects, refinancing existing pr ojects, or some combination of the two. The funds variously amass capital from multiple smaller Tax Inve stors or else target

Cash Investors. Babcock & Brown Wind Partne rs is one such fund that has a global focus. 54


### Two wind developers already have raised debt or tax equity to refinance portions of their existing portfolios. The entry of the large fore ign developers able to fund capital costs, but lacking the requisite tax appetite, likely will spur additional future portfolio refinancings. Such refinancings and poolings of proj ects may increase the use of th e PAYGO financing

le

Each of these various trends and influences w ill affect how future wind power projects are

financed in the United States. It will be usef ul for the DOE to monitor these developments, and their actual impacts on wind financi ng structures, as part of its ongoing review of the cost of energy from wind power.

54 See http://www.bbwi ndpartners.com/

.



### 51

## References

American Wind Energy Association (AWEA). 2007a . “U.S. Wind Industry to Install Over 3, 000 MegaWatts of Wind Power in 2007: First Quar ter Market Report.” AWEA press release, May 10, 2007. Available at www.awea.org/newsroom/releases/AWEA_ First_Quarter_Ma rket_Report_2007.html

______. 2007b. “Wind Power Capacity in U.S. Increas ed 27% in 2006 and is Expected to Grow an Additional 26% in 2007.” AWEA press release, January 23, 2007. Available at www.awea.org/newsroom/releases/Wind_Power_Capacity_012307.html

.

______. 2006. “Energy Department, Wind Industry Jo in to Create Action Plan to Realize National Vision of 20% Electricity From Wind.” AWEA press release, June 5, 2006.

Available at www.awea.org/newsroom/releases/Ener gy_Dept_Wind_Industry_Action_Plan_060506.html

_ _____. 2000. “After Blowout Year in 1999, Wind Ener gy Looks to Even Brighter Future in U.S. Market.” AWEA press releas e, April 30, 2000. Available at http://www.awea.org/news/news000430w2k.html

.

Babcock & Brown Wind P artners. 2007. “B BW Investor Pack 2007.” Available at www.bbwindpartners.com

.

Bailey, Diane. 2007. “Cheaper Finance He lps Offset Rising Turbine Costs. Windpower Monthly

, May 2007, pp. 58-62.

Bolinger, Mark, Ryan Wiser, To m Wind, Dan Juhl, Robert Grace. 2004. A Comparative Analysis of Community Wind Development Options in Oregon . Energy Trust of Oregon. Available at http://www.energytrust.org/RR/wi nd/OR_Community_Wind_Report.pdf

.

Chadbourne & Parke, LLP. 2007. “The Tax Equ ity Market” in the April 2007 edition of Project

Finance Newswire . Chadbourne & Parke, LLP, April 2007, pp. 1-12.

Chester, Jeff. 2007. “Wind Power Market Overvi ew 2006.” Kaye Scholer, LLP, presentation at

Infocast’s Wind Power Finance & Investment Summit 2007 , La Jolla, CA, February 7-9,

2007.

Eber, John. 2006. “Windpower Tax Monetizations Transactions.” JPMorgan Capital Corporation, presentation at AWEA Wind Pr oject Finance & Investment Workshop, April

2006.

Energy Information Administration. 2007. Annual Energy Outlook 2007 with Projections to

2030 . DOE/EIA-0383(2007). Available at www.eia.doe.gov/oiaf/aeo/excel/aeotab_19.xls

.

Energy Northwest. 2007. Nine Canyon Wi nd Project webpage. Available at http://www.energynorthwest.com/generation/nine_canyon.php

.

52

### eo, Ed. 2004. “ F The Equity Market for Wind Proj ects.” Presentation at AWEA’s Wind Power

Fitch Ratings. 2005. Press release, “Fitch Expe Finance & Investment Workshop, September 28-29, 2004.

cts to Rate FPL Nationa l Wind Opco ‘BBB’ and Holdco ‘BB’”, February 9, 2005. Available at http://findarticles.com/p/articles/mi_m0EIN/is_2005_Feb_9/ai_n9509206

.

FPL Group, Inc. 2006. Form 8-K filing to the U.S. Securities & Exchange Commission, June 26,

2006. Available at .pdf

.

Kub http://www.psc.state.fl.us/ library/filings/06/05916-06/05916-06

______ 

### , 2005. Press release, February 23, 2005. Available at http://www.fplenergy.com/news/contents/05020.shtml

.

ert, Charles. 2004. Community Wind Financing: A Handbook by the Environmental Law & Policy Center . Environmental Law & Policy Center. Available at http://www.elpc.org/documents/WindHandbook2004.pdf

.

ridian Clean Fuels, Comparing Alternative Structures fo r Tax Equity Investments in Wind Projects, June 2006 presentation at AWEA’s Wi nd Power 2006 conference in Pittsburgh, Me

ur ind Finance Co mpany Portfolio Financing Transaction.”

Pennsylvania.

phy, James. 2005. “Invenergy W M Invenergy, LLC, presentation at Renewabl e Energy Finance Forum, June 23-24, 2005, organized by Euromoney and American Council on Renewable Energy.

Renewable Energy Access. 2007. “EDP Enters U.S. Market with Acquisition of Horizon Wind Energy.” March 27, 2007. Available at www.renewableenergyaccess.com/rea/news/story?id=47894

.

Skeehan, Brian. 2006. “Cowlitz PUD’s Post 20 11 Power Supply and the White Creek Wind Project.” Presentation at Northwest Public Power Association Power Supply Workshop, April 11, 2006. Available at www.nwppa.org/web/presentati ons/Skeehan_presentation.ppt

.

ent Wiser, Ryan, and Mark Bolinger. 2007. Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2006 . DOE/GO-102007-2433. Washington, DC: U.S. Departm of Energy, Office of Energy Efficiency and Renewable Energy.

53

## A ppendix A: Glossary

Cas

its.

e as h is when a project’s turbines

the PTC.

e oject through one of the this report.

S Debt Service Coverage Ratio – The safety margin required by

In

each flows equal to 1.45

lip

after

investing opportunities and wants to offset its large tax obligations from its primary business activities. Examples include larg e banks and insurance companies.

