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1.1 GeGeneration
The Barbados Light & Power Company Limited 2012 Integrated Resource Plan February 28th 2014
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan i
REVISION HISTORY DATE VERSION COMMENTS
February 28th 2014 Rev. 2 Inclusion of Scenario 6 to reflect government
proposed waste-to energy plant. Revision of
retirement dates and earliest installation date of
reciprocating capacity. Adjustment of heat rate
modeling setting in Plexos.
November15th 2013 Rev. 1 Revisions following review by Fair Trading
Commission and PPA Energy
March 21st 2013 Rev. 0 First Issue
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan ii
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan iii
2012 Integrated Resource Plan Final Report
Table of Contents
VOLUME I
1.1 GeGeneration .................................................................................................................................................
TABLE OF CONTENTS ......................................................................................................................... III
LIST OF TABLES ................................................................................................................................. VI
LIST OF FIGURES ............................................................................................................................ VIII
LIST OF ACRONYMS ......................................................................................................................... IX
1 EXECUTIVE SUMMARY ................................................................................................. 13
1.1 Background......................................................................................................................................... 13
1.2 Integrated Resource Planning ......................................................................................................... 13
1.3 Sustainable Energy Framework for Barbados .............................................................................. 15
1.4 Recommendation ............................................................................................................................... 15
1.5 Structure of Report ............................................................................................................................ 19
2 PLANNING PARAMETERS ....................................................................................... 21
2.1 Study Horizon and Reference Year................................................................................................. 21
2.2 Economic Assumptions ................................................................................................................... 21 2.2.1 Discount Rate ......................................................................................................................................... 21 2.2.2 Cost Estimates ....................................................................................................................................... 21 2.2.3 Capital Cost Estimates .......................................................................................................................... 22 2.2.4 Taxes & Duties ....................................................................................................................................... 22 2.2.5 Currency & Exchange Rates ................................................................................................................ 22 2.2.6 Economic Growth ................................................................................................................................... 22
2.3 Demand Forecast ............................................................................................................................... 23
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan iv
2.3.1 Electricity Prices Variability .................................................................................................................. 24 2.3.2 Weather Variability ................................................................................................................................. 27 2.3.3 Economic Variability .............................................................................................................................. 28 2.3.4 System Load Forecast .......................................................................................................................... 30 2.3.5 System Peak Forecast .......................................................................................................................... 31 2.3.6 Demand Side Management .................................................................................................................. 32 2.3.7 Renewable Energy Rider ...................................................................................................................... 34
2.4 Fuel Price Forecasts .......................................................................................................................... 35 2.4.1 Liquid Fuel .............................................................................................................................................. 36 2.4.2 Natural Gas ............................................................................................................................................. 42 2.4.3 Biomass ................................................................................................................................................... 46 2.4.4 Landfill Gas ............................................................................................................................................. 50 2.4.5 Calorific Values ...................................................................................................................................... 50
2.5 System Criteria ................................................................................................................................... 50 2.5.1 System Reliability ................................................................................................................................... 50 2.5.2 System Stability ...................................................................................................................................... 58
3 GENERATING TECHNOLOGIES ............................................................................. 66
3.1 Existing Plant ...................................................................................................................................... 66 3.1.1 Spring Garden Generating Station ...................................................................................................... 66 3.1.2 Seawell Generating Station .................................................................................................................. 66 3.1.3 Garrison Hill Generating Station .......................................................................................................... 67 3.1.4 Cost and Performance Parameters ..................................................................................................... 67
3.2 Candidate Plant .................................................................................................................................. 70 3.2.1 General Requirements .......................................................................................................................... 70 3.2.2 Conventional Candidate Plant ............................................................................................................. 71 3.2.3 Renewable Energy Technologies ........................................................................................................ 77 3.2.4 RE Technology Assumptions ............................................................................................................... 89 3.2.5 Environmental Criteria ........................................................................................................................... 93
3.3 Levelized Costs .................................................................................................................................. 94
4 MODELING METHODOLOGY................................................................................... 97
4.1 Worlds and Scenarios ....................................................................................................................... 97
4.2 Sensitivities......................................................................................................................................... 99
4.3 Software Model ................................................................................................................................. 100
5 RESULTS ...................................................................................................................... 101
5.1 Expansion Plans .............................................................................................................................. 101 5.1.1 Base Demand World ........................................................................................................................... 102 5.1.2 High Demand World ............................................................................................................................ 108
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan v
5.1.3 Low Demand World ............................................................................................................................. 109
5.2 Sensitivities....................................................................................................................................... 110
