REPORT 

POWER SUPPLY EVALUATION 

Virgin Islands Water and Power Authority

AUGUST 26, 2008 

1000 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 Power Supply Evaluation dated August 26, 2008. This report evaluates 

the Authority’s future electricity and water production 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 develop a scope of service for the preparation of 

a Power Supply Evaluation to evaluate the Authority’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 (“Georgetown”) have supplied 

a series of draft 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 the firm 

was requested by the Authority to finalize the report, 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 regarding the facilities of the Authority, including 

availability and cost of fuel supply and description 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 the information furnished by and obtained from such 

sources and offers no assurances with respect thereto. To its knowledge, the summaries 

presented herein accurately reflect the information 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 operating, capital, financing, and 

other costs of the Authority. Any such adverse changes would likely result in an increase in the 

projected costs of operating the Electric 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 representation of fact and are subject to being 

affected by fluctuating economic and regulatory conditions and occurrence 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 agreement 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 studies and analyses, and those of others included 

herein, as of the dates of those studies or statements. 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 changed conditions and such changed 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 include: Background, Description of Alternatives, 

Environmental Considerations, Description of cases and Results, Financeability, Principal 

Considerations and Assumptions, Conclusions and Implementation Plan. 

Based on the Principal Assumptions set forth in Section 6, and on the results of our analyses and 

review of reports prepared by the Authority and information provided by the Authority which is 

summarized or referenced to in this Power Supply 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 express our appreciation for the spirited cooperation and 

assistance given us throughout the course of this study by each member of management and staff 

of the Authority. 

Respectfully submitted, 
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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 Electric 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 Fluidized 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 CO2 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 CONSIDERATIONS 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 Considerations 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 client for the specific purposes identified in the 

report. The conclusions, observations and recommendations 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 

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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 Subordinate 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 Structures: A Review and Comparative 

Analysis 
Table of Contents 

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List of Acronyms 

Addendum Addendum to the Updated 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 

CO2 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 Subordinated 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 

NOX Nitrogen Oxides 

NPV net present value 

O&M Operation and Maintenance 

OES Obstruction Evaluation Service 
Table of Contents 

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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 

SO2 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, 1998 

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EXECUTIVE SUMMARY 

Executive Summary 

The primary purpose of this Power Supply Evaluation 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 technologies and fuels, 

(iii) To compare the cost of utilizing reverse osmosis technology with existing water 

production technology and costs, and 

(iv) To serve as a basis for evaluating responses to the Request for Proposal (“RFP”) 

to Provide Electric Energy to the Virgin Islands Water and Power Authority. 

As envisioned by the Authority and the Public 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 Bed (“CFB”) units burning pet-coke supplied by 

HOVENSA from its St. Croix facility and Columbian coal fuel, 

 Wind Powered Units 

(ii) The Authority should consider other fuel supply options such as methanol and 

Liquefied Natural Gas (“LNG”), electrical interconnection alternatives, and 

(iii) Reverse Osmosis water production units should be considered as feasible 

alternatives to the existing Multi-Effect Distillation (“MED”) water production 

units and for future expansion. 

Based on the Fatal Flaw Analysis, and in concert with representatives of the PSC, cases were 

developed that involved utilizing various combinations of existing resources, CFB coal fueled 

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

(i) the use of methanol or LNG as a fuel supply with the existing generation 

resources, and 

(ii) installing a high voltage, direct current submarine cable to connect the electric 

systems of St. Thomas and St. Croix. 
EXECUTIVE SUMMARY 

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

The above combinations were evaluated under two different electrical load scenarios (Base 

Load and High Requirements Load) and two different environmental compliance scenarios 

(with and without CO2 allowances). Recognizing the various resources, load, and 

environmental considerations resulted in a total of forty-eight (48) cases being developed and 

evaluated. 

Graph No. ES-1 has been prepared that compares 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 the trade-off between capital investment, and NPV 

cost reductions relative to the existing power and water production systems (“Existing 

Arrangement”). Based on the graphical depiction, the cases plotted in the lower left-hand 

quadrant represents cases that involve relatively low capital investment and high cost reductions 

relative to the Existing Arrangement. As shown on Graph No. ES-1, alternatives involving 

LNG fuel (Existing Arrangement operating on LNG [Case 1-3], Existing Arrangement 

operating on LNG fuel, plus the installation 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 have 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 nearest to the center of the 

matrix, which indicates that such cases represent the next best alternatives in terms of a balance 

with respect to capital investment 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 Summary shows projected retirements, and capacity 

additions over the 20-year period from 2007 through 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 “Financial Assumptions” on 

Table B. All of the projects are assumed 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 levelized 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 are projected to be approximately 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 projected to range from approximately $196 million to 

$432 million in 2008 dollars based on current cost projections and general escalation 

assumptions. 

The next steps involved in proceeding with these plans are described later in the Report under 

the section entitled “Implementation Plan.” 
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Graph No. ES-1 

Base Load Forecast Without CO2 Charge

NPV Costs versus Capital Investment Matrix

Exist

Methanol

LNG

CFB

CFB, RO,

Interconn

Exist, Wind

LNG, Wind

CFB, RO,

Wind

LNG,

RO

0

100000200000300000400000500000600000700000800000900000

1000000

-1000000 -800000 -600000 -400000 -200000 

NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000)

Base Load Forecast Without CO2 Charge

NPV Costs versus Capital Investment Matrix

Exist

Methanol

LNG

CFB

CFB, RO,

Interconn

Exist, Wind

LNG, Wind

CFB, RO,

Wind

LNG,

RO

0

100000200000300000400000500000600000700000800000900000

1000000

-1000000 -800000 -600000 -400000 -200000 

NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000) Exist Methanol LNG CFB 

CFB, RO, Interconn Exist, Wind LNG, Wind 

CFB, RO, Wind 

LNG, RO

0

100000200000300000400000500000600000700000800000900000

1000000

-1000000 -800000 -600000 -400000 -200000 

NPV Cost Difference vs. Existing Arrangement ($000)

Additional Capital Investment ($000)
EXECUTIVE SUMMARY 

ES-4 R:\005141\05-0141

Table A 

Virgin Island Water and Power Authority 

Power Supply Evaluation Implementation Summary 

Case Name Case Description Retirement[1] Additions[1] Inf

 Unit No. MW Year Type Unit MW Year Ty

1 - 3 Existing arrangement LNG 

Fuel 

 None None LN

1 – 3 W Existing Arrangement with 

LNG Fuel and Wind 

 None Wind 10 2012 LN

1 - 4 CFB Units St. Thomas St. Thomas 12 12.5 2012 CFB 20 2012  14 12.5 2012 

St. Croix St. Croix

 10[2] CFB 20 2012 1 – 4 W CFB Units with Wind St. Thomas St. Thomas 12 12.5 2012 CFB 20 2012  14 12.5 2012 

St. Croix St. Croix

 10[2] CFB 20 2012  Wind 10 2012 1 – 9 Existing arrangement with 

LNG Fuel , replace water system with R. O. 

St. Thomas St. Thomas RO Sy

 None None Retirement 

St. Croix St. Croix RO Sy

 None None Retirement [1] Timing of additions and retirements assumed to be 2012 for purpose of the Power Supply Evaluation. Actual timing will be subject to further study. 

[2] To be placed on standby status or retired. 
EX

ES-5 R:\005141\05-0141

Table B 

Total Projected Capital Costs by Case 

($000) 

Case # and Description 1-3 1-3W 1-4 1-4W Capital Costs [1]

Existing 

Arrangement 

LNG Fuel

Existing 

Arrangement 

LNG Fuel and 

Wind

CFB Units CFB Units with 

Wind

 St Thomas

1 MED Capital Improvement 23,650 23,650 23,650 23,650 2 20 MW CFB 0 0 177,640 177,640 

 St Croix

3 MED Capital Improvement 22,575 22,575 22,575 22,575 4 10 MW Wind Turbine 0 30,000 0 30,000 5 20 MW CFB 0 0 177,640 177,640 6 LNG Capital 150,000 150,000 0 0 7 RO Systems 0 0 0 0 8 Total 196,225 226,225 401,505 431,505 

 Financial 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 

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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 existing 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 alternatives evaluated. Actual debt service coverage will depend upon, among other factors, the 

amount to be financed.
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Section 1 

BACKGROUND 

1.1 General 

In the pursuit of identifying the lowest cost, reliable supply of electricity and potable 

water for the Territory, 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. Representatives of the Authority and the firm and in 

collaboration with representatives of Georgetown developed a scope of service for the 

preparation of a Power Supply Evaluation to evaluate the Authority’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 have supplied a series of draft 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 the firm was requested by the Authority to 

finalize the report, 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 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 Authority’s cost of electric power and water 

production and simultaneously reduce its dependence on fuel oil. 

Because of the historical development of the Water System and certain characteristics 

unique to the U.S. Virgin Islands, the Water System serves a small portion of the 

potential customers in the U.S. Virgin Islands. Among such factors is a U. S. Virgin 

Islands building code requirement that, with 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. Thomas and St. John, the construction of the 

water distribution system has been difficult and costly. 

To meet potable water needs, most residential and commercial customers connected to 

the Water System rely on rainwater collection 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 storage 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 the desalination of seawater and the local 

building codes that, for the most part, require the construction of rainwater collection 

and storage facilities in most residential and 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 alternatives to be evaluated. The evaluation 

of the limited number of electric generation alternatives included: (i) Wind Powered 

Electric Generation Resources; (ii) Operating Efficiency Improvements (additional 

heat recovery steam generation); (iii) Waste to Energy Power Production; (iv) 

Circulating Fluidized Bed (“CFB”) Coal/Pet-coke Fueled boilers; (v) Slow Speed 

Diesel Electric Generation; and (vi) Oil/Gas Fueled New Combined Cycle Generation. 

In addition to these technology based alternatives, the parties 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 Analysis1 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 determine if RO technology should be considered 

further as a replacement for all water requirements on the islands of St. Thomas and 

St. Croix or incremental requirements only. 

For the production of electricity and potable water, the Fatal Flaw Analysis gave 

consideration to: (i) Operating constraints; (ii) Siting alternatives (impediments to 

installing necessary infrastructure); (iii) Fuel supply and pricing (busbar screening, 

availability of fuel supply); (iv) Environmental permitability; and (v) Capital and nonfuel operating costs. 

The Fatal Flaw Analysis concluded that2

: 

“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 the HOVENSA St. Croix refinery and 

Colombian Coal, and 

B. Wind Power Units. 

2. Retrofitting CT [combustion turbine] Unit 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 fuel diversity and the capacity of the 

combined cycle unit is likely to present system operation reliability issues. 

 

1

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

2

 Ibid. 
BACKGROUND 

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3. The slow speed diesel, the municipal 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 existing 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 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 [favorable fuel cost] differential will be eroded and 

the projected economic benefits from the high capital investment may not be 

realized. 

6. Feasible sites have been identified for locating generating plants utilizing the 

various technologies as follows: 

A. CFB Plant – St. Thomas: at Grambokola Hill and near the Bovoni 

landfill. St. Croix: at the Authority’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 required 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 [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 for the continued operation of the existing 

power plants. However, it may prove to be feasible... [and] where a large 

portion of the existing generation is replaced 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 address 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 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 issued by the Authority on December 28, 2007. 

The purpose of the RFP was to solicit proposals 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 provide a 20-year Purchase Power Agreement 

(“PPA”). The Authority’s stated goal in the RFP is to displace as much oil fueled 

energy as possible, taking into consideration 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 proposals were due by May 1, 2008. 

The proposals received by the Authority are being evaluated against the lowest cost 

power supply plans resulting from this power supply evaluation to determine if adding 

such proposals to the Authority’s lowest cost generation portfolio would result in 

further cost reductions, in improved fuel diversity, 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 facilities 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 island 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 additional source of steam for water production on 

the island of St. Thomas, the Authority installed a waste heat recovery steam generator 

(“HRSG”), sometimes referred to as a “waste heat boiler.” The HRSG was 
BACKGROUND 

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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. Thomas for the desalination 

of water. 

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

located at the Estate Richmond site on the north shore of the island near Christiansted. 

In addition to generation facilities, the Estate Richmond site includes water 

production, fuel oil unloading and storage and warehouse facilities. 

The Authority is proceeding with the installation 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 combined-cycle 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 on the island of St. Croix. 

To improve generation efficiencies and to continue 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 No. 23; its newest combustion turbine generating unit. 

However, this option does not improve the system’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 level of spinning reserves required in order to 

operate the unit at optimum efficiency and at the same time, maintain the ability to 

withstand the loss of the unit while maintaining 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 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 

lives. At this time, the Authority has not established 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 resources become available. Furthermore, with 

the addition of a second HRSG at the Estate Richmond Generating 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 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 normal rating 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 maintenance. 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 and combustion turbine electric generation 

units is shown on Table No. 1. 

1.4.2 Existing Water Production Facilities 

To produce potable water, the Authority operates nine multi-effect desalination units 

(“MED”): four desalination units are located at the Randolph E. Harley Generating 

Station and four units at the Estate Richmond Generating Station and one unit on St. 

John. In order to produce potable water, the desalination units require both high 

pressure steam (150 psig) and low pressure steam (26 psig). This steam is extracted 

from the steam turbine generating units or supplied 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 compression-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 Corporation for the wholesale purchase of 

desalinated water produced by a reverse osmosis 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 island of St. Thomas is placed 

in service in June 2008. 

Primary potable water production on the three 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 utilizing 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 supplied to the individual island 

water distribution systems. All of the distillation desalination units currently in 

service were designed and constructed by Israel Desalination Engineering, LTD. 

(“IDE”). 

Due to the age of a number of the desalination 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 Industries, Inc. to prepare a Useful Life 

Assessment (the “Useful Life Assessment Report”) of all the desalination 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 island 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 Assessment 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 attaining 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 Thermal 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 Report and the continuation of the existing 
BACKGROUND 

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maintenance procedures, the Authority reports that it has extended the service life of 

the desalination units to 30 years and has revised 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 Desalination 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 Evaluation, it has been assumed that if new RO 

facilities are not installed to replace the existing IDE units, the 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 isolated electric generation and distribution 

systems, and given that the Authority's demand and energy requirements do not 

deviate significantly by season, the Authority, like other isolated electric systems, is 

required to maintain a higher level of generating reserves than interconnected electric 

systems 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 calls for the Authority to have sufficient generating capacity on 

each island to meet its respective electric load 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. The use of these planning criteria has been 

affirmed by the PSC in subsequent orders. 

On the island of St. Thomas, the two largest units are Unit No. 13, a steam turbine 

generator with a reported net 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 turbine 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 cycle operation. Based on HGI’s Condition 

Assessment Study Report, the recommended configuration on the island of St. Thomas 

that meets recognized reliability constraints3

 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 steam 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 handling steam and electrical demand over a full 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 island of St. Croix that meets recognized 

reliability constraints4 assumes that combustion turbine Unit No. 16 and Unit No. 20 

supply waste heat to the new HRSG, which is under construction. Upon completion 

of the new HRSG, steam turbine generators 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 drive 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 the desalination plant on a continuous basis. 

Under the new operating configuration with the new HRSG, the improvement in plant 

efficiency associated with eliminating the steam supply to the existing desalination 

facilities is projected to be less on the island 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 energy requirements, sales and 

customer growth, usage patterns and other 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 normal maintenance and repairs of its existing 

facilities in accordance with normal prudent utility practice. 

To reflect the potential for a higher than expected electrical load, a “Higher 

Requirements” load forecast was prepared as a sensitivity case. This “higher” load 

forecast assumed no reduction in unaccounted-for losses and annual growth rates of 3 

percent and 1.5 percent for the islands of St. Thomas and St. Croix, respectively. 

 

4

 Ibid. 
BACKGROUND 

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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 total 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 reduce non-fuel maintenance expenses by 

approximately $8.1 million dollars per year (2007 dollars). Maintenance costs on 

existing combustion turbine units 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 total cost to maintain the existing MED water production 

facilities in operating condition for the duration of the study period, it was determined 

that substantial capital improvements would be required for each unit on a regular 

basis. The Authority recently 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 developed to reflect the estimated cost and schedule for 

major maintenance of the water production facilities. These costs were included in the 

model for each case when the existing water production is retained for the duration of 

the study period. 

1.4.7 Water System Operations and Maintenance Expenses 

The Authority’s historical water related 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 through 2007. Also shown on this table is the 

portion of the Authority’s water related operating expense that is fuel related. The 

remaining water related production costs are non-fuel operation and maintenance 

costs. Based on the average non-fuel water related operations and maintenance costs 

reported over the years 2003 through 2007, a projected value of approximately $5 

million dollars per year (2007 dollars) was assumed. It was also assumed that in cases 

in which a new RO system would replace the existing desalination system, this annual 

expense can be eliminated. 

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Section 2 

DESCRIPTION OF ALTERNATIVES 

2.1 Existing Arrangement 

The Authority’s existing arrangement alternative is assumed to be a continuation of its 

existing oil fueled electric system and 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 assumed that the existing 

desalination process will be refurbished from time-to-time and will not be retired or 

replaced. Under the Higher Requirements load forecast scenario, a 40 MW 

combustion turbine is assumed to be installed in 2016 on the island of St. Thomas, 

coinciding with the retirement of steam Unit No. 12 and Unit No. 14. 

2.2 Methanol Fuel Supply Option 

This alternative involves converting locally available 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 plant with a methanol 

production capacity of one million gallons per 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 combustion turbines on methanol fuel, it is not 

aware of any facility that burns methanol as a fuel for 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 generating resources on each island 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 transportation 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 shown 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 per MMBtu by 2036. The cost escalation of 
Section 2 

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approximately 0.6 percent per year is the result 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 Fuel 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 analysis of the feasibility of converting the 

Authority’s existing fuel oil fired power plants on the islands of St. Thomas and St. 

Croix to natural gas fuel. Two forms of natural 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 quantities 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 Report, the capital costs associated with this 

scenario including purchasing the LNG ship, 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 LNG from Puerto Rico. In addition to the 

capital costs associated with adding infrastructure for the LNG facilities, further 

capital costs of $5 million per generation site are estimated for the conversion of 

existing fuel oil fired steam boilers and combustion turbines to natural gas and to 

provide the required natural gas infrastructure 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 supply and power plant conversion is provided 

in tabulation below. 
DESCRIPTION OF ALTERNATIVES 

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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 costs 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 conversion 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 attributed 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 Price 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 monthly 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 monthly Henry Hub forward prices to 

calculate an average annual price and adding the total cost adder of $2.22/MMBtu. 

 2010-2030 prices were developed using the annual average 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 plant conversion costs 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 Refinery on the island of St. Croix. 

However, for the purpose of economic modeling, 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 plant design. However, this can be done as a 

part of the plant optimization if this option is selected for implementation by the 

Authority. 

Technical and cost data used in modeling the CFB plant sizes and configurations used 

in the evaluation are shown in the tabulation below. 
DESCRIPTION OF ALTERNATIVES 

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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 that price annually by escalation factors 

calculated from the AEO 2007 coal price forecast in nominal dollars. The AEO coal 

price forecast in nominal dollars was developed 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 price forecast. The firm recognizes that 

there is a potential benefit to be gained by the Authority if a discount 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 negotiation 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 pet-coke delivered to the Authority are 

provided in Table No. 8. The use of lower cost pet-coke and coal would reduce the 

Authority’s dependence on oil. However, there may be socio-political issues that need 

to be addressed. 

2.5 Wind Turbine Generation 

Based on the Fatal Flaw Analysis, wind turbine generation was identified as one of the 

power generation technologies that is projected 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 the 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 that the wind resource is diminished or lost. 

Because of the difficulty in transporting components of the wind turbine generators to 

suitable locations in the Virgin Islands, the 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 generating resources similar to the Vesta V52 

(850 kW) with a total (wind farm) rated capacity of approximately 10 MW. We 

understand Vesta no longer manufactures the V52 turbine; 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 costs at an estimated $50/kW-yr. 

In April 2006, a report titled “A Detailed Wind Energy Case Study for Point Udall on 

St. Croix, Crown Mountain on St. Thomas and Estate Concordia on St. John” was 

prepared for the Virgin Islands Energy Office, 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 resource 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, directional variations, seasonal variation, frequency distribution, 

and correlation with a long term source (for the 10 meter height only), for a five month 

period that excluded the traditionally 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 Wind Atlas of the United States, and air and 

satellite photos. 

Based on the data described above the firm was only able to develop projections of the 

net energy production of a 10 MW wind farm on the island of St. Croix. 

The Wind Resource analyses and the Addendum do not provide sufficient data to 

estimate and analyze the potential wind generation 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 unusual and needs further verification, and the 

complex terrain, reasonable assumptions regarding the annual amount of net 

generation and the distribution of the net energy 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 meters 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, using the wind frequency data from the 

Addendum, the power curve for the V52 wind turbine, 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 represents an annual capacity factor of approximately 21 

percent. Using the limited data available, the annual net energy production was 

distributed on a seasonal and hourly basis as follows: 

Table 2-4 

Annual Net Energy Production on a Seasonal and Hourly Basis 

Synthesized Daily Distribution

Hour Jan Feb March April May June July August 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 warns that it should be used for a reference 

only. Since no data is available 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 time as specific wind farm site data is 

available. 

2.6 Electric Interconnection 

The electric interconnection option involves the installation 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 planning reserves and reduced 

spinning reserves. 

The estimated cost of the interconnection 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 million 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 significant unknowns relating to the cable route 

and installation requirements. 

The Authority has had discussions with the Puerto Rico Electric Power Authority 

(“PREPA“) regarding the potential purchase of 20-30 MW of power via submarine 

transmission line from PREPA to the Authority’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, reduced operating reserves requirements, 

improved system reliability, potential economic long- or short-term arrangements, 

potential participation in non-oil fired generation to be developed in Puerto Rico, and 

the potential to take advantage of economies of scale in the development of larger 

generating units . Due to the potential benefits 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 incorporate 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 part of the Fatal Flaw Analysis and was determined to be 

a feasible option for the Authority to pursue. Thus, an economic evaluation of the 

replacement of the IDE units with RO units 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 existing 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-located at the site of the power plant 

on each island. 

 Cases were prepared assuming alternatively 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 island of St. Croix would be retired in 

conjunction with the replacement of the MED units and replaced with CFB 

generating units, or (ii) the current multi-unit combined cycle 

configurations would be retained on each island, adjusted to reflect no 

steam extraction that is currently used to supply the MED units. 

 The proposed RO facility at each island would be comprised of two 1.5 

MGD capacity units. 

 The estimated costs developed by the 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 Cost5

 = $3.3 million 

 Maximum demand associated with the 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 islands 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 production 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 approvals 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 types of permits that may be required for 

construction of power generation and water production facilities on the islands of St. 

Thomas and St. Croix. It was noted that permitting requirements will vary based on 

the technology selected and design of the facility, as well as site specific conditions. 

For the U.S. Virgin Islands, regulatory programs fall under the jurisdiction 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 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 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. NOX and SO2 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 NOX is virtually 

exhausted at or near the existing Authority’s power plant 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 NOX 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 NOX was predicted to be exceeded. Again, in 

these scenarios, an air quality permit for construction would not be issued to a project. 

There is also information to indicate that SO2 emissions, and possibly NOX emissions, 

are a concern on the south shore on the island of St. Croix near the HOVENSA 

refinery. For power 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. 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 Planning 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 approval, 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. Support 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 CO2 Emission Regulations 

CO2 is recognized as a greenhouse gas, which accumulates in the atmosphere and 

could create significant changes in regional climates around the world. Large amounts 

of CO2 are produced during combustion of fossil fuels in power plants and at this time, 

several incentive based policy options for reducing CO2 emissions in the U. S. and its 

territories are being considered for implementation by the U. S. government. 

The proposed incentive based policy options include: (i) a tax on CO2 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 purpose of the tax would be to motivate CO2

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 place an upper limit on the cost of reducing 

emissions, but the total amount of CO2 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 require regulated entities to hold rights, or 

allowances, to the CO2 emissions permitted under the cap. Each allowance would 

entitle the holder to emit one ton of CO2 over a specified period. After the allowances 

for a given period were distributed, entities would be free to buy and sell the 

allowances among themselves. Unlike a tax, a cap-and-trade program would place an 

upper limit on the amount of CO2 emissions but the cost of reducing CO2 emissions 

would vary on the basis of fluctuations in the energy markets, the weather and the 

technologies available for reducing CO2 emissions. 

At this time it is unclear which of the two approaches will be selected or when the 

selected approach will be implemented. It is also uncertain what the level of tax 

would be if the CO2 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 selected. For the purpose 

of comparing the various power supply alternatives in this study, a sensitivity case has 

been prepared in which it is assumed that a CO2 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 CO2 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 Requirement 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 configurations to meet the Authority’s load 

requirements under different scenarios including permutations involving (i) the Base 

Load forecast and High Requirements load forecast, and (ii) with and without 

replacement of the existing MED desalination 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 appeared to be economically feasible with 

certain attentive risks associated with relatively high capital investment, and with 

respect to LNG, the dependence on the continuation 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 prepared to evaluate the LNG fuel supply 

options. 

As indicated in the Fatal Flaw Analysis, the CFB unit fueled with 50 percent coal and 

50 percent pet-coke is 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 costs 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 and if the Authority’s system is capable of 

accepting that amount of energy at the given capacity factor. In order to evaluate the 

CFB’s projected dispatch on the Authority’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 prepared 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 whether an economic benefit could be achieved 

by replacing major portions of its generating system with such resources. In replacing 

the existing steam system with CFB units, the remaining simple cycle CT units were 
Section 4 

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assumed to supply spinning reserve requirements. These cases also involved replacing 

the existing desalination system with RO technology, which appeared to be an 

economically beneficial option based on the Fatal Flaw Analysis. The addition of the 

RO system and elimination of the existing desalination system is also projected to 

provide more operational flexibility for the generating plant, since a constant steam 

supply is not required for the RO system. Inherent in this analysis is the assumption 

that there would be a reduction in production staffing levels and that Cases 1-5 and 2-5 

were prepared assuming such a major replacement of the Authority’s existing steam 

system and water production system as described above. To evaluate the potential 

economic benefits of just replacing the existing desalination system with RO, 

assuming no other changes to the water or electric 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 the existing MED desalination system. 

The Fatal Flaw Analysis also indicated that a high voltage interconnection between the 

islands of St. Thomas and St. Croix may 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 benefits of operating an integrated system, 

interconnected island systems with the addition 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 further 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 economic benefits of adding wind powered resources 

to the Authority’s power supply portfolio, cases were prepared assuming the addition 

of a 10 MW wind farm facility 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 decided to develop cases based on adding wind 

powered resources to Cases 1-1 and 2-1 (the 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). These 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 provides a summary the cases prepared to 

evaluate the Authority’s power supply and water production options. 

4.2 Discussion of Results 

The results of the Power Supply Evaluation 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 CO2

allowance costs. These costs include projected fuel costs, non-fuel electric production 

O&M costs, non-fuel water related production 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 projected differences in cumulative net present 

value costs between each case and the Existing Arrangement over the period 2008 

through 2027 in thousands of dollars for the cases assuming the Base Load Forecast 

and High Requirements Load Forecast under the assumptions with and without CO2

allowance costs. 

Column (c) on Table No. 10 shows the projected 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 electric cost includes fuel and electricity cost 

associated with producing electric capacity and energy and water, but excludes nonfuel water related production O&M, incremental RO system additions, and associated 

incremental RO capital costs. 

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

dollars for each case associated with generation, replacement of the water system with 

a RO system, high voltage DC interconnection, the LNG infrastructure, methanol and 

wind power related capital costs as appropriate. 

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, respectively) with and without CO2 allowance costs are projected to be the 

lowest cost case compared to the Existing Arrangement on a projected cumulative net 

present value costs and 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 CO2 allowance and without CO2 allowance costs. Cases 1-7 and 2-7 

(adding CFB units, high voltage DC interconnection 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 million 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 alternatives (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 include projected capital investments of approximately $0.9 

to $1.1 billion dollars. 

Cases 1-4 and 2-4 (adding CFB units to the existing steam and water system) are 

projected to result in a net 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 CO2 allowance costs and 

$74 million dollars and $197 million dollars if CO2 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 

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

Cases 1-5 and 2-5 (adding CFB units to replace the existing steam system and adding 

an RO system to replace existing desalination system) are projected to result in a net 

present value cost reduction of $82 million and $340 million dollars, respectively, 

relative to the Existing Arrangement without CO2 allowance and a reduction of $59 

million dollar reduction of $292 million dollars, respectively, if CO2 allowances are 

assumed. Capital investment associated with 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 located at the site of the power 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 longer 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 efficiency 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 new HRSG combined cycle configuration, the 

steam turbine for Unit No. 11 is projected to be typically operated from steam supplied 

totally by the new HRSG and the old HRSG, not the unit boilers. Therefore, 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, which 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 CO2

Allowance Cost 

With CO2 

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 facilities was projected to have only a minor 

impact on total Electric System and Water System costs. However, such an analysis 

does not address the recognized and PSC approved allocation of costs and value 

between the Electric System and Water System, which reflects the symbiotic benefits 

of operating combined electricity and water 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 systems, 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 installation of RO facilities 

may reduce the cost of producing water from those calculated in the Power Supply 

Evaluation. Under the electric power supply alternatives studied, where total Electric 

System and Water System costs are projected to be reduced compared to the Existing 

Arrangement, the projected costs of both the 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 requirements 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 facilities 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 such 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, consideration 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 facilities to new MED facilities the minor cost 

difference associated 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. 

Cases 1-6 and 2-6 (adding CFB units, interconnection 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 Existing Arrangement without CO2 allowance. If CO2

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 

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

the cases with CO2 allowances and without CO2 allowances are shown on Graphs 2 

through 5. 

As indicated by these results the cases involving 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 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 as shown 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 potentially more achievable capital investment 

include cases involving the LNG 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 simultaneously with the addition of CFB units is 

not expected to result in lower costs relative to the Existing Arrangement assuming the 

continued operation of the existing power plants. The reason for this result is that the 

minimum operating levels on the existing plant 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 desalination 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 which 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 capital investment than Case 2-4. 

With respect to cases involving wind power resources a comparison of each wind 

powered cases and the corresponding cases without wind power is summarized below: 
DESCRIPTION OF CASES AND RESULTS 

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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 CO2

Allowance Cost 

With CO2 

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 CO2

Allowance Cost 

With CO2 

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, these results indicate that contrary to the 

intuitive expectation, adding the 10 MW wind 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 CO2 allowance costs are 

assumed, adding the wind powered resource is projected to reduce NPV costs by 

approximately $2.2 million dollars, and under Case 1-5, with and without CO2
Section 4 

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allowances, adding the wind powered resource 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 approximately $3,000 dollars per kW in 2008 dollars. 

The projected result that no benefit is provided by adding a wind powered resource 

under Case 1-3 (which involves adding LNG fuel) and Case 1-4 (which involves 

adding CFB units), is explained by the observation 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 explained 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 facilities 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 Forecast, 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 displace predominately gas fueled simple cycle generation. 

In order to compare the previously described 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 set 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 graphical 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 Existing 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 respect 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. 
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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 feasibility 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 alternatives 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 System, and perhaps, the Authority. In the 

economic evaluation of replacing the existing MED system with an RO system there 

are other factors to consider other than the readily quantifiable costs associated with 

water production. 

Because of existing Territorial Legislation, among other factors, the Water System 

(both production and distribution) developed into a supplemental potable water system 

whereby, when potable water is not available from customer owned cisterns or other 

sources, customers look to the Authority to directly or indirectly provide potable 

water. Due to the difficulty and cost of extending the distribution system throughout 

the islands, there are many areas where potable water must be provided by private 

“water haulers,” cisterns, self-produced water for private use and for resale to end 

users, or some combination thereof. 

Existing Legislation and building codes essentially require, with few exceptions, that 

all residential and commercial buildings have cisterns; that the Authority is prohibited 

from requiring customers to “hook up” to the potable water distribution system when 

and where water distribution facilities are in place, and that the Authority is prohibited 

from imposing a monthly fee regardless of usage to recover a portion of the fixed costs 

associated with standing ready to provide water service on demand. 

The age and then construction practices, among other reasons, of the distribution 

system have also contributed to a higher than normal amount of unaccounted for water 

and losses, and distribution costs when compared to a distributed RO system. 

Moreover, the central location of the existing water production facilities near the 

steam production facilities requires a significant amount of pumping costs to deliver 

potable water throughout the distribution system and on the island of St. Thomas over 

the mountainous, rocky terrain. Discretely locating RO facilities near the population 

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

unaccounted for water and losses as well as make potable water available where 

population centers exist and the demand for potable water is higher. 

All of these factors contribute 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, 
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schools) and other third parties and end users at rates below those allowed by the PSC 

and charged by the Authority. The high cost of water production and distribution, the 

availability of potable water from competitors, 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 unchanged 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 potable water customers to conserve and reduce water 

usage and/or to seek out lower cost water providers. 

Given the situation and the existing legislation, it may not be possible to finance, at a 

reasonable cost, any new improvements or technological changes to the Water System 

regardless of the estimated long term 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 potential alternative third party financing 

arrangements used for wind projects, 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 introduction 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 permanently 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 Territory and the Authority and the 

willingness of investors to purchase Authority indebtedness; 

(v) The existing outstanding indebtedness of the Authority; and 

(vi) The existing restrictions on the issuance 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 

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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. Thomas, 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 equate to an additional 7,000 people per day in 

the Territory. 

5.2.2 Customers 

At June 30, 2007 the Authority provided electric and water service to over 65,000 

residential, commercial and government customers. 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 the 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 supply 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 entities, including HOVENSA, which produce electricity for 

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

5.2.3 Regulatory 

The electric and water rate levels and structures 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 are 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 and the cost of water is over $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. 
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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 indebtedness. 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 Services (“Standard & Poor’s”) issued a 

report on the Authority’s credit rating and outlook. 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 impacts 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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“Given the global oil price 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 could 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 relief 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 that additional time be permitted for its 

review of the requested 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 comply 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, should 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, may 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 outstanding long term indebtedness totals $241,785,000, 

which amount is below the current authorized amount. 

The Authority’s outstanding indebtedness is secured in part by separate and distinct 

claims on revenues, reserve fund balances and credit enhancements. At June 30, 2007 

the reported outstanding long term indebtedness for the Electric System and Water 

System was: 
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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 Subordinate Electric Bond Resolution and the 

Water Bond Resolution include restrictions on the issuance of additional pari passu 

and subordinated indebtedness. In general to protect existing bond holders, the 

various resolutions establish criteria that must be met in order for the Authority to 

issue indebtedness. In addition to demonstrating the ability of the Authority to meet 

certain cash flow projections, the Authority must demonstrate that it has and is 

projected to meet the applicable 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 subordinated debt, the Authority’s rates must 

produce revenues sufficient to provide an additional 15 percent of annual debt service, 

after the payment of operation and maintenance 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 issuance of additional 

indebtedness. Like the Electric Bond Resolution, 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 the Authority to issue the needed debt at 

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

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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 federal 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 potentially reduce or stabilize 

(due to the fluctuation of fuel oil prices) utility bills to customers. 

While many procurement schemes have gained popularity over the years, e.g., Build, 

Own, Operate (“BOO”), Design, Build, Operate, Own and Transfer (“DBOOT”), such 

options may be worth of future considerations. 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 Authority to consider a DBOOT or a similar 

procurement. The DBOOT mechanism would not require the Authority to issue 

indebtedness and would likely result in lower 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 planned operations of the Electric System and 

Water System as summarized in this report have been based upon the firm’s 

understanding, among other matters, of the provisions 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, agreements, 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 exist, or to events, 

which may occur in the future. While the firm believes 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 assumptions provided to us by the Authority and others. While 

the firm believes the use of such information 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 offers no assurances with respect thereto. 

Some actual conditions may vary significantly from the respective assumptions due to 

unanticipated events and circumstances. 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 projected herein. The report summarizes 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 presented 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 pertaining to the historical operations and 

cost of the Authority’s Electric System and Water System are accurate and 

reflect, to the extent possible normalized System operations. The parameters 

in the study were developed based upon actual data averaged for the three year 

period fiscal years 2005-2007. For the St. Croix Plant these parameters have 

remained relatively constant; however, during fiscal year 2008 the St. Thomas 
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Plant experienced the prolonged unavailability of its heat recovery steam 

generator adversely impacting overall plant performance on a three year 

average basis. The study results are based 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 alternatives 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 costs 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 electricity, steam, and potable water, the existing 

labor costs (operation and maintenance costs) were escalated. However, if a 

new resource (CFB facilities) to be developed 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 were adjusted upward by approximately 

25 percent so as to capture the additional 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 current 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 provisions 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), respectively. In addition, for purposes of estimating 

the future cost of oil, the projected crude oil cost estimates contained in the 

AEO 2007 projected fuel prices were utilized after adjustment by 2.3 percent 

annually for inflation. Fuel cost projections 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 higher than prices used in the study, the NPV 

savings associated with the power supply 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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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 projected on the basis of information provided 

by Renaissance and reflects 11,600 Btu/pound, 0.7 percent sulphur Colombian 

coal. The reported 2007 cost 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 the 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 price based on forward prices for 2008 

and 2009 escalated thereafter on the basis 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 projected on the basis of developing an on 

island, publicly financed methanol production plant utilizing pet-coke from 

HOVENSA as a feed stock. The methanol production plant is projected to 

produce approximately 1,000,000 gallons per day at estimated direct 

construction costs of approximately $1 billion dollars. The development of the 

methanol fuel price shown on Table No. 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-owned 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 should a tax or fee be assessed on CO2

emissions), increased competition for electric service and customers, and 

changes in existing tax laws and the imposition of new tax laws. 

12. It has been assumed that demand and energy sales will increase during the 

study period. For purposes of evaluating 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 customers, sales and usage patterns on each 

island, taking into consideration the continued 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 island 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 remain essentially flat. 
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No assumptions or provisions have been made or included in the load 

projections utilized herein to reflect unforeseen material load changes or 

changes in customer consumption characteristics which may be the result of, 

but not limited to, increased competition for customers brought about by 

existing and potential changes in legislation, deviations from normal weather 

conditions, including natural disasters, such as hurricanes, earthquakes, etc., 

modifications to or limitations on existing generation or distribution facilities, 

generation station or unit failures, 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 and 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 including 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 construction period is longer than typical for 

a given resource, the project capital (direct construction cost and 

financing cost) will be higher than assumed herein. 

h. For purposes of consistency in comparing 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 generating 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 industry sources and adjusted to reflect 

the estimated increased cost of constructing such facilities in the Territory. 

However, in a February 2008 report published 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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power plant construction during 2007 increased by 27 percent and during 2005 

through 2007 such costs increased by approximately 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 these unprecedented increases 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 adjusted to reflect the estimated increased 

cost of constructing such facilities in the Territory. 

17. All generating and water production facilities will be wholly owned, operated 

and financed by the Authority. 

18. The heat rate data and condition associated 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 capacity 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 water production facilities is based on 

information provided by the Authority as summarized on Table No. 2. 

21. The Authority’s planning criteria for 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 continue to meet recognized reliability 

constraints that include the requirement that each plant be capable of handling 

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

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

unit. 

23. For cases in which CO2 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 production options evaluated herein are 

assumed to be designed, constructed and operated in compliance with 

applicable environmental air quality rules. To the extent emissions exceed the 

PSD increment at a given site, off-setting NOX or SO2 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 NOX and SO2 since the U.S. 

Virgin Islands are not subject to the Clean Air Interstate Rule (“CAIR”) which 

establishes such programs. 
Section 6 

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

25. The total non-fuel steam related electric production expenses are projected to 

be approximately $8.1 million dollars annually in 2007 dollars based on an 

average of the Authority’s reported historical costs for the period 2005 through 

2007 as shown on Table No. 4. These costs 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 production 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 avoidable 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 approximately $1.5 million dollars annually based on historical 

information over the period 2005 through 2007 as reported by the Authority 

and as shown on Table No. 3. Such costs were assumed to escalate at an 

inflation rate of 2.3 percent. 

28. The earliest year in which new generating 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 assumed to be added as needed to meet 

the Authority’s planning reserve criteria. 

29. Inherent in the development of non-fuel production operating expenses for the 

various alternatives evaluated, (with the exception of the Existing 

Arrangement), changes in the staffing levels and skills have been assumed. 