IRR: Internal Rate of Return – In technical terms, the IRR is the discount rate that sets the net pres ent value of an investment equal to zero. Wind project financings are often st ructured to enable investors to reach a target IRR at a set point in time (i.e., at the Flip Point). A WEA: American Wind Energy Association

h Investor: An investor in a wind project that prefers a cash-based return as opposed to one comprised primarily of Tax Benef

COD: Commercial Operations Date – Th e date on which the project first achieves full commercial operations. This often is the same dat the “placed-in-service date”, whic first are deemed eligible to earn

D eveloper: Sometimes referred to as the projec t sponsor, this is the entity that initiates and develops the wind proj ect, and may wish to participat in the ongoing ownership of th e pr financing structures desc ribed in

DOE: United States Department of Energy

CR: D lenders to ensure that a project wi ll generate sufficient cash flows to service its debt, i.e., to meet pr incipal and interest payments. this report, a DSCR of 1.45 was used, which means that project is expected to generate operating cash times the debt service in each period, for cash-based debt. In this way, the DSCR limits the amount of debt a project can support.

Point: The point at which the Tax Inve stor has received a negotiated F after-tax IRR on its investment. The Flip Point is typically

structured to occur at the tent h anniversary of the COD, which no further PTCs are genera ted and the majority of the depreciation charges have been taken.

Institutional Investor: An entity that invests in a wind project for the Tax Benefits principally as a financial investme nt. The entity seeks returns on excess capital relative to other passive

54

### LCOE: Lev year power purchas elized Cost of Energy – The minimum required nominal 20- e price (with no escalation) that enables a project to cover its operating costs while also satisfying the quity providers.

ACRS: – The method by depreciated for tax purposes b, roughly 90-

MW:

AYGO:

PTC:

RPS:

ll states have instituted RPS requirements of lenders (if any) and e

LIBOR: London Interbank Offer Rate – A floating short-term (e.g., 3-6 month) interest rate that represen ts what banks charge each other

for funds. LIBOR is a benchmar k for a commercial bank lender’s cost of capital. Wind projects seeking debt financing from commercial banks are typically ch arged a basis point spread over the current LIBOR rate. In most cases, prior to closing, the LIBOR rate is swapped out to a fi xed rate over the term of the

loan.

LLC: Limited Liability Company – A form of business entity that is the most popular for wind project companies.

Modified Accelerated Cost Recovery System M which most wind power assets ar e under the U.S. tax code. As a general rule of thum 95% of a wind project’s installed co st can be depreciated using a 5- year MACRS schedule. This accele rated tax depreciation (relative to the project’s expected 20- to 30 -year life) creates tax losses in the early years of a project, wh ich Tax Investors use to offset

taxable income from ot her business operations.

MegaWatt – One thousand kilowatts, or one million Watts. In this context, a MW is a measure of electrical generation capacity.

MWh: MegaWatt Hour – The energy prod uction of one MW for one hour. For example, 10 MW of capacity producing electricity for two hour yields 20 MWh.

The pay-as-you-go financing structure (described in detail in P Section 3.4)

Production Tax Credit – This Fede ral incentive, contained in Section 45 of the U.S. tax code, currently provides an inflationadjusted 10-year tax credit for each MWh of qualified renewable generation produced and sold. For 2007, the inflation-adjusted value of the PTC is $20/MWh.

Renewable Portfolio Standard – A legislative or regulatory requirement that certain load-s erving entities must source a minimum percentage of their gene ration portfolio from eligible

renewable resources. Half of a

55

### requirements. Currently, there is no Federal RPS, although Congress has considered one on several occasions.

Renewable Energy Credit – A REC represents th REC: e attributes

associated with one MWh of rene wable power generation, and can

Sponsor:

trategic Investor: An entity that invests in a wi nd project not only for the Tax

is an electric utility that invests in a range of power generation assets.

Tax Benefits:

Tax Equity:

ax Investor: An entity that invests in a wind project principally for the Tax be sold separately from the genera tion itself. RECs are often used as a tool to evidence compliance with RPS policies.

The developer that initiates a nd develops the wind project, and may wish to participate in the ongoing ownership of the completed project through one of th e financing structures described in this

report.

S

Benefits but also because the investme nt is in line with the entity’s primary business activities. An exam ple

Collective term including the Federal Production Tax Credit and the income tax shield provided to investors from accelerated tax depreciation (i.e., 5-year MACRS de preciation) of the assets of the wind project.

The equity invested in a wind project by Tax Investors.

T Benefits; includes both Strategi c and Institutional Investors

.

56

## Appendix B: Descrip ssumptions

Overview

To facilitate comparisons of t d in this study

nd the impact of these struct ures on the cost of energy, the authors developed a simplified pro forma finan indicative wind project as the end, the authors developed a s

is important to recognize that the purpose of the model is to understand the principal

model. Nor does it attempt t country. Instead, it simply p compared relative to each o typically feature a readsheet listing key assumptions and multiple se parate spreadsheets that focus on different

project developer and for thi cash and Tax Benefits, debt f

Financial models used in fin tions often calculate project flow s on a quarterly or

onthly basis so as to capture more precisely the changes that occur in such time periods. Some

assumptions which developers of actual w . The model purposely does not incl ude the levels of detail typically included either in models used by developers considering whether to undertake a potential wind projec t or in the still-more-richly detailed models that form the basis for negotiati ng equity and debt financ ing from Tax Investors and lenders. Specifically, the model does not at tempt to portray detailed tax partnership allocations derived from capita l accounts (Appendix C provides a brief overview of key tax partnership matters). Though such detail is germ ane for enabling specific return projections in actual negotiations, the simplified model assumptions used in this report suffice to illustrate the main flows for each financing structure. While the authors believe that the assumptions are within the ranges seen in recent market transactions, no attempt was made to ensure that the inputs are precisely correct, as such precision is not the primary purpose of the model.