5.3 Analysis ............................................................................................................................................. 111 5.3.1 Natural Gas Availability & Interruption Risk ..................................................................................... 112 5.3.2 Biomass Availability & Risks .............................................................................................................. 116 5.3.3 Renewable Energy Policy Indicative Target .................................................................................... 117 5.3.4 Proposed Waste to Energy Facility ................................................................................................... 117 5.3.5 Other Policy Considerations ............................................................................................................... 120
5.4 Recommendation ............................................................................................................................. 122
5.5 Avoided Generating Costs ............................................................................................................. 123
6 SUMMARY AND CONCLUSION ........................................................................... 127
6.1 Sustainable Energy Framework for Barbados ............................................................................ 128
6.2 Recommendation ............................................................................................................................. 129
7 REFERENCES ............................................................................................................. 134
VOLUME II
APPENDICES
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan vi
List of Tables
Table 1: Scenario 6: Least-cost Integrated Resource Plan ............................................................ 17 Table 2: Fuel Price Escalation (2012-2036) ................................................................................. 25 Table 3: Electricity Price Growth Scenarios ................................................................................. 27 Table 4: Temperature Scenarios ................................................................................................... 28
Table 5: Economic Growth Scenarios .......................................................................................... 29 Table 6: System Load Growth ...................................................................................................... 31 Table 7: System Peak Demand Growth ........................................................................................ 32 Table 8: SEFB Energy Efficiency Initiatives ................................................................................ 34 Table 9: Renewable Energy Rider Historical and Projected Capacity ......................................... 35
Table 10: Fuel Price Projections for Reference Fuel Price Scenario (2012 $) ............................. 40
Table 11: Liquid Fuel Price Forecast Scenarios (2012 $)............................................................. 41
Table 12: Natural Gas price Forecast Scenarios without Fixed Costs (2012 $) ........................... 45 Table 13: Local Biomass Price Forecast Scenarios (2012 $) ....................................................... 47
Table 14: Imported Biomass Price Forecast Scenarios (2012 $) .................................................. 49 Table 15: Calorific Values Used In Study .................................................................................... 50
Table 16: Generation Reliability Standards in Select Countries .................................................. 53 Table 17: Cost/Benefit Analysis of Generation Reliability .......................................................... 55 Table 18: Comparison of impact of upper limit on reserve margin .............................................. 58
Table 19: Intermittent RE Penetration Levels on Other Island Grids ........................................... 64 Table 20: Cost & Performance Parameters for Existing Plant ..................................................... 68
Table 21: Financial & Performance Data for Liquid Fuel Candidate Plant ................................. 76 Table 22: Financial &Performance Data for Natural Gas Candidate Plant .................................. 76
Table 23: Overview of Renewable Technology Characteristics................................................... 77 Table 24: Cost & Technical Characteristics of Battery Storage Options (Source: BEW
Engineering, 2012) ........................................................................................................................ 86
Table 25: Battery Cost Estimates (Source: BEW Engineering, 2012) ......................................... 87 Table 26: Summary of RE Technologies Included In Study ........................................................ 90
Table 27: RE Technologies Excluded From IRP Study ............................................................... 91
Table 28: RE Technology Assumptions ....................................................................................... 92 Table 29: Environmental Impact Assumptions............................................................................. 94
Table 30: Scenario Matrix of Fuels & Technologies .................................................................... 99 Table 31: NPV Results for Worlds and Scenarios ...................................................................... 101 Table 32: Characteristics of Least-Cost Plans ............................................................................ 102
Table 33: Build Schedule for Liquid + RE Scenario in Base Demand World ........................... 103 Table 34: Build Schedule for Liquid + NatGas + RE Scenario in Base Demand World ........... 104
Table 35: Build Schedule for Liquid + NatGas Restricted + RE Scenario in Base Demand World
..................................................................................................................................................... 105 Table 36: Build Schedule for Liquid + NatGas Restricted + RE Forced Scenario in Base Demand
World .......................................................................................................................................... 106 Table 37: Build Schedule for Liquid + RE Forced Scenario in Base World .............................. 107
Table 38: Waste-to-Energy (Plasma Arc) Assumptions ............................................................. 118 Table 39: Build Schedule for Liquid + WtE Forced Scenario in Base World ............................ 119
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan vii
Table 40: NPV Results for the Six Scenarios ............................................................................. 120 Table 41: Characteristics of Least-Cost Plans ............................................................................ 122 Table 42: Build Schedule for Recommended Plan in Base Demand world ............................... 123 Table 43: Avoided Cost of Renewable Technologies ................................................................. 126
Table 44: Scenario Matrix of Fuels & Technologies .................................................................. 129 Table 45: Scenario 6: Least-cost Integrated Resource Plan........................................................ 130
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan viii
List of Figures
Figure 1: Forecasted Electricity Prices ......................................................................................... 26 Figure 2: Total Demand ................................................................................................................ 30 Figure 3: Forecast System Load ................................................................................................... 31
Figure 4: Forecast System Load under DSM ................................................................................ 33 Figure 5: Average Absolute Difference between the Forecast and Actual Projection Based On
AEO 1993 To 2010 Projections .................................................................................................... 37 Figure 6: AEO 2012 Low Sulphur Crude Oil Projections (2012 US$) ........................................ 38 Figure 7: Historical & Projected Fuel Prices - Reference Case (2012 $) ..................................... 40
Figure 8: World LNG Estimated November 2013 Landed Prices in US$/mm Btu (Source:
Waterborne Energy Inc. Data, October 2013) .............................................................................. 43 Figure 9: Natural Gas Price Forecast without Fixed Costs (2012 $) ............................................ 45
Figure 10: Local Biomass Price Forecast (2012 $) ....................................................................... 47 Figure 11: Imported Biomass Price Forecast (2012 $) ................................................................. 49 Figure 12: Marginal & Total Costs vs. Reserve Margin ............................................................... 56
Figure 13: Reserve Margin for Recommended Plan..................................................................... 56 Figure 14: Comparison of Typical Daily Electricity Demand and Solar PV Output ................... 61 Figure 15: Levelized Costs Based On Base Assumptions ............................................................ 96
Figure 16: NPV Sensitivities on Optimal Plans for each Scenario ............................................. 111 Figure 17: Proportion of Installed Generating Technologies in scenarios 1, 2 & 3 ................... 113
Figure 18: Impact of Delayed in Natural Gas Availability on NPV ........................................... 114 Figure 19: Impact of Delayed Natural Gas Availability on Total Generation Cost ................... 114 Figure 20: Impact of 1-Year Gas Interruption in 2018 on Fuel Cost .......................................... 115
Figure 21: Generation by Energy Source for Recommended Plan ............................................. 131
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan ix
LIST OF ACRONYMS
ACRONYM ACRONYM MEANING