While no production staffing studies 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 Unit No. 9 in 2008 and the Authority’s 

estimate that each unit will require retubing at thee year intervals were used. 

For future years, the IDE 2008 estimate of $1,075,000 was escalated annually 

at an assumed inflation rate of 2.3 percent. 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 Conclusions set forth herein and on the 

results of our analysis and review of reports prepared by or for the Authority and 

information provided by the Authority and others which is summarized or referred to 

in this Power Supply Evaluation, which report should be read in its entirety in 

conjunction with the following, the firm is of the opinion that: 

1. Of the various electric generation and water production alternatives evaluated, 

four standout as being technologically feasible, potentially environmentally 

compliant, financially affordable and worthy 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 installation of RO facilities. 

2. Like many Caribbean island power systems the authority finds itself dependent 

upon fuel oil which in recent years has subjected the Authority’s customers to 

increasing rate levels and volatility. Given that the Authority also faces 

significant issues, which impact its ability 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 development 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, respectively) with and without CO2 allowance costs are 

projected to be the lowest cost case compared 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 CO2

allowance and without CO2 allowance costs. Cases 1-7 and 2-7 (adding CFB 

units, high voltage DC interconnection 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 projected 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 associated cases (methanol, LNG and high voltage 

DC interconnection), the LNG fuel supply alternative (Cases 1-3 and 2-3) are 

projected to have a capital investment of $196 million and $241 million, 

whereas the other two alternatives include 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-off between capital investment and cost 

reduction relative to the Existing Arrangement of the cases evaluated herein, 

but such projected cost reductions are dependent on the continuation of the 

current differential between 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 present 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 CO2 allowance costs and $74 million dollars and $197 

million dollars if CO2 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 and 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 and adding RO on both islands is not 

projected to reduce costs compared to just adding the CFB units unless electric 

load increases similar to the High Load 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 requirements 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 

facilities 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 such RO facilities. Also, given the initial results 

of the firm’s analysis, and since the market 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 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 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 associated 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, replacing 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 

CO2 allowance costs assumed and Case 1-5 (major replacement of existing 

steam system and water production) with and without CO2 allowance costs 

assumed. Adding the 10 MW wind resource 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 LNG 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 offsetting emission reductions from existing 

units. 

11. Adding a high voltage interconnection between the islands is projected to be an 

economically feasible option if the existing steam system and water system is 

also replaced, but such alternatives require a significant capital investment with 

the associated financial risk. 

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

additional indebtedness: 

(i) The number of people that permanently 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 Territory and the Authority and the 

willingness of investors to purchase Authority indebtedness; 

(v) The existing outstanding indebtedness of the Authority; and 

(vi) The existing restrictions on the issuance 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 Resolution and the Water Bond 

Resolution. 

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

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

alternatives. 

13. Although direct Authority ownership should result in the lowest cost to 

acquiring new facilities, it may be necessary for the Authority to consider a 

design, build, operate, own and transfer or similar procurement arrangement so 

that the Authority would not be required to issue further indebtedness. 

The firm expresses its sincere appreciation to representatives of the Authority, HGI, 

Georgetown MACTEC, HOVENSA, Renaissance and others for their assistance, 

guidance, input and spirited cooperation. The firm is prepared 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 forward with the integration of the new electric 

supply resources into the Authority’s system, there are a number of steps that need to 

be undertaken as described below in the implementation 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 collaborative 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 the RFP process with the most economic 

alternatives from the Power Supply Evaluation and develop an integrated 

resource plan that reflects the Authority’s best plan. 

5. Modify Plan – Based on discussions with PREPA, 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 includes any potential arrangement with 

PREPA, the Authority will obtain formal Governing Board and PSC approval 

to proceed. This may require further modifications 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 refined. This will include, among other 

things, developing detailed cost estimates and performance data for proposed 

projects, reviewing retirement of existing facilities and associated costs, 

developing costs for any required infrastructure 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 reveals a significant change in cost, or the 

benefits of the selected plan have substantially changed, the Authority will 

seek formal Governing Board and PSC approval 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 requirements, bond amount and debt service 

payment. Power purchase contracts and construction contracts 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 associated 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. Technology Fuel Type Capacity 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. Technology Fuel Type Capacity 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

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VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Evaluation

Summary of Existing Water Production Facilities [1]

Commercial Planned Design Low Pressure Steam 

Line In Service Retirement Capability Capability [2] Requirements [3] 

No. Location Status Date Date (MGD) (MGD) (lb/hr) 

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

ISLAND OF ST. THOMAS

St. Thomas

1 Unit No. 1 Krum Bay In Service May 1981 Apr 2011 1.25 1.25 45,000 

2 Unit No. 2 Krum Bay In Service Aug 1981 Jul 2011 1.25 1.25 45,000 

3 Unit No. 6 Krum Bay In Service Dec 1983 Nov 2013 0.55 0.36 22,500 

4 Unit No. 8 Krum Bay In Service Feb 1992 Jan 2022 1.40 1.40 50,000 

5 Total 4.45 4.26 162,500 

ISLAND OF ST. CROIX

St. Croix

6 Unit No. 3 Richmond In Service Dec 1981 Nov 2011 1.25 1.25 45,000 

7 Unit No. 4 Richmond In Service Jul 1983 Jun 2013 0.55 0.55 22,500 

8 Unit No. 5 Richmond In Service Sep 1983 Aug 2013 0.55 0.55 22,500 

9 Unit No. 9 Richmond In Service Jun 1993 May 2023 1.30 1.30 45,000 

10 Total 3.65 3.65 135,000 

ISLAND OF ST. JOHN

St. John

11 Unit No. 7 Cruz Bay In Service Jul 1990 Jun 2020 0.15 0.15 0 

12 TOTAL SYSTEM (MGD) 8.25 8.06 297500 

[1] Based on information provided by the Authority.[2] As of June, 2007.[3] 26 psig.[4] 150 psig.

Faciltiy

IDE Unit No.

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls
Table No. 3

Ln.

No. Description 2005 2006 2007

(a) (b) (c) (d)

Island of St. Thomas - Randolph E. Harley

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. Thomas 995,302 1,394,098 907,235

Island of St. John

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

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

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

Island of St. Croix - Estate Richmond Generating Station

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. Croix 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 Maintenance 6,886,511 7,293,135 6,165,723

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

TOTAL COMBINED ISLANDS by Type

Steam

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 Turbine

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. John 11,689 12,078 17,266

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

Total Combined System Production

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 Cost $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 30 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Evaluation

Capital Improvement Schedule for MED Units

($000)

Ln. No Description 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 

St. Croix MED Capital Costs

1 Unit No. 3 $0 $0 $1,232 $0 $0 $1,319 $0 $0 $1,412 2 Unit No. 4 0 1,204 0 0 1,289 0 0 1,381 0 3 Unit No. 5 0 1,204 0 0 1,289 0 0 1,381 0 4 Unit No. 9 1,177 0 0 1,260 0 0 1,349 0 0 1,445 Total St. Croix ($) $1,177 $2,409 $1,232 $1,260 $2,579 $1,319 $1,349 $2,761 $1,412 $1,44

St. Thomas MED Capital Costs

6 Unit No. 1 $1,177 $0 $0 $1,260 $0 $0 $1,349 $0 $0 $1,447 Unit No. 2 1,177 0 0 1,260 0 0 1,349 0 0 1,448 Unit No. 6 0 1,204 0 0 1,289 0 0 1,381 0 9 Unit No. 8 0 0 1,232 0 0 1,319 0 0 1,412 

10 Total St. Thomas ($) $2,355 $1,204 $1,232 $2,521 $1,289 $1,319 $2,699 $1,381 $1,412 $2,8811 Total System Cost ($) 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,33

[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; 7/31/2008
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Evaluation

Capital Improvement Schedule for MED Units

($000)

Ln. No Description

St. Croix MED Capital Costs

1 Unit No. 32 Unit No. 43 Unit No. 54 Unit No. 95 Total St. Croix ($)

St. Thomas MED Capital Costs

6 Unit No. 17 Unit No. 28 Unit No. 69 Unit No. 8

10 Total St. Thomas ($)11 Total System Cost ($)

2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 

$0 $1,619 $0 $0 $1,733 $0 $0 $1,855 $0 

1,582 0 0 1,694 0 0 1,814 0 0 1,941,582 0 0 1,694 0 0 1,814 0 0 1,94

0 0 1,656 0 0 1,773 0 0 1,898 

$3,165 $1,619 $1,656 $3,388 $1,733 $1,773 $3,627 $1,855 $1,898 $3,88

$0 $0 $1,656 $0 $0 $1,773 $0 $0 $1,898 

0 0 1,656 0 0 1,773 0 0 1,898 

1,582 0 0 1,694 0 0 1,814 0 0 1,94

0 1,619 0 0 1,733 0 0 1,855 0 

$1,582 $1,619 $3,312 $1,694 $1,733 $3,546 $1,814 $1,855 $3,796 $1,94

4,747 3,237 4,968 5,082 3,466 5,319 5,441 3,711 5,694 5,82

[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.

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Table 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 72,574,572 68,699,889 98,948,022 134,204,089 150,779,994 

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

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 2,032,233 2,053,486 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; 7/31/2008
Ln. No. Description 2012 2013 2014 2015 2016 2017 2018 2019 2020 202

St. Croix Fuel Requirements

1 MMBtu 4,653,808 4,635,549 4,667,429 4,684,685 4,704,183 4,719,507 4,736,611 4,753,721 4,771,717 4,785

 

2 Petcoke ($/MMBtu) 1.68 1.70 1.71 1.73 1.77 1.81 1.85 1.89 1.93 3 Subtotal Petcoke ($) 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

Petcoke Transportation Cost

4 Transportation Cost ($/ton) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5 Transportation Cost ($/MMBtu) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6 Subtotal Transportation ($) 0000000007 Total St. Croix Petcoke ($) 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

St. Thomas Fuel Requirements

8 MMBtu 8,921,128 8,817,141 9,009,063 9,105,317 9,208,683 9,306,877 9,415,093 9,523,331 9,626,163 9,732

 

9 Petcoke ($/MMBtu) 1.68 1.70 1.71 1.73 1.77 1.81 1.85 1.89 1.93 

10 Subtotal 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

Methanol Transportation Cost

11 Transportation Cost ($/ton) 4.48 4.58 4.69 4.80 4.91 5.02 5.14 5.25 5.38 12 Transportation Cost ($/MMBtu) 0.16 0.16 0.16 0.17 0.17 0.18 0.18 0.18 0.19 13 Subtotal Transportation ($) 1,383,979 1,432,508 1,479,900 1,530,113 1,583,076 1,636,755 1,693,870 1,752,750 1,812,424 1,87414 Total St. Thomas ($) 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

CC at Methanol Plant

15 Plant Rating (MW) 40 40 40 40 40 40 40 40 40 16 MWh Generated (MWh) 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 29717 Annual Capital Carrying Cost ($) 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,864,417 6,86418 Fixed Annual O&M Cost ($) 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 5,36119 CO2 Allowance Cost ($) 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,74220 Variable Annual O&M ($) 834,260 853,448 873,077 893,158 913,700 934,715 956,214 978,207 1,000,705 1,02321 Average Heat Rate (MMBtu/MWh) 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 22 Annual 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 2,29323 Total Annual Fuel Operating Cost ($) 3,851,139 3,891,472 3,932,228 3,973,410 4,058,549 4,145,512 4,234,338 4,325,067 4,417,741 4,55224 Total Annual Operating Cost ($) 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 20,54425 Total Annual Operating Cost ($/MWh) 62.66 63.20 63.74 64.30 65.02 65.75 66.50 67.26 68.05 6

Methanol Plant

26 Annual Capital Carrying Cost ($) 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,579,020 82,57927 Fixed Annual O&M Cost ($) 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 17,18528 Variable Annual O&M ($) 00000000029 Total Annual Operating Cost ($) 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 99,76430 Total Cost ($) 139,220,873 140,195,565 141,151,052 142,147,066 143,487,536 144,844,819 146,260,417 147,712,678 149,192,747 151,00031 Methanol Fuel Cost ($/MMBtu) 10.35 10.33 10.32 10.31 10.31 10.33 10.34 10.35 10.36 1

VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Evaluation

Methanol Fuel Cost

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls; 7/31/2008
Ln. No. Description

St. Croix Fuel Requirements

1 MMBtu2 Petcoke ($/MMBtu)3 Subtotal Petcoke ($)

Petcoke Transportation Cost

4 Transportation Cost ($/ton)5 Transportation Cost ($/MMBtu)6 Subtotal Transportation ($)7 Total St. Croix Petcoke ($)

St. Thomas Fuel Requirements

8 MMBtu9 Petcoke ($/MMBtu)

10 Subtotal Petcoke ($)

Methanol Transportation Cost

11 Transportation Cost ($/ton)12 Transportation Cost ($/MMBtu)13 Subtotal Transportation ($)14 Total St. Thomas ($)

CC at Methanol Plant

15 Plant Rating (MW)16 MWh Generated (MWh)17 Annual Capital Carrying Cost ($)18 Fixed Annual O&M Cost ($)19 CO2 Allowance Cost ($)20 Variable Annual O&M ($)21 Average Heat Rate (MMBtu/MWh)22 Annual Fuel Consumed (MMBtu)23 Total Annual Fuel Operating Cost ($)24 Total Annual Operating Cost ($)25 Total Annual Operating Cost ($/MWh)

Methanol Plant

26 Annual Capital Carrying Cost ($)27 Fixed Annual O&M Cost ($)28 Variable Annual O&M ($)29 Total Annual Operating Cost ($)30 Total Cost ($)31 Methanol Fuel Cost ($/MMBtu)

2025 2026 2027 2028 2029 2030 2031 2032 2033 203

 4,883,343 4,860,665 4,901,048 4,901,048 4,901,048 4,901,048 4,901,048 4,901,048 4,901,048 4,901

 

2.24 2.31 2.38 2.46 2.53 2.61 2.69 2.78 2.87 

10,875,582 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

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

000000000

10,875,582 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

 10,262,250 10,154,211 10,358,804 10,358,804 10,358,804 10,358,804 10,358,804 10,358,804 10,358,804 10,358

 

2.24 2.31 2.38 2.46 2.53 2.61 2.69 2.78 2.87 

22,719,721 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

6.02 6.16 6.30 6.45 6.60 6.75 6.90 7.06 7.22 0.21 0.22 0.22 0.23 0.23 0.24 0.24 0.25 0.25 

2,142,057 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

24,861,778 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

40 40 40 40 40 40 40 40 40 

297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297,840 297

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 6,8645,872,540 6,007,609 6,145,784 6,287,137 6,431,741 6,579,671 6,731,003 6,885,817 7,044,190 7,2062,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,742,850 2,7421,121,203 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

7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 

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 2,2935,131,337 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

21,732,348 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

72.97 74.05 75.16 76.30 77.47 78.68 79.91 81.19 82.49 8

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 82,57918,822,245 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

000000000

101,401,265 101,834,177 102,277,046 102,730,100 103,193,575 103,667,710 104,152,750 104,648,945 105,156,554 105,675

158,870,974 161,056,171 163,272,741 165,259,957 167,303,949 169,406,371 171,568,927 173,793,368 176,081,501 178,435

10.58 10.63 10.70 10.83 10.96 11.10 11.24 11.39 11.54 1

VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Evaluation

Methanol Fuel Cost

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

No. Year No. 2 No. 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 

Agency

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 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.

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

Comments
Table No. 9

COMBUSTION TECHNOLOGY CASES

Major Retirements

Case 1-1 Existing Arrangement Base None None

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

using Methanol fuel

Base Methanol Plant (St Croix) None

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

using LNG fuel

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) None (St. Croix)

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

existing 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 

existing 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 

Requirement

40 MW CT - (St. Thomas) None

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

using Methanol fuel

High 

Requirement

Methanol Plant (St Croix) None

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

using LNG fuel

High 

Requirement

LNG Facilities (St. Thomas 

and St. Croix)

None

Case 2-4 Add CFB Units High 

Requirement

30 MW CFB - 2012 (St. Units 12, 14 (St. 

20 MW CFB - 2012 (St. Coix) None (St. Croix)

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

retire existing Steam Plants,

High 

Requirement

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, High 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 Additions
Virgin 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 water, but excluding non-fuel O&M

and capital costs related to water

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Virgin Islands Water and Power Authority

Power Supply Evaluation

Projected Fuel Cost

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\Project Management\Power Supply Evaluation - Tables_043008.xls Grph 1 - Fuel Cost 

05

101520253035

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 

($/MMBtu)

No. 2 Fuel Oil No. 6 Fuel Oil Pet Coke Coal LNG 
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 CO2 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

$566,176 $573,865

$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 CO2 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 CO2 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 CO2 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

$513,105 $640,965

$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 CO2 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 CO2 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 CO2 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 CO2 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

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PowerSupply Cost Summary_v5.xls ReadMe Page 1 of 25;8/1/2008; RWBeck Inc.
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

1 Case: 1-1 Reference Case- Base Load, no retirements,all oil

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 32

Fuel + 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 9CO2 Charge ($000) 3,423 4,051 4,711 5,425 6,167 6,912 7,704 8,555 9,459 10,337 11,308 1

CC 2

MWh 49,873 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 4

Fuel + 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 1CO2 Charge ($000) 592 710 837 926 1,049 1,184 1,345 1,478 1,615 1,836 1,991 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 9

Total CO2 Charge ($000) 00000 4,015 4,761 5,548 6,351 7,216 8,096 9,049 10,033 11,074 12,172 13,299 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-1 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

1 Case: 1-1 Reference Case- Base Load, no retirements,all oil

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 28Total Authority CO2 Charges ($000) 00000 11,535 13,696 16,032 18,454 20,986 23,702 26,565 29,633 32,857 36,294 39,815 4

Total Authority Incremental Non-fuel Production Cost ($000) 0000000000000000Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 35

Total 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 30NPV with CO2 Charge ($000) 2,941,127NPV without CO2 Charge ($000) 2,723,496

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-1 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

2 Case: 1-1W Same as Case 1-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 440,702 424,991 427,346 430,844 434,820 429,190 443,099 453,055 435,697 453,067 443,673 456,369 457,654 468,153 461,015 46

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 107,272 106,155 109,957 112,942 112,662 121,704 123,867 132,284 137,774 147,012 150,787 15CO2 Charge ($000) 5,914 6,871 8,204 9,586 10,386 12,091 13,165 14,948 16,464 18,417 19,725 2

Unit 13

MWh 30,299 40,164 41,135 41,994 41,813 47,322 42,387 39,646 51,322 43,974 49,902 45,724 47,666 44,385 51,503 5

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 9,052 10,277 9,300 8,806 11,854 10,645 12,492 12,009 13,052 12,872 15,545 1CO2 Charge ($000) 539 720 752 803 1,182 1,135 1,426 1,458 1,677 1,735 2,186 

Unit 15

MWh 979 380 140 210 80 612 874 60 80 405 319 532 697 489 

Fuel + CO2 Charge ($000) 308 126 49 73 29 216 317 0 23 32 150 131 236 308 224 CO2 Charge ($000) 1 13 22 0 2 3 15 14 26 36 27 

Unit 18

MWh 8,470 12,805 13,357 14,568 13,775 17,082 11,630 12,310 16,375 14,318 17,623 15,674 15,048 14,559 16,744 1

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 3,497 4,253 2,977 3,161 4,454 4,042 4,990 4,732 4,659 4,695 5,653 CO2 Charge ($000) 179 257 208 249 385 374 495 499 521 552 693 

Unit 22

MWh 80,936 83,941 84,753 85,544 89,052 93,142 94,197 97,242 104,104 105,034 107,784 111,308 113,505 116,592 120,655 12

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 15,589 16,330 16,602 17,197 19,058 19,973 21,299 22,837 24,187 25,901 27,911 2CO2 Charge ($000) 798 983 1,153 1,356 1,637 1,847 2,108 2,405 2,696 3,026 3,409 

Unit 23

MWh 4,000 3,318 5,469 5,640 6,159 5,453 7,714 4,846 6,842 5,226 9,759 7,405 9,995 7,714 9,595 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,717 1,541 2,090 1,382 2,030 1,645 3,006 2,449 3,350 2,760 3,558 CO2 Charge ($000) 88 93 146 109 175 152 297 258 374 327 436 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 18

Total CO2 Charge ($000) 00000 7,520 8,936 10,485 12,103 13,768 15,602 17,507 19,583 21,760 24,092 26,477 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

2 Case: 1-1W Same as Case 1-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 292,274 293,289 294,843 297,472 299,239 300,629 301,610 303,669 305,959 306,107 308,031 30

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 64,344 64,752 65,322 66,136 69,097 71,922 74,895 78,185 81,728 85,174 89,207 9CO2 Charge ($000) 3,292 3,894 4,533 5,218 5,933 6,650 7,414 8,234 9,109 9,957 10,895 1

CC 2

MWh 49,873 47,522 47,458 46,613 44,910 45,938 46,329 45,083 45,121 45,561 46,526 46,296 45,898 47,683 47,497 4

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 10,641 10,939 11,098 10,859 11,298 11,855 12,580 13,005 13,401 14,512 15,069 1CO2 Charge ($000) 572 691 808 899 1,017 1,150 1,306 1,435 1,565 1,777 1,927 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 548 560 573 586 600 614 628 642 657 672 687 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 9

Total CO2 Charge ($000) 00000 3,864 4,585 5,341 6,116 6,950 7,800 8,720 9,669 10,674 11,734 12,822 1Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

2 Case: 1-1W Same as Case 1-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 28Total Authority CO2 Charges ($000) 00000 11,384 13,520 15,825 18,219 20,718 23,402 26,226 29,253 32,433 35,826 39,299 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 35

Total 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 30NPV with CO2 Charge ($000) 2,938,944NPV without CO2 Charge ($000) 2,724,105

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

3 Case: 1-2 Same as Case 1-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 392,080 378,931 381,059 384,781 389,904 386,544 400,119 412,117 399,451 417,883 410,061 425,909 428,335 442,386 438,758 44

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 65,659 65,267 67,922 70,241 68,471 72,263 71,670 75,023 76,302 79,755 80,034 8

CO2 Charge ($000) 3,362 3,917 4,684 5,499 5,987 6,998 7,629 8,718 9,618 10,831 11,655 1

Unit 13

MWh 23,373 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 3

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 4,659 5,302 4,735 4,245 5,699 4,859 5,901 4,966 5,421 4,648 5,596 

CO2 Charge ($000) 239 320 329 332 504 471 629 579 687 637 821 

Unit 15

MWh 979 380 140 210 50 542 824 60 80 385 269 462 647 439 

Fuel + CO2 Charge ($000) 308 126 49 73 12 122 191 0 14 19 84 63 116 156 107 

CO2 Charge ($000) 1 7 13 0 1 2 9 7 15 21 16 

Unit 18

MWh 15,039 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 3

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 3,523 4,239 3,351 3,618 4,711 4,221 4,687 4,863 4,792 5,069 5,873 

CO2 Charge ($000) 181 256 233 283 416 409 500 567 607 693 860 

Unit 22

MWh 135,620 135,691 136,178 136,558 137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 14

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 14,993 15,144 15,330 15,532 15,850 15,997 16,239 16,468 16,748 17,000 17,296 1CO2 Charge ($000) 768 910 1,059 1,214 1,389 1,549 1,729 1,915 2,113 2,309 2,522 

Unit 23

MWh 4,000 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 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,093 984 1,343 888 1,266 1,001 1,782 1,419 1,892 1,506 1,900 

CO2 Charge ($000) 56 59 93 69 112 97 190 165 240 209 279 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 9Total CO2 Charge ($000) 00000 4,607 5,468 6,411 7,398 8,409 9,525 10,685 11,950 13,280 14,699 16,153 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

3 Case: 1-2 Same as Case 1-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 32

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 42,597 43,000 43,495 44,185 44,874 45,505 46,124 46,912 47,792 48,471 49,441 5CO2 Charge ($000) 2,182 2,583 3,003 3,459 3,931 4,407 4,911 5,454 6,030 6,590 7,209 

CC 2

MWh 49,873 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 4

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 7,159 7,326 7,522 7,338 7,430 7,573 7,829 7,878 7,936 8,369 8,468 

CO2 Charge ($000) 367 440 519 574 650 733 833 915 1,000 1,137 1,233 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 4

Total CO2 Charge ($000) 00000 2,549 3,022 3,522 4,032 4,581 5,140 5,744 6,369 7,031 7,727 8,442 Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

3 Case: 1-2 Same as Case 1-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 14Total Authority CO2 Charges ($000) 00000 7,157 8,491 9,932 11,430 12,990 14,665 16,430 18,320 20,311 22,426 24,595 2Total Authority Incremental Non-fuel Production Cost ($000) 0000000000000000Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 19

Total 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 17NPV with CO2 Charge ($000) 2,082,585NPV without CO2 Charge ($000) 1,948,039

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

4 Case: 1-3 Same as Case 1-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 392,080 378,931 381,059 384,781 389,904 386,544 400,119 412,117 399,451 417,883 410,061 425,909 428,335 442,386 438,758 44

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 73,862 73,191 77,918 81,411 81,821 90,180 89,776 94,647 98,832 104,569 108,062 11

CO2 Charge ($000) 4,035 4,701 5,621 6,600 7,186 8,399 9,156 10,462 11,544 12,999 13,988 1

Unit 13

MWh 23,373 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 3

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 5,244 5,955 5,439 4,921 6,845 6,068 7,397 6,275 7,032 6,122 7,585 

CO2 Charge ($000) 287 384 395 398 605 565 756 695 825 765 986 

Unit 15

MWh 979 380 140 210 50 542 824 60 80 385 269 462 647 439 

Fuel + CO2 Charge ($000) 308 126 49 73 13 137 220 0 17 24 105 80 150 204 144 

CO2 Charge ($000) 1 9 16 0 2 2 11 9 17 25 19 

Unit 18

MWh 15,039 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 3

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 3,965 4,760 3,849 4,195 5,657 5,272 5,876 6,144 6,217 6,667 7,954 

CO2 Charge ($000) 217 307 280 340 500 491 600 680 729 832 1,033 

Unit 22

MWh 135,620 135,691 136,178 136,558 137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 14

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 16,853 16,971 17,573 17,981 18,941 19,947 20,325 20,763 21,679 22,272 23,346 2CO2 Charge ($000) 921 1,091 1,269 1,456 1,665 1,858 2,073 2,296 2,534 2,769 3,024 

Unit 23

MWh 4,000 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 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,225 1,099 1,536 1,026 1,514 1,245 2,224 1,785 2,444 1,985 2,566 

CO2 Charge ($000) 67 71 111 83 134 116 227 198 287 250 334 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 13Total CO2 Charge ($000) 00000 5,529 6,562 7,693 8,878 10,091 11,430 12,823 14,341 15,937 17,640 19,384 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

4 Case: 1-3 Same as Case 1-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 308,724 310,010 311,131 314,085 315,804 317,278 318,167 320,289 322,471 322,496 324,400 32

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 47,899 48,207 49,880 51,188 53,644 56,765 57,754 59,168 61,889 63,554 66,762 6CO2 Charge ($000) 2,618 3,098 3,603 4,149 4,716 5,287 5,892 6,543 7,234 7,905 8,648 

CC 2

MWh 49,873 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 4

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 8,060 8,222 8,637 8,508 8,886 9,458 9,815 9,947 10,288 10,984 11,444 1

CO2 Charge ($000) 440 528 623 689 780 881 1,001 1,100 1,202 1,366 1,481 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 7

Total CO2 Charge ($000) 00000 3,059 3,627 4,226 4,838 5,497 6,167 6,893 7,642 8,436 9,271 10,129 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

4 Case: 1-3 Same as Case 1-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 20Total Authority CO2 Charges ($000) 00000 8,588 10,189 11,918 13,716 15,588 17,598 19,715 21,983 24,373 26,911 29,513 3Total Authority Incremental Non-fuel Production Cost ($000) 0000000000000000Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 26

Total 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 23NPV with CO2 Charge ($000) 2,406,996NPV without CO2 Charge ($000) 2,245,543

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

5 Case: 1-3W Same as Case 1-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 392,080 378,931 381,059 384,781 389,915 386,589 400,229 412,198 399,676 418,298 410,829 427,227 430,013 444,387 440,953 44

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 73,864 73,198 77,935 81,424 81,858 90,252 89,913 94,885 99,148 104,955 108,505 11

CO2 Charge ($000) 4,035 4,701 5,623 6,601 7,189 8,405 9,170 10,489 11,580 13,047 14,045 1

Unit 13

MWh 23,373 28,884 29,869 30,163 30,322 34,348 30,454 26,671 35,401 29,657 36,494 29,915 32,671 27,163 32,320 3

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 5,245 5,952 5,435 4,922 6,845 6,060 7,388 6,238 7,013 6,016 7,516 CO2 Charge ($000) 288 384 395 399 605 564 755 691 823 752 977 

Unit 15

MWh 979 380 140 210 80 612 874 60 80 405 319 532 697 489 

Fuel + CO2 Charge ($000) 308 126 49 73 21 155 233 0 17 24 111 95 173 221 162 CO2 Charge ($000) 1 10 17 0 2 2 11 11 20 28 21 

Unit 18

MWh 15,039 23,443 23,898 25,426 24,414 29,173 22,510 24,098 31,126 27,337 29,677 29,565 28,179 28,825 32,862 3

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 3,958 4,746 3,831 4,184 5,609 5,195 5,702 5,866 5,824 6,262 7,422 CO2 Charge ($000) 217 306 279 339 496 484 582 650 683 781 964 

Unit 22

MWh 135,620 135,691 136,178 136,558 137,903 138,645 139,273 140,161 141,858 141,629 142,302 142,697 143,307 143,474 143,840 14

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 16,853 16,971 17,573 17,981 18,941 19,947 20,325 20,763 21,679 22,272 23,346 2CO2 Charge ($000) 921 1,091 1,269 1,456 1,665 1,858 2,073 2,296 2,534 2,769 3,024 

Unit 23

MWh 4,000 3,318 5,469 5,640 6,159 5,453 7,714 4,846 6,842 5,226 9,759 7,405 9,995 7,714 9,595 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,225 1,099 1,531 1,026 1,514 1,245 2,224 1,778 2,433 1,979 2,558 CO2 Charge ($000) 67 71 111 83 134 116 227 197 285 249 333 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 13Total CO2 Charge ($000) 00000 5,529 6,563 7,693 8,878 10,090 11,429 12,818 14,333 15,927 17,626 19,364 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

5 Case: 1-3W Same as Case 1-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 292,274 293,289 294,843 297,472 299,239 300,629 301,610 303,669 305,959 306,107 308,031 30

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 46,058 46,331 47,996 49,231 51,611 54,610 55,581 56,947 59,597 61,220 64,326 6CO2 Charge ($000) 2,518 2,978 3,467 3,991 4,538 5,086 5,670 6,297 6,967 7,615 8,333 

CC 2

MWh 49,873 47,522 47,458 46,613 44,910 45,938 46,329 45,083 45,121 45,561 46,526 46,296 45,898 47,683 47,497 4

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 7,792 8,002 8,333 8,256 8,614 9,188 9,527 9,661 9,966 10,632 11,073 1CO2 Charge ($000) 426 514 601 669 757 856 972 1,068 1,164 1,322 1,433 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 548 560 573 586 600 614 628 642 657 672 687 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 6

Total CO2 Charge ($000) 00000 2,943 3,492 4,068 4,659 5,294 5,942 6,642 7,365 8,131 8,937 9,766 1Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

5 Case: 1-3W Same as Case 1-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 20Total Authority CO2 Charges ($000) 00000 8,473 10,055 11,761 13,537 15,384 17,371 19,460 21,698 24,057 26,563 29,130 3Total Authority Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 26

Total 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 23NPV with CO2 Charge ($000) 2,412,144NPV without CO2 Charge ($000) 2,252,782

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

6 Case: 1-4 Base Load, add CFB , replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 440,702 424,991 427,346 430,844 366,371 368,734 371,378 375,107 376,773 380,120 381,652 383,737 388,558 390,717 393,386 39

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 88,670 89,438 90,371 91,590 95,631 99,851 104,060 108,536 113,922 119,156 124,837 13

CO2 Charge ($000) 4,891 5,795 6,751 7,773 8,829 9,920 11,062 12,269 13,622 14,939 16,343 1

Unit 13

MWh 30,299 40,164 41,135 41,994 30,671 32,911 32,860 32,154 33,895 33,701 34,895 34,741 34,051 34,260 36,199 3

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 6,851 7,361 7,356 7,309 7,926 8,202 8,795 9,037 9,310 9,709 10,705 1CO2 Charge ($000) 407 513 590 666 785 875 1,003 1,095 1,192 1,303 1,499 

Unit 15

MWh 979 380 140 210 88 190 110 176 10 10 676 

Fuel + CO2 Charge ($000) 308 126 49 73 0 30 70 0 42 0 71 4 0 5 279 CO2 Charge ($000) 0 2 5 0 4 0 7 0 0 1 34 

Unit 18

MWh 8,470 12,805 13,357 14,568 2,888 4,111 4,226 3,668 5,836 5,097 5,174 7,494 6,470 6,737 6,990 

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 787 1,133 1,160 1,040 1,659 1,518 1,602 2,312 2,141 2,341 2,481 

CO2 Charge ($000) 40 68 80 82 142 140 159 243 238 273 303 

Unit 22

MWh 80,936 83,941 84,753 85,544 41,057 41,456 43,739 47,500 48,759 52,080 53,083 57,399 62,262 66,301 66,615 6

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 7,182 7,312 7,764 8,460 9,041 10,036 10,651 11,986 13,459 14,937 15,663 1CO2 Charge ($000) 367 439 539 667 776 928 1,054 1,262 1,500 1,745 1,912 

Unit 23

MWh 4,000 3,318 5,469 5,640 1,481 703 1,327 1,089 219 821 3,238 1,585 319 667 1,858 

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 395 198 373 319 67 258 989 522 113 246 694 

CO2 Charge ($000) 20 12 26 25 6 24 98 55 13 29 85 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 145,500 146,401 147,459 148,554 149,601 150,366 151,326 152,064 152,911 153,462 154,214 15Fuel + 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 1CO2 Charge ($000) 2,061 2,448 2,858 3,294 3,752 4,215 4,718 5,239 5,789 6,356 6,956 

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 14

Total CO2 Charge ($000) 00000 7,787 9,276 10,849 12,507 14,293 16,103 18,101 20,164 22,355 24,645 27,132 2Incremental Non-fuel Production Cost ($000) 00000 19,134 19,221 19,313 19,406 19,502 19,598 19,697 19,797 19,901 20,004 20,111 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

6 Case: 1-4 Base Load, add CFB , replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 207,090 206,913 208,933 209,187 209,058 209,255 211,971 212,262 214,491 213,742 210,999 21

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 49,921 50,133 50,725 51,040 53,024 55,136 57,858 60,157 63,007 65,478 67,680 7CO2 Charge ($000) 2,553 3,012 3,515 4,022 4,546 5,098 5,727 6,335 7,022 7,655 8,266 

CC 2

MWh 49,873 47,522 47,458 46,613 31,686 31,674 30,424 31,241 32,500 32,474 30,569 30,954 30,302 31,575 35,051 3

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 7,594 7,626 7,378 7,636 8,262 8,537 8,364 8,796 8,952 9,715 11,203 1CO2 Charge ($000) 410 484 542 637 750 828 868 971 1,045 1,189 1,432 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 127,218 127,912 128,715 129,129 129,894 130,530 131,127 131,803 132,153 132,750 133,414 13Fuel + 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 1CO2 Charge ($000) 1,809 2,147 2,505 2,874 3,271 3,674 4,105 4,559 5,025 5,520 6,041 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 7

Total CO2 Charge ($000) 00000 4,771 5,643 6,562 7,533 8,567 9,600 10,700 11,865 13,093 14,363 15,740 1Incremental Non-fuel Production Cost ($000) 00000 18,970 19,052 19,137 19,220 19,309 19,398 19,490 19,584 19,678 19,776 19,877 1

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

6 Case: 1-4 Base Load, add CFB , replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 22Total Authority CO2 Charges ($000) 00000 12,558 14,920 17,412 20,040 22,860 25,703 28,801 32,029 35,448 39,009 42,872 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 38,104 38,273 38,449 38,627 38,811 38,996 39,187 39,382 39,578 39,780 39,989 4

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 33

Total 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 28NPV with CO2 Charge ($000) 2,867,522NPV without CO2 Charge ($000) 2,632,980

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

7 Case: 1-4W Base Load, add CFB , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 66

CC 1

MWh 440,702 424,991 427,346 430,844 366,371 368,734 371,378 375,107 376,773 380,120 381,652 383,737 388,560 390,748 393,386 39

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 88,670 89,438 90,371 91,590 95,631 99,851 104,060 108,536 113,922 119,164 124,837 13

CO2 Charge ($000) 4,891 5,795 6,751 7,773 8,829 9,920 11,062 12,269 13,623 14,940 16,343 1

Unit 13

MWh 30,299 40,164 41,135 41,994 30,686 32,909 32,868 32,225 33,907 33,738 34,967 34,836 34,183 34,288 36,262 3

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 6,854 7,361 7,357 7,322 7,929 8,210 8,811 9,060 9,341 9,713 10,721 1CO2 Charge ($000) 407 513 590 667 785 876 1,005 1,098 1,196 1,304 1,502 

Unit 15

MWh 979 380 140 210 88 190 110 176 10 10 676 

Fuel + CO2 Charge ($000) 308 126 49 73 0 30 70 0 42 0 71 4 0 5 279 CO2 Charge ($000) 0 2 5 0 4 0 7 0 0 1 34 

Unit 18

MWh 8,470 12,805 13,357 14,568 2,874 4,131 4,226 3,655 5,824 5,063 5,125 7,399 6,336 6,679 6,944 

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 785 1,135 1,160 1,038 1,657 1,513 1,590 2,295 2,107 2,329 2,471 

CO2 Charge ($000) 40 68 80 82 142 140 157 242 235 272 302 

Unit 22

MWh 80,936 83,941 84,753 85,544 41,057 41,456 43,739 47,500 48,759 52,080 53,083 57,399 62,262 66,301 66,615 6

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 7,182 7,312 7,764 8,460 9,041 10,036 10,651 11,986 13,459 14,937 15,663 1CO2 Charge ($000) 367 439 539 667 776 928 1,054 1,262 1,500 1,745 1,912 

Unit 23

MWh 4,000 3,318 5,469 5,640 1,480 686 1,319 1,031 219 817 3,215 1,585 319 667 1,840 

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 395 193 371 302 67 258 984 522 113 246 689 

CO2 Charge ($000) 20 12 26 24 6 24 97 55 13 29 84 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 145,500 146,401 147,459 148,554 149,601 150,366 151,326 152,064 152,911 153,462 154,214 15Fuel + 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 1CO2 Charge ($000) 2,061 2,448 2,858 3,294 3,752 4,215 4,718 5,239 5,789 6,356 6,956 

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 14

Total CO2 Charge ($000) 00000 7,787 9,276 10,849 12,507 14,293 16,103 18,101 20,165 22,356 24,646 27,133 2Incremental Non-fuel Production Cost ($000) 00000 19,134 19,221 19,313 19,406 19,502 19,598 19,697 19,797 19,901 20,004 20,111 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

7 Case: 1-4W Base Load, add CFB , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 202,415 202,349 203,953 203,739 203,652 203,603 205,736 205,907 207,695 205,980 203,102 20

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 49,138 49,356 49,875 50,110 52,058 54,083 56,655 58,882 61,594 63,804 65,893 6CO2 Charge ($000) 2,513 2,965 3,457 3,949 4,464 5,001 5,608 6,201 6,865 7,459 8,048 

CC 2

MWh 49,873 47,522 47,458 46,613 31,468 31,400 30,183 30,935 32,154 32,073 30,214 30,546 29,903 31,080 34,433 3

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 7,544 7,563 7,321 7,564 8,177 8,435 8,270 8,684 8,838 9,567 11,013 1CO2 Charge ($000) 407 480 537 631 743 818 858 959 1,032 1,171 1,408 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 118,292 118,767 119,720 120,440 121,138 121,903 122,860 123,535 124,257 125,425 126,273 12Fuel + 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 1CO2 Charge ($000) 1,686 1,998 2,336 2,686 3,057 3,438 3,854 4,281 4,734 5,224 5,728 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 560 573 586 600 614 628 642 657 672 687 703 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 7