## Market Assumptions

In setting the values used for the model’s comm on and structure-specific assumptions, the report makes certain guiding assumptions about the market in which the template wind project operates. These broad assumptions are intended to reflect the market conditions experienced by almost all utility-scale wind projects developed and financed in the last several years. These market assumptions are likely to remain the predominant pa radigm for the majority of wind projects in

the near future. As some of these market co nditions are changing for very recent projects, 

## tion of Pro Forma Financ ial Model and

A

he me chanics of each of the seven stru ctures analyze

a Excel-based cial model. The intent of the model is to create a template of an basis for illustrating the effects of each financing structure. To this

e t of key assumptions to define the template project.

It differences across the financing stru ctures. It is not derived from an actual wind project financial o portray a specific project or projects in a particular region of the rovides an underlyi ng platform from which the structures can be

ther. Actual wi nd project financial mode ls

sp aspects of the project, such as : capital costs, operations, depr eciation, equity returns for the rd-pa rty investors, aggregate and partnership allocations of project

inanci ng (if any is used), and sensitivit y analyses, graphs, or charts.

anc ing negotia

m models may add a summary spreadsheet to show key results for ready analysis.

By contrast, the used for this re port summarize many capital a nd operating costs for ind projects generate substantially more-detailed assumptions

57

### however, it will be important to acknowledge any divergences from such market assum a prelude to comparing financing st ructures, financial returns, and the cost of energy for future projects. ptions as

et assumptions relate to the terms fo r selling the project output. The most important that the report’s template wind project is assumed to generate elec tricity for sale on a

t. Chapter 5 otes that a few wind projects curre ntly being financed have relaxe d this assumption, as evidence

of wind power rojects have often been content not to force ne gotiation of a distinct REC price, provided that

off-taker bligations.

he model’s base-case assumptions do not assume a ny inflation in the prices under the off-take Several mark

is wholesale basis to a utility. Th e project’s energy sales are assume d to be on a long-term basis, i.e., for the 20-year time horizon of the model, under a power purchase agreement with a utility. All of the output of the project is assumed to be sold under this arrangement. Put another way, the price for the electricity, as well as the financ ing hurdle rates, assume that the project will not have any exposure to subsequent fluctuations in either price or demand for its outpu

n of how financing structures are evolving.

The model similarly reflects an assumption that a ll of the RECs generated by the project are sold under a long-term off-take agreement – perhaps th e same agreement that governs power sales. The model allows for separate prices and revenue calculations for electricity and REC sales.

This reflects the market in some states where th e existence and nature of a RPS has led to an “unbundled” REC market, separate from power markets. In states that do not have an RPS, the value of a project’s RECs is not as clear. In such instances, develope rs of wind projects often have elected to sell both energy and RECs under a single contract by which all attributes of a project are sold to a single buyer using a consolid ated price. Thus, the important legal points of who owns the RECs (the project owner or the buye r of the electricity) a nd who holds the risk of determining current and future values are establ ished contractually. De velopers

p the single bundled price generates sufficient revenues to make the project commercially viable to develop. In practice, the model allows for alternative scenarios to be considered by changing these assumptions.

The off-take agreement(s) for energy and/or RECs are further assumed to be with a creditworthy entity, i.e., one that the providers of the equity an d debt capital for the proj ect believe is likely to be able to honor the purchase obligations for the full term of the agreement. As such, the model assumptions for off-take prices and required financ ial hurdle rates do not factor in default risk. In practice, investors and lenders typically require that the off- taker has an investment-grade credit rating from one or more of the national credit agencies such as Standard & Poor’s or Moody’s. If the off-taker does not have such cr edit strength, then financing parties will look for a parent company or other entity that does have such credit quality to guarantee the

o

T agreement(s). The establishment of a fixed, non-inf lating price for such sales for the full term of the off-take agreement(s) is common, as it re presents a key advantage enjoyed by wind power producers relative to fossil fuel power plants subject to ongoing fuel price fluctuations. However, the model allows for separate inflation f actors to be used for the sales of electricity and RECs, so as to enable alternative pricing scen arios to be considered in future analysis.

58

### A separate, but important, market assumption is that the template wind project is employing known wind turbine technology and experienced cont ractors for the constr uction and operation of the proj ect. An important f actor for many financial institutions in the wind sector is a belief at technology risks are modest and properly and e ffectively allocated to parties willing and able

se, i.e., the effective co st of energy would increase in rder to attain the equity capital hurdle rates. This would be true irrespective of the financing

rs taking this course handicap themselves relative to other developers ompeting for the right to sell power and RECs to the same off-taker. Similarly, more-expensive

te an estimated after-tax return to project investors. Measur ing investor returns on

n after-tax basis is standard in the industry given the tax-based nature of the equity investment.

espective apital accounts. Transactions involving a flip structure and di sproportionate allocations of cash th

to handle such risks. In exch ange, more capital providers are willing to provide capital on a long-term basis and to reduce their required hurdle rates. This bargain is an attribute of a maturing market. Chapter 5 notes how a few wind projects currently bei ng financed feature new turbine technology and the implications for their financing.

Another market assumption for the template wind project is the availability of the Federal PTC in its current form. For utility -scale wind projects with market -based pricing, the PTC typically represents a substantial part of the total value of the project to investors. Absent this benefit, the power and/or REC prices would need to ri

o structure, since all of them assume the ability to make efficient use of the PTC. The PTC currently is available for projects entering opera tion prior to January 1, 2009. For purposes of this report, the model assumes that the templa te wind project enters operation during calendar year 2008, and that the PTC benefits are therefore available to the owners.

The template project also assumes that the investor s in the project can make full, i.e., efficient, use of the Tax Benefits in the years in which they are generated. This is a simple assumption but one that is very important given the value of the Tax Benefits. Wh ile it is possible for an owner to carry-forward unutilized porti ons of the PTC and depreciation deductions (in the form of net operating losses) for up to 20 years, the time value of money effects of such delays progressively erode the value to the investors. In theory, a developer could offset this erosion by seeking higher prices for power and RECs and a third-pa rty investor could require a higher nominal equity hurdle rate as a condition of investing in a given project. From a competitive standpoint, however, develope

c investor capital will lose out in seeking investment opportunities to less-expensive investment capital able to make efficien t use of the Tax Benefits.