AC Alternating Current
AD Anaerobic Digestion
AOE Annual Energy Outlook
BDS$ Barbadian Dollars
BL&P The Barbados Light & Power Company Limited
CCGT Combined Cycle Gas Turbine
CNG Compressed Natural Gas
CO2 Carbon Dioxide
COUE Cost of Unserved Energy
CSP Concentrating Solar Power
CUM PV Cumulative Present Value
DC Direct Current
DG Distributed Generation
DI Diversity Index
DSM Demand Side Management
ECA External cost Analysis
EIA US Energy Information Administration
EV Electric Vehicle
FCA Fuel Clause Adjustment
FoR Forced Outage Rate
FTC Fair Trading Commission
GDP Gross Domestic Product
GoB Government of Barbados
GoTT Government of Trinidad and Tobago
GWh Gigawatt-hour(s)
HECO Hawaiian Electric Company
HELCO Hawaii Electric Light Company
HFO Heavy Fuel Oil
HVDC High Voltage Direct Current
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan x
IDB International Development Bank
IMF International Monetary Fund
IPPs Independent Power Producers
IRP Integrated Resource Plan
ISO International Organization for Standardization
kV Kilovolt(s)
kW Kilowatt(s)
kWh Kilowatt-hour(s)
LOLE Loss of Load Expectation
LOLP Loss of Load Probability
LF Liquid Fuels, i.e. heavy fuel oil, diesel & Jet A1
LHV Lower Heating Value
LNG Liquefied Natural Gas
LSD Low Speed Diesel
MAUT Multi-Attribute Utility Theory
MECO Maui Electric Company
mmBtu Million British Thermal Unit
mmscf/day Million Standard Cubic Feet Per Day
MSD Medium Speed Diesel
MSW Municipal Solid Waste
MW Megawatt(s)
MWh Megawatt-hour(s)
NG/NatGas Natural Gas
NGr Natural Gas Restricted
NPV Net Present Value
NSEP National Sustainable Energy Policy
OCGT Open Cycle Gas Turbine
O&M Operations & Maintenance
OTEC Ocean Thermal Energy Conversion
PV Photovoltaic
RE Renewable Energy
REf Renewable Energy Forced
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan xi
SEFB Sustainable Energy Framework for Barbados Report
STEO Short Term Energy Outlook
T&D Transmission & Distribution
US$ United States Dollars
U.S. DOE United States Department of Energy
WACC Weighted Average Cost of Capital
WtE Waste to Energy
WTG Wind Turbine Generator
Existing Generating Units
CG01 1.5 MW Co-generating unit connected to units D10-D13
CG02 2.2 MW Co-generating unit connected to units D14 & D15
D10 12.5 MW Low Speed Diesel Generator
D11 12.5 MW Low Speed Diesel Generator
D12 12.5 MW Low Speed Diesel Generator
D13 12.5 MW Low Speed Diesel Generator
D14 29.7 MW Low Speed Diesel Generator
D15 29.7 MW Low Speed Diesel Generator
GT02 13 MW Gas Turbine Generator
GT03 13 MW Gas Turbine Generator
GT04 20 MW Gas Turbine Generator
GT05 20 MW Gas Turbine Generator
GT06 20 MW Gas Turbine Generator
S1 20 MW Steam Turbine Generator
S2 20 MW Steam Turbine Generator
Candidate Generating Technologies
Ana. Digestion Anaerobic Digester Unit
CCGT30 30MW Liquid-fueled Combined Cycle Gas Turbine
CCGT40 40MW Liquid-fueled Combined Cycle Gas Turbine
GT20 20MW Liquid-fueled Gas Turbine
GT30 30MW Liquid-fueled Gas Turbine
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan xii
GT40 40MW Liquid-fueled Gas Turbine
Biomass Biomass Generating Unit
Imp Biomass Imported Biomass Fuel
L/fill Gas Landfill gas-to-energy
LSD17 17MW Low Speed Diesel Generator
LSD30 30MW Low Speed Diesel Generator
LSD38 38MW Low Speed Diesel Generator
MSD17 17MW Medium Speed Diesel Generator
NG-LSD17 17MW Natural gas dual-fuel LSD Generator
NG-LSD30 30MW Natural gas dual-fuel LSD Generator
NG-LSD38 38MW Natural gas dual-fuel LSD Generator
NG-MSD17 17MW Natural gas dual-fuel MSD Generator
NG-CCGT30 30MW Natural gas fired CCGT
NG-CCGT40 40MW Natural gas fired CCGT
NG-GT20 20MW Natural gas fired GT
NG-GT30 30MW Natural gas fired GT
NG-GT40 40MW Natural gas fired GT
Solar Solar Photovoltaic unit
WTE, WtE Waste to Energy
Wind Wind generator
Wind w/storage Wind generator with 10% battery storage
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 13
1 EXECUTIVE SUMMARY
1.1 Background
The Barbados Light & Power Company Limited (BL&P) is an investor owned,
vertically integrated electric utility with a nonexclusive franchise1 for the generation,
transmission and distribution of electricity on the island of Barbados.
BL&P serves approximately 124,000 customers covering an area of 430 square
kilometres. The Company’s electricity generating portfolio consists of 239.1MW of
generating capacity made up of steam (40.0MW), low speed diesel (113.1MW) and
gas turbines (86.0MW) at three generating stations. The base load steam and low
speed diesel units operate on heavy fuel oil (HFO) and the gas turbines operate on
diesel and Jet A1. The transmission and distribution (T&D) network consists of
approximately 116 km of transmission lines operated at voltages of 24kV and 69kV,
and 2800 km of distribution lines at 11kV.
Approximately 104.5MW of existing generating capacity is scheduled for retirement
over the next ten years and electricity demand is expected to grow by an average of
around 1.2% per year. New supply and demand resources will therefore be required
to maintain supply reliability. This report identifies a 25-year resource plan to meet
Barbados’ future electricity requirements at the lowest cost while maintaining
reliability and taking into account energy security and environmental impacts.
1.2 Integrated Resource Planning
System expansion planning at BL&P has traditionally focused on identifying the
least-cost generation expansion plan from a range of generating supply options.
Integrated Resource Planning (IRP) enhances this process by taking into
1 BL&P’s current franchise expires in 2028
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 14
consideration demand side resource options as well as additional evaluation criteria
such as energy security and environmental impact.
Risk and uncertainties associated with variables like fuel price and electricity
demand growth were addressed through sensitivity and scenario analyses.
The study was conducted in accordance with IRP best practices2 and provides a
roadmap, outlining the options to be used in meeting future electricity demands in a
cost effective manner and in compliance with regulatory requirements. A
transparent and participatory approach was employed throughout the process. The
recommendations have been informed by broad consultations with stakeholders who
participated in the process by reviewing assumptions and preliminary results and
providing input into the planning decision.
The IRP was developed using models that incorporate the best information at the
time of planning and will be updated periodically or as conditions change materially.
The IRP is not an application for a review of rates or an investment plan, nor is it a
prohibition against specific third-party initiatives.
Technologies which are not technically or commercially viable and Transmission and
Distribution (T&D) expansion requirements have been excluded from the scope of
the IRP.
The Terms of Reference for the IRP is provided in Appendix A.
2 Best Practices Guide: Integrated Resource Planning For Electricity – The Tellus Institute
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 15
1.3 Sustainable Energy Framework for Barbados
In July 2010, the Government of Barbados (GoB) completed a study titled
‘Sustainable Energy Framework for Barbados’ (SEFB). The objective of the study,
which was conducted by Castalia Strategic Advisors and financed by the IDB, was to
identify viable investments in renewables and energy efficiency to reduce Barbados’
dependency on fossil fuels and thus reduce energy costs, improve energy security
and enhance environmental sustainability. These objectives were also captured in a
draft National Sustainable Energy Policy (NSEP) issued by the Government of
Barbados in March 2012.
Both the SEFB report and the draft NSEP identified indicative targets for renewable
energy (RE) and energy efficiency (EE) of 29% and 22% respectively by 2029.
BL&P’s recommended plan, described in section 1.4, achieves RE levels of 20.8%
by 2029 for the base demand forecast world. To achieve 29% RE by 2029 will
increase the NPV of the plan by 1%. The potential impact of EE measures are
accounted for in the low demand forecast world, which allows for up to 28.3%
reductions through EE by 2029.
Also arising out of the SEFB report were recommendations relating to legislative and
regulatory changes aimed at promoting the development of viable renewable energy
and energy efficiency resources. At the time of writing, the draft energy policy and
legislative changes were under review but not yet finalized by the GoB. However,
the IRP study takes the proposed changes into account and follows a methodology
which is consistent with the recommendations of the SEFB report.
1.4 Recommendation
To assess the risks and uncertainties associated with external market conditions, the
IRP study examined five scenarios representing plausible future paths relating to
fuel types and technologies used. Each of these scenarios was evaluated using
three possible electricity demand growth ‘worlds’, resulting in a total of fifteen plans
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 16
being initially evaluated. Sensitivities for changes in capital costs, fuel costs and
discount rates were also conducted on each of the fifteen plans. A sixth scenario
was also modeled in light of Government’s stated plan to commission up to 60 MW
of waste-to-energy generating capacity.
The least cost plan identified in the IRP is based on a natural gas expansion
scenario. Natural gas is however not yet available in sufficient quantities on the
island for power generation. Development work on the importation of natural gas is
in progress, but there is uncertainty as to when gas will become available. It is
therefore recommended that new generating capacity include reciprocating engines,
which have the capability of being converted to dual-fired gas operation when gas
becomes available. Further, given Government’s announcement on waste-to-energy
(WTE) as part of an integrated waste management strategy for the island, an
expansion plan that takes this development into consideration is recommended.