Total CO2 Charge ($000) 00000 4,606 5,444 6,330 7,266 8,263 9,257 10,320 11,441 12,631 13,854 15,183 1Incremental Non-fuel Production Cost ($000) 00000 22,100 22,191 22,289 22,386 22,486 22,589 22,697 22,804 22,915 23,033 23,150 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

7 Case: 1-4W Base Load, add CFB , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 22Total Authority CO2 Charges ($000) 00000 12,392 14,720 17,179 19,773 22,556 25,360 28,422 31,606 34,987 38,500 42,317 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 41,234 41,413 41,601 41,793 41,988 42,187 42,394 42,601 42,815 43,036 43,261 4

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 33

Total 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 28NPV with CO2 Charge ($000) 2,876,990NPV without CO2 Charge ($000) 2,645,511

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

8 Case: 1-5 Base Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 69

CC 1

MWh 440,702 424,991 427,346 430,844

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 30,299 40,164 41,135 41,994

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 00000000000

CO2 Charge ($000)

Unit 15

MWh 979 380 140 210 95,162 95,773 96,842 95,897 96,027 97,786 99,109 99,403 100,330 101,353 101,433 10Fuel + CO2 Charge ($000) 308 126 49 73 31,622 31,824 32,184 32,199 33,550 35,113 36,750 38,236 39,976 41,864 43,665 4CO2 Charge ($000) 1,618 1,914 2,234 2,539 2,882 3,247 3,638 4,027 4,456 4,895 5,334 

Unit 18

MWh 8,470 12,805 13,357 14,568 142,103 143,881 144,772 143,891 145,363 146,354 146,174 147,142 148,773 148,579 148,368 15

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 32,889 33,272 33,624 33,682 35,299 36,767 38,191 39,860 41,804 43,478 45,260 4

CO2 Charge ($000) 1,683 2,001 2,333 2,658 3,032 3,400 3,781 4,198 4,660 5,083 5,528 

Unit 22

MWh 80,936 83,941 84,753 85,544 100,012 105,240 106,429 108,557 111,485 113,525 117,242 118,517 120,109 122,350 122,530 12

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 17,516 18,452 18,776 19,282 20,553 21,694 23,282 24,442 25,700 27,266 28,521 3CO2 Charge ($000) 896 1,110 1,303 1,520 1,766 2,006 2,305 2,574 2,865 3,185 3,484 

Unit 23

MWh 4,000 3,318 5,469 5,640 7,056 4,860 7,607 9,267 11,344 10,445 10,066 10,991 17,289 14,005 14,315 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,967 1,382 2,148 2,516 3,226 3,128 3,168 3,652 5,674 4,870 5,249 CO2 Charge ($000) 101 83 149 201 277 289 314 384 633 572 643 

New Resources

CT1

Fixed 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 

Variable O&M ($000) 118 127 136 140 162 179 195 215 225 242 236 Capital Cost ($000) 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 MWh 35,834 37,649 39,603 39,795 45,074 48,633 51,817 55,771 56,979 59,920 57,253 6Fuel + 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 2CO2 Charge ($000) 453 565 688 789 1,009 1,215 1,447 1,715 1,923 2,220 2,315 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 2MWh 231,801 232,114 231,744 236,614 231,507 231,751 231,739 231,719 226,892 232,157 242,428 23Fuel + 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 2CO2 Charge ($000) 3,275 3,871 4,481 5,231 5,787 6,491 7,217 7,973 8,578 9,598 10,915 1

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 14

Total CO2 Charge ($000) 00000 8,026 9,544 11,188 12,938 14,752 16,647 18,701 20,871 23,114 25,554 28,218 3Incremental Non-fuel Production Cost ($000) 00000 38,134 38,326 38,516 38,755 38,920 39,137 39,354 39,580 39,749 40,038 40,369 4

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

8 Case: 1-5 Base Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 39

(37)

CC 1

MWh 306,767 302,805 304,385 306,953

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,873 47,522 47,458 46,613

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 00000000000

CO2 Charge ($000)

Unit 16

MWh 0000 11,792 11,794 11,706 11,927 12,601 13,213 13,434 13,245 13,974 13,873 14,454 1Fuel + CO2 Charge ($000) 0000 3,614 3,632 3,604 3,726 3,920 4,354 4,600 4,621 5,262 5,202 5,876 CO2 Charge ($000) 185 218 250 294 336 403 455 486 586 608 717 

Unit 17

MWh 0000 50,846 52,273 53,417 54,389 52,706 55,654 56,898 57,632 58,675 60,787 62,344 6

Fuel + CO2 Charge ($000) 0000 11,498 11,799 12,114 12,326 12,514 13,574 14,340 15,065 15,829 17,091 18,157 1CO2 Charge ($000) 588 709 840 972 1,074 1,255 1,419 1,586 1,764 1,998 2,217 

Unit 19

MWh 0000 353 617 736 904 2,422 1,208 847 1,541 736 1,008 205 

Fuel + CO2 Charge ($000) 0000 117 194 243 289 756 408 317 576 290 422 92 CO2 Charge ($000) 6 12 17 23 65 38 31 61 32 49 11 

Unit 20

MWh 0000 156,482 157,257 157,588 158,035 158,668 158,757 159,566 160,084 160,475 160,771 161,037 16

Fuel + CO2 Charge ($000) 0000 35,378 35,597 35,854 36,148 37,699 39,103 40,793 42,460 44,244 46,134 48,161 5CO2 Charge ($000) 1,810 2,140 2,488 2,852 3,237 3,616 4,038 4,471 4,931 5,393 5,881 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 156,827 156,007 156,353 156,335 156,831 156,334 156,355 156,355 156,839 156,160 156,360 15Fuel + 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 1CO2 Charge ($000) 2,217 2,604 3,027 3,461 3,929 4,378 4,871 5,383 5,936 6,465 7,051 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 7

Total CO2 Charge ($000) 00000 4,806 5,684 6,621 7,602 8,640 9,689 10,815 11,988 13,249 14,512 15,877 1Incremental Non-fuel Production Cost ($000) 00000 19,061 19,155 19,246 19,342 19,444 19,537 19,645 19,751 19,853 19,964 20,077 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

8 Case: 1-5 Base Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 21Total Authority CO2 Charges ($000) 00000 12,832 15,228 17,810 20,540 23,393 26,336 29,515 32,859 36,363 40,067 44,096 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 57,195 57,481 57,762 58,096 58,365 58,673 58,999 59,331 59,602 60,002 60,446 6

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 33Total 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 29NPV with CO2 Charge ($000) 2,882,216NPV without CO2 Charge ($000) 2,641,455

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

9 Case: 1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 69

CC 1

MWh 440,702 424,991 427,346 430,844

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 30,299 40,164 41,135 41,994

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 00000000000

CO2 Charge ($000)

Unit 15

MWh 979 380 140 210 95,195 95,853 96,902 96,060 96,095 97,871 99,270 99,486 100,423 101,445 101,524 10Fuel + CO2 Charge ($000) 308 126 49 73 31,628 31,838 32,195 32,229 33,562 35,131 36,783 38,255 39,997 41,887 43,688 4CO2 Charge ($000) 1,618 1,915 2,234 2,542 2,883 3,248 3,641 4,029 4,458 4,898 5,336 

Unit 18

MWh 8,470 12,805 13,357 14,568 142,249 143,974 144,922 144,091 145,509 146,452 146,376 147,294 148,885 148,769 148,480 15

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 32,914 33,288 33,650 33,720 35,329 36,788 38,233 39,893 41,830 43,524 45,287 4

CO2 Charge ($000) 1,684 2,002 2,335 2,661 3,034 3,401 3,785 4,201 4,663 5,089 5,532 

Unit 22

MWh 80,936 83,941 84,753 85,544 100,035 105,290 106,447 108,612 111,526 113,548 117,323 118,566 120,152 122,398 122,580 12

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 17,519 18,458 18,778 19,288 20,558 21,697 23,293 24,449 25,707 27,273 28,529 3CO2 Charge ($000) 897 1,110 1,304 1,521 1,766 2,006 2,306 2,575 2,866 3,186 3,485 

Unit 23

MWh 4,000 3,318 5,469 5,640 6,982 4,850 7,589 9,197 11,306 10,346 9,968 10,973 17,245 14,009 14,266 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 1,948 1,379 2,143 2,499 3,217 3,102 3,140 3,648 5,661 4,873 5,235 CO2 Charge ($000) 100 83 149 200 276 287 311 384 631 573 641 

New Resources

CT1

Fixed 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 

Variable O&M ($000) 117 126 135 139 161 179 194 214 224 240 235 Capital Cost ($000) 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 MWh 35,704 37,433 39,384 39,442 44,855 48,518 51,463 55,499 56,772 59,582 57,040 6Fuel + 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 2CO2 Charge ($000) 452 562 684 783 1,005 1,212 1,437 1,707 1,916 2,209 2,307 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 26,264 2MWh 231,803 232,118 231,754 236,619 231,509 231,756 231,746 231,724 226,894 232,161 242,437 23Fuel + 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 2CO2 Charge ($000) 3,275 3,871 4,481 5,231 5,787 6,491 7,217 7,973 8,578 9,598 10,915 1

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 14

Total CO2 Charge ($000) 00000 8,025 9,543 11,187 12,936 14,751 16,645 18,697 20,869 23,111 25,552 28,216 3Incremental Non-fuel Production Cost ($000) 00000 38,134 38,325 38,515 38,753 38,920 39,136 39,353 39,579 39,748 40,037 40,368 4

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

9 Case: 1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 39

18,008

CC 1

MWh 306,767 302,805 304,385 306,953

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,873 47,522 47,458 46,613

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 00000000000

CO2 Charge ($000)

Unit 16

MWh 0000 9,109 9,983 9,999 8,960 10,994 11,241 11,348 11,794 11,924 11,924 12,038 1Fuel + CO2 Charge ($000) 0000 2,809 3,072 3,086 2,819 3,408 3,700 3,906 4,119 4,560 4,496 4,979 CO2 Charge ($000) 185 218 250 294 336 403 455 486 586 608 717 

Unit 17

MWh 0000 40,885 41,703 42,792 44,593 41,999 45,011 45,836 46,447 47,580 49,370 51,278 5

Fuel + CO2 Charge ($000) 0000 9,560 9,758 10,082 10,497 10,428 11,443 12,092 12,759 13,424 14,565 15,605 1CO2 Charge ($000) 588 709 840 972 1,074 1,255 1,419 1,586 1,764 1,998 2,217 

Unit 19

MWh 0000 242 522 555 707 2,146 989 690 1,153 618 820 181 

Fuel + CO2 Charge ($000) 0000 81 163 187 227 662 338 261 433 247 348 82 CO2 Charge ($000) 6 12 17 23 65 38 31 61 32 49 11 

Unit 20

MWh 0000 151,226 151,743 152,085 152,978 153,294 153,577 154,841 155,100 155,707 156,284 156,501 15

Fuel + CO2 Charge ($000) 0000 34,587 34,764 35,011 35,355 36,834 38,231 39,971 41,553 43,329 45,258 47,212 4CO2 Charge ($000) 1,810 2,140 2,488 2,852 3,237 3,616 4,038 4,471 4,931 5,393 5,881 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 156,793 155,972 156,325 156,311 156,818 156,315 156,340 156,338 156,827 156,157 156,357 15Fuel + 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 1CO2 Charge ($000) 2,217 2,604 3,027 3,461 3,929 4,378 4,871 5,383 5,936 6,465 7,051 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 6

Total CO2 Charge ($000) 00000 4,806 5,684 6,621 7,602 8,640 9,689 10,815 11,988 13,249 14,512 15,877 1Incremental Non-fuel Production Cost ($000) 00000 19,061 19,155 19,246 19,342 19,444 19,537 19,645 19,751 19,853 19,964 20,077 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

9 Case: 1-5W Base Load, add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 21Total Authority CO2 Charges ($000) 00000 12,831 15,227 17,808 20,538 23,392 26,334 29,512 32,857 36,360 40,064 44,093 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 57,195 57,480 57,761 58,095 58,364 58,673 58,998 59,330 59,601 60,001 60,445 6

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 33Total 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 28NPV with CO2 Charge ($000) 2,851,903NPV without CO2 Charge ($000) 2,611,160

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

10 Case: 1-6 Base Load, Add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 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 66

CC 1

MWh 440,702 424,991 427,346 430,844 430,711 434,107 435,933 439,236 443,044 442,815 447,940 444,308 454,537 466,241 426,305 44

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 98,754 99,789 100,639 101,879 106,692 110,629 115,997 119,492 126,854 134,796 129,581 14

CO2 Charge ($000) 5,448 6,466 7,519 8,648 9,851 10,991 12,332 13,503 15,169 16,901 16,951 1

Unit 13

MWh 30,299 40,164 41,135 41,994 28,417 33,856 34,139 34,137 34,537 33,501 37,816 35,501 31,446 51,132 34,063 4

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 6,770 7,974 8,154 8,206 8,589 8,713 10,073 9,876 9,218 15,530 10,486 1CO2 Charge ($000) 402 556 656 750 853 929 1,149 1,199 1,181 2,088 1,474 

Unit 15

MWh 979 380 140 210

Fuel + CO2 Charge ($000) 308 126 49 73CO2 Charge ($000)

Unit 18

MWh 8,470 12,805 13,357 14,568 1,586 3,029 2,385 2,406 3,351 3,118 3,806 4,388 2,535 4,572 5,932 

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 437 847 665 687 994 939 1,205 1,393 861 1,629 2,145 

CO2 Charge ($000) 22 51 46 54 85 87 119 147 96 191 263 

Unit 22

MWh 80,936 83,941 84,753 85,544 46,342 42,144 45,343 47,201 48,253 51,621 50,215 52,969 56,261 67,881 46,756 6

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 8,066 7,377 7,977 8,359 8,917 9,888 9,991 11,011 12,137 15,154 11,058 1CO2 Charge ($000) 413 445 555 659 768 914 989 1,160 1,353 1,770 1,352 

Unit 23

MWh 4,000 3,318 5,469 5,640 904 363 724 756 44 607 754 1,253 507 652 1,502 

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 240 105 200 219 13 182 240 414 180 241 570 

CO2 Charge ($000) 12 6 14 17 1 17 24 44 20 28 70 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 14

Total CO2 Charge ($000) 00000 6,297 7,524 8,790 10,129 11,558 12,938 14,613 16,052 17,818 20,978 20,110 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

10 Case: 1-6 Base Load, Add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 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 37

CC 1

MWh 306,767 302,805 304,385 306,953 278,443 281,400 285,156 288,673 291,671 297,810 298,714 309,933 310,542 268,146 362,491 32

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 61,531 62,307 63,238 64,157 67,179 70,881 73,782 78,901 82,079 73,516 103,635 9CO2 Charge ($000) 3,146 3,743 4,383 5,056 5,760 6,554 7,302 8,310 9,149 8,588 12,658 1

CC 2

MWh 49,873 47,522 47,458 46,613 225 25 25 701 

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489 0 54 6 6 0 184 0 0 0 0 0 CO2 Charge ($000) 0 3 0 1 0 18 0 0 0 0 0 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 154,735 154,794 155,072 155,310 155,916 155,744 155,963 156,349 158,271 164,976 156,351 15Fuel + 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 1CO2 Charge ($000) 2,188 2,584 3,002 3,440 3,907 4,362 4,859 5,383 5,983 6,829 7,050 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Interconnection Costs 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 3

Methanol Plant Costs LNG 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 8

Total CO2 Charge ($000) 00000 5,334 6,331 7,385 8,496 9,667 10,934 12,161 13,693 15,132 15,418 19,708 1Incremental Non-fuel Production Cost ($000) 00000 50,131 50,212 50,298 50,385 50,478 50,565 50,659 50,756 50,872 51,044 51,049 5

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

10 Case: 1-6 Base Load, Add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 23Total Authority CO2 Charges ($000) 00000 11,632 13,855 16,175 18,625 21,225 23,872 26,774 29,744 32,951 36,396 39,818 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 50,131 50,212 50,298 50,385 50,478 50,565 50,659 50,756 50,872 51,044 51,049 5

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 35

Total 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 31NPV with CO2 Charge ($000) 3,038,093NPV without CO2 Charge ($000) 2,819,989

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

11 Case: 1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 69

CC 1

MWh 440,702 424,991 427,346 430,844

Fuel + CO2 Charge ($000) 105,342 97,604 101,047 101,150 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 30,299 40,164 41,135 41,994

Fuel + CO2 Charge ($000) 6,227 8,006 8,438 8,640 00000000000

CO2 Charge ($000)

Unit 15

MWh 979 380 140 210 41,022 41,580 42,404 41,881 42,455 42,403 42,819 43,912 44,751 45,019 43,753 4Fuel + CO2 Charge ($000) 308 126 49 73 14,238 14,458 14,742 14,801 15,431 15,820 16,617 17,672 18,436 19,351 19,686 2CO2 Charge ($000) 729 870 1,024 1,168 1,326 1,463 1,645 1,861 2,055 2,263 2,405 

Unit 18

MWh 8,470 12,805 13,357 14,568 120,913 122,073 122,146 121,650 123,696 125,841 125,432 129,214 129,610 130,234 130,638 13

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 29,715 29,964 30,131 30,262 31,789 33,328 34,525 36,546 38,106 39,828 41,585 4

CO2 Charge ($000) 1,520 1,802 2,091 2,388 2,730 3,082 3,418 3,849 4,248 4,657 5,080 

Unit 22

MWh 80,936 83,941 84,753 85,544 59,510 62,729 65,803 67,752 74,678 77,862 82,074 84,088 89,267 90,666 91,341 9

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 10,412 11,031 11,626 12,061 13,820 14,915 16,374 17,403 19,153 20,339 21,392 2CO2 Charge ($000) 533 664 808 951 1,188 1,379 1,621 1,833 2,135 2,376 2,614 

Unit 23

MWh 4,000 3,318 5,469 5,640 8,486 7,418 9,901 8,509 10,408 13,304 11,944 13,526 14,476 12,883 11,877 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 2,299 2,000 2,684 2,276 2,979 3,901 3,666 4,284 4,843 4,451 4,335 CO2 Charge ($000) 118 120 187 181 256 361 363 451 540 522 530 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 8

Total CO2 Charge ($000) 00000 2,899 3,456 4,110 4,687 5,500 6,284 7,047 7,995 8,979 9,818 10,628 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-7 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

11 Case: 1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 39

CC 1

MWh 306,767 302,805 304,385 306,953

Fuel + CO2 Charge ($000) 64,284 61,273 63,397 63,538 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,873 47,522 47,458 46,613

Fuel + CO2 Charge ($000) 11,360 10,415 10,723 10,489CO2 Charge ($000)

Unit 16

MWh 0000 878 720 1,795 2,433 604 1,503 1,628 1,184 1,385 2,272 1,346 

Fuel + CO2 Charge ($000) 0000 249 198 496 677 182 455 532 413 488 799 522 CO2 Charge ($000) 13 12 35 53 16 42 53 43 55 93 64 

Unit 17

MWh 0000 62,478 66,087 64,270 66,078 67,827 68,173 70,843 71,846 75,101 75,316 74,166 7

Fuel + CO2 Charge ($000) 0000 12,729 13,495 13,140 13,547 14,447 15,094 16,182 17,010 18,474 19,263 19,795 2CO2 Charge ($000) 651 812 913 1,070 1,241 1,396 1,602 1,792 2,060 2,253 2,418 

Unit 19

MWh 0000 156 204 284 374 136 355 42 197 76 214 173 

Fuel + CO2 Charge ($000) 0000 45 61 88 113 44 114 15 69 29 84 70 

CO2 Charge ($000) 2 4 6 9 4 11 1 7 3 10 9 

Unit 20

MWh 0000 76,343 77,996 80,195 81,317 84,141 83,815 87,686 86,930 92,451 92,522 91,936 9

Fuel + CO2 Charge ($000) 0000 18,481 18,918 19,384 19,768 21,193 21,767 23,591 24,538 26,727 27,801 28,821 3CO2 Charge ($000) 946 1,138 1,346 1,561 1,821 2,013 2,335 2,585 2,980 3,252 3,521 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 2MWh 313,272 312,329 312,508 312,444 313,470 312,565 312,630 312,638 313,562 312,654 312,685 31Fuel + 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 2CO2 Charge ($000) 4,429 5,213 6,048 6,918 7,853 8,754 9,739 10,763 11,864 12,943 14,100 1

CFB2

Fixed 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 

Variable 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 Capital Cost ($000) 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 2MWh 304,086 305,098 305,973 311,908 306,155 306,529 307,171 307,566 300,120 308,420 321,975 30Fuel + 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 2CO2 Charge ($000) 4,299 5,091 5,919 6,899 7,656 8,588 9,569 10,586 11,350 12,754 14,499 1

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Interconnection Costs 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 3

Methanol 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 7

Total CO2 Charge ($000) 00000 10,340 12,270 14,266 16,510 18,591 20,803 23,300 25,776 28,312 31,305 34,610 3

Incremental Non-fuel Production Cost ($000) 00000 88,546 88,875 89,222 89,622 89,929 90,284 90,660 91,042 91,357 91,832 92,389 9

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\

PowerSupply Cost Summary_v6.xls 1-7 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

11 Case: 1-7 Base Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 15Total Authority CO2 Charges ($000) 00000 13,239 15,726 18,375 21,198 24,090 27,087 30,347 33,771 37,291 41,123 45,238 4

Total Authority Incremental Non-fuel Production Cost ($000) 00000 88,546 88,875 89,222 89,622 89,929 90,284 90,660 91,042 91,357 91,832 92,389 9

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 31Total 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 26NPV with CO2 Charge ($000) 2,729,712NPV without CO2 Charge ($000) 2,482,575

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-7 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

12 Case: 1-8 Same as Case 1-1, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 69

CC 1

MWh 440,702 424,991 427,346 430,844 386,378 414,458 404,065 413,508 421,889 412,818 412,630 413,054 413,464 423,066 415,866 41

Fuel + 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 12CO2 Charge ($000) 4,782 6,038 6,808 7,962 9,152 10,027 11,147 12,320 13,547 15,160 16,210 1

Unit 13

MWh 30,299 40,164 41,135 41,994 99,964 86,779 94,895 93,231 92,716 102,839 104,282 108,715 111,849 112,895 120,885 12

Fuel + 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 3CO2 Charge ($000) 1,212 1,241 1,583 1,775 2,010 2,500 2,812 3,279 3,725 4,178 4,863 

Unit 15

MWh 979 380 140 210 80 867 1,355 10 442 328 501 859 568 

Fuel + CO2 Charge ($000) 308 126 49 73 0 29 303 453 4 0 164 130 220 369 260 CO2 Charge ($000) 0 2 21 36 0 0 16 14 25 43 32 

Unit 18

MWh 8,470 12,805 13,357 14,568 19,716 16,281 17,397 17,772 15,246 16,987 16,905 18,432 17,844 17,147 19,764 1

Fuel + CO2 Charge ($000) 2,037 2,989 3,218 3,452 4,908 4,025 4,275 4,410 4,002 4,653 4,719 5,375 5,368 5,362 6,460 CO2 Charge ($000) 252 243 299 350 347 430 468 567 600 630 792 

Unit 22

MWh 80,936 83,941 84,753 85,544 97,008 94,960 98,140 100,683 104,142 108,329 111,418 113,636 115,230 116,278 119,065 12

Fuel + CO2 Charge ($000) 13,790 13,717 14,282 14,349 17,256 17,067 17,719 18,267 19,634 21,134 22,600 23,901 25,170 26,500 28,223 2CO2 Charge ($000) 883 1,027 1,230 1,440 1,687 1,954 2,237 2,517 2,806 3,096 3,447 

Unit 23

MWh 4,000 3,318 5,469 5,640 7,243 4,760 9,052 5,036 4,906 5,336 7,925 7,132 10,012 7,319 9,253 1

Fuel + CO2 Charge ($000) 1,035 845 1,471 1,479 2,026 1,318 2,446 1,457 1,491 1,687 2,479 2,358 3,372 2,629 3,442 CO2 Charge ($000) 104 79 170 117 129 156 245 249 377 311 422 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 17

Total CO2 Charge ($000) 00000 7,233 8,630 10,111 11,681 13,326 15,068 16,925 18,946 21,080 23,419 25,767 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-8 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

12 Case: 1-8 Same as Case 1-1, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 39

CC 1

MWh 306,767 302,805 304,385 306,953 306,373 313,671 315,349 321,350 325,094 324,185 323,250 323,673 323,621 325,440 323,472 32

Fuel + 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 9CO2 Charge ($000) 3,397 4,099 4,774 5,551 6,348 7,063 7,827 8,645 9,493 10,431 11,275 1

CC 2

MWh 49,873 47,522 47,458 46,613 77,736 70,037 69,061 62,323 59,798 62,577 66,134 67,326 69,657 69,239 73,179 7

Fuel + 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 2CO2 Charge ($000) 910 968 1,107 1,141 1,238 1,452 1,706 1,918 2,182 2,371 2,728 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 10

Total CO2 Charge ($000) 00000 4,307 5,067 5,881 6,692 7,587 8,514 9,533 10,564 11,675 12,802 14,003 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-8 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

12 Case: 1-8 Same as Case 1-1, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 28Total Authority CO2 Charges ($000) 00000 11,540 13,697 15,992 18,373 20,912 23,582 26,458 29,510 32,755 36,222 39,771 4

Total Authority Incremental Non-fuel Production Cost ($000) 0000000000000000Existing Electric Resource Expenses:

Steam Related

Non-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 1

Non-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 Non-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 

Combustion Turbine

Non-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 

Non-Fuel Expenses STT ($000) [2] 604 618 632 647 662 677 692 708 725 741 758 776 794 812 831 850 Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal System Non-fuel O&M STT ($000) [3] 2,404 2,459 2,516 2,574 2,633 00000000000Existing Desal System Non-fuel O&M STC ($000) [3] 2,602 2,662 2,723 2,785 2,849 00000000000

Existing Desal Capital Improvements ($000)

Existing Desal Capital Improvements STT ($000) [3]Existing Desal Capital Improvements STC ($000) [3]

New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 35Total 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 31NPV with CO2 Charge ($000) 2,947,923NPV without CO2 Charge ($000) 2,730,622

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 1-8 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

13 Case: 1-9 Same as Case 1-3, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 565,597 565,614 572,164 578,796 610,270 617,298 624,412 631,610 638,895 646,268 653,729 661,279 668,920 676,653 684,478 69

CC 1

MWh 440,702 424,991 427,346 430,844 406,232 402,539 416,479 428,767 415,399 434,369 426,046 442,315 444,639 459,026 455,065 46

Fuel + 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 10

CO2 Charge ($000) 3,826 4,455 5,325 6,249 6,800 7,944 8,657 9,888 10,905 12,274 13,202 1

Unit 13

MWh 30,299 40,164 41,135 41,994 31,586 35,792 31,724 27,741 36,815 30,866 37,955 31,232 34,005 28,616 33,796 3

Fuel + 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 CO2 Charge ($000) 282 376 387 390 591 552 738 679 805 746 962 

Unit 15

MWh 979 380 140 210 52 564 857 0 62 83 400 279 480 671 455 

Fuel + CO2 Charge ($000) 308 126 49 73 14 142 229 0 18 25 109 83 155 212 150 CO2 Charge ($000) 1 9 16 0 2 2 11 9 18 26 19 

Unit 18

MWh 8,470 12,805 13,357 14,568 25,484 30,478 23,541 25,163 32,601 28,809 31,614 31,919 30,914 31,574 36,095 3

Fuel + 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 CO2 Charge ($000) 226 320 291 354 520 510 623 707 757 863 1,071 

Unit 22

MWh 80,936 83,941 84,753 85,544 143,678 144,382 144,968 145,824 147,521 147,217 147,849 148,194 148,762 148,871 149,186 14

Fuel + 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 2CO2 Charge ($000) 960 1,136 1,321 1,515 1,732 1,931 2,154 2,384 2,631 2,873 3,136 

Unit 23

MWh 4,000 3,318 5,469 5,640 6,417 5,678 8,061 5,042 7,116 5,432 10,139 7,732 10,438 8,035 9,993 1

Fuel + 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 CO2 Charge ($000) 70 74 116 86 139 121 236 205 298 259 346 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 13Total CO2 Charge ($000) 00000 5,364 6,369 7,456 8,594 9,783 11,060 12,419 13,872 15,413 17,042 18,737 2Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls 1-9 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

13 Case: 1-9 Same as Case 1-3, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 356,091 350,189 351,828 353,472 376,263 378,040 379,825 381,619 383,422 385,234 387,055 388,885 390,724 392,573 394,430 39

CC 1

MWh 306,767 302,805 304,385 306,953 302,814 311,271 310,330 313,299 317,077 314,974 315,623 316,274 317,282 319,812 316,979 31

Fuel + 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 6CO2 Charge ($000) 2,568 3,111 3,593 4,139 4,735 5,248 5,845 6,461 7,118 7,840 8,450 

CC 2

MWh 49,873 47,522 47,458 46,613 86,611 75,812 80,111 77,873 75,198 79,952 81,259 82,251 83,282 80,939 86,829 8

Fuel + 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 1CO2 Charge ($000) 754 780 955 1,061 1,159 1,380 1,560 1,744 1,941 2,063 2,408 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 7

Total CO2 Charge ($000) 00000 3,323 3,891 4,549 5,200 5,894 6,628 7,404 8,205 9,059 9,902 10,859 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls 1-9 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

13 Case: 1-9 Same as Case 1-3, Replace existing MED water system with RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 20Total Authority CO2 Charges ($000) 00000 8,687 10,260 12,005 13,794 15,677 17,688 19,823 22,077 24,473 26,944 29,595 3Total Authority Incremental Non-fuel Production Cost ($000) 0000000000000000Existing Electric Resource Expenses:

Steam Related

Non-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 1Non-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 Non-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 

Combustion Turbine

Non-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 

Non-Fuel Expenses STT ($000) [2] 604 618 632 647 662 677 692 708 725 741 758 776 794 812 831 850 Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal System Non-fuel O&M STT ($000) [3] 2,404 2,459 2,516 2,574 2,633 00000000000Existing Desal System Non-fuel O&M STC ($000) [3] 2,602 2,662 2,723 2,785 2,849 00000000000

Existing Desal Capital Improvements ($000)

Existing Desal Capital Improvements STT ($000) [3]Existing Desal Capital Improvements STC ($000) [3]

New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 26Total 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 23NPV with CO2 Charge ($000) 2,429,090NPV without CO2 Charge ($000) 2,267,193

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v7.xls 1-9 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

14 Case: 2-1 High Requirements Load , no retirements, all oil fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 449,159 385,716 448,406 453,360 454,582 480,427 466,555 513,432 430,979 486,545 492,539 521,325 493,214 512,628 520,864 53

Fuel + 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 17

CO2 Charge ($000) 6,120 7,615 8,547 10,728 10,136 12,783 14,348 16,733 17,358 19,675 21,717 2

Unit 13

MWh 31,293 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 8

Fuel + 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 2CO2 Charge ($000) 723 791 1,265 1,237 1,493 1,198 1,427 1,476 2,455 2,766 3,330 

Unit 15

MWh 1,159 761 100 318 220 130 869 40 277 60 20 91 100 

Fuel + CO2 Charge ($000) 355 249 35 107 80 47 303 15 104 0 25 9 40 0 48 CO2 Charge ($000) 4 3 21 1 9 0 2 1 4 0 6 

Unit 18

MWh 9,075 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 1

Fuel + 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 CO2 Charge ($000) 198 189 305 172 346 260 355 271 488 515 678 

Unit 22

MWh 85,208 103,456 100,225 108,759 117,644 122,559 128,463 130,199 135,237 134,445 135,933 137,471 140,291 141,833 142,582 14

Fuel + 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 3CO2 Charge ($000) 1,043 1,283 1,555 1,800 2,107 2,342 2,626 2,926 3,266 3,592 3,931 

Unit 23

MWh 4,655 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 1

Fuel + 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 CO2 Charge ($000) 163 146 233 138 148 125 221 165 398 422 502 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 304 282 312 336 399 423 456 Capital Cost ($000) 4,305 4,305 4,305 4,305 4,305 4,305 4,305 MWh 84,507 76,709 82,917 87,250 101,256 104,880 110,475 11Fuel + CO2 Charge ($000) 00000000 19,848 19,074 21,527 23,663 28,254 30,669 33,647 3CO2 Charge ($000) 0000 1,707 1,764 2,131 2,493 3,151 3,587 4,111 

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 24

Total CO2 Charge ($000) 00000 8,252 10,026 11,926 14,075 15,947 18,470 21,112 24,063 27,119 30,559 34,276 3Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,117 6,182 6,242 6,342 6,403 6,475 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

14 Case: 2-1 High Requirements Load , no retirements, all oil fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,047 333,222 330,887 327,570 324,126 320,434 31

Fuel + 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 9CO2 Charge ($000) 3,638 4,304 4,978 5,706 6,448 7,199 7,957 8,749 9,555 10,362 11,194 1

CC 2

MWh 49,051 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 14

Fuel + 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 4CO2 Charge ($000) 669 856 1,117 1,373 1,710 2,075 2,560 3,095 3,729 4,428 5,237 

Unit 16

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 56 141 281 461 743 1,389 1,682 

Fuel + CO2 Charge ($000) 0 0 0 0 0 0 0 0 20 52 108 184 307 599 756 CO2 Charge ($000) 0 0 0 0 2 5 11 19 34 70 92 

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 12

Total CO2 Charge ($000) 00000 4,306 5,160 6,095 7,079 8,159 9,279 10,527 11,863 13,319 14,860 16,523 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

14 Case: 2-1 High Requirements Load , no retirements, all oil fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 36Total Authority CO2 Charges ($000) 00000 12,558 15,186 18,021 21,154 24,106 27,749 31,639 35,926 40,438 45,419 50,799 5

Total Authority Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,117 6,182 6,242 6,342 6,403 6,475 

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 45

Total 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 40NPV with CO2 Charge ($000) 3,461,340NPV without CO2 Charge ($000) 3,189,954

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

15 Case: 2-1W Same as Case 2-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 449,159 385,716 448,406 453,360 454,582 480,427 466,555 513,432 430,979 486,545 492,539 521,325 493,214 512,628 520,864 53

Fuel + 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 17CO2 Charge ($000) 6,120 7,615 8,547 10,728 10,136 12,783 14,348 16,733 17,358 19,675 21,717 2

Unit 13

MWh 31,293 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 8

Fuel + 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 2

CO2 Charge ($000) 723 791 1,265 1,237 1,493 1,198 1,427 1,476 2,455 2,766 3,330 

Unit 15

MWh 1,159 761 100 318 220 130 869 40 277 60 20 91 100 

Fuel + CO2 Charge ($000) 355 249 35 107 80 47 303 15 104 0 25 9 40 0 48 CO2 Charge ($000) 4 3 21 1 9 0 2 1 4 0 6 

Unit 18

MWh 9,075 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 1

Fuel + 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 CO2 Charge ($000) 198 189 305 172 346 260 355 271 488 515 678 

Unit 22

MWh 85,208 103,456 100,225 108,759 117,644 122,559 128,463 130,199 135,237 134,445 135,933 137,471 140,291 141,833 142,582 14

Fuel + 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 3CO2 Charge ($000) 1,043 1,283 1,555 1,800 2,107 2,342 2,626 2,926 3,266 3,592 3,931 

Unit 23

MWh 4,655 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 1

Fuel + 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 CO2 Charge ($000) 163 146 233 138 148 125 221 165 398 422 502 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 304 282 312 336 399 423 456 Capital Cost ($000) 4,305 4,305 4,305 4,305 4,305 4,305 4,305 MWh 84,507 76,709 82,917 87,250 101,256 104,880 110,475 11Fuel + CO2 Charge ($000) 00000000 19,848 19,074 21,527 23,663 28,254 30,669 33,647 3CO2 Charge ($000) 0000 1,707 1,764 2,131 2,493 3,151 3,587 4,111 

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 24

Total CO2 Charge ($000) 00000 8,252 10,026 11,926 14,075 15,947 18,470 21,112 24,063 27,119 30,559 34,276 3Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,117 6,182 6,242 6,342 6,403 6,475 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

15 Case: 2-1W Same as Case 2-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 322,218 326,204 328,963 334,282 336,478 339,062 339,257 339,549 338,649 336,676 333,559 32

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 68,395 69,269 70,029 71,278 74,496 77,706 80,750 83,922 87,066 90,316 93,511 9CO2 Charge ($000) 3,499 4,165 4,859 5,624 6,397 7,185 7,993 8,838 9,704 10,559 11,421 1

CC 2

MWh 49,051 51,273 49,299 51,079 48,165 49,906 53,270 53,694 57,633 61,181 67,136 73,144 80,373 88,493 98,018 10

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 11,719 12,190 13,080 13,253 14,794 16,334 18,641 21,115 24,132 27,715 32,044 3CO2 Charge ($000) 630 770 953 1,097 1,331 1,585 1,935 2,331 2,818 3,393 4,097 

Unit 16

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 23 62 163 326 686 979 

Fuel + CO2 Charge ($000) 0 0 0 0 0 0 0 0 0 1 2 7 15 35 54 CO2 Charge ($000) 0 0 0 0 2 5 11 19 34 70 92 

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 548 560 573 586 600 614 628 642 657 672 687 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 11

Total CO2 Charge ($000) 00000 4,129 4,935 5,812 6,720 7,730 8,774 9,939 11,188 12,556 14,022 15,611 1Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

15 Case: 2-1W Same as Case 2-1, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 36Total Authority CO2 Charges ($000) 00000 12,381 14,961 17,738 20,796 23,677 27,245 31,051 35,252 39,675 44,580 49,886 5

Total Authority Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 9,354 9,380 9,460 9,534 9,648 9,725 9,812 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 45

Total 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 39NPV with CO2 Charge ($000) 3,441,811NPV without CO2 Charge ($000) 3,174,963

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-1W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

16 Case: 2-2 Same as Case 2-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 401,690 350,736 410,081 422,963 432,692 464,471 457,483 507,865 422,204 477,924 485,788 517,383 492,626 515,247 524,775 53

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 75,942 81,499 80,419 89,475 75,017 85,584 87,644 94,069 90,383 95,549 98,524 10

CO2 Charge ($000) 3,889 4,891 5,546 7,004 6,560 8,288 9,329 10,931 11,393 12,976 14,347 1

Unit 13

MWh 23,755 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 4

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 5,349 4,238 6,201 3,704 6,194 4,550 5,320 3,910 6,937 6,525 7,407 

CO2 Charge ($000) 275 256 431 290 546 441 567 456 878 893 1,085 

Unit 15

MWh 1,159 761 100 318 220 130 869 40 277 60 20 91 100 

Fuel + CO2 Charge ($000) 355 249 35 107 55 32 209 10 70 0 16 5 24 0 28 

CO2 Charge ($000) 3 2 15 1 6 0 2 1 3 0 4 

Unit 18

MWh 15,947 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 5

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 5,323 5,146 7,002 6,167 6,881 4,783 5,021 5,064 7,208 7,796 8,806 

CO2 Charge ($000) 273 310 485 483 606 463 535 590 912 1,063 1,288 

Unit 22

MWh 137,099 140,448 140,832 142,080 143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 14

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 16,658 16,783 16,995 17,150 17,401 17,539 17,750 17,965 18,255 18,488 18,761 1CO2 Charge ($000) 853 1,008 1,173 1,341 1,525 1,698 1,890 2,089 2,303 2,511 2,735 

Unit 23

MWh 4,655 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 1

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 2,181 1,657 2,302 1,208 1,156 882 1,425 967 2,154 2,101 2,344 

CO2 Charge ($000) 112 100 160 94 102 85 152 113 273 289 344 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 304 283 313 337 400 425 460 Capital Cost ($000) 4,305 4,305 4,305 4,305 4,305 4,305 4,305 MWh 84,481 76,852 83,171 87,572 101,487 105,454 111,575 11Fuel + CO2 Charge ($000) 00000000 13,315 12,489 13,733 14,712 17,114 18,117 19,414 2CO2 Charge ($000) 0000 1,169 1,209 1,463 1,711 2,161 2,465 2,833 