For purposes of the model, Federal and state income tax rates are assumed to be consistent across

all the structures. State taxes were included in this analysis , but with losses being carried forward until they could be used by the wind pr oject itself. The underl ying assumption is that

the Tax Investor does not have other state tax liabilities (beyond those generated by the template wind project) with which to offset operating losses from the template wind project. Tax rates are used to genera

a

Finally, this analysis does not take into acc ount certain partnership accounting and allocation issues associated with wind projects. Fo r example, the model does not show stop-loss reallocations, minimum gain charge-backs, or cap ital account deficit restoration obligations that can arise in certain financing structures. With tax-based investing, it is very important to

monitor the allocations of cash and Tax Benefits to each partner relativ e to their r

c

59

### and Tax Benefits may trigger income rea llocations that, while mandated by IRS Code requirements, may be nonetheless out of propor tion with the allocati on percentages agreed between the partners. Such reallo cations can materially affect th e economic return to the project owners. The authors did not incorporate partnership accounting or allocation issues into the model, as these factors are highly project-specifi c and require a level of detail beyond the scope of this report. Appendix C provides a qualitative summary of these matters.



## Common Assumptions Across All Structures

The model consists of a single Excel workbook, with th e common assumptions used by all of the structures aggregated on a single worksheet. To facilitate comparison of the financing structures, the worksheet aggregates in separate columns the distinct financing-related assumptions for each

structure. The model also includes dedicated wo rksheets to compute the cost of energy for the template wind project using each of the seven fina ncing structures. To the extent possible, each

calculation worksheet follows the same format and draws from the common assumptions. Using the various assumptions, the model then calculates the requisite 20-year cost of energy for each financing structure. For each stru cture involving third-party capital, the model solves for the cost of energy that yields the specified required Tax Investor IRR at the end of te n years. A ten-year

me frame is used because project developers a nd Tax Investors typically use it as a basis for

plate wind project that are common to all f the financing structures. For each assumpti on, the value used in the model is given and ti negotiating the IRR for a specific project. PTC generation expires on the tenth anniversary of the start of commercial operations and most of the tax depreciation benefits have been utilized by that time. Note that the model is simplified in that it does not model the exercise of a post-flip purchase option by the developer. In other words, the analyses assume that the Tax Investor remains involved with the project over the full twenty-year life of the project. The model is also simplified by including a fixed initial development fee and by excluding an ongoing management fee in the returns to the developer. For the Corpor ate structure, the model solves for the cost of energy that yields the specified re quired developer IRR at th e end of twenty years. The use of a 20-year target return is consistent with the developer in this structure being the sole investor, with a longer-term time horizon.

Table B1 lists the various input assumptions for the tem

o background notes are listed on the basis for the value.

60

### Table B1. Input Assumptions Common to All Structures

ASSUMPTION VALUE NOTES

PROJ ECT INFORMATION

Yea r of Initial Commercial Operation 2008 The proj ect becomes operational at the beginning of 2008.

Pro ject Capacity 100 MW Represen tative project size in 2008.

Ann 07). ual Net Capacity Factor 36.00% Average 2006 cap. factor for recent projects (Wiser and Bolinger 20

Infl 007. ation Rate 2.00% Close to GDP price deflator projection in Annual Energy Outlook 2

Inte rate. rest on Reserves 2.00% Set to be c onsistent with assumed inflation

CAPI T AL COSTS ($000)

Hard Costs

D evelopment Costs 5,000

Wind Turbines 120,000

B alance of Plant 25,000

I Roughly consistent with the range of recent project costs presented in

nterconnection 10,000 Wiser and Bolinger (2007)

t Costs Sof

I nterest During Construction (IDC)

Interest Rate 6.70% Consistent with the rates for cash and PTC-based debt (see Table B 3).

Construction Period 12 months Estimate includes turb ine delivery and actual project construction.

C ( onstruction Debt Closing Fee % of debt amount) 1.25% Estimate based on industry review.

S oft Cost Totals ($000) Interest During Construction (IDC) Calc ulation Assumes 100% of costs outstandi ng for half the construction period

. Equity Closing Costs 400 Based on industry review (legal fees & consulta nts; no finder’s fee)

. Developer Fee 3,500 Residual value assumption. Actual fee amounts vary by project, depending on relative project value and financing terms. Working Capital 1,000 Estimate based on industry review. Contingency (5% of Hard Costs) 8,000 5% figure ba sed on industry review; the $ amount is calculated.

AL OPERATING EXPENSES ANNU

Ope rations & Maintenance (O&M) Costs

F ixed O&M ($/kW-yr) 11.50

V ariable O&M ($/MWh) 6.00 Aggregate fixed and variable O&M cost s are consistent with those used

in DOE/AWEA’s 20% Wind Vision Analysis.

PPA Letter of Credit (LOC)

L OC Amount ($000) 5,000 Based on industry expe rience (this figure can vary widely)

A nnual LOC Rate 1.50% The annual cost of the 20-year LOC, based on industry experience.

PTC

PTC Base Year ($/MWh) 15.00 Energy Policy Act of 1992

200 7 Inflation Adjustment Factor 1.3433 Page 14862 of the 2007 Federal Register (volume 72)

200 2007 inflation adju stment factor inflated by 2% assumed inflation 8 Inflation Adjustment Factor 1.3702 2008 PTC Rate ($/MWh) 21.00 $15/MWh multiplied by 1.3702 and rounded to the nearest integer

Yea rs Available 10 Qualifying projects ca n currently claim the PTC for 10 years.

S TAXE

Stat e 6.0% Representative state tax rate.

Federal 35.0% y assumption for Federal corporate tax rate. Standard i ndustr

DEPRECIATION ALLOCATION

Hard Costs Development Costs Indirect

Wind Turbines

Balance of Plant Direct 5-yr MACRS

Interconnection Direct 20-yr SL Soft Costs Interest During Construction (IDC) Indirect Debt Closing Costs (when debt is used) Direct 15-yr SL Debt Closing Fee (when de bt is used) Indirect

Debt Service Reserve Equity Closing Costs Working Capital Non-Depreciable

Developer Fee Indirect Contingency (5% of Hard Costs) Indirect Estimates are based on indus try experience. Items labeled as “Indirect” are depreciated using the same sche dules in the same proportions used for directly depreciable assets in aggregate. For example, if 90% of all directly depreciable costs or asse ts are depreciated using 5-year MACRS, then 90% of all “Indirect” co sts will also be depreciated using 5-year MACRS.