WTE is not selected in any of the initial five scenarios as it results in increased
electricity production costs, but the capacity announced by Government should be
factored into expansion plans to avoid potential generating overcapacity. Scenario 6
was therefore created to determine the least-cost expansion plan assuming that the
WTE is commissioned by Government in 2018.
The first ten years of the resulting least-cost plan for Scenario 6 are displayed in
Table 1 . The reciprocating units identified in this scenario should be designed to
allow for conversion to dual fired operation (HFO and natural gas) with minimum
time and effort when natural gas becomes available in the future.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 17
Year Demand
GWh
Supply-side Resources Demand-side Resources
Retire New Capacity
2012 981
2013 980
2014 979
2015 984
2016 993 L/fill Gas –1.5 MW
Solar – 8 MW
Wind – 2 MW
2017 1005 S1, S2 – 40 MW
GT02 – 13 MW
Reciprocating Engines – 47 MW
L/fill Gas –1.5 MW
2018 1018 Biomass –25 MW
Waste to Energy – 60 MW
Wind – 1 MW
2019 1036 D10, D11, D12,
D13 – 50 MW
WH01 – 1.5 MW
2020 1054
2021 1074 Wind – 1 MW
Table 1: Scenario 6: Least-cost Integrated Resource Plan
The model assumes that all plant retirements take place at 00:00hrs on January 1st
of the years identified in the table. In practice, an overlap of around six months may
be required between retired and replacement capacity to ensure a reliable transition
and allow any ‘teething’ problems with the new plant to be addressed.
The IRP recommendations are contingent on the following:
Acquiring land access for the development of wind energy and/or successful
negotiation of Power Purchase Agreements with Independent Power
Producers (IPPs) for wind energy.
Access to a secure supply of biomass, municipal solid waste and landfill gas
at the prices used in the IRP.
Future DSM
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 18
The generating capacity and timing of waste-to-energy and biomass is
achieved. If there are variations in the scope and timing of these projects, the
retirement schedule of existing units could be affected.
Extension of BL&P’s franchise which currently expires in 2028.
Compliance with legislative requirements.
The plan laid out in Table 1 provides a roadmap of expansion options to be used in
meeting future electricity demands cost effectively, given the constraints and
assumptions used in Scenario 6. Investment plans by the utility and potential
Independent Power Producers should be guided by the IRP, while taking into
consideration licensing, land availability and location specific development costs.
Two key issues were identified during the IRP process which will require additional
work:
As identified in the IRP Terms of Reference, Demand Side Management
(DSM) options evaluated in the IRP study were to be derived from the energy
efficiency recommendations made in the SEFB study conducted by the IDB
for the Government of Barbados. However, based on subsequent feedback
received from the consultants who conducted the SEFB study, the energy
efficiency measures were found to be insufficiently well defined for modeling
in the IRP. A DSM study will be completed in 2014 to identify specific DSM
measures for implementation. It is important to note however, that the short-
term expansion recommendations (2013 to 2018) remain unchanged in the
low demand forecast world and are therefore compatible with the indicative
EE targets identified in the SEFB. It should be noted that DSM could change
the forecasted system load factor. This will be evaluated in more detail in the
forthcoming DSM study and the IRP revised accordingly.
Based on a preliminary review of system impacts and practices in other island
grids, an intermittent Renewable Energy (RE) limit of 10% of peak demand
has been used in the study. An Intermittent RE Penetration study will be
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 19
completed in 2014 to further evaluate the issues associated with intermittent
RE and allowable limits.
1.5 Structure of Report
This report consists of six chapters. Chapter 1 is the Executive Summary which
presents the background and introduction to the report and gives some detail on the
integrated resource planning process. The chapter also highlights the Sustainable
Energy Framework for Barbados and presents the recommended plan based on the
results of the study. Finally, this chapter presents the structure of the report.
Chapter 2 details the planning parameters used in the study. The economic
assumptions are presented followed by the electricity demand forecast for the
planning period. Fuel assumptions are also critical to the study being undertaken.
These are presented in this chapter. Finally, this chapter presents the system criteria
assumptions used in the study.
Chapter 3 reviews the existing and candidate technologies used in the model. The
cost and performance characteristics of the existing plant are presented followed by
similar data on the conventional generating technologies used in the study. The
chapter also presents a review of RE technologies and their present state of
development. RE technologies excluded from the study are then identified, followed
by those included in the study along with their assumed cost and performance
characteristics. The environmental assumptions for the generating technologies
used in the study are also presented. The chapter concludes with the levelized cost
for technologies included in the study.
Chapter 4 outlines the modeling methodology used in conducting the study. The
worlds and scenarios used to model the options available are presented followed by
information on how sensitivity analyses on the results were conducted. The chapter
also presents information on the software model used in the study and the decision
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 20
criteria used to evaluate the optimal plans produced by the software model. Finally,
information is presented on the decision model and software used in conducting the
decision analysis.
Chapter 5 presents the results of the worlds and scenarios modeled. Results are
presented for the five scenarios in the base, high and low electricity demand
“worlds.” This chapter also presents the sensitivity results. The results of the
decision analysis model are also presented as well as the recommended plan. The
avoided cost for technologies included in the study is also presented in this chapter.
Chapter 6 presents the conclusion and recommendations.
Appendices are provided containing further background information on study
assumptions, detailed model results, stakeholder consultations and communications.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 21
2 PLANNING PARAMETERS
2.1 Study Horizon and Reference Year
The Integrated Resource Plan study period is 25 years, from the reference year
2012 up to and including 2036.
2.2 Economic Assumptions
2.2.1 Discount Rate
The discount rate is an important factor in determining the optimal expansion plan
due to the manner in which costs of the generation technologies are reflected in the
modeling. The discount rate used in developing the IRP is the weighted average
cost of capital (WACC) of 10% that was approved by the Fair Trading Commission
during the BL&P’s 2009 rate hearing. The real WACC of 7% was assumed for this
study and was derived using the Fisher Formula using a nominal WACC of 10% and
an expected inflation of 3%. The real discount rate of 7% was assumed for this study
and was derived using the Fisher Formula using the nominal discount rate of 10%
and an expected inflation of 3%. Sensitivity tests for the discount rate were
conducted at 5% and 9%.
All discounting was done to January 1st 2012 and all expenditures were assumed to
occur at the end of a calendar year.
2.2.2 Cost Estimates
The IRP uses real 2012 Barbados dollars (BDS$) over the period of the study, i.e.
inflation was not accounted for.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 22
2.2.3 Capital Cost Estimates
Overnight capital cost is the cost of construction provided that no interest was
incurred during construction (i.e. cost if the project was completed "overnight"). In
reality however, the construction of new generating plant cannot be completed
overnight. In this report, the capital cost assumptions for the candidate technologies
are reported as overnight cost in keeping with industry practices while interest during
construction is accounted for in the model. The interest during construction for each
technology is dependent on the technology build time.
2.2.4 Taxes & Duties
Local taxes and duties were not included in the model. These have not been
included as the rates for taxes and duties over the planning period are unknown and
could vary over time, therefore causing distortions to the true cost of the
technologies.