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 13

Total CO2 Charge ($000) 00000 5,405 6,567 7,809 9,213 10,513 12,185 13,938 15,890 17,924 20,197 22,637 2Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,118 6,183 6,243 6,343 6,406 6,479 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

16 Case: 2-2 Same as Case 2-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,059 333,239 330,887 327,570 324,126 320,468 31

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 48,584 49,030 49,337 49,882 50,356 50,873 51,140 51,493 51,818 52,153 52,535 5CO2 Charge ($000) 2,489 2,945 3,406 3,905 4,412 4,926 5,445 5,987 6,539 7,091 7,661 

CC 2

MWh 49,051 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 14

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 8,699 9,504 10,790 11,701 13,027 14,272 16,015 17,742 19,706 21,713 23,939 2CO2 Charge ($000) 445 570 744 915 1,139 1,382 1,705 2,062 2,484 2,950 3,487 

Unit 16

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 56 141 281 461 743 1,389 1,682 

Fuel + CO2 Charge ($000) 0000 0 0 0 0 13 34 69 114 186 353 434 CO2 Charge ($000) 0 0 0 0 1 3 7 13 23 48 63 

Unit 20

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 6

Total CO2 Charge ($000) 00000 2,935 3,515 4,151 4,819 5,552 6,312 7,157 8,062 9,046 10,089 11,211 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

16 Case: 2-2 Same as Case 2-1 but with methanol fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 20Total Authority CO2 Charges ($000) 00000 8,340 10,083 11,959 14,032 16,065 18,497 21,095 23,952 26,970 30,285 33,848 3Total Authority Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,118 6,183 6,243 6,343 6,406 6,479 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 27

Total 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 23NPV with CO2 Charge ($000) 2,507,940NPV without CO2 Charge ($000) 2,327,212

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-2 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

17 Case: 2-3 Same as Case 2-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 401,690 350,736 410,081 422,963 432,692 464,471 457,483 507,865 422,204 477,924 485,788 517,383 492,626 515,247 524,775 53

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 79,539 85,090 85,892 96,548 83,460 99,438 102,215 110,491 108,998 116,638 123,853 13

CO2 Charge ($000) 4,345 5,465 6,197 7,827 7,330 9,261 10,425 12,214 12,731 14,499 16,032 1

Unit 13

MWh 23,755 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 4

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 5,596 4,424 6,619 3,991 6,905 5,281 6,198 4,593 8,362 7,980 9,325 1

CO2 Charge ($000) 307 286 481 323 609 492 633 509 980 996 1,211 

Unit 15

MWh 1,159 761 100 318 220 130 869 40 277 60 20 91 100 

Fuel + CO2 Charge ($000) 355 249 35 107 57 34 223 11 78 0 18 6 29 0 35 

CO2 Charge ($000) 3 2 16 1 7 0 2 1 3 0 5 

Unit 18

MWh 15,947 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 5

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 5,569 5,371 7,473 6,648 7,671 5,552 5,850 5,947 8,688 9,522 11,077 1

CO2 Charge ($000) 305 346 541 539 677 517 597 659 1,018 1,187 1,437 

Unit 22

MWh 137,099 140,448 140,832 142,080 143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 14

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 17,344 17,422 18,047 18,391 19,262 20,258 20,579 20,981 21,889 22,436 23,458 2CO2 Charge ($000) 948 1,120 1,303 1,489 1,694 1,887 2,099 2,320 2,559 2,789 3,039 

Unit 23

MWh 4,655 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 1

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 2,275 1,725 2,450 1,298 1,284 1,021 1,656 1,133 2,589 2,570 2,944 

CO2 Charge ($000) 125 111 178 105 113 95 169 125 304 322 383 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 304 283 313 337 400 425 460 Capital Cost ($000) 4,305 4,305 4,305 4,305 4,305 4,305 4,305 MWh 84,481 76,852 83,171 87,572 101,487 105,454 111,575 11Fuel + CO2 Charge ($000) 00000000 14,781 14,453 15,953 17,218 20,563 22,046 24,328 2CO2 Charge ($000) 0000 1,301 1,346 1,628 1,905 2,405 2,743 3,153 

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 18

Total CO2 Charge ($000) 00000 6,033 7,330 8,716 10,284 11,730 13,597 15,553 17,733 20,000 22,537 25,259 2Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,118 6,183 6,243 6,343 6,406 6,479 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

17 Case: 2-3 Same as Case 2-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 335,808 337,115 336,044 337,064 336,171 336,059 333,239 330,887 327,570 324,126 320,468 31

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 50,896 51,209 52,711 53,837 56,084 59,121 59,656 60,506 62,514 63,709 66,093 6CO2 Charge ($000) 2,782 3,291 3,807 4,364 4,931 5,506 6,086 6,691 7,308 7,925 8,562 

CC 2

MWh 49,051 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 14

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 9,106 9,918 11,519 12,615 14,486 16,574 18,669 20,829 23,754 26,497 30,084 3CO2 Charge ($000) 498 637 831 1,021 1,272 1,544 1,904 2,303 2,775 3,295 3,895 

Unit 16

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 56 141 281 461 743 1,389 1,682 

Fuel + CO2 Charge ($000) 0000 0 0 0 0 15 39 80 134 224 431 545 

CO2 Charge ($000) 0 0 0 0 1 4 8 15 26 54 71 

Unit 20

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 8

Total CO2 Charge ($000) 00000 3,280 3,928 4,638 5,385 6,205 7,053 7,998 9,008 10,109 11,273 12,527 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

17 Case: 2-3 Same as Case 2-1 but with LNG fuel

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 27Total Authority CO2 Charges ($000) 00000 9,313 11,259 13,354 15,670 17,935 20,650 23,551 26,741 30,109 33,810 37,787 4Total Authority Incremental Non-fuel Production Cost ($000) 000000000 6,104 6,118 6,183 6,243 6,343 6,406 6,479 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 34

Total 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 30NPV with CO2 Charge ($000) 2,807,365NPV without CO2 Charge ($000) 2,605,599

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

18 Case: 2-3W Same as Case 2-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 401,690 350,736 410,081 422,963 434,024 465,770 458,825 509,098 424,389 480,067 487,188 518,275 493,179 515,371 524,373 53

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 79,739 85,286 86,101 96,743 83,815 99,805 102,456 110,644 109,096 116,657 123,766 13

CO2 Charge ($000) 4,356 5,478 6,212 7,842 7,361 9,295 10,449 12,231 12,742 14,502 16,021 1

Unit 13

MWh 23,755 53,722 30,886 30,668 32,847 25,181 37,106 21,372 34,909 25,226 30,051 21,265 38,198 35,402 39,557 4

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 5,595 4,357 6,569 3,959 6,877 5,253 6,200 4,588 8,374 8,023 9,357 1CO2 Charge ($000) 307 282 477 321 607 489 633 509 982 1,002 1,216 

Unit 15

MWh 1,159 761 100 318 240 210 929 40 277 60 20 91 100 

Fuel + CO2 Charge ($000) 355 249 35 107 62 55 239 11 78 0 18 6 29 0 35 CO2 Charge ($000) 3 4 17 1 7 0 2 1 3 0 5 

Unit 18

MWh 15,947 44,647 26,547 31,017 31,462 29,403 39,769 32,721 42,505 28,743 29,467 28,528 40,140 41,987 47,020 5

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 5,315 5,166 7,225 6,366 7,682 5,579 5,845 5,997 8,725 9,522 11,116 1CO2 Charge ($000) 291 333 523 516 678 520 597 664 1,022 1,187 1,442 

Unit 22

MWh 137,099 140,448 140,832 142,080 143,650 143,901 144,612 144,707 145,273 144,761 144,818 144,818 145,274 144,970 144,818 14

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 17,344 17,422 18,047 18,391 19,262 20,258 20,579 20,981 21,889 22,436 23,458 2CO2 Charge ($000) 948 1,120 1,303 1,489 1,694 1,887 2,099 2,320 2,559 2,789 3,039 

Unit 23

MWh 4,655 8,719 8,761 8,099 11,673 8,886 12,249 6,362 6,078 4,424 7,297 4,755 10,713 10,315 11,458 1

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 2,273 1,724 2,448 1,298 1,293 1,016 1,654 1,128 2,583 2,548 2,953 CO2 Charge ($000) 124 111 178 105 114 95 169 125 303 319 384 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 296 275 307 332 396 423 459 Capital Cost ($000) 4,305 4,305 4,305 4,305 4,305 4,305 4,305 MWh 82,266 74,571 81,617 86,239 100,503 104,858 111,178 11Fuel + CO2 Charge ($000) 00000000 14,370 13,981 15,588 16,880 20,288 21,838 24,128 2CO2 Charge ($000) 0000 1,265 1,302 1,591 1,867 2,373 2,718 3,127 

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 18

Total CO2 Charge ($000) 00000 6,030 7,327 8,711 10,275 11,725 13,587 15,540 17,717 19,984 22,516 25,232 2Incremental Non-fuel Production Cost ($000) 000000000 6,096 6,109 6,177 6,238 6,339 6,403 6,477 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

18 Case: 2-3W Same as Case 2-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 322,218 326,204 328,963 334,282 336,478 338,841 338,323 338,907 337,192 335,385 332,419 32

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 49,411 50,022 51,932 53,550 56,159 59,519 60,354 61,603 63,869 65,325 67,878 7CO2 Charge ($000) 2,701 3,215 3,751 4,341 4,938 5,543 6,157 6,812 7,466 8,126 8,793 

CC 2

MWh 49,051 51,273 49,299 51,079 48,165 49,906 53,270 53,694 57,633 61,406 68,111 73,794 81,848 89,793 99,168 11

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 8,345 8,672 9,551 9,800 10,969 12,357 13,930 15,393 17,778 20,044 23,170 2CO2 Charge ($000) 456 557 689 794 963 1,151 1,421 1,702 2,076 2,492 3,000 

Unit 16

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 17

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Unit 19

MWh 23 62 163 326 686 979 

Fuel + CO2 Charge ($000) 0 0 0 0 0 6 18 47 98 213 317 CO2 Charge ($000) 0 0 0 0 0 1 2 5 11 26 41 

Unit 20

MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 548 560 573 586 600 614 628 642 657 672 687 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 8

Total CO2 Charge ($000) 00000 3,157 3,772 4,440 5,134 5,901 6,694 7,579 8,519 9,554 10,645 11,834 1Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 3,250 3,263 3,277 3,292 3,307 3,322 3,337 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

18 Case: 2-3W Same as Case 2-1 but with LNG fuel, add Wind Project

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 26Total Authority CO2 Charges ($000) 00000 9,187 11,099 13,151 15,409 17,626 20,282 23,119 26,236 29,539 33,161 37,066 4Total Authority Incremental Non-fuel Production Cost ($000) 00000 3,197 3,210 3,223 3,236 9,346 9,373 9,455 9,530 9,645 9,725 9,815 Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 34

Total 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 29NPV with CO2 Charge ($000) 2,800,480NPV without CO2 Charge ($000) 2,602,215

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-3W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

19 Case: 2-4 High Requirements Load, Add CFBs, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 449,159 385,716 448,406 453,360 364,663 370,035 377,902 351,864 432,141 403,487 367,629 443,237 427,215 449,295 459,853 47

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 88,481 89,535 91,411 85,021 108,274 104,050 97,723 121,582 120,784 131,522 139,527 14

CO2 Charge ($000) 4,881 5,795 6,820 7,208 9,994 10,338 10,387 13,739 14,434 16,477 18,252 2

Unit 13

MWh 31,293 74,466 43,638 48,090 30,312 34,850 35,251 54,727 14,853 37,718 67,274 35,584 53,708 52,239 57,822 6

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 6,838 7,865 7,960 12,424 3,585 9,388 17,011 9,527 14,857 15,166 17,588 2CO2 Charge ($000) 406 551 644 1,138 355 1,001 1,941 1,157 1,908 2,043 2,472 

Unit 15

MWh 1,159 761 100 318 40 513 461 124 60 

Fuel + CO2 Charge ($000) 355 249 35 107 0 15 171 144 0 0 0 0 0 57 29 CO2 Charge ($000) 0 1 12 11 0 0 0 0 0 7 4 

Unit 18

MWh 9,075 25,082 15,070 15,973 2,569 5,089 4,702 9,248 1,927 7,203 15,275 7,038 10,957 10,883 13,536 1

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 697 1,386 1,308 2,533 537 2,099 4,536 2,201 3,553 3,600 4,550 

CO2 Charge ($000) 36 83 92 201 46 194 449 232 398 424 558 

Unit 22

MWh 85,208 103,456 100,225 108,759 42,430 44,990 49,659 67,714 57,075 75,767 87,375 81,353 92,482 96,176 99,913 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 7,428 7,970 8,886 12,059 10,715 14,552 17,262 16,776 19,649 21,216 22,927 2CO2 Charge ($000) 380 480 618 951 920 1,346 1,709 1,767 2,191 2,478 2,801 

Unit 23

MWh 4,655 8,719 8,761 8,099 1,730 592 2,455 2,231 261 130 696 594 232 1,128 1,717 

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 456 159 658 637 79 41 229 203 85 419 616 

CO2 Charge ($000) 23 10 46 51 7 4 23 21 10 49 75 

New Resources

CT1

Fixed O&M ($000) 1,496 1,530 1,565 1,601 1,638 1,676 

Variable O&M ($000) 6 31 10 34 35 46 Capital Cost ($000) 4,404 4,404 4,404 4,404 4,404 4,404 MWh 1,537 8,318 2,588 8,647 8,675 11,076 1Fuel + CO2 Charge ($000) 0 0 0 0 0 405 2,351 751 2,624 2,753 3,644 CO2 Charge ($000) 0 0 0 0 0 37 233 79 294 324 447 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 2MWh 214,724 218,971 223,150 227,990 229,451 231,958 233,932 233,505 234,858 234,382 234,526 23Fuel + 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 2CO2 Charge ($000) 3,043 3,662 4,323 5,052 5,751 6,498 7,288 8,040 8,887 9,703 10,575 1

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 18

Total CO2 Charge ($000) 00000 8,768 10,582 12,556 14,612 17,073 19,418 22,029 25,036 28,120 31,504 35,183 3Incremental Non-fuel Production Cost ($000) 00000 26,751 26,908 27,069 27,241 27,384 33,447 33,664 33,813 34,031 34,210 34,410 3

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

19 Case: 2-4 High Requirements Load, Add CFBs, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 226,166 219,852 226,659 230,827 236,142 201,876 275,737 244,495 248,947 251,732 256,184 25

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 53,534 52,136 53,837 54,872 58,042 51,246 72,837 66,661 70,197 73,753 77,870 8CO2 Charge ($000) 2,737 3,135 3,736 4,329 4,977 4,738 7,210 7,020 7,824 8,622 9,510 1

CC 2

MWh 49,051 51,273 49,299 51,079 28,929 37,702 35,575 35,552 33,847 73,199 3,350 39,124 40,387 42,394 43,446 4

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 6,922 9,052 8,578 8,641 8,587 19,201 918 11,075 11,892 13,000 13,904 1CO2 Charge ($000) 374 572 625 715 780 1,863 95 1,222 1,388 1,591 1,777 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000 34 45 101 23 90 

Fuel + CO2 Charge ($000) 0000 0 0 0 0 12 17 0 40 9 39 0 CO2 Charge ($000) 0 0 0 0 1 2 0 4 1 5 0 

Unit 20

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 137,357 139,164 140,361 141,809 143,694 144,315 146,226 147,692 148,509 149,892 151,140 15Fuel + 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 1CO2 Charge ($000) 1,949 2,330 2,725 3,147 3,608 4,050 4,563 5,092 5,628 6,211 6,821 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 9

Total CO2 Charge ($000) 00000 5,060 6,037 7,085 8,192 9,365 10,653 11,868 13,339 14,842 16,429 18,108 1Incremental Non-fuel Production Cost ($000) 00000 18,970 19,052 19,137 19,220 19,309 19,398 19,490 19,584 19,678 19,776 19,877 1

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

19 Case: 2-4 High Requirements Load, Add CFBs, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 27Total Authority CO2 Charges ($000) 00000 13,828 16,619 19,641 22,804 26,439 30,071 33,897 38,375 42,962 47,933 53,291 5

Total Authority Incremental Non-fuel Production Cost ($000) 00000 45,721 45,960 46,206 46,461 46,693 52,846 53,154 53,397 53,708 53,986 54,287 5

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 41

Total 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 35NPV with CO2 Charge ($000) 3,264,773NPV without CO2 Charge ($000) 2,977,661

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

20 Case: 2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 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 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 90

CC 1

MWh 449,159 385,716 448,406 453,360 364,678 370,035 377,933 351,987 432,138 403,712 367,753 443,239 427,278 449,388 459,813 47

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 88,484 89,535 91,417 85,044 108,274 104,097 97,750 121,582 120,799 131,544 139,516 14

CO2 Charge ($000) 4,881 5,795 6,821 7,210 9,994 10,342 10,390 13,739 14,436 16,479 18,251 2

Unit 13

MWh 31,293 74,466 43,638 48,090 30,302 34,885 35,208 54,626 14,860 37,542 67,300 35,700 53,864 52,284 57,944 6

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 6,835 7,871 7,950 12,396 3,586 9,335 17,007 9,548 14,886 15,169 17,618 2CO2 Charge ($000) 406 551 643 1,135 355 996 1,941 1,160 1,912 2,043 2,476 

Unit 15

MWh 1,159 761 100 318 40 513 464 124 60 

Fuel + CO2 Charge ($000) 355 249 35 107 0 15 171 145 0 0 0 0 0 57 29 CO2 Charge ($000) 0 1 12 11 0 0 0 0 0 7 4 

Unit 18

MWh 9,075 25,082 15,070 15,973 2,564 5,054 4,713 9,246 1,924 7,208 15,316 7,015 11,184 11,022 13,614 1

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 697 1,376 1,310 2,532 536 2,100 4,541 2,186 3,594 3,627 4,564 

CO2 Charge ($000) 36 83 92 201 46 194 450 231 402 427 559 

Unit 22

MWh 85,208 103,456 100,225 108,759 42,430 44,990 49,659 67,714 57,075 75,767 87,375 81,353 92,482 96,176 99,913 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 7,428 7,970 8,886 12,059 10,715 14,552 17,262 16,776 19,649 21,216 22,927 2CO2 Charge ($000) 380 480 618 951 920 1,346 1,709 1,767 2,191 2,478 2,801 

Unit 23

MWh 4,655 8,719 8,761 8,099 1,730 592 2,455 2,207 261 130 696 594 232 1,128 1,717 

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 456 159 658 633 79 41 229 203 85 419 616 

CO2 Charge ($000) 23 10 46 51 7 4 23 21 10 49 75 

New Resources

CT1

Fixed O&M ($000) 1,530 1,565 1,601 1,638 1,676 1,714 

Variable O&M ($000) 6 31 10 33 35 46 Capital Cost ($000) 4,404 4,404 4,404 4,404 4,404 4,404 MWh 1,483 8,126 2,493 8,202 8,399 10,916 1Fuel + CO2 Charge ($000) 0 0 0 0 0 390 2,297 724 2,490 2,667 3,589 CO2 Charge ($000) 0 0 0 0 0 36 227 76 278 314 440 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 21,617 2MWh 214,724 218,971 223,150 227,990 229,451 231,958 233,932 233,505 234,858 234,382 234,526 23Fuel + 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 2CO2 Charge ($000) 3,043 3,662 4,323 5,052 5,751 6,498 7,288 8,040 8,887 9,703 10,575 1

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 18

Total CO2 Charge ($000) 00000 8,768 10,582 12,556 14,611 17,073 19,415 22,027 25,034 28,115 31,501 35,181 3Incremental Non-fuel Production Cost ($000) 00000 26,751 26,908 27,069 27,241 27,384 33,481 33,699 33,849 34,066 34,247 34,449 3

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

20 Case: 2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 216,847 209,249 215,588 220,489 223,928 192,163 262,783 232,448 237,463 238,481 243,184 24

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 51,945 50,310 51,933 53,065 55,848 49,430 70,324 64,240 67,820 70,912 74,978 7CO2 Charge ($000) 2,737 3,135 3,736 4,329 4,977 4,738 7,210 7,020 7,824 8,622 9,510 1

CC 2

MWh 49,051 51,273 49,299 51,079 27,793 36,959 33,984 32,917 32,470 68,422 1,650 36,073 36,286 39,806 40,284 4

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 6,653 8,879 8,201 8,006 8,243 17,960 452 10,216 10,689 12,214 12,901 1CO2 Charge ($000) 374 572 625 715 780 1,863 95 1,222 1,388 1,591 1,777 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000 17 6 45 11 39 

Fuel + CO2 Charge ($000) 0000 0 0 0 0 6 2 0 18 5 17 0 CO2 Charge ($000) 0 0 0 0 1 2 0 4 1 5 0 

Unit 20

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 15,690 1MWh 131,517 133,963 136,101 137,713 140,053 141,366 143,299 145,119 146,288 147,892 149,363 15Fuel + 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 1CO2 Charge ($000) 1,949 2,330 2,725 3,147 3,608 4,050 4,563 5,092 5,628 6,211 6,821 

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000) 548 560 573 586 600 614 628 642 657 672 687 

Variable O&M ($000) 00000000000Capital Cost ($000) 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 2,650 MWh 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 18,044 1Fuel + 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 8

Total CO2 Charge ($000) 00000 5,060 6,037 7,085 8,192 9,365 10,653 11,868 13,339 14,842 16,429 18,108 1Incremental Non-fuel Production Cost ($000) 00000 22,168 22,262 22,360 22,456 22,558 22,662 22,767 22,876 22,984 23,098 23,215 2

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

20 Case: 2-4W High Requirements Load, add CFBs , add Wind Project, replace older capacity

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 27Total Authority CO2 Charges ($000) 00000 13,828 16,619 19,641 22,803 26,439 30,068 33,895 38,373 42,957 47,930 53,289 5

Total Authority Incremental Non-fuel Production Cost ($000) 00000 48,919 49,170 49,429 49,697 49,943 56,143 56,466 56,725 57,051 57,345 57,663 5

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 41

Total 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 35NPV with CO2 Charge ($000) 3,264,441NPV without CO2 Charge ($000) 2,977,347

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-4W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

21 Case: 2-5 High Requirements Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 92

CC 1

MWh 449,159 385,716 448,406 453,360

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 31,293 74,466 43,638 48,090

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 00000000000

CO2 Charge ($000)

Unit 15

MWh 1,159 761 100 318 102,085 103,737 104,646 42,389 42,635 41,568 43,243 45,638 47,737 49,601 50,240 5Fuel + CO2 Charge ($000) 355 249 35 107 32,842 33,230 33,526 14,840 15,487 15,672 16,685 18,066 19,186 20,377 21,282 2CO2 Charge ($000) 1,680 1,998 2,325 1,171 1,330 1,449 1,652 1,903 2,139 2,383 2,600 

Unit 18

MWh 9,075 25,082 15,070 15,973 149,572 151,299 153,118 109,062 113,978 116,642 120,075 124,332 129,916 135,517 140,229 14

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 34,143 34,528 35,044 28,456 30,408 31,932 33,788 35,857 38,332 41,033 43,760 4

CO2 Charge ($000) 1,747 2,076 2,432 2,246 2,612 2,952 3,345 3,777 4,273 4,798 5,345 

Unit 22

MWh 85,208 103,456 100,225 108,759 123,577 125,576 128,860 49,035 58,776 67,994 73,194 79,059 86,346 91,297 96,432 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 21,478 21,898 22,567 8,882 11,078 13,256 14,780 16,512 18,669 20,513 22,567 2CO2 Charge ($000) 1,099 1,317 1,566 700 953 1,226 1,463 1,739 2,082 2,396 2,757 

Unit 23

MWh 4,655 8,719 8,761 8,099 12,342 15,079 17,296 4,640 7,144 5,863 8,113 7,913 12,731 11,800 18,518 2

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 3,358 4,160 4,814 1,268 1,955 1,757 2,474 2,545 4,163 4,151 6,640 CO2 Charge ($000) 172 250 334 102 168 162 245 268 464 488 813 

New Resources

CT1

Fixed 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 

Variable O&M ($000) 196 219 234 69 76 100 122 144 167 197 229 Capital Cost ($000) 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 MWh 59,531 65,139 67,983 19,599 21,166 27,086 32,305 37,336 42,282 48,891 55,587 6Fuel + 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 2CO2 Charge ($000) 750 970 1,173 392 471 677 895 1,145 1,426 1,807 2,234 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 2MWh 232,244 239,009 248,552 249,559 249,273 253,609 258,598 262,922 258,142 267,671 268,942 26Fuel + 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 2CO2 Charge ($000) 3,282 3,990 4,813 5,534 6,248 7,118 8,069 9,061 9,767 11,072 12,113 1

CFB 2

Fixed O&M ($000) 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 

Variable O&M ($000) 2,551 2,635 2,714 2,783 2,856 2,965 3,006 3,076 Capital Cost ($000) 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 2MWh 266,009 268,515 270,428 271,002 271,893 275,917 273,424 273,525 27Fuel + CO2 Charge ($000) 0 0 0 14,262 15,361 16,449 17,521 18,660 20,091 21,171 22,489 2CO2 Charge ($000) 0 0 0 5,891 6,731 7,576 8,441 9,356 10,443 11,320 12,334 1

CFB 3

Fixed 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 12

Total CO2 Charge ($000) 00000 8,730 10,602 12,642 16,036 18,513 21,161 24,110 27,249 30,593 34,264 38,195 4Incremental Non-fuel Production Cost ($000) 00000 33,623 33,888 34,178 64,656 65,048 65,506 65,967 66,436 66,853 67,372 67,842 6

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

21 Case: 2-5 High Requirements Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 47

CC 1

MWh 317,225 320,208 327,636 331,508

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,051 51,273 49,299 51,079

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 00000000000

CO2 Charge ($000)

Unit 16

MWh 0000 15,576 15,446 1,133 4,125 3,881 2,730 3,711 5,439 4,965 5,145 5,330 Fuel + CO2 Charge ($000) 0000 4,628 4,560 341 1,204 1,185 859 1,203 1,837 1,770 1,929 2,134 CO2 Charge ($000) 237 274 24 95 102 79 119 193 197 225 260 

Unit 17

MWh 0000 104,200 106,608 60,077 66,661 65,265 67,577 68,914 70,232 73,078 76,198 79,630 7

Fuel + CO2 Charge ($000) 0000 20,562 21,065 14,520 15,614 15,977 16,930 17,806 18,766 20,014 21,351 22,906 2CO2 Charge ($000) 1,052 1,267 1,008 1,232 1,372 1,565 1,763 1,976 2,230 2,496 2,797 

Unit 19

MWh 0000 23,053 24,037 23,022 22,852 22,817 22,877 22,860 22,979 23,183 23,045 22,725 2

Fuel + CO2 Charge ($000) 0000 7,749 8,065 7,816 7,807 8,106 8,435 8,755 9,144 9,576 9,935 10,220 1CO2 Charge ($000) 397 485 543 616 696 780 867 963 1,067 1,162 1,248 

Unit 20

MWh 0000 132,153 135,048 59,848 69,939 66,701 69,119 71,523 72,789 75,960 77,803 80,287 8

Fuel + CO2 Charge ($000) 0000 31,903 32,488 16,539 18,923 18,858 20,286 21,633 22,909 24,589 26,295 28,096 2CO2 Charge ($000) 1,632 1,953 1,149 1,493 1,619 1,876 2,141 2,412 2,740 3,073 3,431 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 1MWh 156,734 155,943 153,948 154,379 155,021 155,313 155,449 155,664 155,985 155,665 155,956 15Fuel + 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 1CO2 Charge ($000) 2,216 2,603 2,982 3,419 3,884 4,350 4,843 5,360 5,904 6,445 7,033 

CFB2

Fixed O&M ($000) 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 

Variable O&M ($000) 1,367 1,264 1,396 1,450 1,497 1,551 1,591 1,648 1,690 Capital Cost ($000) 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 1MWh 145,846 131,803 142,265 144,414 145,771 147,606 148,026 149,925 150,259 15Fuel + CO2 Charge ($000) 0 0 7,382 7,084 8,154 8,799 9,442 10,148 10,794 11,620 12,363 1CO2 Charge ($000) 0 0 2,829 2,927 3,572 4,053 4,549 5,089 5,610 6,212 6,779 

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 7

Total CO2 Charge ($000) 00000 5,533 6,582 8,534 9,781 11,244 12,704 14,282 15,994 17,750 19,613 21,549 2Incremental Non-fuel Production Cost ($000) 00000 17,717 17,792 36,296 36,336 36,616 36,818 37,015 37,223 37,423 37,636 37,844 3

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

21 Case: 2-5 High Requirements Load, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 20Total Authority CO2 Charges ($000) 00000 14,263 17,184 21,176 25,817 29,757 33,865 38,392 43,242 48,344 53,877 59,744 6

Total Authority Incremental Non-fuel Production Cost ($000) 00000 51,339 51,680 70,474 100,992 101,664 102,324 102,982 103,659 104,276 105,008 105,686 10

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 38Total 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 32NPV with CO2 Charge ($000) 3,169,548NPV without CO2 Charge ($000) 2,850,172

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-5 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

22 Case: 2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 92

CC 1

MWh 449,159 385,716 448,406 453,360

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 31,293 74,466 43,638 48,090

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 00000000000

CO2 Charge ($000)

Unit 15

MWh 1,159 761 100 318 102,085 103,737 104,646 42,389 42,635 41,568 43,243 45,638 47,737 49,601 50,240 5Fuel + CO2 Charge ($000) 355 249 35 107 32,842 33,230 33,526 14,840 15,487 15,672 16,685 18,066 19,186 20,377 21,282 2CO2 Charge ($000) 1,680 1,998 2,325 1,171 1,330 1,449 1,652 1,903 2,139 2,383 2,600 

Unit 18

MWh 9,075 25,082 15,070 15,973 149,572 151,299 153,118 109,062 113,978 116,642 120,075 124,332 129,916 135,517 140,229 14

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 34,143 34,528 35,044 28,456 30,408 31,932 33,788 35,857 38,332 41,033 43,760 4

CO2 Charge ($000) 1,747 2,076 2,432 2,246 2,612 2,952 3,345 3,777 4,273 4,798 5,345 

Unit 22

MWh 85,208 103,456 100,225 108,759 123,577 125,576 128,860 49,035 58,776 67,994 73,194 79,059 86,346 91,297 96,432 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 21,478 21,898 22,567 8,882 11,078 13,256 14,780 16,512 18,669 20,513 22,567 2CO2 Charge ($000) 1,099 1,317 1,566 700 953 1,226 1,463 1,739 2,082 2,396 2,757 

Unit 23

MWh 4,655 8,719 8,761 8,099 12,342 15,079 17,296 4,640 7,144 5,863 8,113 7,913 12,731 11,800 18,518 2

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 3,358 4,160 4,814 1,268 1,955 1,757 2,474 2,545 4,163 4,151 6,640 CO2 Charge ($000) 172 250 334 102 168 162 245 268 464 488 813 

New Resources

CT1

Fixed 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 

Variable O&M ($000) 196 219 234 69 76 100 122 144 167 197 229 Capital Cost ($000) 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 3,930 MWh 59,531 65,139 67,983 19,599 21,166 27,086 32,305 37,336 42,282 48,891 55,587 6Fuel + 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 2CO2 Charge ($000) 750 970 1,173 392 471 677 895 1,145 1,426 1,807 2,234 

CFB 1

Fixed 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 

Variable 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 Capital Cost ($000) 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 21,672 2MWh 232,244 239,009 248,552 249,559 249,273 253,609 258,598 262,922 258,142 267,671 268,942 26Fuel + 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 2CO2 Charge ($000) 3,282 3,990 4,813 5,534 6,248 7,118 8,069 9,061 9,767 11,072 12,113 1

CFB 2

Fixed O&M ($000) 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 

Variable O&M ($000) 2,551 2,635 2,714 2,783 2,856 2,965 3,006 3,076 Capital Cost ($000) 23,202 23,202 23,202 23,202 23,202 23,202 23,202 23,202 2MWh 266,009 268,515 270,428 271,002 271,893 275,917 273,424 273,525 27Fuel + CO2 Charge ($000) 0 0 0 14,262 15,361 16,449 17,521 18,660 20,091 21,171 22,489 2CO2 Charge ($000) 0 0 0 5,891 6,731 7,576 8,441 9,356 10,443 11,320 12,334 1

CFB 3

Fixed 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 12

Total CO2 Charge ($000) 00000 8,730 10,602 12,642 16,036 18,513 21,161 24,110 27,249 30,593 34,264 38,195 4Incremental Non-fuel Production Cost ($000) 00000 33,623 33,888 34,178 64,656 65,048 65,506 65,967 66,436 66,853 67,372 67,842 6

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

22 Case: 2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 47

CC 1

MWh 317,225 320,208 327,636 331,508

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,051 51,273 49,299 51,079

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 00000000000

CO2 Charge ($000)

Unit 16

MWh 0000 13,407 13,992 926 3,590 3,495 2,136 2,799 4,555 2,873 3,223 2,767 Fuel + CO2 Charge ($000) 0000 4,087 4,213 285 1,067 1,090 668 916 1,574 998 1,199 1,090 CO2 Charge ($000) 209 253 20 84 93 62 91 166 111 140 133 

Unit 17

MWh 0000 99,591 101,577 63,964 69,862 67,768 69,802 69,832 70,438 72,535 74,661 77,602 7

Fuel + CO2 Charge ($000) 0000 19,774 20,193 15,010 15,997 16,268 17,193 17,885 18,727 19,876 21,056 22,518 2CO2 Charge ($000) 1,012 1,214 1,042 1,262 1,397 1,590 1,770 1,972 2,215 2,461 2,750 

Unit 19

MWh 0000 22,936 23,930 22,982 22,830 22,800 22,865 22,830 22,963 23,132 23,015 22,725 2

Fuel + CO2 Charge ($000) 0000 7,717 8,035 7,804 7,801 8,101 8,431 8,746 9,139 9,559 9,924 10,220 1CO2 Charge ($000) 395 483 542 616 696 780 866 963 1,066 1,160 1,248 

Unit 20

MWh 0000 121,100 123,709 32,674 44,931 42,575 46,989 51,369 53,963 58,725 62,249 66,114 6

Fuel + CO2 Charge ($000) 0000 30,171 30,743 8,747 11,870 11,797 13,599 15,224 16,705 18,665 20,817 22,974 2CO2 Charge ($000) 1,543 1,848 608 936 1,012 1,257 1,507 1,759 2,080 2,433 2,805 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 14,123 1MWh 156,665 155,872 154,837 155,249 155,867 155,770 155,911 156,043 156,532 155,943 156,191 15Fuel + 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 1CO2 Charge ($000) 2,215 2,602 2,999 3,438 3,905 4,363 4,857 5,372 5,925 6,456 7,043 

CFB2

Fixed O&M ($000) 2,291 2,344 2,398 2,453 2,510 2,567 2,626 2,687 2,749 

Variable O&M ($000) 1,410 1,296 1,426 1,470 1,514 1,562 1,605 1,656 1,696 Capital Cost ($000) 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 14,780 1MWh 150,348 135,146 145,301 146,436 147,439 148,721 149,386 150,664 150,819 15Fuel + CO2 Charge ($000) 0 0 7,603 7,259 8,323 8,919 9,547 10,223 10,891 11,676 12,408 1CO2 Charge ($000) 0 0 2,914 3,000 3,647 4,108 4,600 5,127 5,661 6,243 6,804 

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed 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 6

Total CO2 Charge ($000) 00000 5,374 6,401 8,125 9,335 10,750 12,160 13,691 15,358 17,057 18,893 20,784 2Incremental Non-fuel Production Cost ($000) 00000 17,716 17,791 36,347 36,376 36,654 36,843 37,037 37,239 37,443 37,647 37,853 3

(159) (181) (409) (446) (495) (544) (591) (636) (693) (720) (765) 

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\

PowerSupply Cost Summary_v6.xls 2-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

22 Case: 2-5W High Requirements Load,add Wind Project, Replace Steam Units with CFB and RO

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 19Total Authority CO2 Charges ($000) 00000 14,103 17,003 20,766 25,371 29,263 33,321 37,801 42,607 47,651 53,157 58,979 6

Total Authority Incremental Non-fuel Production Cost ($000) 00000 51,339 51,680 70,525 101,032 101,702 102,349 103,004 103,675 104,296 105,019 105,695 10

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 5.52 5.60 5.68 5.77 5.86 5.94 6.04 6.13 6.22 6.32 6.42 

Total 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 38Total 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 31NPV with CO2 Charge ($000) 3,125,047NPV without CO2 Charge ($000) 2,809,856

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-5W 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

23 Case: 2-6 High Requirements Load, add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 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 90

CC 1

MWh 449,159 385,716 448,406 453,360 390,476 457,585 446,620 442,876 457,434 466,709 473,307 498,515 471,082 486,057 491,921 49

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 88,968 104,753 102,281 101,649 108,869 114,935 120,764 131,951 129,301 138,984 146,409 15

CO2 Charge ($000) 4,905 6,780 7,631 8,617 10,036 11,419 12,836 14,911 15,452 17,411 19,152 2

Unit 13

MWh 31,293 74,466 43,638 48,090 44,832 28,007 39,568 47,292 47,115 51,845 57,080 54,455 76,952 82,407 90,981 10

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 10,431 6,547 9,226 11,115 11,531 13,264 14,979 14,975 21,908 24,499 27,994 3

CO2 Charge ($000) 620 458 745 1,018 1,148 1,415 1,709 1,817 2,811 3,295 3,928 

Unit 15

MWh 1,159 761 100 318 

Fuel + CO2 Charge ($000) 355 249 35 107 0 0 0 0 0 0 0 0 0 0 0 CO2 Charge ($000) 0 0 0 0 0 0 0 0 0 0 0 

Unit 18

MWh 9,075 25,082 15,070 15,973 4,590 4,009 5,214 6,806 7,710 7,661 11,017 8,119 13,274 14,801 19,503 1

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 1,234 1,037 1,407 1,865 2,115 2,167 3,244 2,513 4,194 4,836 6,502 CO2 Charge ($000) 63 62 99 148 183 200 321 265 469 567 796 

Unit 22

MWh 85,208 103,456 100,225 108,759 58,998 45,331 54,555 64,305 69,124 77,990 81,188 86,496 97,105 99,501 101,688 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 10,292 7,991 9,644 11,403 12,723 14,853 16,034 17,718 20,543 21,834 23,210 2CO2 Charge ($000) 527 481 671 899 1,094 1,373 1,587 1,866 2,290 2,551 2,836 

Unit 23

MWh 4,655 8,719 8,761 8,099 393 2,158 1,074 1,781 1,807 1,171 3,718 2,663 6,717 7,328 11,118 1

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 113 568 303 504 525 367 1,170 875 2,276 2,624 4,021 

CO2 Charge ($000) 6 34 21 40 45 34 116 92 254 309 492 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 19

Total CO2 Charge ($000) 00000 6,121 7,816 9,166 10,723 12,506 14,441 16,569 18,951 21,276 24,133 27,204 3Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

23 Case: 2-6 High Requirements Load, add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 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 45

CC 1

MWh 317,225 320,208 327,636 331,508 307,738 295,941 311,971 321,965 329,041 335,641 342,923 349,636 364,161 369,752 376,508 38

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 66,353 64,704 67,591 69,595 73,583 77,485 81,832 86,279 92,544 97,575 103,160 10CO2 Charge ($000) 3,395 3,892 4,692 5,492 6,320 7,164 8,101 9,087 10,316 11,408 12,600 1

CC 2

MWh 49,051 51,273 49,299 51,079 200 749 375 575 1,225 375 950 2,445 2,844 

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475 0 48 0 183 95 152 336 107 284 755 916 CO2 Charge ($000) 0 3 0 15 9 15 35 12 34 93 117 

Unit 16

MWh 0000

Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 17

MWh 0000Fuel + CO2 Charge ($000) 0000CO2 Charge ($000)

Unit 19

MWh 0000 

Fuel + CO2 Charge ($000) 0000 00000000000CO2 Charge ($000) 00000000000

Unit 20

MWhFuel + CO2 Charge ($000) 0000

CO2 Charge ($000)

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 20,968 2MWh 234,974 234,168 234,497 234,527 235,191 234,509 234,540 234,540 235,260 234,510 234,540 23Fuel + 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 2CO2 Charge ($000) 3,322 3,909 4,538 5,193 5,892 6,568 7,306 8,075 8,902 9,708 10,576 1