These high-level allocations are meant to be representative; actual allocations are highly cost-item depe ndent. Specific advice from tax counsel and accounting firm s is highly recommended.



### 61

### In several instances, the model draws upon basic project assumptions used in the 20% Wind oject being conduc ed jo intly by the DOE and AWEA. 59 

### Since the Wind lready b ed w hem

rather than creat erent plified (e.g., cost items), the fact th epo nces in the ures rather than craft g a mode l of a potential real project allows for such Notwithstanding thi model is set up to accept more-detailed assumptions as ed appropriate by future users.

ject assumptions such as the project’s annual net capacity factor (a measure of energy

inflation rates are shown in Table B1. The 100 MW project size is m representative of the uti ale w he capacit d av

uilt in 2004 or 2005 e cap mportant for projects

oth the amount of energy produced for sale and the amount of PTCs generated.

T (2.0 inf

assum mation Administrat model has the option of escalating p price t. As

n ave assum at rev ong-term hase a

s.

d” – i.e. not inclu finan $160 million roughly consisten h data n in rge portion of the ha ts are i.e. the financing costs, are specific to each fi nancing scenario and consequently vary across the

re lating to de show total projec The

rtant to the investo rns. A be depreciated over the f five y d celerated Cost Recovery System ar M ount over

years generates large deprec iation charges in the early years that tax-based investors can use ther operation Most o aining total cost of wind power projects er depreciated using several other sche dules (including 15-year MACRS and 15- and 20- ne schedules), is ind lloca

allocations for ta

h tax convention. P e

rpose are n

M cost ptions in the model are taken from the DOE/AWEA n Analysis . These numbers a Vision Analysis pr t

Vision ass umptions have a een vett ithin the wind industry, this report has used t where appropriate ing di ff assumptions. Although some of the Wind Vision assumptions are sim O&M s are aggregated rather than broken out into

individual co st ing struct at this r rt’s focus is on comparing differe

financ in simplification. s, the may be deem

al pro Gener production), capacity, and

eant to be lity-sc ind projects currently being developed. The 36% capacity factor reflects t y-weighte er age 2006 capacity factor of a sample of utilityscale projects b

. 60 

### Th acity factor is partic ularly i

as it determines b

he table lists a two percent %) annual lation rate. This is in line with the inflation rate ed in the Energy Infor ion’s most recent Annual Energy Outlook

. The s by inflation over time or l eaving them fla 61



### ower oted earlier, th e authors h

l ed th enue s are not inflated, i.e., t hat the power price is

range ment. Thus, the inflation rate is only used fixed at the outset under a p rc u r to increase operating expense

The aggregate “har ding cing costs – capital cost estimate of (or $1600/kW) is t wit on recent installed project costs. 62 

### As see Table B1, a la rd cos comprised of the wind turbines. The soft costs,

structures (soft c osts bt are n in Table B3 ). T he hard and soft costs add together to generate a t cost. treatment of project cost s for tax depreciation purposes is impo r retu s a general rule, roughl y 90-95% of the project

costs can irst ears of project life using the 5-year Modifie

A c (5-ye A CRS). Depreciating such a large am

five

to offset income from o s. f the rem

is eith year straigh t-li irectly a te d, or is non-depreciable. The cost of items that

o cated proportionally to the other categories, in depr eciation allocation figures used in this study ot meant to be used for specific projects. are indirect x purposes is all keeping wit lease note, th

are sim plified for illustrative pu s nd a

The fixed and variable O& assum 20% Wind Visio re meant to be inclusive of all operating costs,

om/releases/ ept_Wind_Industry_Action_Plan_060506.html 59 See www.aw ea.org/newsro Energy_D

60 As presented in Wiser and B olinger (200 it.

61 See the GDP chain-type price index found at www.eia.doe.gov/oiaf/ aeo/excel/aeotab_19.xls 7), op. c

. 62 As presented in Wiser and Bolinger (2007), op. cit.



### 62

### including items such as land lease payments, prope rty taxes, insurance, management fees, etc.

The model does have line items for each of these de tailed cost items in th e event that a future

user desires to break ou t individual components.



## Structure-Specific Assumptions

In addition to the common assumptions described in the previous section, the calculation of the cost of energy for each scenario relies on cer tain financing assumptions specific to each particular structure. These rela te to two asp ects: (i) the cost of financ ing provided under each

ructure, and (ii) where applicable, the allo cations of the project’ s cash and Tax Benefits

investors requiring the lowest minimum IRR. It is important, owever, to put the use of the IRR into context. Project-specific f actors influence the IRR

uctures ave become better defined, the number of Tax Inve stors willing and able to make efficient use

greater than the supply of solid projects, competition has been fostered among capital sources

tor IRR levels st between the different types of e quity investing in the project.

The costs of debt and equity financing are expre ssed in different ways. The cost of financing from Tax Investors typically is negotiated in term s of the IRR required by the investor. In cases where the Tax Investor’s or developer’s IRR is magnified due to a low initial contribution, developers and investors sometimes also look at the net present value of their investment, or other metrics. Tax Investors typi cally also consider the develope r’s return to ensure that the developer has sufficient exposure to be motivated to perform its obligations. Tax Investors set their required IRR to account for th e relative risk associated with the project. In general, the higher the perceived risk of the project, the higher the required I RR, and vice-versa. Currently, wind project developers solicit equity capital from multiple sources and, assuming all other factors are held equal, will favor

h requirements negotiated between the developers a nd Tax Investors. Tax Investors will adjust their requisite IRR based on the perceived risks of a given project. They will seek a higher IRR to compensate for the added risk of debt at th e project level. In addition to the calculable financial returns, investors will adjust their requisite IRR to reflect qualitative risks across projects or in the timing of the financial return s. For example, a wind project with only shortterm or even no power or REC purchase agreements in place is typically considered to be more risky than a project with a long- term off-take contract. Sim ilarly, a wind project with most benefits occurring later in the project life is co nsidered more risky than one that relies more on returns generated early in the project life, even if each project shows the same IRR. Project developers can meet a Tax Investor’s IRR target by adjusting the relative allocations of cash and Tax Benefits as well as the level and timing of certain fees paid to the developer. The power sales price is another potential le ver that can be adjusted, if not already fixed in a power purchase

agreement.