2.2.5 Currency & Exchange Rates
The United States dollar and the British pound were the main currencies for which
cost estimates were denominated. The exchange rate of US$1 to BDS$2 was used
as the conversion for the United Sates dollar, while a conversion of GB£1 to
BDS$3.50 was employed as the conversion rate for the British pound.
2.2.6 Economic Growth
The impact of the growth of Gross Domestic Product (GDP) on the demand for
electricity is well accepted. The IRP assumes an average annual GDP growth of
1.6% as its base case growth rate and low and high growth case scenarios of 1%
below and above the average growth of the base scenario. The growth assumptions
are discussed further in the Demand Forecast.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 23
2.3 Demand Forecast
The Integrated Resource Planning process requires the preparation of energy and
load demand forecasts for the planning period 2012 through to 2036 that represent
BL&P’s best estimate of the future demand for electricity within Barbados. Appendix
B –Demand and Load Forecast contains more detailed information regarding the
demand and load forecasts.
The base case annual average load forecast represents BL&P’s estimate of the
most probable outcome for load growth during the planning period and is based on
the most recent economic, demographic and weather forecasts for Barbados.
However, the actual path of future electricity demand is unlikely to follow the exact
path suggested by the base case load forecast. Therefore, two additional load
forecasts were prepared; these provide a range of possible load growths due to
economic uncertainty, electricity price changes and load variability associated with
abnormal weather. The high and low growth scenarios provide a range of possible
load growths over the planning period due to variable economic, demographic and
weather-related influences.
The demand and load demand forecast is created by developing a separate forecast
for each individual customer demand category. The major customer classes for
which demand forecasts are prepared include residential, small commercial, large
commercial & industrial and streetlights. These individual forecasts are aggregated
to provide a forecast of total demand. The total electricity demand forecast is
provided as billed and requires the addition of losses to convert this to a projection of
net system load. Loss factors are determined by BL&P’s System Planning and
Performance Department. The most recent five-year annual average energy loss
coefficient (6.8%) is multiplied by the aggregated demand forecast to derive system
load.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 24
The forecast utilized a number of economic, weather and demographic variables as
forecast drivers within its models. Historical series for the economic variables were,
for the most part, obtained from publications of the Central Bank of Barbados and
the Barbados Statistical Service. Historical series for average daily temperatures,
the primary weather variable utilized in the models, were obtained from the
Barbados Meteorological Department. To the author’s knowledge, there exists no
local agency that develops and publishes short-term or long-term forecasts for the
variables included in the models. Forecasted values for a number of other input
variables were either developed by BL&P from national census and economic data
or obtained from publications of the International Monetary Fund (IMF).
Economic growth assumptions and expectations of normal temperatures influence
most of the individual customer class demand growth rates. In addition to the
economic and weather assumptions used to drive the base case forecast scenario,
several specific assumptions were incorporated in the forecasts for the individual
customer classes. These included assumptions related to customer growth, the
growth in the population and electricity prices.
Over the 25-year planning horizon, there could be major changes in the electric
utility industry, such as the impact of Government’s Sustainable Energy Policy,
changes to the Electric Light & Power Act, the introduction of IPP’s, energy
efficiency programmes and the potential for much higher electricity prices impacting
future electricity demand. The high degree of uncertainty associated with these
changes and the variability of the main input drivers are assumed to be reflected in
the high and low case scenarios described below.
2.3.1 Electricity Prices Variability
Fuel prices, in combination with economic drivers, impact long-term trends in
electricity demand. Changes in relative fuel prices can also have significant impacts
on the price of and demand for electricity. The US Energy Information Administration
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 25
(EIA) provides a forecast of long-term changes in nominal and real fuel prices in its
Annual Energy Outlook (AEO). Projections of long-term fuel prices relevant to BL&P
were estimated from the EIA projections after exchange rates and delivery charges
adjustments. The projected annual growth rates for the weighted average nominal
and real price of fuel over the planning period are presented in Table 2.
Nominal *Real
Fuel Prices …………………………………………... 3.2% 1.2%
*adjusted for inflation
(Average annual percent change)
Table 2: Fuel Price Escalation (2012-2036)
The impact of fuel prices on electricity prices are transmitted through the Fuel
Clause Adjustment (FCA). The Fuel Clause Adjustment is a major component of the
cost of electricity to customers and accounts for over 200% of the base rate of both
commercial & industrial and residential customers in 2011. Regression models are
used to identify the relationships between historical fuel prices and historical
movements in the price of electricity. These models are employed to project the
expected growth in the residential and large commercial & industrial electricity prices
using the fuel price projections (base, high and low scenarios) published by the EIA.
The modeling of future electricity prices assumes that price changes will mainly be
reflected in variations in the price of fuel and the mix of generation plant employed to
meet future electricity demand. The reasonableness of the electricity price forecast
was confirmed by comparing the forecasted electricity prices for the planning period
with the indicative tariff profile of the recommended plan. The electricity price
forecast and the tariff profile were found to be, on average, within 0.3% of each
other.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 26
Figure 1: Forecasted Electricity Prices
Figure 1 illustrates the average electricity price paid by BL&P’s residential and large
commercial & industrial customers over the historical period 1986 to 2011 and over
the forecast period 2012 to 2036. Both nominal and real prices are shown. Nominal
electricity prices are expected to climb to over one dollar per kilowatt-hour (kWh) by
the end of the forecast period in 2036 from just over 62 cents per kilowatt hour in
2011 for residential customer class. The Large Commercial & Industrial price of
electricity is expected to rise from 64 cents per kilowatt-hour in 2011 to $1.14 per
kilowatt-hour at the end of the planning period. Real electricity prices (inflation
adjusted) for customers in the Residential and Commercial & Industrial customer
classes are expected to remain relatively unchanged by the end of the forecast
period. The base case scenario assumes that the average annual real growth in
electricity would be flat over the planning period. The high case annual price
increase is projected to average 0.7%, while a marginal average annual decline is
forecasted for the low case scenario (Table 3).
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 27
Scenarios
Real Average Growth Rate 2012-2036
Residential Large Industrial & Commercial
High Case …………………………………………...… 0.7% 0.7%
Base Case ………………………………………..….. 0.0% 0.0%
Low Case ……………………………………………… -0.6% -0.6%
Table 3: Electricity Price Growth Scenarios
The price of electricity and its elasticity are incorporated into the forecast models
because they measure the ratio between the demand for electricity and a change in
its price. A customer that is sensitive to price change has a relatively elastic demand
profile. Conversely, a customer that is unresponsive to price changes has a
relatively inelastic demand profile. Prior to 2008, BL&P’s customers displayed low
price sensitivity (-0.126 for residential and -0.069 for large commercial & industrial)
mainly due to infrequent base rate adjustments and relatively low volatility in the
Fuel Clause Adjustment. However subsequent to 2008, increased price sensitivity
has been observed in response to the electricity rate adjustment in 2010 and the rise
in the Fuel Clause Adjustment (-0.129 for residential and -0.111 for large commercial
& industrial).