CFB2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB3

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Wind Project

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Interconnection Costs 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 3

Methanol 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 10

Total CO2 Charge ($000) 00000 6,717 7,804 9,230 10,700 12,221 13,747 15,442 17,173 19,251 21,209 23,293 2Incremental Non-fuel Production Cost ($000) 00000 57,272 57,388 57,518 57,648 57,787 57,916 58,055 58,197 58,350 58,491 58,643 5

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

23 Case: 2-6 High Requirements Load, add CFB, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 29Total Authority CO2 Charges ($000) 00000 12,838 15,620 18,395 21,423 24,726 28,188 32,011 36,124 40,526 45,342 50,498 5

Total Authority Incremental Non-fuel Production Cost ($000) 00000 57,272 57,388 57,518 57,648 57,787 57,916 58,055 58,197 58,350 58,491 58,643 5

Existing Electric Resource Expenses:

Steam Related

Non-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 1

Combustion Turbine

Non-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 

Existing 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 Existing Desal Capital Improvements ($000) 00000 3,532 3,613 2,464 3,781 3,868 2,638 4,048 4,142 2,825 4,334 4,434 

New Water Resources

Water 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 2,03

RO System:

Annual O&M Excl. Electric Energy Costs ($000)[5]Capital ($000) 2X1.5 MGD facility on each Island ($000)[6]$/kGal Excl. Energy Costs

Total 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 43

Total 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 38NPV with CO2 Charge ($000) 3,434,720NPV without CO2 Charge ($000) 3,163,392

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-6 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

24 Case: 2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. ThomasIncremental Electric and Water Production CostsPeak Demand 88.2 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 Energy Requirements 563,867 580,783 598,207 616,153 634,637 678,204 697,815 718,013 738,818 760,247 782,318 805,052 828,468 852,586 877,427 903,014 92

CC 1

MWh 449,159 385,716 448,406 453,360

Fuel + CO2 Charge ($000) 106,771 87,489 104,708 105,139 00000000000

CO2 Charge ($000) 00000000000

Unit 13

MWh 31,293 74,466 43,638 48,090

Fuel + CO2 Charge ($000) 6,472 14,831 9,051 10,126 00000000000

CO2 Charge ($000)

Unit 15

MWh 1,159 761 100 318 44,078 46,065 46,184 39,769 41,272 40,539 41,132 43,202 44,148 45,347 45,581 4

Fuel + CO2 Charge ($000) 355 249 35 107 14,798 15,271 15,468 14,370 15,193 15,467 16,246 17,492 18,365 19,352 20,095 2CO2 Charge ($000) 757 919 1,074 1,133 1,305 1,430 1,608 1,843 2,047 2,263 2,455 

Unit 18

MWh 9,075 25,082 15,070 15,973 133,361 136,696 138,689 64,179 62,532 64,591 68,579 76,668 80,697 94,271 93,403 9

Fuel + CO2 Charge ($000) 2,188 5,893 3,629 3,880 31,566 32,127 32,593 17,380 17,372 18,286 19,924 22,657 24,691 29,889 30,225 3

CO2 Charge ($000) 1,615 1,932 2,262 1,372 1,493 1,691 1,972 2,386 2,753 3,495 3,692 

Unit 22

MWh 85,208 103,456 100,225 108,759 94,980 102,519 106,408 59,900 64,836 74,150 80,026 85,348 94,895 98,939 105,443 10

Fuel + CO2 Charge ($000) 14,458 16,629 16,704 18,017 16,621 17,978 18,779 10,683 12,011 14,269 15,994 17,687 20,371 22,074 24,484 2CO2 Charge ($000) 851 1,081 1,304 842 1,032 1,319 1,583 1,863 2,271 2,579 2,991 

Unit 23

MWh 4,655 8,719 8,761 8,099 18,332 18,512 19,673 5,136 5,917 6,532 6,593 10,091 11,487 14,251 18,022 2

Fuel + CO2 Charge ($000) 1,200 2,242 2,318 2,153 4,873 4,927 5,199 1,384 1,709 1,917 2,046 3,222 3,771 4,916 6,393 CO2 Charge ($000) 249 296 361 109 147 177 203 340 421 576 781 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 2

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB 3

Fixed 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 7

Total CO2 Charge ($000) 00000 3,472 4,229 5,000 3,457 3,978 4,618 5,366 6,431 7,492 8,913 9,919 1Incremental Non-fuel Production Cost ($000) 0000000000000000

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-7 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

24 Case: 2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Island of St. CroixIncremental Electric and Water Production CostsPeak Demand 53.7 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 Energy Requirements 360,407 365,813 371,300 376,870 382,523 409,285 415,109 421,020 427,020 433,110 439,291 445,565 451,933 458,397 464,957 471,616 47

CC 1

MWh 317,225 320,208 327,636 331,508

Fuel + CO2 Charge ($000) 65,864 63,789 66,863 67,169 00000000000

CO2 Charge ($000) 00000000000

CC 2

MWh 49,051 51,273 49,299 51,079

Fuel + CO2 Charge ($000) 11,180 11,220 11,131 11,475CO2 Charge ($000)

Unit 16

MWh 0000 2,004 2,494 3,530 500 218 882 733 584 1,847 1,830 2,718 

Fuel + CO2 Charge ($000) 0000 564 714 969 152 64 274 241 198 613 671 1,014 CO2 Charge ($000) 29 43 67 12 6 25 24 21 69 78 124 

Unit 17

MWh 0000 76,536 81,406 78,592 55,417 57,454 62,114 67,210 69,280 75,211 79,388 83,429 8

Fuel + CO2 Charge ($000) 0000 15,241 16,232 15,773 12,305 13,129 14,477 15,999 17,004 18,988 20,755 22,646 2CO2 Charge ($000) 780 976 1,095 971 1,128 1,339 1,584 1,791 2,117 2,427 2,766 

Unit 19

MWh 0000 345 657 908 50 97 65 123 227 264 689 

Fuel + CO2 Charge ($000) 0000 102 195 275 0 16 35 24 44 85 103 270 CO2 Charge ($000) 5 12 19 0 1 3 2 5 10 12 33 

Unit 20

MWh 0000 95,610 103,166 103,340 66,113 75,616 80,538 87,173 91,063 99,554 95,609 109,639 11

Fuel + CO2 Charge ($000) 0000 22,333 24,110 24,205 17,241 20,427 22,252 24,676 26,687 29,721 29,236 34,883 3CO2 Charge ($000) 1,143 1,450 1,680 1,361 1,755 2,057 2,443 2,811 3,313 3,419 4,260 

New Resources

CT1

Fixed O&M ($000)Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

CFB1

Fixed 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 

Variable 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 Capital Cost ($000) 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 2MWh 313,632 312,666 323,275 301,248 312,791 312,191 312,501 312,546 313,505 312,646 312,701 31Fuel + 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 2CO2 Charge ($000) 4,434 5,219 6,251 6,671 7,836 8,744 9,735 10,760 11,862 12,943 14,100 1

CFB2

Fixed 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 

Variable 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 Capital Cost ($000) 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 20,764 2MWh 309,086 309,581 319,461 304,250 305,729 306,909 308,165 308,943 312,426 311,376 311,859 31Fuel + 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 2CO2 Charge ($000) 4,368 5,164 6,186 6,742 7,658 8,599 9,600 10,632 11,827 12,892 14,063 1

CFB3

Fixed O&M ($000) 4,688 4,796 4,906 5,019 5,135 5,253 5,374 5,497 

Variable O&M ($000) 2,595 2,632 2,750 2,875 2,978 2,988 3,181 3,284 Capital Cost ($000) 22,229 22,229 22,229 22,229 22,229 22,229 22,229 22,229 2MWh 270,593 268,230 273,932 279,991 283,468 278,009 289,381 292,030 29Fuel + CO2 Charge ($000) 0 0 0 14,549 15,380 16,714 18,157 19,509 20,273 22,429 24,025 2CO2 Charge ($000) 0 0 0 6,007 6,732 7,699 8,748 9,783 10,534 11,987 13,170 1

Wind Project

Fixed O&M ($000)

Variable O&M ($000)Capital Cost ($000)MWhFuel + CO2 Charge ($000)CO2 Charge ($000)

Interconnection Costs 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 30,914 3

Methanol 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 9Total CO2 Charge ($000) 00000 10,758 12,864 15,298 21,765 25,117 28,466 32,136 35,803 39,731 43,758 48,517 5

Incremental Non-fuel Production Cost ($000) 00000 86,778 87,104 87,633 117,138 117,760 118,354 118,977 119,581 120,143 120,833 121,470 12

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-7 
Virgin Islands Water and Power Authority

Power Supply Evaluation

Appendix 2

24 Case: 2-7 High Requirements Load, Replace Steam Units with CFB and RO, Interconnected System

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20

Total 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 17Total Authority CO2 Charges ($000) 00000 14,230 17,093 20,299 25,222 29,095 33,083 37,502 42,234 47,223 52,671 58,436 6

Total Authority Incremental Non-fuel Production Cost ($000) 00000 86,778 87,104 87,633 117,138 117,760 118,354 118,977 119,581 120,143 120,833 121,470 12

Existing Electric Resource Expenses:

Steam Related

Non-Fuel production Expense ($000) [1] 8,136 8,323 8,514 8,710 8,910 00000000000

Combustion Turbine

Non-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 

Existing Desal System Non-fuel O&M ($000) [3] 5,006 5,121 5,239 5,359 5,483 00000000000

Existing Desal Capital Improvements ($000)New Water Resources

Water 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 2,03

RO 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 

Capital ($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 $/kGal Excl. Energy Costs 6.58 6.66 6.74 6.83 6.92 7.00 7.10 7.19 7.28 7.38 7.48 

Total 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 37Total 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 30NPV with CO2 Charge ($000) 3,076,120NPV without CO2 Charge ($000) 2,763,717

R:\Orlando\005141 - VIWAPA\05-01414-10101 Power Supply Study\037778\PowerSupply Cost Summary_v6.xls 2-7 
Appendix B 

Fatal Flaw Analysis 
1000 Legion Place Suite 1100, Orlando Florida 32801 407-422-4911 Fax: 407-648-83822 

R:\Orlando\005141 - VIWAPA\037778\Fatal Flaw Analysis 2-25-08 .doc 

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 Analysis 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 production. 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 overarching objective of the Power Supply Study is to provide the 

Authority with an understanding of near- and long-term power supply options that would 

improve the Authority’s cost of electric power production and simultaneously 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 available 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

Page 2 of 42 

R:\Orlando\005141 - VIWAPA\037778\Fatal Flaw Analysis 2-25-08 .doc 

R. W. Beck was also requested to consider on a high level basis long-term options 

including: 

 Direct current (DC) transmission intertie 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 Analysis. This analysis is a 

high-level fatal flaw review of the candidate near-term electric supply technologies at 

existing sites and potential new sites. This analysis also included a comparison of the 

incremental and fully allocated cost of reverse 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 all water requirements 

on St. Thomas and St. Croix or incremental requirements 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 screening, 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 Study Report prepared by Harris Group, Inc. 

(HGI) in 2005, and various associated 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 facilities 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 island of St. Thomas 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

Page 3 of 42 

R:\Orlando\005141 - VIWAPA\037778\Fatal Flaw Analysis 2-25-08 .doc 

All of the existing generation facilities on the island of St. Croix are located at the Estate 

Richmond site on the north shore of the island near Christiansted. In addition to 

generation facilities, the Estate Richmond site includes water production, fuel oil 

unloading and storage and warehouse facilities. 

As a part of its plan to provide for increased demand for electricity and to improve the 

reliability of service, the Authority has acquired and installed a 41 MW combustion 

turbine generating unit which has been designated as Unit No. 23 on the island of St. 

Thomas, and which became operational in December 2004. 

To provide, among other things, an additional source of steam for water production on 

the island of St. Thomas, the Authority installed a waste heat recovery steam generator 

(HRSG), sometimes referred to as a “waste heat 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. Thomas for the desalination of water. 

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

Combustion Turbine Unit No. 16 and No. 20 at the Estate Richmond Generating Station 

from simple-cycle operation to combined-cycle 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 continue 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 facilities consist of steam, 

combustion turbine, and diesel generating units. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

Page 4 of 42 

R:\Orlando\005141 - VIWAPA\037778\Fatal Flaw Analysis 2-25-08 .doc 

St. Thomas/St. John – Randolph E. Harley Power Plant 

Unit No. Technology Fuel Type Rated Capacity 

(MW) 

In Service 

Date 

7 (St. John) Reciprocating Engine 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 production units. 

[2] Capacity shows CTG output only. 

St. Croix – Estate Richmond Plant 

Unit No. Technology Fuel 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 supply STGs 10 and 11 and four multi-effect distillation water production units. 

[4] Capacity shows CTG output only. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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. However, 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, 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 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 normal rating of 37 MW. In addition, combustion 

turbine Unit No. 22 on the island of St. Thomas has been removed from service. Both of 

these units are assumed to be fully operational over the study period. 

Given that the Authority operates 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 isolated 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 calls for the Authority to have sufficient 

generating capacity on each island to meet its respective electric load 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. The use of this planning 

criterion has been affirmed by the PSC in subsequent orders. 

On the island of St. Thomas, the two largest units are Unit No. 13, a steam turbine 

generator with a reported net 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 turbine generators, 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 energy requirements, sales and 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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customer growth, usage patterns and other 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 Study the projected annual average growth 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 normal maintenance and repairs of its existing plant in accordance 

with normal prudent utility practice. 

To reflect the potential for a higher than expected 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 and 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 generation for St. Thomas – St. John, and St. 

Croix, respectively. The projected peak demand for St. Thomas – St. John, and St. Croix 

is shown on line 13 and 27, respectively. Capacity 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 shown on lines 17 and 31 

indicates that under the base assumptions, no additional capacity 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, could 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 

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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 Retrofit 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 power generating source. OTEC is an energy technology that 

converts solar energy collected by the ocean to electric power. The OTEC process can 

also be applied to produce 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 20o

C temperature difference, which would be found in very deep water, is 

required for OTEC operation. Tropical 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 conducted 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 deep area of the Atlantic Ocean. 

While there are small sized demonstration plants operating in India, Japan and Hawaii, 

there are no installations that demonstrate the technical and economic viability of this 

technology on a commercial basis. According to the National Renewable Energy 

Laboratory (NREL), to accelerate the development of OTEC systems, researchers need 

to: 

 Obtain data on OTEC plant operation with appropriately sized demonstration plants, 

 Develop and characterize cold-water pipe technology and create a database of 

information on materials, design, deployment, and installation, 

 Conduct further research in the areas of innovative turbine concepts 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 demonstration phase with plant sizes no larger than 

1 MW and since there are technical 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 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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as a commercially proven resource to meet the 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 the 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. Thomas that meets recognized reliability 

constraints1

 assumes that combustion turbine units 15 and 18 are supplying waste heat to 

the heat recovery steam generators (HRSG). Steam turbine generators 11 and 13 are 

driven by steam from the HRSG and boilers 11 and 13. Units 22 and 23 are brought on 

as needed. Units 12 and 14 are in reserve status. Steam is supplied to the desalination 

plant on a continuous basis. 

HGI’s recommended configuration on St. Croix that meets recognized reliability 

constraints1

 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 supply 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 costs 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 generating technologies was 

conducted. Cost projections were prepared for each potential generating technology and 

compared to each other to reduce the number 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 summarized on Table 4. The busbar screening curves on 

Exhibit 1 show the all-in average costs per MWh, including debt service on capital 

investment, fixed and variable projected operations and maintenance expenses, and fuel 

expense (if applicable), levelized over a 25-year 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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All of the Authority’s generating units are fueled by oil. Historically, the Authority has 

purchased its fuel oil supply from Hess Oil 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 facilities 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 prices 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, delivered fuel prices were approximately $90.00 

per barrel for December 2007 deliveries. 

Certain options considered in this evaluation 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 process. Pet-coke from HOVENSA would be 

priced at a market index. The current price 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 received. 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 reported by a representative of St. 

Croix Renaissance Inc. Escalation for delivered 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 establish capital and operating cost estimates for a 

specific plant at a level of detail and precision to support investment decisions. However, 

these planning level cost estimates are considered to be appropriate for purposes of 

screening alternative power supply plans. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Environmental Considerations 

Any of the generation options listed above 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 approvals that may be required 

from various agencies are presented in the table 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 selected and design of the facility, as well as site specific 

conditions. Thus, the actual permits required for a specific technology and design will 

likely vary from another technology and design. For the U.S. Virgin Islands, regulatory 

programs fall under the jurisdiction of several different agencies and the agency 

identifiers below are intended to be generic in nature, particularly at the territorial-level. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Listing of Key Permits and Approvals 

Approval Responsible Agency 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Approval Responsible Agency Timing Comments 

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 appears the most significant obstacle that will 

affect permitting of a generating facility, based on technology using combustion, is 

related to air quality. NOx and SO2 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 difficulty in securing a PSD permit, without offsetting NOx 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 NOx was predicted to be exceeded. Again, in these scenarios, an 

air quality permit for construction would not be issued to a project. 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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There is also information to indicate that SO2 emissions, and possibly 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 the 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 requires preparation 

of an Environmental Assessment (EA). The EA includes, among other things, analyses 

of impacts to air quality, wetlands, 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 new 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 characteristics, 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 injection of a portion of the combustion air 

through a bed of fuel, ash and limestone on the 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 material wear rates caused by erosion in the combustion zone 

and is also more difficult to operate and requires 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 commercial power plant locations, and pressurized 

designs, which operate at several atmospheres of pressure, and have higher thermal 

efficiencies. Pressurized CFB boilers are considered a developmental technology and 

therefore are not being included for the Authority’s consideration. 

The most notable CFB achievements lie in the ability to burn less desirable fuels such as 

pet-coke and satisfy current environmental emissions restrictions without the need for 

additional and costly NOX and SO2 control systems. This feature is achieved through 

lower combustion temperatures to minimize NOx emissions and the ability to introduce 

limestone directly into the combustion area to remove SO2. 

As sufficient pet-coke is available from the HOVENSA Refinery in St. Croix to more 

than meet the Authority’s current and future power generation needs on both islands and 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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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 technology as a means of utilizing the readily 

available fuel. The CFB technology would provide 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 availability 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 quantity of solid waste (CaSO4) produced from the limestone 

that is used for removal of SO2. While there is a market for this waste in the mainland 

United States for use in concrete, wall board and other associated products, the sale of the 

waste is generally coordinated to minimize disposal expenses and typically does not 

provide a significant revenue stream 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 operated in baseload mode at or near full 

capacity as much as possible. Cycling and load-following operations 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 estimate that a CFB plant with a site build-out 

capacity of 3 x 20 MW units would ideally require approximately 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 would 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 required 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 water for cooling and boiler make-up 

 Proximity to deep water harbor for fuel and limestone deliveries and ash collection if 

necessary 

 Property rezoning and plant siting requirements 

 Proximity of nearby residences and other potentially sensitive noise receptors 

 Ability to meet environmental permitting requirements 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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 Proximity of suitable point of interconnection to the electric system 

 Access to site for construction and long-term operation 

 Limitations and restrictions caused by the operation of other facilities in the vicinity, 

such as airports 

On the island of St. Croix, the Authority owns approximately 7.5 acres of property in the 

South Shore area near the HOVENSA refinery that can be made available as the site for a 

power generating plant. In addition, the Authority reports that the property situated to the 

north of and adjacent to the Authority’s property 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 planned 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 preparation for construction. A portion of the site 

appears to be low lying and prone to flooding. This area would require filling to raise the 

level. 

The South Shore site is ideally situated to facilitate 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 refinery 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 SO2. 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 SO2 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 businesses that operate heavy industrial 

processes including power generation, 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 that 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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. Croix is located in the area 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 miles 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 required since there are no industrial facilities in 

the general area. No residences 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 the 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 Hill site is reported to be 

owned by the Federal Government. It once contained residences that were destroyed by a 

major hurricane several years ago and were never repaired or rebuilt. 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 grading of the hillside will be 

required in order to create a site that makes maximum use of the available space. Similar 

excavation of the hillside was performed to create the adjacent Krum Bay site. This site 

satisfies the site selection criteria with regards to: availability of sufficient water; 

proximity to deep water harbor; property zoning; distance from residences; close 

proximity of electric interconnection point; and 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 proximity 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. Further investigations of these issues would be 

necessary if this site warrants further consideration. 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 elevation of the site and its close proximity to the aircraft 

landing and takeoff path, it will 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Other potential issues that are likely to be presented 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 house 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 site will not expand beyond its current footprint 

and that all of the unused land on the Stalley Bay peninsula will be made 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 deliveries. There are no docking facilities in the 

vicinity of the site. Access to the site from Bovoni Road is provided 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 approximately 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 this 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 approval 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 output is projected to burn approximately 158 

tons of pet-coke per day. According to HOVENSA, the pet-coke produced at the refinery 

is sold primarily to the Jacksonville Electric 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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 price 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 Btu/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 Islands there are significant concerns, both at the existing 

Authority power plant sites and near the existing HOVENSA Refinery, with respect to 

NOx and SO2 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/MMBtu basis, NOx emissions from a CFB are considerably 

lower than from the slow speed diesel reciprocating engines evaluated in the MACTEC 

report. However, the characteristics of the emissions, such as a difference in temperature, 

flow rate, and pound per hour emission rate, do not allow a simple ratioing or 

extrapolation from the slow speed diesel analysis to estimate what a modeled impact 

might be. 

Although CFBs can achieve high levels of control with respect to SO2 emissions, the high 

sulfur content of the pet-coke could cause SO2 emissions to be a concern, particularly in 

an area such as the south shore of St. Croix. As discussed above since the existing 

HOVENSA Refinery and the St. Croix Renaissance facility near the south shore site, 

consume the existing PSD increment for SO2, 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 compliance 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 the 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 incorporate 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 capacity factor of 85 percent are $100.00/ kWyr and $8.18/MWh (including limestone supply and solid waste disposal), respectively as 

shown on Table 4. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Option 2 – Wind Turbine Generators 

In April 2006, a report titled “A Detailed Wind Energy Case Study for Point Udall on St. 

Croix, Crown Mountain on St. Thomas and Estate Concordia on St. John” was prepared 

for the Virgin Islands Energy Office, 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 “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 purposes of this Fatal Flaw Analysis, it has 

been assumed that wind turbine generation can achieve an average annual capacity factor 

in the range of 20 – 30 percent. However, the report recommends additional data 

monitoring at the operational height of the selected wind turbine over a twelve month 

period in order to better predict the performance of the wind turbine generator. 

Because of the difficulty in transporting components 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 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 capacity and serve in the role of producers of energy only. In 

addition, because of the inconsistency and sudden 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 Island 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 Udall area. Most of the land in this area is reportedly owned 

by the Virgin Islands Government and The Nature Conservancy. There are no 

residential developments in the area. The Authority’s Feeder No. 2 may be used to 

connect the wind turbine generators to the electric system. 

 Various potential locations exist on the hills 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 upper 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. Access to potential sites is poor and the 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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 developed, 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 installations. 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 would be clearly visible by residents along 

the southeast coast and the surrounding hills. 

Environmental Permitability 

It is expected that under this technology option, permits related to local zoning and 

special use would be the key permits for construction. There could be impacts related to 

aesthetics and noise and local opposition to such an installation 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 permit 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-shore installation) is approximately $30 million 

or $3,000 per kW. All of the O&M costs associated 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-shore 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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 add a waste heat recovery steam generator 

(HRSG) at the Randolph E. Harley Generating 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 feedwater system. The steam 

will be used for power generation and water production and will replace steam that is 

currently being produced by oil-fired boilers. 

The GE Frame 6B units have been in simple 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 intermediate 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/stop 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 electric power and steam production capacity. 

Siting Alternatives 

The HRSG and associated auxiliary equipment 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 combustion resource, a combined cycle option may 

be the most attractive from a permitting standpoint. The combined cycle technology 

lends itself well to the use of selective catalytic reduction (SCR) for 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 SO2 emissions. However, without further 

evaluation, which would likely include a screening-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 combustion turbine with a 

HRSG and 20 MW steam turbine generator 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 operate at a capacity factor of 50 percent are 

$41.25/ kW-yr and $4.03/MWh, respectively. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Option 4 – Municipal Solid Waste Steam Turbine Generator 

The Authority reports that in discussions with the Government Department responsible 

for solid waste collection and disposal, it was disclosed that the Department is interested 

in installing a single facility to incinerate the municipal solid waste (MSW) from the 

entire group of islands. The incineration would take place in a boiler, producing steam 

that then would be used to produce electricity 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 financially since traditionally 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) facilities. 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 facilities, 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 metals 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 attributes 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 MSW collected on St. Thomas, St. John and St. 

Croix, which consists of everyday items such as product packaging, grass clippings, 

furniture, clothing, bottles, food scraps, newspapers, appliances, paint 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, the 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 haulers 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 analysis to determine the required tipping fee or 

fuel subsidy on a dollar per ton basis that would be required to render the dollar per 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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megawatt hour cost of the MSW plant option equal to the cost of the CFB option burning 

50% pet coke and 50% coal. The required 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 typically seen in Florida for MSW facilities. 

Environmental Permitability 

MSW units lend themselves well to the control of emissions generated from combustion 

of the waste in a boiler. The inclusion of SCR, a dry scrubber, and fabric filter in the 

design can allow the unit to achieve fairly low emission rates for NOx, SO2, and 

particulate matter The federal New Source 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 technologies involving combustion, without further 

evaluation, which would likely include a screening-level modeling of estimated emission 

rates, a definitive answer as to the permitability 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 located 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 percent are $375/ kW-yr and $75/MWh, 

respectively. 

Option 5 –Reciprocating Engine Generator 

Reciprocating engine generators burning No. 6 heavy fuel oil are a proven technology for 

power generation and are in use in island systems similar to the Virgin Islands. 

Operating Constraints 

These units are generally operated as base load generating resources. The performance of 

the engines is typically guaranteed for operation down to 50 percent of rated capacity. 

Siting Alternatives 

On both St. Thomas and St. Croix, the alternative 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 engines would continue to be supplied from the 

HOVENSA refinery. While this technology will not lessen the Authority’s dependence 

on oil, it would provide substantial 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. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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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 technologies, such as medium speed and high 

speed options may be permitable, but a definitive 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 speed 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-conductor 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 major 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-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 capacity and serve in the role of suppliers of energy only. Of course, 

energy can only be generated by PV units during 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 plant 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 environmental effort in order to obtain the 

permits and approvals necessary for construction. Depending on the interconnection 

circuit routing, an EIS may be required. 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Capital and Non-Fuel Operating Costs 

At approximately $8,500 per kilowatt, the estimated 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. Fixed 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. Croix and St. Thomas power plant sites is 

approximately 45 miles as the crow flies. However, the direct 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 approximately 6,000 feet deep, a route length of 

about 100 miles would be required for submarine cable to interconnect the two island 

electric systems. Because of the considerably 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, the planning reserve margin is based on the two 

largest units on each island. The interconnection could reduce this planning margin to 

the two largest units on the two islands collectively. Another potential advantage of an 

interconnection would be the ability to replace smaller generating units with larger units 

that have lower capital costs per kW. Without the interconnection, 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 its smaller load and existing 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 systems, larger units could be 

installed on either island without reducing the systems reliability. 

Also with an interconnected system the amount 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 associated 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 maintaining their local production of steam to drive the 

desalination units on the individual islands. 
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Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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Environmental Permitability 

This activity could require a significant environmental effort in order to obtain the 

permits and approvals necessary for construction. 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 significant unknowns related to the installation 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 generating 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 Authority or hired on a 

long term basis to make deliveries exclusively to the Authority. To accommodate the 

LNG deliveries, the Authority would have to construct a receiving port, storage and regasification facilities at St. Thomas and St. Croix. 

Operating Constraints 

Conversion to natural gas would not be expected to impose any significant constraints on 

the operation of the existing generating plant and the cost of necessary modifications to 

the plant fuel systems and equipment combustion and control systems would be very 

minimal compared to the cost of the ship, port, storage and re-gasification facilities. 

Siting Alternatives 

The location of the gas receiving port and the storage and re-gasification 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 proximity of residents and a school to the 

St. Croix power plant, there may be some opposition 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 generating units as dual fired and 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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retain on-site fuel oil storage as back-up. Projected cost of LNG delivered to the 

Authority’s generating plants is shown Table 3. 

Environmental Permitability 

Depending on the facility design and location, a significant environmental effort may be 

required to obtain the approvals necessary for construction and operation. The 

construction of pipelines and loading terminals 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 existing 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 available 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 methanol 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 which is then used to produce liquid methanol. 

In addition to producing a fairly user-friendly and easily transportable fuel, the 

gasification process also converts 99 percent of the feed sulfur into hydrogen sulfide gas 

and results in minimal formation of SO2, 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 that generates minimal NOx and SO2 when burned. 

In a position paper prepared in 2001, GE states that tests have shown that, with fuel 

system and combustor modifications, liquid methanol 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 power output due to the higher mass flow, and 

lower NOx emissions due to the lower flame temperature. Since methanol contains no 

Sulfur, there are no SO2 emissions. Also, the clean burning 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 sizing 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 addition of a lubricity agent. The low flash point 

necessitates precautions to eliminate possible sources of ignition. Floating roof storage 
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Virgin Islands Water and Power Authority 

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tanks and explosion proof components are required. In addition, unit startup must be 

performed on distillate or natural gas. 

Applicable fuel system modifications are required for oil-fired boilers of the type 

operated by the Authority. 

GE reports that in a 12-hour test conducted on a 20 MW combustion turbine, the NOx 

emissions when firing methanol were 74 percent less than the NOx emissions when firing 

distillate. 

Based on the Authority’s total fuel requirement for St. Thomas and St. John, a 

gasification plant with a methanol production capacity of one million gallons per day is 

required. Such a plant would require approximately 40 MW of dedicated generating 

capacity to serve the plant auxiliaries. 

Operating Constraints 

Using methanol as the main fuel for firing its existing generating plants would not impose 

any significant operating constraints on the Authority beyond those that are experienced 

when operating on distillate or heavy fuel oil. However, changes in plant operations 

would have to be implemented to address the explosion hazard introduced 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 the CFB plant would be the ideal site for this 

facility. In order to accommodate the plant 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 necessary to locate the 40 MW 

of dedicated generation for the gasification plant at the existing power plant site. 

An alternative to the South Shore site would 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 extension of the electric distribution 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 transported 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. 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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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 SO2 with a high efficiency is a distinct advantage. The 

permitting requirements and challenges for this option would vary depending on whether 

a combined cycle unit, which would utilize the methanol as fuel, was constructed in 

conjunction with the gasification plant at the south shore site or at another site. The 

primary considerations for this option would be the need for deminimus air quality 

permitting considering the current air permitting issues associated with the HOVENSA 

and St. Croix Renaissance facilities near-by. 

Capital and Non-Fuel Operating Costs 

See Discussion of Results. 

Water Production by Reverse Osmosis 

Membrane processes are well-established technologies for seawater desalination. The 

membrane processes included for seawater desalination is generally Reverse Osmosis 

(RO). RO uses pressure as a motive force for the separation process and a semipermeable membrane. An RO desalination plant 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 important to be assured that all of the requisite 

facilities have been included that will be necessary to produce water of the quality desired 

for the customers. A concept design is typically developed to identify the site specific 

unique requirements and process options needed. 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 preliminary planning level estimate of cost, but 

is intended to provide a useful basis for discussion of potential costs alternatives. 

The purpose of this of this section of the report is to provide the Authority with high level 

overview of available RO plant cost information to consider in a fatal flaw evaluation and 

as a possible prelude to a planning effort to assess needs, develop a concept design and a 

planning level estimate of probable costs or to develop proposal requirements. 

R. W. Beck has been provided certain information regarding proposals from vendors that 

would supply an assortment of different components for skid mounted RO equipment 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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and/or turnkey supply of components for skid mounted RO equipment, operation and sale 

of water. In addition we have reviewed water demand projections and historic water 

usage data. The evaluation to develop the costs estimates included a review of the 

following: 

 Average Daily Production (2002-2007), Virgin 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 performance 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 locations of the MED units on St. Croix and St. 

Thomas would enable the installations to utilize existing seawater intake and discharge 

infrastructure at potentially significant cost savings to the project. Both sites appear to 

have sufficient space to accommodate RO units 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 configuration of the power plant cooling systems, and 

operation of the power plant. The advantages 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 source 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 desalination 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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Virgin Islands Water and Power Authority 

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condition of the power plant’s National Pollutant Discharge Elimination System 

(NPDES) permit, a large amount of cooling water is typically needed for cooling 

purposes. As a result, this configuration allows heated water to be reused as raw intake 

water for a desalination facility after the cooling water exits the power plant’s condenser. 

The warmer water can reduce the energy required for the RO process. Additionally, the 

since the raw water supply for the desalination facility 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 aquatic impingement and entrainment impacts due to the 

desalination facility. In addition, if the flow of power plant cooling water is sufficient, 

the concentrate from the desalination process may be blended with power plant’s cooling 

water discharge and mixed with the ambient seawater without significant discernable 

environmental impacts. Since the power facilities 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 must be below the manufacturer’s temperature 

for the RO element’s warranty. Typically, this requires seawater below 40 to 45 degrees 

Celsius. In collocated desalination plants, this fact may require the need for cooler 

seawater to control the temperature 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 seawater intake and pumping this 

into the warm post condenser seawater supply. This consideration may impact the 

facility’s permitting requirements and cost. 

In addition to the cooling system configuration, a power plant’s operating regime should 

also be evaluated to determine if the regime is suitable for co-location. Power plant 

operating regimes may be classified 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 continuously. Consequently, this type of electric generating 

unit rarely goes offline and provides a constant 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 sources, as multiple electric generating units 

help prevent interruptions due to scheduled or unscheduled outages of any of the 

individual electric generating units at the power plant. At a peaking power plant, power 

generation is normally restricted to operation during the periods of highest daily, weekly, 

or seasonal loads. Therefore, electric generation and cooling 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 provide a continuous or reliable source of 

electricity or cooling water for an RO desalination facility. A base-load/peaking power 

plant is usually generating some power. However, 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 generating units would be shut down during 
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Virgin Islands Water and Power Authority 

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periods of reduced electric demand. Since the individual electric 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 most 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-location with power plants that consist of 

one or two electric generating 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 concentrate blending is available. 

While co-location with these facilities may be economically feasible, each situation 

should be carefully evaluated on an individual basis. Reduced SWRO facility production 

will increase water production costs ($/1,000 gallons), 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, due 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 Point to serve the Island of St. John and the east end of St. 

Thomas. RO units are well suited for distributed locations where seawater intake and 

discharge infrastructure 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 planning level. A great deal of additional analysis and due 

diligence would be required to establish capital 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 cost 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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Virgin Islands Water and Power Authority 

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Project Cost Estimate for a Seawater 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 Seawater 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 

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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 below. While they may be an apple to oranges 

comparison, they highlight some major differences. 

GE Proposal Summary 

 3 Train 4 Train 5 Train 6 Train 

Normal Operating Conditions 400 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 for 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 (kgals) 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 connections. 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 the estimated costs for the 0.5, 1.0 and 1.5 MGD 

facilities in the co located cost table above. These values are for a completely installed 

and functioning plant per the 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. This graph shows the all-in levelized cost in 

dollars per MWh for each option at various capacity factors over each option’s typical 

range of operation. The all-in levelized costs 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 and 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 

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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 Exhibit 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 percent capacity factor is projected to be lower than the 

Authority’s displaced energy costs. This indicates that energy associated with the wind 

option is projected to be produced at a cost 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 alternatives are projected to be lower than the 

Authority’s displaced energy costs in the 40 – 60 percent capacity factor range. At the 70 

percent capacity factor the CFB unit fueled with 50 percent coal / 50 percent pet-coke is 

projected to be lower than the Authority’s displaced 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 and if the Authority’s 

system is capable of accepting the amount of energy 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 benefit, but it would have to replace major 

portions of its generating system with the new 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 CO2 emissions. Some of these Bills call for mandatory 

caps on CO2 emissions with an emissions trading program. These programs will result in 

a regulatory regime that will require the purchase of CO2 allowances by CO2 producers. 

At this time, the schedule for enactment of such a program and the cost of CO2 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 this fatal flaw analysis, we have assumed 

an average levelized CO2 allowance price of $15 per ton starting in 2012. The graphical 

presentations of busbar costs with assumed CO2 allowances are shown on Exhibits 1b 

and 2b. Under the assumptions of CO2 allowance, wind power, CFB, and combined 

cycle retrofit generation technology options, are still projected 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 factors, whether the resource is renewable, permitability, siting, 

dispatchability and fuel diversity. As shown on Table 8, two of the options, MSW 

generation (with no tipping fee) and PV cells are 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 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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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 permitable at some sites. The slow 

speed reciprocating engines are considered to be the least likely permitable of the options 

at the sites considered. The other options are considered more likely to be permitable at 

certain sites, but will require further evaluation. With respect to the CFB and combined 

cycle retrofit, additional air quality monitoring 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 and MSW resources are generally considered 

renewable resources. The output from these resources can sometimes be sold at a 

premium to certain customers as “Green” energy, which could help offset some of the 

higher costs associated with these type resources. 

Because the source of the energy associated with wind powered and PV resources is 

intermittent, these resources are not dispatchable, nor are they considered dependable 

capacity. MSW resources are also considered “must take” facilities, and as such are not 

dispatchable. All of the resources provide fuel diversity to the Authority except the 

combined cycle retrofit and the slow speed reciprocating engines. Since one of the main 

goals for the Authority is to reduce its dependence on fuels that are tied to the price of oil, 

fuel diversity should be a high priority for any new resource considered. 

There are certain assumptions made in the evaluation 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 therefore are sensitive to changes in investment 

cost assumptions. The combined cycle retrofit and slow speed reciprocating engines are 

fueled by relatively high priced No. 2 oil and No. 6 oil respectively, so would be more 

sensitive to fuel price variations than the other alternatives. The CFB unit and slow speed 

reciprocating engines have the highest CO2 emissions compared to the other options and 

therefore would be most impacted by a carbon tax or CO2 cap and trade program that 

requires the purchase of CO2 allowances. The relative sensitivity to the various types of 

costs discussed above are summarized on Table 8 for each option. 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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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 SO2 

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 SO2 

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 SO2 

off-sets for 

auxiliary 

generation 

Not applicable Likely; no 

apparent 

impediments 

Not applicable Not applicable 

Interconnection of St. Thomas and St. Croix Electric Systems

As stated previously the major savings associated with the interconnection is the ability 

to utilize larger sized units, reduced planning reserves, and reduced spinning reserves. 

Since no capacity is projected to be needed over the study period, under the base case 

there is no immediate cost reduction associated with reducing planning reserves or being 

able to install larger units. The major cost reduction would be associated with a reduction 

in spinning reserves and the ability to operate units closer to the most efficient full load 

capacity. The current recommended spinning reserve practice is to operate the 

combustion turbine at no greater than 80 percent 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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Virgin Islands Water and Power Authority 

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previously described, a reduction of 20 percent 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 this 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 approximately $393 million per year by 2030. An increase 

in efficiency of 1.75 percent would be equivalent 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 interconnection could allow the installation of 

fewer and larger new generating units which may possibly justify the investment 

associated with the interconnection. 

In particular, if it is determined 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 needs of St. Thomas would normally be supplied 

from the generating plant located on St. Croix 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 Natural Gas Fuel Supply

Based on the Beck 2007 Fuel Conversion Report, 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 the Authority or hired on a long-term basis 

to make deliveries exclusively to the Authority. 

The capital costs associated with this scenario including purchasing the LNG ship, on-site 

storage and regasification facilities for each island, dock improvements and 

interconnection facilities for 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 based 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 generation site are assumed for conversion of 

existing fuel oil fired steam generation and 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. 
February 25, 2008 

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Virgin Islands Water and Power Authority 

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Based on the Beck 2007 Fuel Conversion Report, 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 year. As also stated in the Beck 2007 Fuel 

Conversion Report, the actual benefit will depend on the price differential between the 

volatile oil and gas commodities. A differential 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-side associated with this alternative is the infrastructure 

investment of $134 - $158 million and the risk that the differential between oil and 

natural gas prices will decrease in the future to less than the break-even differential, 

eliminating the potential cost reduction associated with this project and providing no 

reduction in revenue requirements to offset the debt service associated with the 

infrastructure investment. 