IRR levels in the wind sector are also affected by the relative supply of equity capital predisposed to invest in these projects. Since 1999, as the market has matured and the str

h of the Tax Benefits has gradually expanded. Devel opers of solid wind proj ects currently are able to solicit third-party equity capital from multiple sources. With the suppl y of capital currently

and, along with other factors, this has contributed to a broad decl ine in Tax Inves ibuting factors are not ed in Chapter 2. for wind projects in recent years. Other c ontr

63

### 64 ions between each partner. For example, for a eriod of time all of the cash could go to the devel oper while all of the Tax Benefits could go to rt provides details about the varying cash and Tax Benefit llocations specific to each structure.

t in vestments, the developer and rospective Tax Investor will nego tiate the level of the IRR require d by the latter. Therefore, to

and allocations shou ld be considered merely indicative; actual percentages will ary by project according to relative project value. A key facet of several of the financing structures is a differential alloca tion of the cash and Tax Benefits to the project developer and the Tax Investors. It is im portant to note that the cash and Tax Benefits can be allocated in varying proport

p the Tax Investor. Chapte r 3 of the repo

a

These allocations can vary both in terms of percentage amounts a nd over time. The rationale for these allocations, as well as their impact on the respective IRRs for the developer and the other investor(s), vary by the financi ng structure. Chapter 3 describes these influences and impacts for each of the financing structur es. For actual wind projec

p facilitate comparison of the effective cost of energy across the various fi nancing structures, the report assumes an IRR target value and target da te for the cost of Tax Investor capital for each structure. The cost of energy is the price th at yields the required Tax Investor return.

Due to the differential allocations in amount s and timing mentioned above, the IRR for an overall project will vary from the respective IRRs for the project developer and the Tax Investor. While it would be possible to de velop a single weighted-average of the IRRs for the different investors, the report does not use this approach fo r the structures accessing third-party capital, as such averages are not used in actual practice a nd thus are not readily comparable to market conditions. Instead, the author s assume an IRR required by a Tax Investor and percentage

allocations of cash and Tax Benefits under each fi nancing structure. The model determines the required price of power to achie ve the stipulated 10-year IRR for the Tax Investor, and then calculates the resulting IRR for the project a nd the project developer. For the Corporate structure, the model determines the required price of power to achieve the stipulated 20-year IRR for the developer, which in this case is the Corporate investor.

Table B2 summarizes the equity-related financing a ssumptions that are specific to each structure. For those structures involving more than one i nvestor (i.e., with e quity capital from a Tax Investor as well as the project de veloper), the table show s the percentage allocations of the initial equity contributions, cash returns, and Tax Bene fits to the project developer and to the Tax Investor. For those financing structures where the allocations change over time, the allocations prior to and after the Flip Point are listed. The flip occurs when the returns to the Tax Investor have reached the agreed upon IRR target (also shown in Table B2). 63 

### All of these percentage

contributions

v

63 If project performance does not meet initial expectations, then the Tax In vestor likely will not reach its IRR target

n schedule (at the end of 10 years), in which case the Flip Point will simply be delayed until the target is met. In this way, Tax Investors are somewhat shielded from performance risk. o

### Table B2. Structure-Specific Equity Financing Assumptions

VALUE ASSUMPTION Developer Tax Investor NOTES

PART NERSHIP ALLOCATIONS Eq uity Contributions Corporate 100% N/A Constructed on the balance sh eet of a single entity with tax appetite

. Strategic Investor Flip Cash Leveraged Cash & PTC Leveraged 1% 99% Because these structures are used by developers with limited capita developer equity will be a low number. Developer equity can vary l,

slightly, but this is a standard industry assumption.

I

B nstitutional Investor Flip ack Leveraged 40% of total capital. 40% 60% Though project-specific, de veloper equity typically ranges from 20% to

Pay-As-You-Go 45% 55% Developer equity typica lly ranges from 40% to 60% of total capital.

Ca sh Allocations Pre-Flip Cash Corporate 100% N/A This structure in volves only one investor, so no flip. Strategic Investor Flip Cash Leveraged Cash & PTC Leveraged 1% 99% Pre-flip sharing ratios are pro rata with equity interests in these

structures.

Institutional Investor Flip Back Leveraged 0% 100% The developer gets 100% of th e cash until it earns a return of its capit after which the pre-flip allocations reflect those shown here. al,

Pay-As-You-Go 30% 70% Developer re ceives substantial cash to refl ect its hig h equity investment.

P ost-Flip Cash Corporate 100% N/A This structure in volves only one investor, so no flip. Strategic Investor Flip Cash Leveraged Cash & PTC Leveraged Institutional Investor Flip Back Leveraged 90% 10%

Pay-As-You-Go 95% 5% Estimates based on industry experience . The post-flip sharing ratio transaction-specific. As a general ru le the Tax Investor share will no go below 5% for tax opinion reasons. The figures here were sized to obtain an industry estimate of the 20-year Tax Investor return being 50- 70 basis points higher than the 10-year return. is

t

Ta x Benefit Allocations Pre-Flip Tax Corporate 100% N/A This structure in volves only one investor, so no flip. Strategic Investor Flip Cash Leveraged Cash & PTC Leveraged 1% 99%

Institutional Investor Flip Back Leveraged 0% 100% Estimates based on industry experience. In all cases virtually all of the pre-flip Tax Benefits (i.e., PTC and depreciation losses) are allocated

the Tax Investor – i

Pay-As-You-Go to .e., the partner that can efficiently use them.