2.3.2 Weather Variability
The future demand for electricity among BL&P’s customers is represented by three
load forecast scenarios reflecting a range of load uncertainty due to weather. The
base case load forecast assumes normal temperatures and a 50% chance that
loads will be higher or lower than the base case load due to cooler than average or
warmer than average temperatures. Since actual loads can vary significantly
depending on weather conditions, two alternative scenarios were considered that
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 28
address load variability due to temperatures within weather sensitive customer
classes (i.e., residential and large commercial & industrial classes).
Higher loads are expected when temperatures are at their highest levels, conversely
lower loads are anticipated when temperatures are at their lowest. Temperature data
obtained from the Government Metrological Department over the most recent thirty
(30) years indicates that average temperatures were 27 °C. The 90th percentile
temperature of 27.5°C represents the high case average temperature scenario and
indicates a probability of one out of ten years that this temperature would be
exceeded. The 10th percentile temperature indicates a probability of one in ten years
that the average annual temperature would fall below 26.5°C. In the high case
scenario for residential and large commercial & industrial load forecasts,
temperatures were assumed to be at the 90thpercentile of normal temperatures,
while the low case scenario assumes temperatures to be in the 10th percentile of
normal temperatures (Table 4).
Scenarios Temperature Probability
High Case (90th Percentile) 27.5 °C 1-in-10 years above
Base Case (normal temperature) 27.0°C 1-in-2 years
Low Case (10th Percentile) 26.5°C 1-in-10 years below
Table 4: Temperature Scenarios
There is some weather sensitivity within BL&P’s system load and these scenarios
allow an examination of load variability and how it may impact future resource
requirements.
2.3.3 Economic Variability
Electricity fuels a local economy that historically has been dependent on sugarcane
cultivation and related activities. However, in recent years the economy has
diversified into light industry and tourism with about three-quarters of GDP and 80%
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 29
of exports being attributed to services. The economy experienced significant growth
between 2003 and 2007 bolstered by increases in construction projects and tourism
related revenues. These sectors however registered declines at the end of 2008 with
the global economic downturn. After two years of negative growth, real GDP growth
in 2010 was a mere 0.2% and 0.5% in 2011. The economy registered no growth in
2012 as its main traded sectors were stagnant during the year.
Scenarios Average Growth
High Case …………………………………………...… 2.6%
Base Case ……………….…………………………… 1.6%
Low Case ……………………………………………… 0.6%
Table 5: Economic Growth Scenarios
Growth in electricity sales is influenced to a large extent by growth in output within
the general economy. In recent years, a high correlation has been observed
between GDP and the growth in electricity consumption, therefore periods of robust
future growth in the economy are expected to result in strong demand for electricity.
The base case load forecast is based on the most recent economic forecast for
Barbados and represents the most probable outcome for load growth during the
planning period. A forecast of economic growth for Barbados was obtained from the
Central Bank of Barbados up to 2018 and was estimated by BL&P thereafter based
on the historical distribution of growth rates. The real Gross Domestic Product
(GDP) of Barbados is projected to decline marginally by 0.7% at the end of 2013, but
is expected to grow steadily in the future to register an average annual growth of
1.6% over the planning period. The low and high growth case scenarios are 1%
below and above, respectively, the average annual growth of the base scenario
(Table 5). The distribution of GDP growth rates over the past twenty-five years
suggest that a narrow cone of ±1% growth is very realistic and appropriate over the
planning period.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 30
2.3.4 System Load Forecast
The system load forecast was developed by applying the five-year annual average
energy loss coefficient (details provided in Appendix C) to the total demand forecast
that was derived by aggregating the individual residential, small commercial, large
commercial& industrial and streetlights forecasts (Figure 2). Current system losses
are relatively low by regional and international standards and non-technical losses
on the system are negligible. No changes to the network that would significantly
impact system losses are anticipated over the planning period. The Company will
continue to judiciously manage system losses and believes that the current five-year
average of 6.8% is a reasonable assumption for the IRP model.
Figure 2: Total Demand
In the base case scenario, BL&P’s system load is forecasted to increase from 980
GWh in the year 2012 to 1,358 GWh in 2036 (Figure 3). In the base case, system
load growth is projected to average 1.2% per year over the 25 years of the planning
period (2012–2036). In the low case load scenario, the system load is forecasted to
reach 903 GWh at the end of the planning period, while the high case load forecast
scenario is projected to reach 1,986 GWh in the year 2036 (Table 6).
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 31
Figure 3: Forecast System Load
Scenarios (GWh) 2012 2020 2028 2036 Average Growth Rate 2012-2036
High Case…………………………... 981 1,233 1,570 1,986 3.0%
Base Case………………….………. 981 1,200 1,200 1,358 1.2%
Low Case…………………………… 981 864 870 903 -0.4%
Table 6: System Load Growth
2.3.5 System Peak Forecast
The system peak load forecast was prepared in conjunction with the load demand
forecast. In the past ten (10) years, BL&P’s system peak normally occurred in the
months of May and October when average daily temperatures were generally
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 32
highest. The peak demand forecast uses statistically derived peak day temperatures
based on the most recent thirty (30) years of average daily temperatures.
BL&P’s system peak load is expected to grow to 208.1 MW in 2036 from the 2011
actual system peak of 163.0 MW. The projected growth in system peak is
considerably higher than the highest system peak on record, 167.5 MW, registered
in 2010. In the base case scenario, BL&P’s system peak increases at an average
growth rate of 1.0% per year over the 25 years of the planning period (Table 7).
Table 7: System Peak Demand Growth
2.3.6 Demand Side Management
Demand Side Management (DSM) consists of policies and measures which serve to
modify the demand for electricity. The goal of DSM initiatives is usually to influence a
reduction in the amount of energy demanded by consumers through financial
incentives, education and/or availability of more energy efficient technologies. In July
2010, the Government of Barbados published its ‘Sustainable Energy Framework for
Barbados’ (SEFB) report which identified a number of energy efficiency options for
the country by 2029. The analysis contained in the SEFB report suggested that
energy efficiency initiatives could reduce the base case load growth scenario by
22% by 2029. The impact of DSM on the future demand for electricity is considered
within the IRP by applying the energy efficiency initiatives and targets outlined in the
SEFB to the IRP’s base case load forecast scenario.