The Beck 2007 Fuel Conversion Report concluded, among other things, that considering 

the possible savings indicated from the feasibility analysis, further research 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. The evaluation compares the fuel savings of 

replacing fuel oil with methanol in the Authority’s existing generating units versus the 

costs of constructing and operating a methanol production plant, providing additional 

electric generation to supply the plant, methanol storage and transportation to St. 

Thomas, and conversion of existing generating plants to accommodate 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 
February 25, 2008 

Mr. Glenn Rothgeb 

Virgin Islands Water and Power Authority 

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As shown on Table 9, line 3, the total operating 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 No. 2 oil and No. 6 oil versus the 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 approximately $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 supply 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 environmental 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 billion dollars. 

It is not clear whether the Authority or a developer will be able to finance this level of 

investment. 

Seawater RO Desalination Facility

As previously described, and summarized below, projected water costs 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 water 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]. Based on the replacement of the Authority’s 

existing water system with similarly sized units, a potential decrease 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 generating resources. It is further assumed that 

the Authority’s historical water production cost is an incremental cost and all costs 

allocated to the production of water from the electric system will be eliminated with the 

installation of the RO system. Based on the annual water production of approximately 

2,200 million gallons, a decrease of $1.5/1,000 gal 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 review of reports prepared by or for the 

Authority and information provided by the Authority and others which is summarized or 

referred to in this Fatal Flaw Letter Report, which 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 the HOVENSA St. Croix refinery and 

Columbian coal, and 

b.) Wind Power units. 

2. Retrofitting CT Unit 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 fuel diversity and the capacity of the combined cycle unit is likely to 

present system operation reliability issues. 

3. The slow speed diesel, the municipal 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 existing 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 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 

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6. Feasible sites have been identified for locating generating plants utilizing the 

various technologies as follows: 

a. CFB Plant – St. Thomas: at Grambokola Hill and near the Bovoni 

landfill. St. Croix: at the Authority’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 required 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 the 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 replaced 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 address 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 interconnection/CFB plant alternatives to reduce the financial risk 

of these alternatives. 

Sincerely, 

R. W. BECK, INC. 

Attachments 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Projected Loads and Capicity Resources (MW)

Base Case 

Fiscal Year Ending June 30

Line Description 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 

No. (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q) (r) 

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 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 3 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 4 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 5 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 6 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 7 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 8 Unit 22 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 9 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 

10 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 

11 Planned Additional Capability 0 0 0 0 0 0 0 0 0 0000000012 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 13 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 14 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 15 As a % of Projected Maximum Demand 116 116 116 113 111 108 106 103 101 98 96 94 91 89 87 85 83 16 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 

 Capacity Available For Reserves With Two

17 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 18 As a % of Projected Maximum Demand 30% 29% 29% 28% 26% 25% 23% 22% 20% 19% 18% 16% 15% 13% 12% 11% 9% 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 

ISLAND 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 21 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 22 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 23 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 24 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 25 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 26 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 27 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 28 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 29 As a % of Projected Maximum Demand 118% 120% 124% 123% 122% 121% 120% 119% 117% 116% 115% 114% 113% 112% 111% 110% 109% 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 

 Capacity Available For Reserves With Two

31 Largest Units Out of Service 18 19 20 20 19 19 19 18 18 18 18 17 17 17 17 16 16 32 As a % of Projected Maximum Demand 34% 35% 38% 37% 36% 36% 35% 34% 34% 33% 32% 32% 31% 30% 30% 29% 29% 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 

NOTES:[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 UNITS

B-56
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Projected Loads and Capicity Resources (MW)

High Requirements Case

Fiscal Year Ending June 30

Line Description 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 

No. (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q) (r) 

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 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 3 Unit 12 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 0 0 0 0 0000

4 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 5 Unit 14 [2] 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 0 0 0 0 00006 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 7 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 8 Unit 22 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 24 9 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 

10 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 

11 Planned Additional Capability 0 0 0 0 0 0 0 0 0 0000000012 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 13 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 14 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 15 As a % of Projected Maximum Demand 116 110 104 98 92 87 81 76 71 44 40 36 32 28 24 21 17 16 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 

 Capacity Available For Reserves With Two

17 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 18 As a % of Projected Maximum Demand 30% 26% 22% 19% 15% 12% 9% 5% 2% -22% -25% -27% -29% -31% -33% -35% -37% 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 

ISLAND 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 21 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 22 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 23 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 24 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 25 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 26 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 27 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 28 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 29 As a % of Projected Maximum Demand 118% 114% 111% 108% 105% 102% 99% 96% 93% 90% 88% 85% 82% 79% 77% 74% 72% 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 

 Capacity Available For Reserves With Two

31 Largest Units Out of Service 18 17 17 16 15 14 13 12 11 10 10 98765432 As a % of Projected Maximum Demand 34% 32% 30% 28% 26% 24% 22% 21% 19% 17% 15% 14% 12% 10% 9% 7% 6% 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 

NOTES:[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 UNITS

B-56
VIRGIN 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".

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Table 3_fuel prices_rev.xls Page 1 of 1; 2/25/2008; RWBeck, Inc.
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening

Resource Assumptions without CO2 Allowance Cost

Resource Options

1 2 3 4 

Ln

No. Item Option 1 - CFB Option 2 - Wind

Option 3 - CC 

Retrofit Option 4 - MSW O

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

1 Plant Type CFB/Steam On-Shore Wind Unit 23 CC Retrofit MSW/Steam Sl2 Location ST/SC ST/SC ST ST 3 VIWAPA Ownership % 100 100 100 100 4 Nominal Capacity MW 20 10 60 10 5 Fuel Type PET Coke/Coal #N/A #2 oil MSW 6 Capital Cost $000 $ 30,000 160,000 $ 73,980 $ 105,000 $ 

$ 

7 Capital Cost $/kW $ 3,000 8,000 $ 1,233 $ 10,500 $ 

$ 

8 Start of Eng to CO Months 36 9 18 30 9 HR Average Btu/kWh 12000 #N/A 7900 17500 

10 HR Average MMBtu/MWh 12.000 #N/A 7.900 17.500 11 Mature FOR % 5.0% 5.0% 5.0% 6.9% 12 Scheduled Maintenance % 6.3% 1.3% 2.5% 12.5% 13 Capacity Factor % 85% 25% 50% 75% 14 CO2 Emissions Rate lb/MMBtu 204 #N/A 159 92 15 CO2 Emissions Charge $/ton 0 #N/A 0 0 16 FOM $ 2,000,000 $ 500,000 $ 2,475,000 $ 3,750,000 $ 

$ 

17 FOM $/kW-yr $ 50.00 100.00 $ 41.25 $ 375.00 $ 

$ 

18 Limestone for PET Coke $/MWh $ 1.03 $ - - $ - $ 

$ 

19 Solid Waste Disposal for PET Coke $/MWh $ 1.53 $ - - $ - $ 

$ 

20 VOM $/MWh $ #N/A 4.03 5.63 $ 75.00 $ 

$ 

21 VOM Total $/MWh 8.18 $ #N/A 4.03 $ 75.00 $ 

$ 

22 Total O&M $ 3,218,625 $ 500,000 $ 3,533,164 $ 8,677,500 $ 

$ 

23 Total O&M $/MWh 21.61 $ 22.83 $ 13.44 $ 132.08 $ 

$ 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 4_resource assumptions_noCO2.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening

Resource Assumptions without CO2 Allowance Cost

Resource Options

1 2 3 4 

Ln

No. Item Option 1 - CFB Option 2 - Wind

Option 3 - CC 

Retrofit Option 4 - MSW O

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

Other Assumptions

24 Capital Payment Period (yrs) 25 25 25 25 

25 Annual carrying cost factor 7.82% 7.82% 7.82% 7.82% 26 Bond Factor 1.1237 1.0541 1.0773 1.1082 27 Annual Interest Rate 6.00% 6.00% 6.00% 6.00% 28 Issuance Expenses 3.00% 3.00% 3.00% 3.00% 29 Inflation 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 for modeling purposLimestone 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 yST/SC - St Thu / Str Croix

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 4_resource assumptions_noCO2.xls 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Screening Curves for Generation without CO2 Allowance Cost

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Ex1&2_noCO2_rev.xls Pag

0

100200300400500600

0.1 0.2 0.3 0.4 0.5 0.6 0.7 

Capacity Factor

$/MWh

Option 1 - CFB Coal/PET Coke Option 2 - WindOption 3 - Retrofit w/No. 2 Oil Option 4 - MSW Stoker/CFBOption 5 - Recip w/No. 6 Oil Option 6 - PV SolarApproximate Displaced Energy Cost for St. Thomas Approximate Displaced Energy CoAverage System Cost - St. Thomas Average System Cost - St. Croix

Average System Cost - St. Thomas

Average System Cost - St. Croix

PV Solar

Wind

Approximate Displaced Energy 

Cost for St. Thomas and St. Croix
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Screening Curves for Generation without CO2 Allowance Cost

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Ex1&2_noCO2_rev.xls Pag

0

50

100150200250300350

0.1 0.2 0.3 0.4 0.5 0.6 0.7 

Capacity Factor

$/MWh

Option 1 - CFB Coal/PET Coke Option 2 - WindOption 3 - Retrofit w/No. 2 Oil Option 5 - Recip w/No. 6 OilApproximate Displaced Energy Cost for St. Thomas Approximate Displaced Energy CoAverage System Cost - St. Thomas Average System Cost - St. Croix

Average System Cost - St. Thomas

Average System Cost - St. Croix

Wind

Approximate Displaced Energy 

Cost for St. Thomas and St. Croix
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening

Resource Assumptions with CO2 Allowance Cost

Resource Options

1 2 3 4 

Ln

No. Item Option 1 - CFB Option 2 - Wind

Option 3 - CC 

Retrofit Option 4 - MSW O

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

1 Plant Type CFB/Steam On-Shore Wind Unit 23 CC Retrofit MSW/Steam Sl2 Location ST/SC ST/SC ST ST 3 VIWAPA Ownership % 100 100 100 100 4 Nominal Capacity MW 20 10 60 10 5 Fuel Type PET Coke/Coal #N/A #2 oil MSW 6 Capital Cost $000 $ 30,000 160,000 $ 73,980 $ 105,000 $ 

$ 

7 Capital Cost $/kW $ 3,000 8,000 $ 1,233 $ 10,500 $ 

$ 

8 Start of Eng to CO Months 36 9 18 30 9 HR Average Btu/kWh 12000 #N/A 7900 17500 

10 HR Average MMBtu/MWh 12.000 #N/A 7.900 17.500 11 Mature FOR % 5.0% 5.0% 5.0% 6.9% 12 Scheduled Maintenance % 6.3% 1.3% 2.5% 12.5% 13 Capacity Factor % 85% 25% 50% 75% 14 CO2 Emissions Rate lb/MMBtu 204 #N/A 159 92 15 CO2 Emissions Charge $/ton 15 #N/A 15 15 16 FOM $ 2,000,000 $ 500,000 $ 2,475,000 $ 3,750,000 $ 

$ 

17 FOM $/kW-yr $ 50.00 100.00 $ 41.25 $ 375.00 $ 

$ 

18 Limestone for PET Coke $/MWh $ 1.03 $ - - $ - $ 

$ 

19 Solid Waste Disposal for PET Coke $/MWh $ 1.53 $ - - $ - $ 

$ 

20 VOM $/MWh $ #N/A 4.03 5.63 $ 75.00 $ 

$ 

21 VOM Total $/MWh 8.18 $ #N/A 4.03 $ 75.00 $ 

$ 

22 Total O&M $ 3,218,625 $ 500,000 $ 3,533,164 $ 8,677,500 $ 

$ 

23 Total O&M $/MWh 21.61 $ 22.83 $ 13.44 $ 132.08 $ 

$ 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 4_resource assumptions_withCO2.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening

Resource Assumptions with CO2 Allowance Cost

Resource Options

1 2 3 4 

Ln

No. Item Option 1 - CFB Option 2 - Wind

Option 3 - CC 

Retrofit Option 4 - MSW O

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

Other Assumptions

24 Capital Payment Period (yrs) 25 25 25 25 

25 Annual carrying cost factor 7.82% 7.82% 7.82% 7.82% 26 Bond Factor 1.1237 1.0541 1.0773 1.1082 27 Annual Interest Rate 6.00% 6.00% 6.00% 6.00% 28 Issuance Expenses 3.00% 3.00% 3.00% 3.00% 29 Inflation 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 for modeling purposLimestone 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 yST/SC - St Thu / Str Croix

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 4_resource assumptions_withCO2.xls 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Screening Curves for Generation with CO2 Allowance Cost

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Ex1&2_withCO2_rev.xls Pag

0

100200300400500600

0.1 0.2 0.3 0.4 0.5 0.6 0.7 

Capacity Factor

$/MWh

Option 1 - CFB Coal/PET Coke Option 2 - WindOption 3 - Retrofit w/No. 2 Oil Option 4 - MSW Stoker/CFBOption 5 - Recip w/No. 6 Oil Option 6 - PV SolarApproximate Displaced Energy Cost for St. Thomas Approximate Displaced Energy CoAverage System Cost - St. Thomas Average System Cost - St. Croix

Average System Cost - St. Thomas

Average System Cost - St. Croix

Approximate Displaced Energy 

Cost for St. Thomas and St. Croix

PV Solar

Wind

C
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Electric System

Screening Curves for Generation with CO2 Allowance Cost

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Ex1&2_withCO2_rev.xls Pag

0

50

100150200250300350

0.1 0.2 0.3 0.4 0.5 0.6 0.7 

Capacity Factor

$/MWh

Option 1 - CFB Coal/PET Coke Option 2 - WindOption 3 - Retrofit w/No. 2 Oil Option 5 - Recip w/No. 6 OilApproximate Displaced Energy Cost for St. Thomas Approximate Displaced Energy CoAverage System Cost - St. Thomas Average System Cost - St. Croix

Average System Cost - St. Thomas

Average System Cost - St. Croix

Approximate Displaced Energy 

Cost for St. Thomas and St. Croix

Wind

C
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Water System

Historical Water Sales and Requirements [1],[2]

Line 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 Supply 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 Supply 2,182,116 2,123,771 2,099,033 2,068,682 2,192,428 2,203,576

Operating Expenses [3]

Production Expenses ($)

40 Total Production Expenses 10,928,468 11,103,855 11,597,540 14,085,280 19,909,213 19,708,554

Average Production Expenses ($/1000gal)

41 Total Average Operating Expenses 5.01 5.23 5.53 6.81 9.08 8.94

[1] Amounts obtained from the Authority's June Monthly Financial Reports, Production and Operating Data by Island and Quarterl

Report and Statistical Data.

[2] Total System quantities might not match Monthly Financial Reports due to rounding

[3] Operating Expenses 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 AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

1 Option 1 - CFB Coal/PET Coke

Plant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 Annual Capital Carrying Cost ($) 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 160,631 164,325 168,105 171,971 175,927 179,973 184,112 188,347 192,679 197,111 201,644 Average Heat Rate (MMBtu/MWh) 12 12 12 12 12 12 12 12 12 12 12 Annual 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 Total Annual Fuel Operating Cost ($) 533,808 539,399 545,048 550,756 562,558 574,612 586,924 599,500 612,345 630,961 650,143 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 970 974 977 981 985 989 993 998 1,002 1,007 1,012 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

2 Option 2 - CC w/LNG

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 3,224,853 3,206,887 3,275,565 3,302,622 3,407,870 3,565,928 3,584,000 3,615,856 3,724,840 3,789,546 3,929,198 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 599 600 604 606 610 616 618 621 625 629 634 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

3 Option 3 - Wind

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 Fixed Annual O&M Cost ($) 560,207 573,091 586,272 599,757 613,551 627,663 642,099 656,867 671,975 687,431 703,242 CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Variable Annual O&M ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 346 348 349 351 352 354 356 357 359 361 363 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

4 Option 4 - Retrofit w/No. 2 Oil

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 237,116 242,570 248,149 253,856 259,695 265,668 271,778 278,029 284,424 290,966 297,658 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 6,750,994 6,718,554 6,686,270 6,654,141 6,863,027 7,078,471 7,300,677 7,529,860 7,766,236 8,048,139 8,340,275 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 304 305 306 307 312 317 323 329 335 342 349 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

5 Option 5 - MSW Stoker/CFB

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 736,111 753,042 770,362 788,080 806,206 824,749 843,718 863,124 882,975 903,284 924,059 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 1,603 1,616 1,629 1,643 1,656 1,671 1,685 1,700 1,715 1,731 1,747 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

6 Option 6 - Recip w/No. 6 Oil

Plant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 Annual Capital Carrying Cost ($) 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 2,312,999 2,301,884 2,290,823 2,279,815 2,351,383 2,425,198 2,501,329 2,579,851 2,660,837 2,757,422 2,857,512 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 429 431 432 434 441 448 455 462 469 478 486 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%) 10% No CO2Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

7 Option 7 - PV Solar

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 Fixed Annual O&M Cost ($) 350,129 358,182 366,420 374,848 383,469 392,289 401,312 410,542 419,984 429,644 439,526 CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Variable Annual O&M ($) 122,685 125,507 128,394 131,347 134,368 137,458 140,620 143,854 147,163 150,547 154,010 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 883 885 886 887 889 890 891 893 894 896 897 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

8 Option 8 - CC w/No.2

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 00000000000Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 5,296,517 5,170,295 5,047,081 4,926,803 5,102,163 5,283,765 5,471,831 5,666,591 5,868,282 6,052,573 6,242,651 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 303 303 303 302 308 313 319 325 331 337 343 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)Adjusted Avoided CostsAll Hours Benchmark for St. Thomas ($/M 157.64 156.07 157.12 156.89 160.05 167.85 173.57 181.02 187.61 196.86 204.08 

Check $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 $190.55 

All Hours Benchmark for St. Croix ($/MWh 164.57 163.86 163.26 161.70 166.77 171.63 177.37 182.62 188.20 195.75 202.57 

Check $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 $191.68 Adjust Average System Energy CostSt. Thomas ($/MWh) 237.31 236.38 234.91 233.80 241.25 248.62 256.56 264.76 273.09 283.01 293.08 

$276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 $276.64 

St. Croix ($/MWh) 218.71 216.62 214.36 212.38 218.86 225.11 231.79 238.62 245.81 253.87 262.41 

$249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 $249.62 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%)Year

1 Option 1 - CFB Coal/PET Coke

Plant 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)

2 Option 2 - CC w/LNG

Plant 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)

3 Option 3 - Wind

Plant 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 CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

20 20 20 20 20 20 20 20 20 20 20

17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 

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

3,080,825 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 3,867,438

00000000000

220,845 225,925 231,121 236,437 241,875 247,438 253,129 258,951 264,907 271,000 277,233

12 12 12 12 12 12 12 12 12 12 12

210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240733,612 756,670 780,452 804,981 830,282 856,378 883,294 911,056 939,690 969,225 999,688

18,099,963 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 

1,033 1,039 1,045 1,050 1,057 1,063 1,069 1,076 1,082 1,089 1,096 

7,552,482 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 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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

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 7,541,504

00000000000

202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4

388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944

4,403,554 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 5,908,664

34,343,689 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 

653 659 665 670 675 681 687 693 699 706 712 

14,330,421 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 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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

770,206 787,921 806,043 824,582 843,548 862,949 882,797 903,101 923,873 945,122 966,860

#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/A

3,244,025 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 

370 372 374 377 379 381 383 385 388 390 393 

1,353,618 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 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%)Year

4 Option 4 - Retrofit w/No. 2 Oil

Plant 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)

5 Option 5 - MSW Stoker/CFB

Plant 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)

6 Option 6 - Recip w/No. 6 Oil

Plant 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 CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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 6,234,6783,812,521 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 4,785,955

00000000000

326,002 333,500 341,170 349,017 357,045 365,257 373,658 382,252 391,044 400,038 409,238

7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9

415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224

9,572,983 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 13,036,771

19,946,183 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 

379 387 395 403 411 419 428 437 446 456 465 

8,322,845 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 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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 9,102,9295,776,547 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 7,251,446

00000000000

1,012,051 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 1,270,453

17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5

153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300

#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A

15,891,527 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 

1,814 1,832 1,850 1,869 1,888 1,907 1,927 1,948 1,969 1,990 2,012 

6,630,979 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 

20 20 20 20 20 20 20 20 20 20 20

17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 

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 3,371,0072,310,619 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 2,900,579

00000000000

202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75

153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300

3,279,857 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 

523 532 542 551 561 572 582 593 604 616 627 

3,823,773 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 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening without CO2 Allowance Cost

Selected Calculations

Capacity Factor (%)Year

7 Option 7 - PV Solar

Plant 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)

8 Option 8 - CC w/No.2

Plant 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 ($/MWh)Adjusted Avoided CostsAll Hours Benchmark for St. Thomas ($/M

Check

All Hours Benchmark for St. Croix ($/MWhCheckAdjust Average System Energy CostSt. Thomas ($/MWh)St. Croix ($/MWh)

10% No CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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

481,379 492,451 503,777 515,364 527,217 539,343 551,748 564,438 577,420 590,701 604,287

#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A

168,675 172,555 176,523 180,583 184,737 188,986 193,333 197,779 202,328 206,982 211,742

#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/A

7,916,268 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 

904 905 907 909 911 913 915 916 918 921 923 

3,303,182 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 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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 6,126,6846,007,609 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 7,541,504

00000000000

202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4

388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944

7,078,450 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 9,717,173

19,415,153 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 

369 377 384 392 400 407 415 424 432 441 450 

8,101,265 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 

238.79 248.54 255.06 264.32 275.86 

$190.55 $190.55 $190.55 $190.55 $190.55 

232.66 241.09 248.76 256.11 263.70 

$191.68 $191.68 $191.68 $191.68 $191.68 

335.84 345.76 357.17 367.22 375.26 

$276.64 $276.64 $276.64 $276.64 $276.64 

299.13 308.68 318.28 329.39 339.07 

$249.62 $249.62 $249.62 $249.62 $249.62 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\noCO2\Table 7_Selected Calc_noCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%) 10% with CO2

Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

1 Option 1 - CFB Coal/PET Coke

Plant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 Annual Capital Carrying Cost ($) 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 14,064,680 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 Variable Annual O&M ($) 160,631 164,325 168,105 171,971 175,927 179,973 184,112 188,347 192,679 197,111 201,644 Average Heat Rate (MMBtu/MWh) 12 12 12 12 12 12 12 12 12 12 12 Annual 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 Total Annual Fuel Operating Cost ($) 533,808 539,399 545,048 550,756 562,558 574,612 586,924 599,500 612,345 630,961 650,143 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 989 992 996 999 1,003 1,007 1,012 1,016 1,020 1,025 1,030 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

2 Option 2 - CC w/LNG

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 23,730,115 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 3,015,932 2,992,991 3,080,687 3,115,238 3,249,632 3,451,462 3,474,538 3,515,217 3,654,381 3,737,006 3,915,332 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 601 603 607 609 614 620 623 626 631 635 640 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

3 Option 3 - Wind

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 2,473,819 Fixed Annual O&M Cost ($) 560,207 573,091 586,272 599,757 613,551 627,663 642,099 656,867 671,975 687,431 703,242 CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Variable Annual O&M ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 346 348 349 351 352 354 356 357 359 361 363 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%) 10% with CO2

Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

4 Option 4 - Retrofit w/No. 2 Oil

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 6,234,678 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 Variable Annual O&M ($) 237,116 242,570 248,149 253,856 259,695 265,668 271,778 278,029 284,424 290,966 297,658 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 6,750,994 6,718,554 6,686,270 6,654,141 6,863,027 7,078,471 7,300,677 7,529,860 7,766,236 8,048,139 8,340,275 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 314 314 315 316 321 327 333 338 345 351 359 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

5 Option 5 - MSW Stoker/CFB

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 9,102,929 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 Variable Annual O&M ($) 736,111 753,042 770,362 788,080 806,206 824,749 843,718 863,124 882,975 903,284 924,059 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 1,615 1,628 1,641 1,655 1,669 1,683 1,697 1,712 1,727 1,743 1,759 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

6 Option 6 - Recip w/No. 6 Oil

Plant Rating (MW) 20 20 20 20 20 20 20 20 20 20 20 MWh Generated (MWh) 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 Annual Capital Carrying Cost ($) 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 3,371,007 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 2,312,999 2,301,884 2,290,823 2,279,815 2,351,383 2,425,198 2,501,329 2,579,851 2,660,837 2,757,422 2,857,512 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 440 442 444 446 452 459 466 473 481 489 498 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%) 10% with CO2

Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

7 Option 7 - PV Solar

Plant Rating (MW) 10 10 10 10 10 10 10 10 10 10 10 MWh Generated (MWh) 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 Annual Capital Carrying Cost ($) 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 7,266,214 Fixed Annual O&M Cost ($) 350,129 358,182 366,420 374,848 383,469 392,289 401,312 410,542 419,984 429,644 439,526 CO2 Allowance Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Variable Annual O&M ($) 122,685 125,507 128,394 131,347 134,368 137,458 140,620 143,854 147,163 150,547 154,010 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 883 885 886 887 889 890 891 893 894 896 897 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)

8 Option 8 - CC w/No.2

Plant Rating (MW) 60 60 60 60 60 60 60 60 60 60 60 MWh Generated (MWh) 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 Annual Capital Carrying Cost ($) 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 6,126,684 Fixed Annual O&M Cost ($) 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 CO2 Allowance Cost ($) 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 Variable Annual O&M ($) 147,222 150,608 154,072 157,616 161,241 164,950 168,744 172,625 176,595 180,657 184,812 Average 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 Annual 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 Total Annual Fuel Operating Cost ($) 5,296,517 5,170,295 5,047,081 4,926,803 5,102,163 5,283,765 5,471,831 5,666,591 5,868,282 6,052,573 6,242,651 Total Annual Operating cost ($) 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 Total Annual Operating cost ($/MWh) 312 312 311 311 317 322 328 334 340 346 352 PV Total Annual Operating cost ($) 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 Levelized Annual Operating Cost ($/MWh)Adjusted Displaced Energy CostsAll Hours Benchmark for St. Thomas ($/M 169.94 168.31 169.50 169.28 172.29 180.35 186.10 193.68 200.33 209.75 216.98 

Check $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 $203.26 

All Hours Benchmark for St. Croix ($/MWh 176.96 176.08 175.48 173.92 178.90 183.78 189.51 194.77 200.32 207.84 214.72 

Check $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 $203.87 Adjusted Average System Energy Cost

St. Thomas ($/MWh) 238.87 236.44 235.39 233.80 239.16 246.45 253.05 260.58 268.03 277.32 285.96 

$271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 $271.96 

St. Croix ($/MWh) 223.48 222.12 220.96 219.46 225.75 231.84 238.53 245.14 252.15 260.65 269.17 

$255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 $255.86 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%)

Year

1 Option 1 - CFB Coal/PET Coke

Plant 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)

2 Option 2 - CC w/LNG

Plant 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)

3 Option 3 - Wind

Plant 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 CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

20 20 20 20 20 20 20 20 20 20 20

17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 

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

3,080,825 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 3,867,438

320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983 320,983220,845 225,925 231,121 236,437 241,875 247,438 253,129 258,951 264,907 271,000 277,233

12 12 12 12 12 12 12 12 12 12 12

210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240 210,240733,612 756,670 780,452 804,981 830,282 856,378 883,294 911,056 939,690 969,225 999,688

18,420,945 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 

1,051 1,057 1,063 1,069 1,075 1,081 1,088 1,094 1,101 1,108 1,115 

7,686,417 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 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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

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 7,541,504

342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159 342,159202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4

388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944

4,521,053 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 6,442,975

34,803,346 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 

662 668 675 681 687 693 700 707 714 721 729 

14,522,220 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 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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

770,206 787,921 806,043 824,582 843,548 862,949 882,797 903,101 923,873 945,122 966,860

#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/A

3,244,025 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 

370 372 374 377 379 381 383 385 388 390 393 

1,353,618 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 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%)

Year

4 Option 4 - Retrofit w/No. 2 Oil

Plant 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)

5 Option 5 - MSW Stoker/CFB

Plant 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)

6 Option 6 - Recip w/No. 6 Oil

Plant 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 CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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 6,234,6783,812,521 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 4,785,955

496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605 496,605326,002 333,500 341,170 349,017 357,045 365,257 373,658 382,252 391,044 400,038 409,238

7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9

415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224 415,224

9,572,983 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 13,036,771

20,442,788 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 

389 396 404 412 420 429 438 446 456 465 475 

8,530,061 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 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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 9,102,9295,776,547 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 7,251,446

105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777 105,777

1,012,051 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 1,270,453

17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5

153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300

#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A

15,997,304 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 

1,826 1,844 1,862 1,881 1,900 1,919 1,939 1,960 1,981 2,002 2,024 

6,675,116 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 

20 20 20 20 20 20 20 20 20 20 20

17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 17,520 

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 3,371,0072,310,619 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 2,900,579

199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774 199,774202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75

153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300

3,279,857 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 

534 544 553 563 573 583 594 604 616 627 639 

3,907,131 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 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\wCO2\Table 7_Selected Calc_withCO2_rev.xls 
VIRGIN ISANDS WATER AND POWER AUTHORITY

Power Supply Study

November 2007 - Generation Screening with CO2 Allowance Cost

Selected Calculations

TOCapacity Factor (%)

Year

7 Option 7 - PV Solar

Plant 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)

8 Option 8 - CC w/No.2

Plant 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 ($/MWh)Adjusted Displaced Energy CostsAll Hours Benchmark for St. Thomas ($/M

Check

All Hours Benchmark for St. Croix ($/MWhCheckAdjusted Average System Energy CostSt. Thomas ($/MWh)St. Croix ($/MWh)

10% with CO2

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 

10 10 10 10 10 10 10 10 10 10 10

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 

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

481,379 492,451 503,777 515,364 527,217 539,343 551,748 564,438 577,420 590,701 604,287

#N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A #N/A

168,675 172,555 176,523 180,583 184,737 188,986 193,333 197,779 202,328 206,982 211,742

#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/A

7,916,268 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 

904 905 907 909 911 913 915 916 918 921 923 

3,303,182 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 

60 60 60 60 60 60 60 60 60 60 60

52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 52,560 

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 6,126,6846,007,609 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 7,541,504

465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174 465,174202,410 207,066 211,828 216,700 221,684 226,783 231,999 237,335 242,794 248,378 254,091

7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4

388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944 388,944

7,078,450 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 9,717,173

19,880,327 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 

378 385 393 401 408 416 424 432 441 450 459 

8,295,366 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 

252.02 261.90 268.40 277.74 289.48 

$203.26 $203.26 $203.26 $203.26 $203.26 

244.81 253.25 261.01 268.37 275.95 

$203.87 $203.87 $203.87 $203.87 $203.87 

324.43 334.40 342.61 352.78 364.17 

$271.96 $271.96 $271.96 $271.96 $271.96 

305.55 314.82 323.76 333.14 342.62 

$255.86 $255.86 $255.86 $255.86 $255.86 

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VIRGIN ISLANDS WATER AND POWER AUTHORITY

Generation Screening

Fatal Flaw Analysis

Qualitative Assessment

Line Option

No. Description 1 2 3 4 

1

Name of Option:

Circulating

Fluidized Bed

Wind

Turbine Generators

Combined

Cycle Retrofit

Municipal Solid Waste Steam Turbine 

Generator

Slow Spee

Engine 

2 Plant Size (MW) 20 20 20 10 3 Expected Capacity Factor 85% 25% 50% 85% 4 Lower than Average System Cost at 

Expected Capacity Factor Yes Yes Yes No [2] 

5 Lower than Avoided Cost at 

Expected Capacity Factor Yes Yes Yes No [2] 

6 Permittability/Siting Feasibility Yes[1] Yes [1] Yes Yes 7 Renewable No Yes No Yes 8 Dispatchable Yes No Yes No 9 Fuel Diversity Yes Yes No Yes 

Sensitivity to:

10 Capital Costs High High Medium High M11 O&M Costs Medium Medium Medium High M12 Fuel Costs Medium None High None [2] 13 CO2 Costs High None Medium 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.xls 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Study

Projected Cost of Methanol Plant versus Fuel Cost Reduction

Line

No. Description NPV

(a) (b)

PV Total Annual Operating Cost [1]

1 CC @ 40MW [2] 229,096,616

2 Methanol Plant [3] 1,278,439,8823 Total 1,507,536,497

Fuel Cost [4]

St. Croix

4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost Difference

St. Thomas

7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost Difference

Total System

10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13 Net Total Cost Difference (1,720,945,829)

14 Levelized Cost Difference (134,623,944)

2012 2013 2014 2015 2016 2017 

(c) (d) (e) (f) (g) (h) 

15,769,382 15,927,833 16,089,443 16,254,278 16,464,239 16,678,900 96,584,184 96,906,303 97,235,830 97,572,937 97,917,797 98,270,589 

112,353,566 112,834,136 113,325,273 113,827,215 114,382,036 114,949,489 

73,197,312 73,132,508 72,994,119 72,911,935 75,513,775 78,138,001 

7,784,247 7,896,754 8,002,813 8,116,523 8,324,943 8,531,021 

(65,413,065) (65,235,754) (64,991,307) (64,795,412) (67,188,832) (69,606,980) 

138,194,287 139,152,233 139,848,589 140,663,564 146,726,243 152,945,954 

16,190,165 16,570,210 16,926,913 17,305,669 17,879,582 18,459,946 

(122,004,122) (122,582,023) (122,921,676) (123,357,894) (128,846,661) (134,486,008) 

211,391,599 212,284,740 212,842,708 213,575,499 222,240,018 231,083,955 

23,974,412 24,466,964 24,929,726 25,422,193 26,204,525 26,990,967 

(187,417,186) (187,817,777) (187,912,983) (188,153,306) (196,035,494) (204,092,988) 

(75,063,620) (74,983,641) (74,587,710) (74,326,091) (81,653,458) (89,143,500) 

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xls 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Study

Projected Cost of Methanol Plant versus Fuel Cost Reduction

Line

No. Description NPV

(a) (b)

PV Total Annual Operating Cost [1]

1 CC @ 40MW [2] 229,096,616

2 Methanol Plant [3] 1,278,439,8823 Total 1,507,536,497

Fuel Cost [4]

St. Croix

4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost Difference

St. Thomas

7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost Difference

Total System

10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13 Net Total Cost Difference (1,720,945,829)

14 Levelized Cost Difference (134,623,944)

2020 2021 2022 2023 2024 2025 2026 

(k) (l) (m) (n) (o) (p) (q) 

17,352,151 17,624,788 17,904,652 18,191,936 18,486,842 18,789,576 19,105,499,378,400 99,764,786 100,160,059 100,564,423 100,978,087 101,401,265 101,834,

116,730,551 117,389,574 118,064,710 118,756,359 119,464,929 120,190,841 120,939,

86,678,526 90,093,163 93,734,985 97,552,059 101,462,767 105,525,386 109,342

9,191,814 9,499,543 9,827,290 10,169,267 10,516,739 10,875,582 11,269

(77,486,713) (80,593,620) (83,907,696) (87,382,792) (90,946,028) (94,649,803) (98,073

173,563,500 181,844,352 190,405,348 199,387,751 208,713,690 218,814,338 228,078

20,355,413 21,191,646 22,049,015 22,943,281 23,864,743 24,861,778 25,897

(153,208,087) (160,652,706) (168,356,333) (176,444,471) (184,848,946) (193,952,560) (202,180

260,242,026 271,937,515 284,140,334 296,939,811 310,176,456 324,339,724 337,421

29,547,226 30,691,189 31,876,305 33,112,548 34,381,482 35,737,360 37,167

(230,694,800) (241,246,326) (252,264,029) (263,827,263) (275,794,974) (288,602,364) (300,253(113,964,249) (123,856,752) (134,199,319) (145,070,904) (156,330,045) (168,411,522) (179,314

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xls 
VIRGIN ISLANDS WATER AND POWER AUTHORITY

Power Supply Study

Projected Cost of Methanol Plant versus Fuel Cost Reduction

Line

No. Description NPV

(a) (b)

PV Total Annual Operating Cost [1]

1 CC @ 40MW [2] 229,096,616

2 Methanol Plant [3] 1,278,439,8823 Total 1,507,536,497

Fuel Cost [4]

St. Croix

4 No. 2 and No. 6 Oil [5]5 PET Coke6 Cost Difference

St. Thomas

7 No. 2 and No. 6 Oil [6]8 PET Coke [7]9 Cost Difference

Total System

10 No. 2 and No. 6 Oil11 PET Coke12 Cost Difference (3,228,482,326)13 Net Total Cost Difference (1,720,945,829)

14 Levelized Cost Difference (134,623,944)

2029 2030 2031 2032 2033 2034 2035 

(t) (u) (v) (w) (x) (y) (z) 

20,105,366 20,456,957 20,818,115 21,189,104 21,570,199 21,961,682 22,363,84

103,193,575 103,667,710 104,152,750 104,648,945 105,156,554 105,675,837 106,207,0123,298,941 124,124,667 124,970,864 125,838,049 126,726,753 127,637,519 128,570,9

120,392,467 124,168,544 128,063,057 132,079,720 136,222,365 140,494,942 144,901,

12,410,946 12,801,023 13,203,360 13,618,342 14,046,367 14,487,845 14,943,

(107,981,521) (111,367,522) (114,859,698) (118,461,378) (122,175,998) (126,007,098) (129,958,

252,573,816 260,495,725 268,666,103 277,092,742 285,783,681 294,747,209 303,991,

28,624,946 29,504,453 30,411,140 31,345,849 32,309,450 33,302,841 34,326,

(223,948,871) (230,991,272) (238,254,963) (245,746,894) (253,474,231) (261,444,368) (269,664,

372,966,284 384,664,270 396,729,160 409,172,463 422,006,046 435,242,151 448,893,

41,035,892 42,305,476 43,614,499 44,964,190 46,355,817 47,790,685 49,270,

(331,930,392) (342,358,794) (353,114,661) (364,208,272) (375,650,229) (387,451,465) (399,623,(208,631,451) (218,234,126) (228,143,796) (238,370,223) (248,923,476) (259,813,946) (271,052,

R:\Orlando\005141 - VIWAPA\037778\Tables for Revise Report 2-22-08\Table 9_methanol conversion_rev.xls 
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 

ERNEST ORLANDO LAWRENCE

BERKELEY NATIONAL LABORATORY

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 Berkeley 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 Energy 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 agency thereof, nor The Regents of the 

University of California, nor any of their 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 disclosed, or represents 

that its use would not infringe privately owned rights. Reference herein to any specific 

commercial product, process, or service by its 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 and opinions of authors expressed herein do 

not necessarily state or reflect those of the United States Government or any agency 

thereof, or The Regents of the University of California. 

Ernest Orlando Lawrence Berkeley National 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 reviewing earlier versions of this 

manuscript, the authors thank (in alphabetical order, by last name): Jeff Chester (Kaye Scholer 

LLP), Karlynn Cory (NREL), Mike Davies (FreeStream Capital LLP), Ed Ing (Law Offices of 

Edwin T.C. Ing), Tim MacDonald (Meridian Investments), Alejandro Moreno (U.S. DOE), Ric 

O’Connell (Black & Veatch), Kevin Pearson (Stoel Rives LLP), Liz Salerno (AWEA), Ryan 

Wiser (LBNL), and one anonymous reviewer. Of course, 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 Investors 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 Forma Financial Model and Assumptions........................ 57

Appendix C: Overview of Partnership 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, representing a 27% increase in cumulative capacity. 

This rapid expansion has required the mobilization of a tremendous amount of capital to finance 

wind project costs. Roughly $18 billion (in real 2006 dollars) has been invested in wind project 

installation in the U.S. since the 1980s, with more than $3.7 billion 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 American Wind Energy Association (“AWEA”), and the 

required amount of capital will likely continue to increase in future years if market growth 

continues. 