Post-Flip Tax Corporate 100% N/A This structure in volves only one investor, so no flip. Strategic Investor Flip Cash Leveraged Cash & PTC Leveraged Institutional Investor Flip Back Leveraged 90% 10%

Pay-As-You-Go 95% 5% Estimates based on industry experience . The post-flip sharing ratio transaction-specific. As a general ru le the Tax Investor share will n go below 5% for tax opinion reasons. The figures here were sized to obtain an industry estimate of the 20-year Tax Investor return being 50- 70 basis points higher than the 10-year return. is

ot

IRR TARGET (10-year Tax Investor target, except for the Corpor ate structure, which is a 20-year developer target)

Co for

r the nal cost of funds likely paid by unregulated utility subsidiaries and other large entities that us e the Corporate structure. rporate 10.00%
(20-yr target) N/A This is the developer’s 20-year target , since it invests in the project its lifetime and does not seek any outsi de capital. 10% is a proxy fo

inter

Strategic Investor Flip N/A 6.50% This 10-year target is at a slight discount to the developer’s 10-year IRR computed for the Corporate structure. The discount reflects the Tax Investor’s avoidance of developmen t/construction risks and receipt of most project flows until achieving its target IRR. Very few projects have used this structure in recent years, making this estimate uncertain.

Institutional Investor Flip Pay-As-You-Go Back Leveraged N/A 6.50% The estimates for these all-equity structures are based on industry experience for an average-quality wind project. Since the Back Leveraged structure involves debt onl y at the developer (not project)

d. level, from the Tax Investor’s perspec tive, this structure is unlevere

Ca sh Leveraged N/A 9.00%

Ca for veraged is due to the added PTC tranche of debt. sh & PTC Leveraged N/A 9.25% The premium over all-equity structures reflects the greater default risk born by the Tax Investor. The 25 basis-point incremental premium

Cash & PTC Le



### 65

### Table B2 illustrates the s med allocation percenta the target equity

rious fina ncing structures. The rationale s for the allocation differences Chapter 3 e values them

ter 4.

g structures have projectee loan meters e th wind project: the interes , th e tor typically quote interest rates as spread over LIBOR. In stitutional lenders such e companies instead ote ost debt

discussions are LIBOR-based. Le nders typically require borrowers rest rate risk, which usually means swapping th ting of the loan. Hedging costs to fix the intere st rate are added at the tim 64



### The DSCR is a measure o proje ope

ments on the loan. A DSCR of 1.45:1 means that the project is obliged to generate operating cash flow in a given time pe e.g led debt service obligations, principal and interest, durin based on their perception of a project’s risks.

lev with seasonal wind pat schedule for a given wind project. Such schedu support more mortgage-style or fixed-pr incipal amortization sche dules. The loans are

n a limited recourse ba sis, where the lated cash flows and assets for repayment sec typically

inc d guarantee m the T ves

Ta pecif ebt financing as

inc bt. As with the assumptions ou tlined previously, the values assumed here are

te recent m rket conditions. owever, these assumptions are not derived from any specific existing project or proje nor spective projects, absent adjustment to incorporate th

as odified as deeme rop difference in the assu ges and

IRR rates across the va

are discussed in . Th se lves are indicativ e of recent market levels, as discussed in Chap

Two of the financi n el. Thr level debt, while one has debt at the developer

e mo st effect in determining the size and cost of company lev para hav

the loan for a t rate loan term, and the DSCR. Commercial banks in

the wind sec a

as c insuran may qu spr eads over U.S. Treasuries, but m to hedge the inte

e floa interest rate for one that is fixed for the duration e of closing.

f the cted rati ng cash flow available to meet interest and principal pay riod,

., one year, equal to 145% of the schedu g such time period. Lenders will set these terms Lenders use these tools and projected revenue

te rns) to customize a loan amount and repayment les typically allow wind pr ojects to els (which m ay vary

debt than would provided o lenders look principally to the project-re urity for the loan (the PTC loan also and

ludes a limite fro ax In tor).

sumptions used by the model for those structures ble B3 outlin es the s ic d orporating de

intended to illustra a H

cts, are they appropria te to utilize for pro

e risk profile of the specific project. These riate by future users of the model. sumptions can be m d app

64 The Federa floating 3-mo l Reserve Bank upd n a dai For

nth LIBOR rate to rates of te rm

serve. gov/releases/h15/u ates o
fixed ly basis

various m H.15, which provides indicative costs of swapping a s (e.g., see the “Interest Rate Swaps” section of http://www.federalre pdate/ ).



### 66

### Table B3. Structure-Specific Debt Financing Assumptions

ASSUMPTION VALUE NOTES

TERM DEBT (project-level debt backed by cash flows or a pledge of PTCs)

Cash Flow Debt Debt Tenor (Years) 15 Standard term given a 20-year PPA with a creditworthy counterparty.

All-In Annual Interest Rate 6.70% 10-year (estimated average life of the loan) swap rate of 5.20% plus a constant spread of 150 basis points. Th e constant spread is a simplification from common industry practice of lower rates in the early years, followed by rising rates in later years. Debt Service Coverage Ratio 1. 45 Standard industry practice.

PTC Debt Debt Tenor (Years) 10 Standard term coinciding with duration of PTCs. All-In Annual Interest Rate 6.70% Same assumption as term debt. Debt Service Coverage Ratio 1. 45 Standard industry practice. Both “Cash Leveraged” and “Cas h & PTC Leveraged” Structures Debt Closing Costs 400 Based on industry experience (legal f ees, technical consu ltants).

Total Debt Closi ng Fee Calculation industry practice. Specif ic dollar amount is calculated by the model. Assumes a fee equal to 1.25% of the loan amount, based on standard

Debt Service Rese rve Calculation Assumes an amount equal to 6 months of debt service obligations, based on standard industry practice. Speci fic $ amount calculate d by the model.

Annual Debt Agency Fee ($000 flat) 25 & 40 The lower estimate is for the Cash Leveraged structure and the higher estimate is for the Cash & PTC Leveraged structure (the added tranche of debt in the latter yields a higher cost per year).