Scenarios (MW) 2012 2020 2028 2036 Average Growth Rate 2012-2036
High Case…………………………... 156.7 195.8 242.8 300.0 2.5%
Base Case…………………..……... 156.7 167.2 186.7 208.1 1.0%
Low Case…………………………… 156.7 137.9 136.3 139.2 -0.6%
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 33
Figure 4: Forecast System Load under DSM
The energy efficiency initiatives outlined within the SEFB report are highlighted in
Table 8. Total system load after adjustments for DSM initiatives targeted within the
SEFB is expected to decline to 940.3GWh by the end of 2036. The average annual
growth in the demand for electricity over the forecast period when DSM targets are
taken into account is expected to be -0.3% over the planning period (Figure 4). The
demand forecast, taking into account the targeted DSM initiatives, exceeds the low
case average system load forecast of -0.4%. The impact of DSM initiatives over the
planning period can therefore be presumed to be reflected in the low system load
growth scenario. In addition to their impact on system load, it should be noted that
DSM initiatives could have an impact on the forecasted system load factor and that
this will be evaluated in more detail in the forthcoming DSM study and in subsequent
revisions to the IRP.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 34
• Lighting - Compact Fluorescent Lamps (CFLs) - T8 Fluorescent Lamps with Occupancy Sensor - T5 High Output Fluorescent Lamps - Street Lighting technologies (Magnetic Induction Street
Lighting, LED, and Solar LED) • Air Conditioning
- Efficient Window A/C Systems - Efficient Split A/C Systems
• Refrigeration - Efficient Residential Refrigerators - Efficient Retail Refrigerators
• Mechanical
- Premium Efficiency Motors - Variable Frequency Drives - Efficient Chillers
• Other efficient appliances
- LCD Computer Monitors - Power Monitors
Table 8: SEFB Energy Efficiency Initiatives
2.3.7 Renewable Energy Rider
In July 2010, BL&P introduced, on a pilot basis, a Renewable Energy Rider for
connection of distributed solar and wind generators. The pilot period ended in June
2012 at which time BL&P made recommendations to the regulator to make the Rider
permanent, with some modifications. In August 2013, the regulator approved the
Rider on a permanent basis with a review of the rate to be conducted every three
years. Currently, the Rider caters for a total of 7.0 MW and allows for customer-
owned solar and wind systems with maximum individual customer capacities of 1.5
times the customer’s current usage up to a maximum capacity of 150 kW.
At the end of August 2013, there were approximately 200 customers on the RE
Rider representing approximately 2.1 MW. The historical and projected growth on
the Renewable Energy Rider is shown in Table 9.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 35
Date Renewable Energy Rider
Capacity (MW)
January 2012 0.02
June 2012 0.13
January 2013 1.0
June 2013 1.7
January 2014 2.6
January 2015 4.4
January 2016 7.0
Table 9: Renewable Energy Rider Historical and Projected Capacity
In developing the demand forecast to be used in this study, the energy generated
from the systems on the Renewable Energy Rider was not included in the demand
forecast. This is based on the assumption that these systems are used to offset
customers’ internal demand and hence would reduce the customers’ demand from
the grid. However, the energy from these systems was taken into account in
accounting for the amount of intermittent generation on the system.
2.4 Fuel Price Forecasts
For this study, two possible conventional fuel supply scenarios have been
considered: Liquid fuels (HFO, Diesel &Jet A1) and natural gas. This study also
takes into consideration biomass plant as a candidate technology; hence biomass is
treated as a fuel.
This section sets out the fuel price assumptions for both conventional and biomass
fuels that will be used in this study.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 36
2.4.1 Liquid Fuel
2.4.1.1 Source for Liquid Fuel Projections
Projections of long-term oil prices are performed regularly by third party oil market
analyst groups and can show significant variation of results. In this report, and in line
with previous studies undertaken by BL&P, the most recent oil price forecast
produced by the U.S. Energy Information Administration (EIA) was used.
The EIA is the statistical and analytical agency within the U.S. Department of Energy
(DOE). It collects, analyzes and disseminates independent and impartial energy
information to promote sound policymaking, efficient markets and public
understanding of energy and its interaction with the economy and the environment.
The EIA publishes two reports which form the basis for the fuel price forecast:
Short-Term Energy Outlook (STEO): Energy projections for the next
eighteen (18) months, updated monthly.
Annual Energy Outlook (AEO): Projection and analysis of U.S. energy
supply, demand and prices over a 25 to 30 year period based on the EIA's
National Energy Modeling System.
The EIA’s fuel price forecasts include Reference, High and Low fuel price scenarios
which have been used in the IRP for sensitivity testing.
In addition to forecasting fuel energy prices, the EIA provides a report on the
accuracy of their forecasts in the Retrospective Review Report3. Figure
5demonstrates that the average absolute difference between the forecast and actual
projections for the first eleven (11) years, based on the AEO 1993 to 2010
projections, is less than 7%. After year eleven (11), the accuracy decreases rather
rapidly as shown in Figure 5.
3 Annual Energy Outlook Retrospective Review: Evaluation of 2011 and Prior Reference Case Projections-
March 2012- http://www.eia.gov/forecasts/aeo/retrospective/pdf/retrospective.pdf
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 37
Figure 5: Average Absolute Difference between the Forecast and Actual Projection Based On AEO 1993
To 2010 Projections
2.4.1.2 Crude Oil Prices
The EIA’s AEO 2012 report4 has been used to forecast the crude oil prices. The
prices in the AEO 2012 reference case predicts that world prices for imported low
sulphur crude oil will increase from US$98per barrel in 2012 to approximately
US$107in 2013. The price is then projected to steadily increase through to 2036,
reaching a price of US$151per barrel by the end of the study period (all prices are
expressed in real 2012 dollars).
Due to the significant variation that can be experienced in fuel prices, the EIA also
produces high and low scenarios for fuel prices in the AEO 2012 report. The
projections for imported low sulphur crude oil are shown in Figure 6 below. Further
data can be found in Appendix E.
4 AEO 2012 Report - http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0-
AEO2012&table=12-AEO2012®ion=0-0&cases=ref2012-d020112c
0.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
Avera
ge A
bso
lute
Dif
fere
nce b
etw
een
fo
recast
an
d
actu
al (%
)
Forecast Years (Years)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 38
Figure 6: AEO 2012 Low Sulphur Crude Oil Projections (2012 US$)
2.4.1.3 Liquid Fuel Forecast Methodology
In determining the price forecast for HFO, Diesel and Jet A1, the following
methodology was used:
The forecast for 2012 was based on the average delivery price up to
December2012.
The forecast for 2013 to 2036 was based on the AEO 2012report - June
20125. The residual oil and Jet fuel forecast was used as the basis of the
forecast.
5 AEO 2012 Report - http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0-
AEO2012&table=12-AEO2012®ion=0-0&cases=ref2012-d020112c
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
160.00
180.00
200.00
220.00
2012 2017 2022 2027 2032 2037
Cru
de O
il P
rice
(U
S$/b
bl)
Crude Oil Price Forecasts
Crude Oil Forecast - Base Case Crude Oil Forecast - High Case Crude Oil Forecast - Low Case
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 39
A relationship was determined between the historical residual oil price and the
HFO delivered price over the period 2001 to 2011. This was used to
determine the delivered HFO price for the price forecast.
A relationship was determined between the historical Jet fuel price and the
Jet A1 delivered price over the period 2001 to 2011. This was used to
determine the Jet A1 price for the price forecast.
A relationship was determined between the historical Jet fuel price and the
Diesel delivered price over the period 2001 to 2011. This was used to
determine the Diesel price for the price forecast.