The financing of new wind projects varies from that of fossil-fueled power projects due to the 

different cost characteristics of each. Specifically, 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 extraction to transportation, power production, and 

emissions controls), tax incentives for wind projects are instead targeted almost exclusively at 

the power production stage. The two principal Federal tax incentives available to wind projects 

are the production tax credit (“PTC”) and accelerated depreciation deductions (together with the 

PTC, the “Tax Benefits”). These Tax Benefits provide 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 multiple financing structures to attract various 

investors to projects, manage project risk, and allocate Tax Benefits to entities that can use the 

Tax Benefits most efficiently. Some of these structures 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 debt financing to leverage their equity exposure and returns. 

This report surveys the seven principal financing structures through which most new utility-scale 

wind projects in the United States have been financed from 1999 to the present, excluding 

projects owned by investor-owned and publicly-owned utilities where 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 does not cover financing structures used for smaller communitybased wind power projects, though it may have some indirect utility for parties considering such 

projects, as several financing options used for smaller projects are derived from structures first 

conceived for larger projects. Finally, this report is relevant only to the U.S. market, since the 

i
presence and structure of the Tax Benefits have driven the development of financing structures in 

ways not applicable for other national markets. 

The report has three primary objectives: (1) to survey recent trends in the financing of utilityscale wind projects in the United States, (2) to describe the seven 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 investors (both Strategic and 

Institutional Investors, jointly known as “Tax Investors”), and commercial debt. Their origins 

stem from variations in the financial capacity and strength, as well as the business objectives, of 

wind project developers. The structures 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 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. 

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 contributes 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 finances 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 Investor Flip structure, but adds 

debt financing. Likely involves 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 Leveraged 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 shown in Table ES-1 and covered in this report is not intended to 

be exhaustive. Various permutations of these structures, as well as other structures altogether, 

are possible. That said, the initial construction costs of most new utility-scale wind projects in 

the United States from 1999 to the 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 template wind power project was constructed. The 

template project is based on a set of assumptions intended to reflect market conditions for 

projects coming on-line in 2007 and 2008 for items such as non-financing capital costs, 

operating costs, energy production, taxes, and revenue flows. The template project is then 

customized to reflect each financing structure. For the six financing structure 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. The 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-year 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 Investor 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 developer’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 the project on a longer-term basis than 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 (except for the Corporate 

structure, where the relevant input is the developer’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 financing input assumptions are described in Chapter 4 and Appendix 

B. The outputs are the 20-year LCOE, the Tax Investor’s 20-year IRR, and the developer’s 10-

year and 20-year IRR (again, except for the Corporate structure, where the developer’s 20-year 

IRR target is a model input). In practice, negotiations with Tax Investors focus principally on 

the Tax Investor’s IRR. The developer’s return calculations are presented (in both IRR and NPV 

terms) primarily for informational purposes, though some Tax Investors 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 Investor capital, the developer’s return in the model (and in 

actual negotiations) is the residual, or what is left after satisfying the Tax Investor’s return requirements. In practice, 

developer returns also reflect relative project attributes, 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 the 20-year LCOE required under the various 

financing structures. This variation is principally a function of: 

(1) financing-related transaction costs (shown 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 shown in Table ES-2, but discussed in Chapter 3 

and Appendix B), including the level of equity contributions and pre- and post-flip 

allocations of both cash and Tax Benefits. 

Table ES-2. Project Costs, Investor Returns, 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 input, 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 years 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 market 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 detailed 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 accounting analysis. Accordingly, the returns should 

not be assumed as likely for specific projects using the various financing structures. Instead, the 

comparative nature of the analysis means that these 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 the 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 impact of financing structures – rather than 

individually or on an absolute basis. 

Table ES-2 suggests that leverage at the project level provides the 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 years 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-lowest LCOE is found with the Cash Leveraged structure, at 

$50/MWh (with the slightly higher 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, and 

suggests that leveraged structures should be popular in the market. Debt has a cheaper cost of 

capital than does equity. Other matters held equal, 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 investors still receive the 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 the 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 structure. Factors not easily quantifiable in a financial model, e.g., a 

parent company’s corporate financing strategy and project risk considerations, also play major 

roles. 

The Institutional Investor Flip and Back Leveraged structures have the next lowest LCOE at 

$53/MWh. These all-equity structures are identical with the exception of the developer’s 

company-level debt in the Back Leveraged structure. 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 developer’s returns. For the 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 has 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 pays the developer an annual amount equal to a 

fixed percentage of the PTCs generated – is found to be the next-cheapest, with a LCOE of 

$59/MWh. This LCOE, as well as the developer’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 Investor’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 requirements should be lower than required for a Corporate structure 

investment (in which the Corporate entity takes development risks). The equity return to the 

developer under the Strategic Investor Flip structure is artificially magnified by the small amount 

of capital contributed. Finally, the Strategic Investor Flip structure results in a higher LCOE 

than does the Institutional Investor Flip structure 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 resulting from the analysis is associated 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 developer’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 the risks (and returns) between two 

equity parties, with one party having lower risks and, hence, lower returns, than the other. In this 

way, the 10% developer’s target return might be thought of as a blended equity hurdle rate, 

reflecting a melding of the typical returns to Tax 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 corporate level. Other things held equal, a decrease in the 

developer’s required return will reduce the corresponding LCOE. 

Variations in the LCOE across financial structures (assuming the same underlying template 

project) reflect the different assumptions made about the equity returns and debt financing costs 

required by Tax Investors and lenders in the marketplace. Investors and lenders require higher 

returns to invest in wind projects that use structures deemed more risky, e.g., those that defer 

returns until later in the life of the project, or that use leverage. Thus, assuming all other cost and 

operating parameters are held equal,iv 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 becomes a competitive differentiator among project developers. 

Those with access to cheaper money will be able to offer lower-cost power to their customers. 

The variation in LCOE across structures also indirectly touches 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 across 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 available 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 relative popularity across structures over time and among different 

developers and capital providers. These attributes suggest that inefficiencies and differing risk 

perceptions remain in financing wind projects. 

More broadly, this analysis highlights the fact that developers decide which 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 use the Tax Benefits and to provide the capital 

funding, as well as the financial robustness 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 expiration 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 meeting in-service deadlines for the 

PTC. Secondary factors also influence the decision, e.g., the relative preference for realizing 

value up-front via a development fee or capital gain on the sale of the project, or over time from 

the net cash flows from operations. The relative 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 time, especially as their own 

financial situations have changed. In short, there is no single “correct” structure for all 

developers for all projects 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 choosing a financing structure. Table ES-3 

provides a list of several key corporate and project-level considerations. Depending on a given 

developer’s views on each consideration, one or more financing structures are likely to be more 

suitable than other structures to meet the needs of the developer. Table ES-3 lists several nonexhaustive scenarios with differing combinations of these developer considerations. The 

financing structure(s) most typically used for each scenario is identified in the final column. 

Section 3.8 describes the scenarios 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 through 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 structure (Scenario 3) or, if the project returns look low, the Cash 

Leveraged or Cash & PTC Leveraged structures (Scenario 5). Which of these two leveraged 

structures is used will generally 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 financial obligations associated with PTC debt. 

A developer lacking the ability to use the Tax Benefits, but with 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 structures (Scenarios 4 and 8), with Back Leverage 

employed to reduce the developer’s stake and/or to boost the developer’s return. Those 

developers that own existing projects but are seeking 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 financing trends. Even in the short period since 

1999, financing structures have risen and declined in their relative popularity among developers 

and investors. The current diversity of financing structures is in response to the evolving needs 

of developers and new investors in the wind sector. Existing financing structures will continue 

to evolve, and new structures will 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 existence of the PTC – and the fact that choice of financing structure 

can, as demonstrated in this report, have a significant impact on LCOE, suggests that it will be 

useful for the U.S. Department of Energy to stay abreast of changes in the market and to 

periodically review the impact of financing structures on the cost of wind energy. 

viii
1. Introduction 

After a long period of relative stagnation that began in the late 1980s and lasted throughout much 

of the 1990s, the U.S. wind power market has grown rapidly in recent years (Figure 1). From 

1998 through 2006, almost 9,900 MW of new wind capacity 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 Growth 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

3,000

1982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006

Annual Capacity (MW)

0

2,000

4,000

6,000

8,000

10,000

12,000

Cumulative Capacity (MW)

 Annual US Capacity (left scale)

 Cumulative US Capacity (right scale)

F

T

term. AWEA’s August 2007 forecast projects record 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 project 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 developers will need to raise close 

to $6 billion in 2007 in order to finance the expansion projected by AWEA, and the required 

amount of capital will likely continue to increase in future years if market growth continues. 

Moreover, these figures do not include financing raised 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 amounts 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 wind project developers 

have been small single-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 with not only access to the capital required to build 

the project, but also a tax base large enough to efficiently use 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 Internal Revenue Code provides a 

production tax credit for power generated by certain types of 

renewable energy projects, including 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 the credit, a project must meet 

several factors to demonstrate 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 renewable 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 developers 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 efficiently. These structures balance the varying 

needs for financial return, risk, and operating control presented by wind power project 

developers, tax-oriented investors, and, where utilized, debt providers. 

While these new financial structures have enabled more wind power projects to attract capital, 

the diversity in the purpose, framework, and economics 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 structures effectively create different returns for 

 

3

 As wind project installed costs have increased in recent years, the returns 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 output 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 returns 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 utility-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 structure, 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 development of wind power projects that 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 provision, which has no expiration date, 

certain wind project equipment – including the turbines, 

generators, power conditioning equipment, 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 the 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 notes on the scope of this work merit mention: 

1) This report is focused on the financing of large utility-scale wind projects designed to sell 

electricity directly to utilities or into power markets on a wholesale 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 financing structures used in the wind power marketplace affect the cost of wind energy. It is not 

intended to replace the DOE’s ongoing internal evaluations of the cost of energy from various 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 structures used for smaller community-based wind 

power projects, or for distributed generation or behind-the-meter wind power projects. 

Several reports have been released that profile the financing 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 considering 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 presence 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/documents/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, reflecting a widening and deepening of the capital markets for wind power. 

Prior to roughly 1999, the financing community generally perceived the wind market as exotic, 

i.e., complex, small, and risky. Earlier difficulties and financial losses experienced by projects 

and manufacturers had soured the market for several 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 complex, includes more and larger transactions, and has 

recorded a marked reduction in the cost of equity and (to a lesser 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, increasingly 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 developments in financing trends and structures in the U.S. wind 

market since the burst of wind project development in the 1998/1999 time period. These 

developments, along with variations on these themes, have fostered the creation of the multiple 

financing structures profiled in this report. Two concern the equity side: (i) the entrance of large 

companies with strong balance sheets interested in actively developing and owning wind power 

projects (“Strategic Investors”) and, (ii) the entry of large, but more-passive investors principally 

interested in investing in wind projects for the Tax Benefits (“Institutional Investors”).6 The 

third development has been the entry of multiple European commercial banks to compete for 

wind project debt financing opportunities in the United States market. 

While these developments cannot be tied to a particular 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 through 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 within 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 better understand the seven 

specific financing structures described 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 their 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 Investors Dominate the Market 

The 1998/1999 time period marked the beginning of the current era of substantial new growth in 

U.S. wind power capacity (see Figure 1). For 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 projects in Minnesota and Iowa, respectively. 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 such as PacifiCorp, Public Service Company of 

Colorado, Platte River Power Authority, and Madison Gas & Electric installed projects for their 

own account. A few private independent developers (“developers” or “sponsors”) and utility 

subsidiaries developed the remaining utility-scale projects. Little capacity came on line after 

June 30th, 1999 through the end of 2000, as the Congress did not renew the PTC until late in 

1999, and developers needed time to develop a new round of projects. 

The financing structures for most wind projects during this period were not complex. Although 

the PTC was available to projects coming on line prior to June 30, 1999, most developers lacked 

the financial strength to fund a project or to make efficient use of the Tax Benefits. As a result, 

their main financing option was simply to sell the 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 experience in the power sector who intended to take an active, if 

not controlling, management role in wind projects. 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 these Strategic Investors, who used their internal 

financial resources to fund the equity share of capital costs (and all of the costs if no project-level 

debt was used). Institutional Investors – i.e., those entities interested in passively investing in 

wind projects primarily for the Tax Benefits – had not yet entered 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 the sector. One institution, Fortis Capital, drew 

upon its success in financing European wind projects to dominate wind sector debt financing in 

the United States. Plain-vanilla, uncomplicated, construction and senior term debt financing 

were the principal offerings. A few deals included 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 service obligations. While PTC loan 

monetizations can be attractive 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 financial strength and willingness to provide the related 

6
guarantees.7

 Overall, much of the new capacity added from 1998-2000 was financed on balance 

sheet, with no project debt (i.e., using the Corporate structure described later in Section 3.1). 

New capacity additions surged in 2001, as developers 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-national petroleum company, entered the U.S. wind market 

as a Strategic Investor. A few electric utilities also made their first acquisitions of wind projects 

as investors (rather than for internal generation purposes). These included American Electric 

Power and Entergy. Equity financing structures did not change significantly, however. In each 

case, these new investors typically acquired wind projects developed initially by smaller, 

independent developers unable to utilize the Tax Benefits. In most cases, the larger Strategic 

Investor acquired the projects outright. Joint venture collaborations involving two larger 

companies were used for some projects, but this structure was the exception rather than the rule. 

Also in 2001, bond market financing was used for the first time to finance a large wind project. 

A group of public utility districts in Washington 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 proceeds directly financed construction costs, rather than being merely a takeout of other construction debt. 

There was little new project activity in 2002, as the PTC was not available 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-based 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 investment opportunities (e.g., tax credits supporting 

affordable housing) all restrained interest 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 more capital. Several 

new, independent developers entered the sector around this time. With little or no ability to 

make efficient use of the Tax Benefits, some of these developers nonetheless sought structures 

that allowed them to finance their projects in a tax-efficient manner, while retaining an 

ownership stake. With many of the earlier utility-based Strategic Investors still financially 

constrained due to the difficulties in the merchant power sector, developers of larger projects 

sought tax-oriented Institutional Investor capital. 

Three developments assisted in this effort. First, from September 11, 2001 through the end of 

2004, the Federal Government offered a temporary 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 after the 9/11 terrorist attacks. By boosting the near-term return 

to investors, this incentive enhanced the attractiveness 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 Internal 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-oriented equity, entered the wind sector to assist 

in sourcing capital for new projects. As a result of this confluence of events, 2003 and 2004 saw 

the closing of the first large transactions involving simple partnership flip structures. 

Institutional Investors remained few in number, however. Most projects 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 larger 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 lower. 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 institutional 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 several wind projects, and the financing is 

obtained at the holding company level (rather than for each project individually). Portfolio 

financings can offer developers several benefits. These include potential transaction cost savings 

by negotiating a single set of financing documentation, more favorable financing terms due to 

perceived lower aggregate risks of the portfolio, and the enabling of financing of projects 

otherwise too small or risky to attract financing on their own. 

In addition, a transaction in 2003 combined two different financing sources for the first time: 

PTC debt financing and Institutional Investor equity capital. The transaction required the three 

parties contributing funds to the project – the developer, the Institutional Investor, and the lender 

– to identify and allocate project risks. In particular, the lender and the Tax Investor had to craft 

their respective rights and risks with respect to the PTC debt financing. Previous transactions 

had involved simpler, bilateral negotiations between 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 continued, stimulated by the broader expansion of the 

overall wind sector and the focus of project developers 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 evolution towards larger projects reflects multiple 

factors, including economies of scale in development costs and an up-scaling of turbine size.9

 

Most importantly, the effort, cost, and time to develop wind projects do not increase in step with 

project size; thus, developers have been able to reduce costs on a per-MW basis by focusing on 

 

9

 According to Wiser and Bolinger (2007), the average turbine size installed in 2006 was 1.6 MW (with turbines 

exceeding 2 MW used for many projects), which is more than double the 0.7 MW average turbine size installed in 

1998/99. 

8
larger projects. For their part, Tax Investors also have been able to achieve economies of scale 

in financing by deploying larger blocks of capital in single transactions. 

Increased project development activity has put upward pressure on turbine 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 higher global prices for 

manufacturing inputs such as steel. In response, turbine manufacturers have raised prices and 

required developers to make early turbine commitments and cash down-payments in order to 

secure access to turbines. In addition to turbine price increases, interconnection costs have risen 

for projects being sited further away from transmission lines. All of these factors have raised 

wind project financing requirements substantially since 1999. AWEA estimated that the 663 

MW of capacity installed in 1999 represented some $700 million in investment, resulting in an 

average cost of $1,056 per kilowatt of capacity.10 By contrast, AWEA estimated that $4 billion 

in investment capital was mobilized to finance 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 reach 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 have taken place both at the project level and at 

the corporate level. Most directly, fewer developers 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 smaller developers or to buy them outright. 

A key method for financing new construction has continued to be the single-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 initial 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 costs of their projects. 

These large developers include foreign companies, e.g., BP, Iberdrola, Acciona, and Enel, as 

well as domestic entities such as PPM Energy and Horizon Wind Energy. The ability to finance 

new construction without having to tap third-party capital has emerged as a useful competitive 

advantage by reducing transaction costs and time to operation. 

The continued use of this form of financing structure has been accentuated by the marked 

consolidation in the industry since 2002. Large entities, including especially foreign entities, 

 

10 See www.awea.org/news/news000430w2k.html 11 See www.awea.org/newsroom/releases/Wind_Power_Capacity_012307.html 12 In the last few years, FPL Energy has closed several privately-placed long-term debt refinancings of portfolios of 

its existing and new projects. The refinancings appear principally to be limited-recourse in nature, but include credit 

support from FPL Energy on certain aspects. In August, the company was reported as considering a tax equity 

monetization for five projects, including one under construction. 

9
have forged alliances with, or acquired outright, several smaller developers 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 partnered with Tax Investors. This 

consolidation trend has accelerated in the last few years: at least thirteen mergers or acquisitions 

totaling 35,000 MW of wind project 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 capacity, and have acquired 

several projects from developers. Their motives vary, but include an ability to use the Tax 

Benefits, and a willingness to use their own internal corporate funds to finance capital costs. In 

addition, some utilities are seeking outright project ownership in part because their state 

regulators allow them to earn a return on the investments. Another incentive is a desire to avoid 

potential complications with rating agencies wanting to reflect credit risks of buying power from 

unrated project entities by establishing a debt equivalency value for power purchases. 

At the same time, Institutional Investor capital sources have increasingly been asked to finance 

new construction. In 2006, thirteen 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 Corporation, a leading Institutional Investor in wind 

projects, estimates that third-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 aggregate 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 prominent 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 transaction. Of the thirteen participants, six 

firms acted as lead investor in transactions, up from only one or two 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 comfort 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 resource risk, and a standardization 

of financing structures. Broader market factors in the rise of Institutional Investors include an 

increasing comfort that Federal and state tax and other incentives for renewable power will 

remain in place or be expanded, Congressional action in 2003 that granted investors the ability to 

use the PTC against alternative minimum tax obligations during the first four years of a wind 

project, and declining attractiveness of alternate tax-oriented investment opportunities for 

Institutional Investors (e.g., in the low-income housing sector). 

Such broadening of the investor pool has added to the competitiveness of the market for capital. 

Developers have been able to secure equity financing from Tax Investors at steadily lower rates. 

At the AWEA wind power conference in May 2003, Meridian Investments estimated that 

Institutional Investor returns would 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 deals 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 projects, 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 and even risk-free Treasury securities. 

2.4 Recent Debt Financing Developments 

Debt has remained mostly a secondary consideration in the financing 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 cash flow and control between project lenders and 

the Institutional Investors in loan default situations. The concern is the potential risk of their upfront equity investment being squeezed out by lenders seeking to recover the value of their loans. 

Additionally, some Institutional 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 costs more up-front, it also takes more time to close 

the financing transaction. The repeated expirations in the PTC, and short-term renewals of 

several of the PTC extensions, have given a competitive advantage to developers not needing to 

obtain debt financing as a condition of commencing construction. 

With term debt not in high demand, the debt market has expanded principally in the types of loan 

financing made available to project developers. Several developers, for example, have accessed 

shorter-term turbine supply loans, construction financing, and letter of credit 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 several transactions in 2006 using the Back 

Leveraged structure. The Back Leveraged financing structure – with debt incurred by the 

developer, rather than at the project level (described 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 finances a portion of the developer’s equity contribution to the project 

company. These debt facilities principally assist the developer by stretching its capital, thereby 

enhancing its ability to expand operations. 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 primary financing tool, the number of institutions 

providing debt financing of all types, as well as the average size of loan transactions, has risen in 

recent years. Eleven financial institutions acted as lead arranging lender for debt transactions in 

the wind sector that closed in 2006. This was 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 construction loan facilities to support a portfolio of projects. 

Anecdotal information by loan arrangers at industry conferences indicate that the number of 

banks participating in loan syndications and average loan participation 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 rates and are innovating in terms and structures 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 and PTC monetization debt financing structures in 

the U.S. market during the 1998-2001 time period. Since then, the informal mantle of mostactive lead arranger has always been held by one or another European bank such as Dexia Crédit 

Local or HSH Nordbank. Of the eleven institutions that led one or more debt financing 

syndications in 2006, only three were U.S. financial institutions, and one of those three only 

acted as a lead arranger for a transaction developed by an affiliate. A few insurance companies 

also have provided institutional debt financing, but the majority of project leverage has come 

from commercial banks. 

Relative to the dramatic decrease in equity returns, debt terms have not changed as significantly. 

The typical loan term (or duration) remains a function of the length of the underlying power and 

REC purchase agreements. For projects with long-term power purchase agreements (e.g., twenty 

years) with creditworthy utility buyers, commercial bank lenders are willing to extend loans with 

 

20 Jeff Chester presentation (“Wind Power Market 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 lenders, e.g., insurance companies, have been willing 

to go as long as nineteen years for comparable transactions. For projects involving shorter term 

power purchase agreements (“PPAs”) or utilizing power marketing contracts in lieu of power 

purchase agreements, loan terms are shorter and/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 information suggests that commercial bank interest 

rate margins over their cost of funds have declined by approximately 50 basis 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 margins gradually in later years, e.g., up to 200 basis 

points over LIBOR for the final years 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. Broadly stated, equity and debt capital 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, capital is now chasing projects. This upheaval has 

fostered the development of the various financing structures profiled in the next chapter. To the 

extent that this situation endures, capital providers will continue to innovate financing terms and 

financing structures as means to secure 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 Current 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 initial construction costs. 

• Leverage: whether project-oriented limited-recourse 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 installment (i.e., “pay-as-you-go”) basis tied to 

generation of PTCs by a project. 

• Management: the division of management responsibilities among the several 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 utility) have used one of seven structures to finance the capital 

costs. This chapter describes each of these structures in detail. The simplest structure is a single 

investor, all-equity approach dubbed the Corporate structure. Three 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 both 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 either the project or developer 

level.24 In addition to describing each of these structures both textually and schematically, this 

chapter discusses each structure’s rationale for use, 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 construction costs of most new utility-scale wind projects in 

the United States from 1999 to the 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 the four all-equity structures, it is the 

nature of the Tax Investor (i.e., Corporate, Strategic, Institutional). 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 ways 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 descriptions and reviews of the various financing 

structures presented here do not include formal legal analyses of their tax and accounting 

implications. The authors are not attorneys or accountants, and the information presented here 

should not be considered as formal legal or accounting advice. Instead, the information 

presented here is at a general level and is not specific to a particular project or investment. 

Though the report identifies certain important aspects relating to partnership issues associated 

with the financing structures described here, project developers, investors, and others are 

strongly encouraged to seek tax 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 project costs and sufficient tax appetite to use all of the project’s Tax 

Benefits. The Corporate parent developer/investor typically establishes a special purpose entity 

to house the assets of the project. This structure, which continues 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 company using internally generated funds from other 

operations, and all of the project’s net cash flows and Tax Benefits 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 financing are involved (at least initially) at the project level. The parent 

exercises full management control over the project (although it is not uncommon even for this 

type of developer/investor to engage an outside firm to perform 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 cash, taxable losses/gains, and PTCs. The underlying boxes with 

percentages show how the respective 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 (principally 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 flows 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

Å 100% 100% Æ

Figure 2. Schematic of Corporate Structure 

Rationale for Use 

The advantage of this structure relative to other 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 incurs the least amount of out-of-pocket transaction 

costs. In the wind sector, these aspects have become 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 focus their efforts on projects 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 finish development of their projects. 

Earlier in the decade, some corporate investors leveraged their financial strength still further. 

The ability to internally develop and finance entire projects provides a significant negotiating 

advantage when acquiring projects from smaller developers lacking the internal wherewithal or 

16
time to mobilize the capital to finish projects prior to the next PTC expiration 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 developers opted to accept a discounted price for selling the rights 

to their projects. This type of market power 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 confidence has grown that the PTC will be extended. 

Other Strategic Investors have used their financial strength to fashion on-going relationships with 

smaller developers as a means of securing a pipeline 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 developer to finish the development 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 smaller development companies by larger companies 

entering the sector are further examples of the use of financial strength to competitive advantage. 

Lastly, the larger, financially strong developers have placed down-payments to acquire rights for 

deliveries of wind turbines from turbine manufacturers. With a scarcity of wind turbines in the 

marketplace, the advance payments to secure deliveries prior to the next PTC expiration date 

have been another means by which larger developers have used their 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 costs than competitors, which has provided a further 

competitive advantage in competing for utility purchase contracts. 

Investor Type 

The companies using this structure most commonly are large, financially strong, and have 

significant and predictably recurring income tax obligations. They have the cash flow to 

undertake the full investment and the ability to utilize the Tax Benefits in the years in which they 

are generated by the project. Companies using the Corporate structure typically have strategic 

reasons to be investing in the wind sector. They view it as a core part of their business plan, 

rather than simply a convenient means to reduce tax obligations. In effect, 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 structure to finance the initial costs of most of its 

wind projects.27

Use of the Corporate financing structure often reflects a broader, corporate-wide decision to fund 

all corporate investments at the parent level, rather than individually at a project level. This 

financing strategy reduces financing costs, e.g., rates and transaction costs, to the lowest levels 

available to the Corporate parent investor, since the risks of any single investment, 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 aggregate cash flow from current and future 

operations. Electric utilities and petroleum companies historically have taken this 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 Corporate financing structure enables decisions on 

project development to be separate 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 refinancing via the capital markets using other financing 

structures such as the Pay-As-You-Go or leveraged portfolio financing structures. 

Frequency 

The Corporate financing structure is the most commonly 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 brought 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 Benefits changed. For one reason or another, most 

other developers have found it useful or necessary to tap third-party equity or debt capital to 

finance their projects. The recent entry of several large foreign developers into the U.S. market 

and the related consolidation of the sector by large financially strong players suggest that the 

Corporate structure will continue to be widely utilized going forward. At the same time, it will 

increasingly be employed not as the final structure, but rather as an interim means to get wind 

projects built and into operation pending later refinancings. To the extent that the foreign entities 

have insufficient U.S. tax appetite, such refinancings 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 name 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 percentage ownership share by the Strategic 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 partnership structure is similar to a basic 50/50 joint venture structure. 

However, three key elaborations set it apart from a conventional 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 developer provides the remaining 1%. Under 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 flows 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 and Tax Benefits to reach a pre-negotiated IRR 

on its investment. After the Flip Point, the percentage allocations of project 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. The Flip Point is usually projected to be reached on or shortly 

after the tenth anniversary of the project’s commercial operation date. The tenth anniversary is 

used as a marker date, since the PTC is available 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 flip 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, later, Flip Point and to 

have the inversion of the percentage allocations be staged across 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 second 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 the ownership interests held by the 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 investment (and to recognize the consequent Tax Benefits), most 

projects set the purchase price on at least a “fair 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 cash flow thereafter and the exhaustion of the Tax Benefits serve 

to reduce the fair market value of the Tax Investor’s ownership interests after that point and, 

consequently, the price that must be paid by the project developer for such interests. 

Under this structure, no limited-recourse 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 structure, the project developer usually retains broad management control 

prior to the Flip Point. However, it is not uncommon for the Tax Investor to exercise majority 

control pro rata with its ownership 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 representation of the Strategic Investor Flip structure. 

Specifically, the schematic shows the relative percentage 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 Benefits – 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 Tax 

Benefits 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 the equity contribution 

and pre- and post-flip allocation percentages shown 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 therefore be considered illustrative. 

Strategic Tax Investor 

(99% of equity)

Developer 

(1% 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 

99% Æ

Å 1% / 90% 99% / 10% Æ

Å 1% / 90% 99% / 10% Æ

Å 1%

Figure 3. Schematic of Strategic Investor Flip Structure31

 

31 Figures 3, 4, 6, and 7 are adapted from a June 2006 Meridian Clean Fuels presentation titled Comparing 

Alternative Structures for Tax Equity 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 relative simplicity. All financial flows prior to the Flip 

Point, both in and out of the project company, are on the same pro rata basis as ownership. The 

structure is useful for those project developers lacking both the financial strength to fund initial 

capital costs and the appetite for the Tax Benefits, but who are nonetheless unwilling to simply 

sell the project outright. In effect, the Tax Investor buys the majority of the project and gets the 

lion’s share of the aggregate Tax Benefits during roughly the first decade of operation, when 

most of the Tax Benefits are generated. The project developer receives most of the cash and the 

remaining Tax Benefits generated thereafter; the developer also typically 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 manage the project capably during this first period, 

as the project’s success is key to the Flip Point occurring on schedule and the developer realizing 

the long-term value thereafter. The Flip Point historically 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 some transactions to be extended by a few years to 

enable the Tax Investor to reach its negotiated target return. Changes in negotiated power prices 

and underlying interest rates also will affect the relative positioning 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 this structure typically have a business plan that calls for them to 

evolve into larger entities over time. They are not content simply to receive a single up-front 

development fee, but wish to develop a pool of projects that will generate cash flow over time. 

Some closely-held developers view 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 public 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 this structure as it enables them to partner with 

capable, if cash-poor, project developers. Some Tax Investors believe that making the project 

developer wait for its returns until after the Flip Point motivates good project management. The 

structure gives preferred return rights to the Tax Investor and, in so doing, allocates much of the 

risks of a wind project to the developer. If the wind resource proves weaker than first thought, if 

turbine technical availability proves less than promised, or if maintenance 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 reaches 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 Investors, 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 structure for these reasons. 

Frequency 

The Strategic Investor Flip financing 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 developers, there are limitations. At least one Tax Investor currently 

in the market discounts the structure’s utility, considering it to be little different from the 

Corporate structure. For developers, 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 quickly, without being saddled with unwanted Tax Benefits. 

Separately, several of the medium-scale wind project developers that might otherwise have 

utilized the Strategic Investor Flip structure have instead solved their project financing needs by 

agreeing either to sell their projects 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 structure for its many transactions). It 

is similar to the Strategic Investor Flip structure, in that the project developer 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 important 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 percentages 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 the developer contributing a greater portion of the 

initial equity capital (e.g., 30% - 40% of the total), all of the distributable cash 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 allocated 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 Investor is allocated 100% of the Tax Benefits 

from the outset of project operations. 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, depending on the relative returns generated from 

cash flows versus PTCs.33 Once the Flip Point has been reached, a majority of the cash and Tax 

Benefits, typically around 90%, are allocated to the developer. The post-flip sharing percentages 

are sized to provide the Tax Investor with a targeted 20-year return, so they vary depending on 

the specifics of the project. The general assumption is that the 20-year return 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 financing at either the project or 

company level. The developer usually maintains 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 contributions from the project developer and the 

Tax Investor into the project company to fund initial construction costs, as well as allocations of 

cash flows and Tax Benefits to each party. As discussed above, this structure features two Flip 

Points for cash allocations (though just one Flip Point for Tax Benefits): initially all cash goes to 

the developer until it recoups its investment in the 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 developed to address limitations of the Strategic 

Investor Flip for various types of developers and investors. Specifically, 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 Investor Flip, with its pro rata link between the percentage amount 

of capital invested and receipt of cash and Tax Benefits, does not give them the means to invest 

capital without being saddled with unwanted Tax Benefits. 

Another more recent driver has been the entry of cash-based investors (“Cash Investors”) into the 

wind sector. These are typically Strategic Investors but can be Institutional Investors or even 

ratepayer-funded state clean energy funds; the distinction 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 jointly 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 same 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 development rights or simply acquired the smaller 

developer outright so as to become the sole project sponsor. For such Cash Investors, the 

Strategic Investor Flip structure is not suitable, since 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 structure 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 Institutional 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 Investors to avoid the time, expense, governance, and cash flow 

allocation issues of debt financing. 

Institutional Tax Investor 

(60% of equity)

Developer 

(40% 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

Å 0% / 90% 100% / 10% Æ

Å 100% / 0% / 90% 0% / 100% / 10%Æ

Å 0%

Figure 4. Schematic of Institutional 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 reasonably predictable tax 

obligations. To date, these have been comprised primarily of banks and insurance companies. 

Tax-oriented Institutional Investors active in the wind sector have included JPMorgan Capital 

Corporation, GE Financial Services, Wells Fargo, 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 strategic goals as Strategic Investors, 

but lack the tax capacity to use all of the Tax Benefits. 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 & Brown Wind Partners and 

ArcLight Capital. 

Frequency 

For the last several years, those developers seeking third-party financing (and not simply selling 

their projects outright) have most commonly used the Institutional Investor Flip structure. Of the 

13 transactions involving tax equity 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 some standardization of transaction documentation. 

3.4 Pay-As-You-Go 

Description 

The underlying structure for Pay-As-You-Go (“PAYGO”) is very loosely based on the Strategic 

Investor Flip Structure, with three main differences. Under the PAYGO structure, (i) the 

developer contributes roughly half (40%-60%) of the initial capital required (compared to the 

much lower percentages in the Strategic Investor Flip structure), (ii) the allocation 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 payments equal to a pre-determined value of the 

PTCs generated (e.g., 80–90 cents per dollar of PTCs generated), thereby effectively increasing 

its equity contributions over time. Actual percentage equity contributions both initially and over 

time will vary by the relative value of individual projects, as well as the associated depreciation 

treatment. 

 

34 In July, 2007, Iberdrola announced an agreement to acquire 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 into the project company. More commonly, they are structured as 

delayed payments for the ownership interests received from the outset in the project company, 

with the payments made directly to the developer 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 generated. In all cases, an important tax consideration 

is to structure PAYGO transactions 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 the 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 contributions to exceed 50% of the net present value of the Tax 

Investor’s total investment 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 the distributable cash prior to the Flip Point. 

As with the other structures, the terms are structured 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 either the project or the equity 

holding company level. The developer usually 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 typically are limited still 

further. 

Figure 5 provides a schematic representation of the PAYGO structure. The schematic shows the 

relative equity contributions of the project developer and the Tax 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 project company, as shown here – 

from the Tax Investor to the developer 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 equity)

Developer 

(45% 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

Å 0% / 95% 100% / 5% Æ

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 has not been used in connection with the initial financing of 

projects, as other structures can generate higher initial percentage contributions from Tax 

Investors and, if used, lenders. The structure instead is finding use in connection with the 

refinancing of existing wind projects. Several such scenarios have emerged. For developers that 

initially financed their projects using the Corporate structure, refinancing with the PAYGO 

structure can raise capital for other corporate purposes or reduce the investment stake in the 

projects. The structure also enables developers to maintain a significant amount of capital at 

work in their projects, while focusing their return 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 changed (e.g., via a corporate divestiture) such that they are no 

longer able to use the Tax Benefits efficiently. The PAYGO structure enables them to maintain 

ownership and control, rather than being forced to sell the projects outright. Lastly, Cash 

27
Investors desiring to acquire existing wind project assets but lacking tax 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. This structure allows the developers to 

maintain a long-term ownership interest in their projects. In these situations, the developers 

desire to remain active owners of their projects and thus typically look for an Institutional 

Investor, i.e., a passive financial partner, to act as the Tax Investor for the project. Foreign 

companies entering the market also may find it useful. For example, Energias de Portugal, S.A. 

initially considered using a form of this structure 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 operator, or some other project risk. In each 

case, the PAYGO structure reduces the exposure of the Tax Investors 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, while still achieving an 

efficient use of the Tax Benefits. These structural risk mitigants also might be attractive to 

potential Tax Investors just entering the market and desiring to reduce 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 projects 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 existing 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 finance, 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 (without a flip) or the Corporate structure 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 developer and the Tax Investor are the same as with the all-equity 

Strategic Investor Flip, but the amount of the initial equity capital required is decreased by the 

amount of the debt. In turn, the loan principal and interest payments decrease the amount of 

distributable cash available to the investors. The overall project capital costs rise by the amount 

of initial closing costs associated with the loan facility such as legal fees, technical consultants, 

etc., and with any lender-required cash reserves such 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), the 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 equity investors are consistent with those found 

in the Strategic Investor Flip structure, with one important difference: the impact of the 

customary lender covenants on project governance. Specifically, the lender will have a first lien 

on the assets, first rights to cash generated, and approval rights with respect to major operating 

decisions. This measure of control afforded the debt provider is a direct result of the lower cost 

associated with these funds. A general 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 representation of the Cash 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 are deducted 

from the cash flows, with the residual distributed 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). 

Rationale for Use 

Developers seek limited recourse project debt for two principal reasons: to boost equity returns 

and to reduce required equity contributions. All other things held equal, adding debt to a project 

will increase equity returns (because debt is typically 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, has 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 financing (compared to 61% debt for the Cash & PTC Leveraged 

structure, described next). 

39 Note, however, that a lower-than-desired 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 debt)

Tax Investor 

(99% of equity)

Developer 

(1% of equity)

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

Å 1% / 90% 99% / 10% Æ

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 corporate strategy of minimizing their 

capital investments in individual transactions. They are comfortable in their ability to access 

debt efficiently and to work through Tax Investor concerns, such that they are comfortable that 

they can realize the promise of the improved project returns possible with leverage. These are 

typically developers with prior experience in using debt, perhaps in conventional power projects. 

30
Developers who have tapped term debt include Invenergy Wind, UPC Wind, enXco, and Noble 

Environmental Power. 

While the structure itself is an adaptation of the Strategic Investor Flip (at least in a mechanical 

sense, with pro rata allocations), developers using the structure typically seek to retain 

substantive control of their projects and are not looking for an active Strategic Investor. Instead, 

more passive Institutional Investors are typically the type of Tax Investors sought by developers. 

The use of debt on a project can, however, limit the pool of Tax Investors that are willing to 

invest. Some Tax Investors are more comfortable with all-equity structures. Such investors do 

not want to have to contend with a lender in case a project encounters 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 potential for such an “equity squeeze” 

can arise since their share interests in the project 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. Timing may also be an issue for some investors: 

closing on debt financing not only costs more up-front, it also takes additional time to close 

relative to an all-equity deal. In contrast, other 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 better-structured deals and thereby 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, levered structures are currently in the minority for 

financing wind projects. All-equity 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 structure 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 the PTC loan is ten years, corresponding to the period in which the 

PTC can be claimed. As a tax credit used by the project owners, the PTCs do not generate cash 

at the project level that can be used to repay project-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, lenders 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 Investor or the actual debt service payment 

shortfall. Lenders usually focus on the credit-worthiness 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 incremental PTC loan. With this incremental 

source of project-level cash flow, 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 structure described in Section 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 periodic injections vary. Under the Cash & PTC 

Leveraged structure, the lender provides a PTC loan to complete the initial funding, and both 

owners (albeit mostly the Tax Investor) make periodic equity contributions directly to the project 

company to help repay the PTC-based loan, if necessary. In contrast, under the PAYGO 

structure, no debt is involved, so the developer provides more initial 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 debt 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 Investor. 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 restrictions on the project. The additional PTC-based loan 

amount generally does not lead lenders to tighten these restrictions, 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 event 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 there is not enough cash to repay the PTC debt, the 

Tax Investor (and sometimes) the developer make pro rata equity contributions into the project 

company sufficient to support the PTC debt; these incremental contingent contributions are 

shown as dotted arrows parallel to their 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 debt + PTC debt)

Tax Investor 

(99% of equity)

Developer 

(1% of equity)

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

Å 1% / 90% 99% / 10% Æ

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 previously discussed. Namely, the lower cost of 

debt capital boosts project returns and requires less up-front investment from equity participants. 

This structure maximizes the use of leverage by including a PTC-based tranche of debt that is 

supported by a pledge of ongoing contingent equity infusions. 