BACK LEVERAGE DEBT (debt secured by the developer, rather than by the project itself)

Debt Tenor (Years) Calculation (5.5 years in base case) Though there are different structures in the market, it is common for the

amortization to be based on a nomina l 15-year tenor. However, cash sweep provisions reduce the actual tenor to well under ten years. For simplicity, the template model ties the term to the period of time needed for the developer to recoup its initial investment (on grounds that the

lender will not want to have the loan outstanding for longer than the developer’s own exposure). All-In Annual Interest Rate 6.70% Same assumption as term debt. Debt Service Coverage Ratio 1. 45 Standard industry assumption.



### The table lists two forms of de bt financing used at the proj ect-level. While both are limited recourse financings, they vary in the sources of cash to repay the loans. Cash Flow Debt refers to debt financing extended on the ba sis of the cash flow generated fr om the sale of the electricity and RECs from the project. Th ese cash flows are the source of funds to repay the loan. PTC

ebt refers to a loan facility supported by the guarantee of incremental periodic equity D

c ontributions provided by the Tax Investor receiving the PTCs ge nerated by the project. As the PTCs are a non-cash item to the project, the bank requires a commitment from the Tax Investor to contribute, if necessary, any amounts required to make the scheduled PTC Debt principal and interest payments. The commitment to make such additional contributions effectively creates a second source of cash flow against wh ich the lender is willi ng to extend a second loan facility; in effect, the equity investor receiving the PTCs monetizes the future PTC benefits in order to

reduce its initial investment. The relative projected amount of the future PTC benefits, along with the terms above, determines the principal amount of the PTC Debt. The ten-year term of

the PTC Debt is tied to the te n-year period during which the PT C benefits are generated. In practice, some lenders to wind projects provide a single loan facility w ith a customized loan

amortization that consolidates Cash Flow and PT C debt. For transparency and clarity in this report, the model portrays them as separate loan facilities.

67

### The other type of debt listed above is leverage at the develope r company level, one step above he pro develope of debt to finan ce its equ stment in the project is

onal I the developer contributes a significant amount of up-front capital and re ceives 100% of cash

distr has recovere ts in ure. However, in the analysis there is no di

Insti as th in impact on the project. t ject-level. A r’s use ity inve nvestor Flip structure, in which known as “back leveraging.” This report uses the Instituti

ibutions until it d i vestment, as the basis for the Back Leveraged struct

fferen ce in the LCOE between the Back Leveraged and

the form er is at the developer level and therefore has no tutional Flip structure e debt

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## Appendix C: Overview of Part nership Tax Accounting Issues

Virtually all utility-scale wind projects involvi ng multiple investors use a special purpose limited liability company (“LLC”) to hold the assets of the project. An LLC with more than one member is usually treated as a partnership for U.S. federal income tax purposes. A key feature of partnerships is that they ar e generally not directly subject to U.S. federal income tax on their income. Instead, the partnership’ s taxable income or losses flow through to the owners of the partnership and are repo rted on the owners’ separate tax returns.

Allocations of partnership income or losses for tax purposes can di ffer from distributions of cash to partners. Partnership tax rules generally allo w items of partnership income and deductions to be allocated to each partner in any manner that is agreed upon by the partners, provided that the agreed-upon allocations have “s ubstantial economic effect” as required under the IRS Tax Code. To meet the “substantial economic effect” requir ement, the partnership must maintain capital accounts and must make liquidating distributio ns in accordance with positive capital account balances. In addition, the partne rship agreement must contain eith er (i) a defici t capital account restoration obligation or (ii) a number of regulatory allocation provisions, such as “minimum gain chargeback” and “qualified income offs et” provisions. These regulatory allocation provisions are generally designe d to prohibit partners from having deficit capital account balances when the partnership is liquidated. These “substantial economic effect” requirements and regulatory allocation provisions may have a significant impact on partnership allocations throughout the life of the partnership. As a resu lt, the financial model for a specific project should track changes in each partner’s capital account and adjusted tax basis in the partnership, as well as the impact of th e regulatory partnership alloca tions on partners hip operations. 65



### The complexity arises in reconciling these tax allocation and accounting rules with the desires of project developers and investors to direct project cash and Tax Benefits to the parties best able to make use of them. Agreeing to disproportionate cash distribut ions and tax allocations can violate these rules, absent specia l reallocations pursuant to the regulatory allocation provisions or compliance with certain exceptions. 66 

### The exceptions themselves can create contingent financial obligations on the partners such as deficit capital account restoration obligations requiring a partner to inject capital back into the entity in the event of a liquidation of the partnership or regulatory tax allocations that re quire allocations of taxable income to eliminate a partner’s capital account defici t prior to liquidation.

Non-recourse debt financing at the project level also adds to the complexity in allocating tax losses. In certain circumstances, gross income may be specially allocated to a partner to reflect a reduction in the potential taxable gain that would be recognized s hould the loan ever go into default and the lender foreclose on the assets (suc h an allocation is known as a “minimum gain chargeback”). This gain represents, in esse nce, that partner’s sa vings from avoiding the repayment obligation of the loan. These requireme nts interact with the partnership allocation

65 Since this report does not model a specific wind project , the finer nuances of these partnership issues are not included in the analysis.

66 For example, one partner with a negative capital account cannot be allocated additional losses (i.e., a capital account reduction) until the other partner ha s a capital account of at least zero. This rule, simply stated, is that a partner’s capital account cannot go “more negative” if the other partner’s capital account is positive.



### 69

### rules to further complicate the accounting. Other tax requirements also affect the odeling of partnership- based wind projects. financial

m

Allocation of the PTCs is also subject to potentia l adjustments. Pursuant to the partnership tax allocation regulations, PTCs must be allocated in the same manner as gross income from electricity sales (“GIFES”). To the extent ther e is a reallocation of GI FES due to partnership accounting issues discussed above, the PTCs may also have to be reallocated to the partners in percentages that are inconsistent with the original and negotiated agreement.

Partnership accounting rules are highly complex and can affect the economic return to both partners. Moreover, not all ta x attorneys agree on the specific manner in which PTCs can be specially allocated. Developers and investors should therefore consult thei r legal counsel and accountants for guidance.

70