33
Investor Type 

Developers considering the Cash & PTC Leveraged 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 Leveraged structure, they 

usually have prior experience in using debt, want to retain substantive control of their projects, 

and seek passive Institutional Investors to be the Tax Investor in the transactions. However, the 

inclusion of a PTC tranche of debt 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 expected rate of return against 

its cost of capital. This evaluation becomes problematic 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 availability of funds, many Tax 

Investors prefer the certainty of making just one initial investment over making an initial 

investment and a series of potential future contributions. 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 – particularly if the project is not performing well (i.e., when such 

contributions are most likely). Given such issues, relatively few Tax Investors have proved 

willing to sign up for this structure. 

Frequency 

This type of structure, involving 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. Invenergy Wind also used a version of the structure to finance a 

portfolio of three projects in 2005.41 No other such transactions are believed to have been done. 

As loan documentation and terms are worked out that address Tax Investor concerns, however, 

there are indications that this structure may 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 ownership interests in the project company to secure 

the debt, and uses the debt to fund 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 often is significantly shorter, e.g., as short as four to six years. 

Figure 8 provides a schematic representation of the 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 post-flip allocations of cash flows and Tax Benefits 

to each party. The developer repays its borrowed equity stake out of the cash flow allocated to it. 

igure 8. Schematic of Back Leveraged Structure 

Senior Lender 

(back leverage)

Institutional Tax Investor 

(60% of equity)

Developer 

(40% 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

Å 0% / 90% 100% / 10% Æ

Å 0%

Å 100% / 0% / 90% 0% / 100% / 10%Æ

F

35
Rationale for Use 

The Back Leveraged structure allows the developer to increase its long-term IRR by securing 

lower cost capital with which to fund its initial 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 desiring 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 later refinancing as part of a portfolio. 

Investor Type 

This structure is used by developers that either have limited capital or who have the financial 

resources to invest but that want to reduce their cost of funds. The Tax Investors are not 

impacted by this type of financial engineering at the 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 the Tax Investor for their transactions. 

Frequency 

This structure is becoming more common in the market. It allows developers to increase their 

ownership in a project and capture the relative economic 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 principal means by which most 

large-scale wind projects (excluding utility-owned projects) are currently financed in the United 

States. These structures vary in several respects, including the contractual flow of funds and 

obligations among the financing parties, their relative utility for different types of project 

developers and investors, the timing of funding, their frequency of use, and (as will be shown in 

the next chapter) their impact on the 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 considerations. 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., whether 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 also played a role; pending PTC expiration dates led 

some developers to adjust their project development and financing strategies so as to increase the 

prospects of meeting PTC deadlines. As this pressure 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 preference 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 importance of these various considerations differs from developer to developer and 

om project to project. Furthermore, some developers’ preferred financing structures have 

project-level 

onsiderations. Depending on a given developer’s views on each consideration, one or more 

tures are likely to be more suitable than other structures to meet the needs of the 

eveloper. The table provides several 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 developers 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 (hypothetical) 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 structure(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. Other 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 developers lacking the financial or technical wherewithal to carry a 

project through construction into operation. Such developers commonly adopt a business 

strategy that focuses on early project development, with the goal being to sell their projects to 

larger entities prior to construction. Earlier in the decade, this was the only real alternative for 

developers unable to carry their own projects into operation. Larger developers on occasion 

have taken this approach as well as a means of maintaining business teams, generating cash flow 

to support operations, or to meet the requirements of key utility clients desiring to own wind 

projects outright. Purchasers of these projects – which are often Strategic Investors – 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 

to fund the project, efficiently use the Tax Benefits, and desires a long-term ownership stake for 

strategic reasons. This is the most common wind project financing structure in the United States 

37
(in terms of installed capacity), though only a handful of large developers are able to make use of 

it. 

Scenarios 3 and 4 pertain to all-equity flip structures, where the developer 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 return than investors focused on long-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 Scenario 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 ization is needed to achie

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 either for the Institutional 

tations of 

e various considerations identified 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 not needing significant early cash flows. This 

structure has been used by some of the “community wind” projects in the Midwest, 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 structure, then the Institutional Investor 

Flip structure (Scenario 4) may be more useful. This scenario also may make sense if the 

developer has received development-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 significan 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 ns) u “bac age cenario 8 – th

 choice of which leverage structure to

enta onet ve requisite equity 

pe roje the in ina blig ass d with PTC debt. 

or ns discu e us erag 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 and in part on the perceived relative transaction 

costs and complexity of the two structures. The use of these structures for refinancing projects is 

becoming more common as developer consolidation, often involving foreign entities without 

U.S. tax liability, increases. 

As noted, these scenarios are simplified to illustrate key differences. Specific developers likely 

will have additional or other considerations in connection with specific projects or with their 

overall corporate goals that will impact the choice of financing structure. Other permu

th

38
4. The Impact of Financing Structure on the Levelized Cost of Wind 

Energy 

 the pro forma financial model used for the LCOE 

ortray how the agreed-upon allocations of the 

ax Benefits may be adjusted to comply with IRS tax partnership accounting requirements 

y virtually all 

utility-scale wind projects developed and financed in the last 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 mechanics 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 lenders (if any) and equity providers. This 

chapter begins with a brief overview of

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 the impact of each financing structure on the cost of wind energy, 

the authors developed a simplified Excel-based pro forma financial model. The model uses a 

template of an indicative wind project as the common basis for illustrating 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 project financial model (such 

models are considerably more detailed), nor does it attempt to portray 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 conditions experienced b

it is assumed that the template project uses proven technology to generate electricity for 

sale on a long-term, wholesale basis to a creditworthy utility, and that the project owners 

make full use of the project’s Tax Benefits in the year they are earned. 

(2) Common assumptions are those that are project-specific – i.e., narrower than market 

assumptions – yet nevertheless common to all seven financing structures analyzed. 

These include assumptions about turbine and other “hard” project costs, net capacity 

factor, O&M costs, marginal income tax 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 equity contributions and 

pre- and post-flip allocations of the project’s cash and Tax Benefits among the relevant 

investors. The specific assumptions about equity

39
Appendix B describes the market, common, and structure-specific assumptions used in the 

template model, and lists the specific values used for these input assumptions. 

The model itself consists of a single Excel workbook. Each financing structure is housed in its 

own worksheet. Based on the assumptions described 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 return target at the end of ten years, while not violating minimum 

DSCRs or other lender constraints (for those 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 twenty-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 post-flip cash and tax allocations. 

the first approach. 

For

4.2 L

Tab

The

Corpor

assume

are 

IRR

model 

 

the industry’s default assumption for the life of a wind project. For all of the structures, 

measuring investor returns on an after-tax basis is stan

n

The modeling process adopted for this report starts with assumed return targets, equity 

contribution ratios, and cash and Tax Benefit allocations and then solves for the power sales 

price required to satisfy these targets and constraints. Developers initially follow a similar 

approach (i.e., starting with assumptions about the cost of financing) to evaluate the viability of 

potential projects and to arrive at a starting point for power price negotiations. However, this is 

the reverse of the process that actually occurs when 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 Investor 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 the potential impact of financing 

structures on the cost of wind energy, this report takes 

 more details on the structure of the model and on the input assumptions, see Appendix B. 

evelized Cost of Energy Comparisons 

le 2 summarizes the highlights of the modeling analysis, including key inputs and results. 

 key inputs listed are the project costs, the Tax 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 three structures using debt financing. The outputs 

 20-year LCOE, the Tax Investor’s 20-year IRR,43 the the developer’s 10-year and 20-year 

 (again, except for the Corporate structure, where the developer’s 20-year IRR target is a 

input), and the developer’s 20-year NPV. For those 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 informational purposes, though some Tax 

vestors also assess the developer’s returns to ensure a reasonable allocation of project returns 

• For the six structures other than the Corporate structure, the Tax Investors’ 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 expensive and least expensive structures. The 

leveraged structures are the most expensive – assumed to be nearly $1,830/kW – due to 

the closing costs and reserve accounts associated with debt.44 Conversely, the Corporate 

structure is assumed to be the cheapest – at $1,725/kW – as it incurs no debt-related 

transaction costs and, unlike the all-equity structures involving third-party Tax Investors, 

does not utilize construction debt or incur equity closing costs. 

IRR (which our analysis assumes is always 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 target, 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 developer. The developer’s IRR (both 10- and 

20-year) is an output of the model (except for 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 throughout the 20-year period. 

to $63/MWh, suggesting that choice of financing structure can have a significant imp

on a wind project’s LCOE. 

A

are, of course, a function of the modeling assumptions. These assumptions are merely indicative 

and do not reflect a specific project. Using a different set of input parameters will generate 

different results.45 Finally, the model does not undertake detailed tax-oriented analysis with 

respect to partnership accounting issues, as introduced in Appendix C. Accordingly, the returns 

should not be assumed as likely for specific projects using the various financing structures. 

Instead, the comparative nature of the analysis means that these LCOE results are best 

44 However, the depreciable basis for these 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 factor for the template wind project. 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 illustrate the relative impact of financing structures – 

rather than individually or on an absolute basis. 

Table 2. Project Costs, Investor Returns, and LCOE by Financing Structure 

Leveraged 

Cash 

Leveraged 

Institutional 

Investor 

Flip 

Back 

Leveraged PAYGO 

Strategic 

Investor 

Flip Corporate 

Cash & PTC

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 input, 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 years 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-Ye

($000 @ 7,208 7,540 1,578 4,673 7,811 20,745 0 ar NPV 10%)

20-Year Levelized Cost of Energy (LCOE)

Nominal $/MWh 48 50 53 53 59 61 63 

The a

key dif

10-year

rget re ll as the relative relationships of these assumptions among 

strong projects securing a slightly lower rate and other, less-strong projects 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 resulting LCOE. Since there is no public registry of the Tax Investor 

 IRR agreed upon between the developer and the Tax Investor for individual projects, the 

ta turns assumed here, as we

structures, are based on anecdotal industry information. Nonetheless, some 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 other structures. The 

6.50% rate is in the range of projects closing financing in the last year, with some especially 

utilizing Tax Investors. 

The Tax Investor’s 10-year IRR targets for the Cash Leveraged and Cash & PTC Leveraged 

structures are assumed to be 250 and 275 basis points, respectively, above the Tax Investor 

return for the Institutional Investor Flip structure. The target returns are set higher to reflect both 

42
the incremental risk46 and the mechanical impact of debt on equity returns.47 The study sets the 

10-year Tax Investor IRR target 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 does for ctures. 

Also, some Tax Investors say that 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 Strategic Investor Flip 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 little different from that required fo

he 

Institutional Investor Flip structure, 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, the 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 IRR 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 projects. 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 PAYGO 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 market ar e

r the Corporate structure. This

investor also argues that it should be higher than the required Tax Investor return under t

 struct quires s up-f t capit be 

nd, un e Corp te stru e, the gic 

the project, and does not require the Tax Investor to assume 

oreover, compa ith the tutiona tor 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 the 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 invest in long-term ownership, but rather it is a hybrid of the 

two. While the 10%, 20-year IRR assumption and the calculated 6.64% ten-year IRR can be 

compared to the developer returns under the other 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 first 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 

risk considerations – since the incremental operating cash flow after servicing the cheaper debt (relative to the cost 

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 impact 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 results are discussed in more detail below. 

As shown in Table 2, the financing structure with the lowest LCOE is Cash & PTC Leveraged, 

which has a 20-year LCOE of $48/MWh. In other words, given the assumptions used in the 

analysis, the template project – when financed using this structure – requires a flat $48/MWh for 

the first twenty years 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 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 equity return requirements. In this 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 equity, 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 used. Moreover, the investors still receive the full 

amount of the Tax Benefits as if the project had been financed with all equity and no debt. 

Additionally, debt interest payments are tax-deductible, so they increase the tax loss in the early 

years of the project (a potentially counter-intuitive 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 leverage at the proje

n

in 2006 included project level debt.49 In a perfect market, economic 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 use debt, including concerns about up-front 

transaction costs, increased default risk, and additional time to close. As discussed, up-front fees, 

reserve accounts, and transactional expenses will reduce the net IRR gain from using debt. 

Many Tax Investors prefer not to have a bank holding a first claim on the project assets, in the 

event the project underperforms materially. While the indicative cost assumptions used for the 

model are meant to reflect current market conditions, they may nonetheless not be incorporating 

all perceived market costs or risks when developers and investors structure financing for actual 

projects. 

T

10-year after-tax 

Leveraged structures, respectively. These targets are 250-275 basis points 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 Strategic 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 returns for the two leveraged structures are about 9% (for the 10-

year return) and over 30% (for the 20-year return). This is because in these scenarios the 

developer contributes very little initial capital, yet 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 leverage makes these 

rojected returns more uncertain. Lower-than-projected wind production will disproportionately 

bt is not at the 

roject level, the Back-Leveraged structure uses the same 6.50% IRR assumption and these two 

he PAYGO structure – where the Tax Investor pays the developer an annual amount equal to a 

 of PTCs produced. If that amount decreases to 80 cents the LCOE decreases from 

59 to $56, and the developer return decreases to 10.5%. In practice, the developer and the Tax 

p

reduce or delay cash flow distributions to the developer, since the annual debt service 

requirements do not change. This significant volatility, 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 have the next lowest LCOE at 

$53/MWh. As noted earlier, these all-equity structures are identical with the exception of the 

developer’s company-level debt in the Back Leveraged structure. Because this 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-year 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 significant 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 assumes that the Tax Investor receives a 10-year 

target return of 6.5%, inclusive of the PTC monetization payments; 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 lowest of the structures involving Tax 

Investor equity, with a 20-year after-tax IRR of 11.5%. This return is a function of the amount 

of capital contributed up-front (the most of any structure, at 45% of total equity) and the receipt 

of a majority of the return, via the PTC payments, over time. 

The LCOE and developer return for the PAYGO structure are affected greatly by the PTC 

payment percentage. This analysis assumes the Tax Investor pays the developer 85 cents for 

each dollar

$

Investor negotiate a PTC payment rate at a level that will achieve their respective return 

requirements. 

The Strategic Investor Flip structure has the second-highest LCOE, at $61/MWh. The 

developer’s 20-year return in this structure is projected to be the highest of all the structures. 

This is because (i) the developer contributes just 1% of the up-front capital 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 allocations 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 project 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 Strategic or Institutional) 10-year target return for 

the all-equity partnership structures is uniformly set at 6.5%. As a result, one might expect that 

e Strategic Investor Flip and Institutional Investor Flip structures would generate the same 

he highest LCOE resulting from our analysis is associated with the Corporate structure, and is 

 using this structure have a lower 

eighted-average cost of capital than assumed for this study, then the LCOE would be reduced. 

 required by Tax Investors 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 former is $8/MWh greater than in the latter. The 

difference is due to the developer’s capital contribution and return profile. In the Strategic 

Investor Flip structure, the developer contributes almost no cash, 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 the Institutional Investor Flip structure 

invests a larger amount of capital but receives only a return of capital in the first ten years (0% 

IRR). In other words, under the Institutional Investor flip structure, the developer recovers its 

capital in the first four to six years of operation (six years in this analysis), but receives nothing 

from that point through year ten. Because the developer is not receiving a return in the first ten 

years of operation, the project is essentially using a large percentage 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 model 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 Investor. Although this is technically an all-equity 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 returns, than the other. In other words, the target return might be 

thought of as a blended equity hurdle rate, reflecting a melding of the returns to the Tax Investor 

and the developer in other all-equity structures. Alternatively, it could be considered the blended 

rate of a higher equity return requirement, averaged 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 assumption is reduced to a 9% blended return, then the 

calculated LCOE would decrease to $58/MWh. 

In sum, variations in the LCOE across financial structures (assuming the same underlying 

template project) reflect the different assumptions made about the equity returns and debt 

financing costs

re

that defer returns until later in the life of the project, 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 becomes 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 than 

another, LCOEs would not differ substantially among structures, and there should be little 

difference in the degree of usage of these structures. This analysis suggests that the economists’ 

perfect world does not exist in the wind financing marketplace. Additionally, 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. Information 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 financing structure for their wind 

projects. 

47
5. Conclusions – Observations & Future Trends 

nancing structures will change in popularity from 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 spurred 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 leveraged 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 if 

lenders 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 wind 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 wind as a viable power source. Since then, project costs have 

been rising, and developers have offset a significant amount of the cost increase with the 

financial gains from reductions in third-party equity and debt return 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 Point dates later than ten years, which 

provides more time for projects to reach the investors’ 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 last three years also will affect the choice of 

financing structures for future projects. Larger, well-capitalized developers have more financing 

options than do small developers. Such companies 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 structures to attract both Institutional Investors and Strategic 

Investors wanting to enter the sector. Different financing structures 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 evolution 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 Helps Offset Rising Turbine Costs,” Windpower Monthly, May 2007, pp. 58-62. 

48
advantage of market conditions. By de-linking financings from project deadlines and by 

providing more corporate support in the financings, larger developers will foster new or 

differentiated financing structures and also put pressure on capital 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 wind power technology and markets is enabling some transactions 

to be able to handle risks previously considered unfinanceable, i.e., risks that lenders and Tax 

Investors historically required project developers to absorb. Earlier in the decade, lenders and 

Tax Investors only financed wind projects with long-term PPAs with stipulated prices in place. 

This was based on the belief that variances in both production (to be expected 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 uncertainty in the level of cash flow available to service the debt. 

Additionally, many banks had suffered huge losses in having financed conventional power 

projects without such contracts (known as merchant plants), and 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 and Tax Investors have become 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 providers 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 Texas and New York in the next year; developers and bankers also are 

exploring if such hedge contracts are feasible in financing wind 

Separately, lenders and Tax Investors are becoming more willing to finance projects using new 

wind turbine technology from companies such as Suzlon Energy Limited and Clipper 

Windpower. Their willingness stems in part from the increased supply of lenders and Tax 

Investors relative to available 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 highly-negotiated incremental support offered by the 

developer and the turbine manufacturer to mitigate perceived incremental risks. 

Investor-owned utilities also are showing renewed interest in acquiring wind projects outright to 

add to their internal generating portfolio. This differs from unregulated developer subsidiaries of 

utilities (such as FPL Energy) buying projects where the power is sold to other utilities. Such 

direct acquisitions to a utility’s internal generation portfolio can p

compared with entering into long-term power purchase agreements with stand-alone projectspecific entities. The Tax Benefits of ownership of wind projects are attractive to utilities 

enjoying profitability, and therefore with enough tax liability to benefit from the Tax Benefits of 

wind projects. The effective price of power may also be somewhat lower, to the extent that the 

utilities are able to fund project costs with lower-cost corporate funds than can be accessed by 

purchasing projects, the use 

49
structures will be unnecessary. Direct ownership also obviates increasing pressure by credit 

rating agencies to treat long-term power purchase agreements as forms of contingent 

indebtedness, and provides utilities a direct return on their rate base. 

At the same time, expanding interest in direct ownership by publicly owned (e.g., municipal and 

cooperative) utilities is fostering development of different financing structures. For example, 

ur cooperatives and public utility districts in Washington 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 Benefits because of their tax-exempt status. They 

devised a financing structure that 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 financial 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 entities becoming increasingly 

comfortable with wind power technology to be willing to make such pre-payments. 

Publicly owned utilities and cooperatives separately are beginning to tap a new tax credit bond 

financing program known as Clean Renewable 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 first 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 limited. The IRS, which administers the program, 

currently allocates CREBs mostly to small projects. Congress is considering 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 Federal 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 period 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 longer-term PTC extension may lead Tax 

Investors not currently participating in the wind sector due to the temporary nature of the PTC to 

commence financing projects. Separately, some investment bankers are attem

fi

hitherto reluctant Tax Investors by fine-tuning their projected exposure to project 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 risks if they are to be 

allocated the Tax Benefits. 

On the other hand, if the PTC framework is not renewed or is changed substantively to limit its 

cost to the Treasury, wind power financing structures designed to attract Tax Investors may no 

longer be attractive absent changes in the structures 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. industry, as the current structures developed 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 existing 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 financings are being stimulated by the increasing pace 

of development. Several investment banking firms have established or are developing pools or 

funds of institutional investor capital to invest in projects. Funds being set up by financial 

institutions vary in targeting new projects, refinancing existing projects, or some combination of 

the two. The funds variously amass capital from multiple smaller Tax Investors or else target 

Cash Investors. Babcock & Brown Wind Partners 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 foreign developers able to fund capital costs, but 

lacking the requisite tax appetite, likely will spur additional future portfolio refinancings. Such 

refinancings and poolings of projects may increase the use of the PAYGO financing

le

Each of these various trends and influences will affect how future wind power projects are 

financed in the United States. It will be useful for the DOE to monitor these developments, and 

their actual impacts on wind financing structures, as part of its ongoing review of the cost of 

energy from wind power. 

 

54 See http://www.bbwindpartners.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 Quarter Market Report.” AWEA press release, 

May 10, 2007. Available at 

www.awea.org/newsroom/releases/AWEA_First_Quarter_Market_Report_2007.html

______. 2007b. “Wind Power Capacity in U.S. Increased 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 Join 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/Energy_Dept_Wind_Industry_Action_Plan_060506.html 

______. 2000. “After Blowout Year in 1999, Wind Energy Looks to Even Brighter Future in 

U.S. Market.” AWEA press release, April 30, 2000. Available at 

http://www.awea.org/news/news000430w2k.html. 

Babcock & Brown Wind Partners. 2007. “BBW Investor Pack 2007.” Available at 

www.bbwindpartners.com. 

Bailey, Diane. 2007. “Cheaper Finance Helps Offset Rising Turbine Costs. Windpower Monthly, 

May 2007, pp. 58-62. 

Bolinger, Mark, Ryan Wiser, Tom 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/wind/OR_Community_Wind_Report.pdf. 

Chadbourne & Parke, LLP. 2007. “The Tax Equity Market” in the April 2007 edition of Project 

Finance Newswire. Chadbourne & Parke, LLP, April 2007, pp. 1-12. 

Chester, Jeff. 2007. “Wind Power Market Overview 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 Project 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 Wind Project webpage. Available at http://www.energynorthwest.com/generation/nine_canyon.php. 

52
Feo, Ed. 2004. “The Equity Market for Wind Projects.” Presentation at AWEA’s Wind Power 

Fitch Ratings. 2005. Press release, “Fitch Expe

Finance & Investment Workshop, September 28-29, 2004. 

cts to Rate FPL National 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 for Tax Equity Investments in Wind 

Projects, June 2006 presentation at AWEA’s Wind Power 2006 conference in Pittsburgh, 

Me

ur ind Finance Company Portfolio Financing Transaction.” 

Pennsylvania. 

M phy, James. 2005. “Invenergy W

Invenergy, LLC, presentation at Renewable 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 2011 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/presentations/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
Appendix 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 large banks and insurance companies. 

IRR: Internal Rate of Return – In technical terms, the IRR is the 

discount rate that sets the net present value of an investment equal 

to zero. Wind project financings are often structured to enable 

investors to reach a target IRR at a set point in time (i.e., at the Flip 

Point). 

AWEA: 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 – The 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 

Developer: Sometimes referred to as the project sponsor, this is the entity that 

initiates and develops the wind project, and may wish to participat

in the ongoing ownership of the pr

financing structures described in

DOE: United States Department of Energy 

D CR:

lenders to ensure that a project will generate sufficient cash flows

to service its debt, i.e., to meet principal 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. 

F Point: The point at which the Tax Investor has received a negotiated 

after-tax IRR on its investment. The Flip Point is typically 

structured to occur at the tenth anniversary of the COD, 

which no further PTCs are generated 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 investment. 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 represents what banks charge each other 

for funds. LIBOR is a benchmark for a commercial bank lender’s 

cost of capital. Wind projects seeking debt financing from 

commercial banks are typically charged a basis point spread over 

the current LIBOR rate. In most cases, prior to closing, the 

LIBOR rate is swapped out to a fixed 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. 

M Modified Accelerated Cost Recovery System

which most wind power assets are 

under the U.S. tax code. As a general rule of thum

95% of a wind project’s installed cost can be depreciated using a 5-

year MACRS schedule. This accelerated tax depreciation (relative 

to the project’s expected 20- to 30-year life) creates tax losses in 

the early years of a project, which Tax Investors use to offset 

taxable income from other 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 production of one MW for one hour. 

For example, 10 MW of capacity producing electricity for two 

hour yields 20 MWh. 

P The pay-as-you-go financing structure (described in detail in 

Section 3.4) 

Production Tax Credit – This Federal 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-serving entities must source a 

minimum percentage of their generation portfolio from eligible 

renewable resources. Half of a

55
requirements. Currently, there is no Federal RPS, although 

Congress has considered one on several occasions. 

REC: Renewable Energy Credit – A REC represents the attributes 

associated with one MWh of renewable power generation, and can 

Sponsor:

trategic Investor: An entity that invests in a wind 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 generation itself. RECs are often used 

as a tool to evidence compliance with RPS policies. 

The developer that initiates and develops the wind project, and 

may wish to participate in the ongoing ownership of the completed 

project through one of the financing structures described in this 

report. 

S

Benefits but also because the investment is in line with the entity’s 

primary business activities. An example 

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 depreciation) of the assets of the 

wind project. 

The equity invested in a wind project by Tax Investors.

T

Benefits; includes both Strategic and Institutional Investors. 

56
Appendix B: Descrip

ssumptions 

Overview 

To facilitate comparisons of t d in this study 

nd the impact of these structures 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 separate 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 flows 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 include the levels of detail typically included either in models used by 

developers considering whether to undertake a potential wind project or in the still-more-richly 

detailed models that form the basis for negotiating equity and debt financing from Tax Investors 

and lenders. Specifically, the model does not attempt to portray detailed tax partnership 

allocations derived from capital accounts (Appendix C provides a brief overview of key tax 

partnership matters). Though such detail is germane 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 common 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 paradigm for the majority of wind projects in 

the near future. As some of these market conditions are changing for very recent projects, 

tion of Pro Forma Financial Model and 

A

he mechanics of each of the seven structures 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 

et of key assumptions to define the template project. 

It

differences across the financing structures. 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 underlying platform from which the structures can be 

ther. Actual wind project financial models 

sp

aspects of the project, such as: capital costs, operations, depreciation, equity returns for the 

rd-party investors, aggregate and partnership allocations of project 

inancing (if any is used), and sensitivity analyses, graphs, or charts. 

ancing negotia

m

models may add a summary spreadsheet to show key results for ready analysis. 

By contrast, the used for this report summarize many capital and 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 structures, financial returns, and the cost of energy for future 

projects. 

ptions as 

et assumptions relate to the terms for selling the project output. The most important 

 that the report’s template wind project is assumed to generate electricity for sale on a 

t. Chapter 5 

otes that a few wind projects currently being financed have relaxed this assumption, as evidence 

 of wind power 

rojects have often been content not to force negotiation of a distinct REC price, provided that 

off-taker 

bligations. 

he model’s base-case assumptions do not assume any inflation in the prices under the off-take 

Several mark

is

wholesale basis to a utility. The project’s energy sales are assumed 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 financing 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 all of the RECs generated by the project are sold 

under a long-term off-take agreement – perhaps the 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 the 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, developers 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 consolidated price. Thus, the important legal points of 

who owns the RECs (the project owner or the buyer of the electricity) and who holds the risk of 

determining current and future values are established contractually. Developers

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 and debt capital for the project 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 financial 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 credit 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-inflating price for such sales for the full term of 

the off-take agreement(s) is common, as it represents 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 factors to be used for the sales of electricity and 

RECs, so as to enable alternative pricing scenarios 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 contractors for the construction and operation 

of the project. An important factor for many financial institutions in the wind sector is a belief 

at technology risks are modest and properly and effectively allocated to parties willing and able 

se, i.e., the effective cost 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. Measuring 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 disproportionate allocations of cash 

th

to handle such risks. In exchange, 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 being 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 operation prior to January 1, 2009. For purposes of 

this report, the model assumes that the template 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 investors 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. While it is possible for an owner 

to carry-forward unutilized portions 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-party 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 efficient 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 project itself. The underlying 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 account certain partnership accounting and allocation 

issues associated with wind projects. For example, the model does not show stop-loss 

reallocations, minimum gain charge-backs, or capital 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 relative to their r

c

59
and Tax Benefits may trigger income reallocations that, while mandated by IRS Code 

requirements, may be nonetheless out of proportion with the allocation percentages agreed 

between the partners. Such reallocations can materially affect the 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-specific 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 the 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 worksheets to compute the cost of energy for the 

template wind project using each of the seven financing 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 structure involving third-party capital, the model solves for the cost 

of energy that yields the specified required Tax Investor IRR at the end of ten years. A ten-year 

me frame is used because project developers and Tax Investors typically use it as a basis for 

plate wind project that are common to all 

f the financing structures. For each assumption, 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 Corporate structure, the model solves 

for the cost of energy that yields the specified required developer IRR at the 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 

PROJECT INFORMATION 

Year of Initial Commercial Operation 2008 The project becomes operational at the beginning of 2008. 

Project Capacity 100 MW Representative project size in 2008. 

Annual Net Capacity Factor 36.00% Average 2006 cap. factor for recent projects (Wiser and Bolinger 2007). 

Inflation Rate 2.00% Close to GDP price deflator projection in Annual Energy Outlook 2007.

Interest on Reserves 2.00% Set to be consistent with assumed inflation rate. 

CAPITAL COSTS ($000) 

Hard Costs 

Development Costs 5,000 

Wind Turbines 120,000 

Balance of Plant 25,000 

I

Roughly consistent with the range of recent project costs presented in 

nterconnection 10,000 

Wiser and Bolinger (2007) 

Soft Costs 

Interest During Construction (IDC) 

Interest Rate 6.70% Consistent with the rates for cash and PTC-based debt (see Table B3). 

Construction Period 12 months Estimate includes turbine delivery and actual project construction. 

C

(

onstruction Debt Closing Fee 

% of debt amount) 1.25% Estimate based on industry review. 

Soft Cost Totals ($000) 

Interest During Construction (IDC) Calculation Assumes 100% of costs outstanding for half the construction period. 

Equity Closing Costs 400 Based on industry review (legal fees & consultants; 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 based on industry review; the $ amount is calculated. 

ANNUAL OPERATING EXPENSES 

Operations & Maintenance (O&M) Costs 

Fixed O&M ($/kW-yr) 11.50 

Variable O&M ($/MWh) 6.00 

Aggregate fixed and variable O&M costs are consistent with those used 

in DOE/AWEA’s 20% Wind Vision Analysis.

PPA Letter of Credit (LOC) 

LOC Amount ($000) 5,000 Based on industry experience (this figure can vary widely) 

Annual 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 

2007 Inflation Adjustment Factor 1.3433 Page 14862 of the 2007 Federal Register (volume 72) 

2008 Inflation Adjustment Factor 1.3702 2007 inflation adjustment factor inflated by 2% assumed inflation 

2008 PTC Rate ($/MWh) 21.00 $15/MWh multiplied by 1.3702 and rounded to the nearest integer 

Years Available 10 Qualifying projects can currently claim the PTC for 10 years. 

TAXES

State 6.0% Representative state tax rate. 

Federal 35.0% Standard industry assumption for Federal corporate tax rate. 

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 debt 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 industry experience. Items labeled as “Indirect” 

are depreciated using the same schedules in the same proportions used 

for directly depreciable assets in aggregate. For example, if 90% of all 

directly depreciable costs or assets are depreciated using 5-year 

MACRS, then 90% of all “Indirect” costs will also be depreciated using 

5-year MACRS. 

These high-level allocations are meant to be representative; actual 

allocations are highly cost-item dependent. Specific advice from tax 

counsel and accounting firms is highly recommended. 

61
In several instances, the model draws upon basic project assumptions used in the 20% Wind 

oject being conduc ed jointly 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 model 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 financing scenario and consequently vary across the 

relating 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 depreciation 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 schedules (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 assumptions have a een vett ithin the wind industry, this report has used t

where appropriate ing diff assumptions. Although some of the Wind Vision

assumptions are sim O&M s are aggregated rather than broken out into 

individual cost 

ing struct

at this r rt’s focus is on comparing differe

financ in

simplification. s, the 

may be deem

General pro

production), capacity, and 

eant to be lity-sc ind projects currently being developed. The 36% 

capacity factor reflects t y-weighte erage 2006 capacity factor of a sample of utilityscale projects b .

60 Th acity factor is particularly 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 leaving them fla

61

ower

oted earlier, the authors h

 l

ed th enues are not inflated, i.e., that the power price is 

fixed at the outset under a p rc u rrangement. Thus, the inflation rate is only used

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 costs bt are n in Table B3). The hard and soft costs add 

together to generate a t cost. treatment of project costs for tax depreciation 

purposes is impo r retu s a general rule, roughly 90-95% of the project 

costs can irst ears of project life using the 5-year Modifie

Ac (5-ye ACRS). Depreciating such a large am

five

to offset income from o s. f the rem

is eith

year straight-li irectly a ted, or is non-depreciable. The cost of items that 

ocated proportionally to the other categories, in 

depreciation 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 simplified 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.awea.org/newsro Energy_D 60 As presented in Wiser and Bolinger (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, property taxes, insurance, management fees, etc. 

The model does have line items for each of these detailed cost items in the event that a future 

user desires to break out 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 certain financing assumptions specific to each 

particular structure. These relate to two aspects: (i) the cost of financing provided under each 

ructure, and (ii) where applicable, the allocations 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 factors influence the IRR 

uctures 

ave become better defined, the number of Tax Investors 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 equity investing in the project. 

The costs of debt and equity financing are expressed in different ways. The cost of financing 

from Tax Investors typically is negotiated in terms 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 typically also consider the developer’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 the relative risk associated with the project. In general, the 

higher the perceived risk of the project, the higher the required IRR, 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 and 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 the 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 returns. 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. Similarly, a wind project with most 

benefits occurring later in the project life is considered 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 lever 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. Developers of solid wind projects currently are able 

to solicit third-party equity capital from multiple sources. With the supply of capital currently 

and, along with other factors, this has contributed to a broad decline in Tax Inves

for wind projects in recent years. Other contributing factors are noted in Chapter 2. 

63
64

ions between each partner. For example, for a 

eriod of time all of the cash could go to the developer 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 investments, the developer and 

rospective Tax Investor will negotiate the level of the IRR required by the latter. Therefore, to 

 and allocations should 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 allocation of the cash and Tax 

Benefits to the project developer and the Tax Investors. It is important to note that the cash and 

Tax Benefits can be allocated in varying proport

p

the Tax Investor. Chapter 3 of the repo

a

These allocations can vary both in terms of percentage amounts and 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 financing structure. Chapter 3 describes these influences and impacts for 

each of the financing structures. For actual wind projec

p

facilitate comparison of the effective cost of energy across the various financing structures, the 

report assumes an IRR target value and target date for the cost of Tax Investor capital for each 

structure. The cost of energy is the price that yields the required Tax Investor return. 

Due to the differential allocations in amounts 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 develop a single weighted-average of the IRRs for the different 

investors, the report does not use this approach for the structures accessing third-party capital, as 

such averages are not used in actual practice and thus are not readily comparable to market 

conditions. Instead, the authors assume an IRR required by a Tax Investor and percentage 

allocations of cash and Tax Benefits under each financing structure. The model determines the 

required price of power to achieve the stipulated 10-year IRR for the Tax Investor, and then 

calculates the resulting IRR for the project and 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 assumptions that are specific to each structure. 

For those structures involving more than one investor (i.e., with equity capital from a Tax 

Investor as well as the project developer), the table shows the percentage allocations of the initial 

equity contributions, cash returns, and Tax Benefits 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 Investor 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 

PARTNERSHIP ALLOCATIONS 

Equity Contributions 

Corporate 100% N/A Constructed on the balance sheet 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, developer equity typically ranges from 20% to 

Pay-As-You-Go 45% 55% Developer equity typically ranges from 40% to 60% of total capital. 

Cash Allocations 

Pre-Flip Cash 

Corporate 100% N/A This structure involves 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 the cash until it earns a return of its capitafter which the pre-flip allocations reflect those shown here. 

al, 

Pay-As-You-Go 30% 70% Developer receives substantial cash to reflect its high equity investment. 

Post-Flip Cash 

Corporate 100% N/A This structure involves 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 rule 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 

Tax Benefit Allocations 

Pre-Flip Tax 

Corporate 100% N/A This structure involves 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 involves 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 rule 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 Corporate 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 use 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 outside 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 development/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 only at the developer (not project) 

level, from the Tax Investor’s perspective, this structure is unlevered. 

Cash 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 financing structures. The rationales for the allocation differences 

 Chapter 3 e values them

ter 4. 

g structures have projectee loan meters e th

wind project: the interes , the

tor typically quote interest rates as spread over LIBOR. Institutional lenders such 

e companies instead ote ost debt 

discussions are LIBOR-based. Lenders typically require borrowers rest rate 

risk, which usually means swapping th ting

of the loan. Hedging costs to fix the interest 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-principal amortization schedules. The loans are 

n a limited recourse basis, 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 outlined 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 selves are indicative of recent market levels, as 

discussed in Chap

Two of the financin

el. Thr

level debt, while one has debt at the developer 

company lev para hav e most effect in determining the size and cost of 

the loan for a t rate loan term, and the DSCR. Commercial banks in 

the wind sec a

as c insuran may qu spreads 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 rating 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 

terns) to customize a loan amount and repayment 

les typically allow wind projects to 

els (which may vary

debt than would

provided o lenders look principally to the project-re

and urity for the loan (the PTC loan also 

ludes a limite fro ax In tor). 

ble B3 outlines the s ic d sumptions used by the model for those structures

orporating de

intended to illustra a H

cts, are they appropriate to utilize for pro

e risk profile of the specific project. These 

sumptions can be m d app riate by future users of the model. 

 64 The Federa

floating 3-mo

l Reserve Bank upd n a dai For

nth LIBOR rate to rates of term

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. The 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 “Cash & PTC Leveraged” Structures

Debt Closing Costs 400 Based on industry experience (legal fees, technical consultants). 

Total Debt Closing Fee Calculation industry practice. Specific dollar amount is calculated by the model. 

Assumes a fee equal to 1.25% of the loan amount, based on standard 

Debt Service Reserve Calculation Assumes an amount equal to 6 months of debt service obligations, based 

on standard industry practice. Specific $ amount calculated 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 nominal 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 debt financing used at the project-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 basis of the cash flow generated from the sale of the electricity 

and RECs from the project. These cash flows are the source of funds to repay the loan. PTC 

Debt refers to a loan facility supported by the guarantee of incremental periodic equity

contributions provided by the Tax Investor receiving the PTCs generated 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 which the lender is willing 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 ten-year period during which the PTC benefits are generated. In 

practice, some lenders to wind projects provide a single loan facility with a customized loan 

amortization that consolidates Cash Flow and PTC 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 developer company level, one step above 

he pro develope of debt to finance its equ stment in the project is 

onal I

the developer contributes a significant amount of up-front capital and receives 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

known as “back leveraging.” This report uses the Instituti nvestor Flip structure, in which 

ibutions until it d i vestment, as the basis for the Back Leveraged struct

fference in the LCOE between the Back Leveraged and 

tutional Flip structure e debt the former is at the developer level and therefore has no

68
Appendix C: Overview of Partnership Tax Accounting Issues 

Virtually all utility-scale wind projects involving 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 are 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 reported on the owners’ separate tax returns. 

Allocations of partnership income or losses for tax purposes can differ from distributions of cash 

to partners. Partnership tax rules generally allow 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 “substantial economic effect” as required under the IRS Tax Code. 

To meet the “substantial economic effect” requirement, the partnership must maintain capital 

accounts and must make liquidating distributions in accordance with positive capital account 

balances. In addition, the partnership agreement must contain either (i) a deficit capital account 

restoration obligation or (ii) a number of regulatory allocation provisions, such as “minimum 

gain chargeback” and “qualified income offset” provisions. These regulatory allocation 

provisions are generally designed 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 result, 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 the regulatory partnership allocations on partnership 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 distributions and tax allocations can 

violate these rules, absent special 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 require allocations of taxable income to eliminate a partner’s 

capital account deficit 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 should the loan ever go into 

default and the lender foreclose on the assets (such an allocation is known as a “minimum gain 

chargeback”). This gain represents, in essence, that partner’s savings from avoiding the 

repayment obligation of the loan. These requirements 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 has 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 potential 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 there is a reallocation of GIFES 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 tax attorneys agree on the specific manner in which PTCs can be 

specially allocated. Developers and investors should therefore consult their legal counsel and 

accountants for guidance. 

70