High and low fuel price scenarios published in the AEO 2012 report were
used following the above methodology to arrive at the price forecast for the
high and low fuel scenarios.
2.4.1.4 Liquid Fuel Forecast
Using the methodology outlined above, Table 10 shows the fuel price projections
derived for the base fuel price scenario. Figure 7 shows how the forecast compares
with actual historical prices for the three fuels.
Additional information related to the high and low scenarios can be found in
Appendix E.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 40
Year
Imported Low Sulphur
Light Crude Oil HFO Price Diesel Jet A1
US$/bbl Bds$/ton Bds$/ton Bds$/ton
2012 102.50 1464 1992 2197
2013 110.32 1321 1813 2161
2014 114.73 1418 1918 2286
2015 117.90 1485 1990 2372
2016 115.38 1510 2025 2413
2017 117.02 1540 2061 2457
2018 117.68 1552 2076 2474
2019 118.59 1569 2092 2493
2020 119.74 1587 2117 2523
2021 120.84 1600 2139 2549
2022 122.33 1627 2156 2569
2023 123.39 1644 2175 2592
2024 124.41 1654 2192 2613
2025 125.39 1665 2217 2643
2026 126.17 1663 2236 2665
2027 126.87 1658 2251 2682
2028 127.78 1672 2266 2701
2029 129.42 1677 2294 2734
2030 130.88 1682 2312 2755
2031 132.39 1686 2356 2808
2032 133.58 1683 2391 2850
2033 134.85 1665 2377 2833
2034 136.31 1681 2402 2863
2035 137.54 1694 2441 2910
2036 138.78 1707 2481 2957 Note: 2012 fuel prices are based on average delivery prices
Table 10: Fuel Price Projections for Reference Fuel Price Scenario (2012 $)
Figure 7: Historical & Projected Fuel Prices - Reference Case (2012 $)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 41
Table 11 presents the delivered fuel price projections as derived and proposed by
BL&P expressed in 2012 prices. The table sets out the projected fuel price scenarios
used in this study (base, high and low) based on the AEO2012 price projections.
Year
Base - Bds$/mmbtuLHV High - Bds$/mmbtuLHV Low - Bds$/mmbtuLHV
HFO Jet A1 Diesel HFO Jet A1 Diesel HFO Jet A1 Diesel
2012 37.14 52.62 48.51 37.14 52.62 48.51 37.14 52.62 48.51
2013 33.53 51.75 44.14 55.87 83.77 71.45 18.35 30.99 26.43
2014 36.00 54.75 46.70 58.08 84.74 72.28 18.12 30.50 26.01
2015 37.69 56.81 48.45 58.97 84.14 71.76 18.14 30.16 25.72
2016 38.32 57.80 49.30 59.47 83.65 71.34 17.87 29.93 25.53
2017 39.07 58.84 50.19 59.82 83.91 71.57 17.92 30.04 25.62
2018 39.39 59.25 50.53 60.10 83.08 70.86 17.84 29.77 25.39
2019 39.83 59.71 50.93 59.88 82.34 70.23 17.49 29.38 25.06
2020 40.27 60.44 51.55 59.32 82.50 70.36 17.07 28.94 24.68
2021 40.60 61.06 52.08 59.37 82.45 70.32 17.13 28.96 24.70
2022 41.28 61.54 52.48 59.60 84.78 72.31 17.26 29.10 24.82
2023 41.72 62.09 52.95 59.70 85.10 72.58 17.79 30.07 25.65
2024 41.98 62.58 53.38 59.59 85.12 72.59 17.95 30.28 25.83
2025 42.25 63.29 53.98 59.75 85.65 73.05 18.12 30.59 26.09
2026 42.19 63.84 54.45 59.80 85.65 73.05 18.57 31.28 26.67
2027 42.08 64.25 54.80 60.02 85.91 73.27 18.67 31.49 26.86
2028 42.43 64.69 55.18 60.16 85.93 73.29 18.63 31.61 26.96
2029 42.57 65.49 55.86 60.54 86.30 73.60 18.54 31.84 27.16
2030 42.69 65.99 56.28 60.34 86.30 73.60 18.44 31.90 27.20
2031 42.79 67.25 57.35 60.95 87.24 74.40 18.59 32.16 27.43
2032 42.72 68.26 58.21 60.89 87.34 74.49 18.59 32.34 27.58
2033 42.25 67.85 57.87 60.40 87.31 74.46 18.42 32.69 27.88
2034 42.67 68.57 58.49 60.73 87.77 74.85 18.41 33.03 28.17
2035 43.00 69.69 59.44 60.56 88.05 75.10 18.26 33.35 28.44
2036 43.33 70.83 60.41 60.39 88.33 75.34 18.11 33.67 28.72
Table 11: Liquid Fuel Price Forecast Scenarios (2012 $)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 42
2.4.2 Natural Gas
The Government of Barbados (GoB) has stated its intent to supply natural gas to the
island in order to assist in the reduction of the national fuel bill. The GoB has been in
negotiation with the Government of Trinidad and Tobago (GoTT) regarding the
supply of gas via an undersea pipeline. Other methods by which natural gas can be
delivered to the island are LNG tanker and CNG tanker. The forecast prepared for
this study is not based on any single transport method. A range of natural gas prices
is presented based on current available information and is wide enough to cover any
of the three transportation methods.
While there are well established global price benchmarks for crude oil like WTI and
Brent, there is no equivalent “global” index for natural gas. This is partially due to the
relatively expensive and dedicated infrastructure generally required to either pipe,
liquefy or compress the gas. Consequently, gas prices in the three major regional
gas consuming markets - US, Europe and Asia - tend to be driven by energy price
references within their own regions and vary widely. In the US, gas prices are
referenced to the Henry Hub index whereas in Japan, the world’s largest LNG
importer, prices are indexed to a basket of imported crudes. Increasing supplies of
shale gas in the US have significantly depressed the Henry Hub price of gas in that
market. However prices in Europe and Asia are significantly higher, as shown in
Figure 8.
At the time of writing this report, the source of natural gas for Barbados is likely to be
Trinidad & Tobago (T&T) which is located approximately 180 miles south-west of
Barbados. T&T currently exports all of its gas as LNG at prices that are typically
based on medium to long-term gas contracts held between Atlantic LNG, the lone
LNG producer, and its suppliers and customers. These contracts are confidential
and therefore not accessible; however, a ‘Net Back’ pricing mechanism is used in
which all parties in the value chain share in the end market value of gas. T&T makes
use of spot market based trading to diversify its LNG export markets and benefit
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 43
from higher prices in regions other than the US. In 2012, approximately 75% of its
LNG exports were to Europe, Asia, Latin America and the Caribbean.
Current pricing information suggests that the price of imported natural gas from T&T
will likely be linked to a crude oil price index. Consequently, the escalation rates
used for natural gas in this study are the escalation rates for crude oil as projected in
the AEO 2012 report.
Figure 8: World LNG Estimated November 2013 Landed Prices in US$/mm Btu (Source: Waterborne
Energy Inc. Data, October 2013)
For the purpose of this study, it is assumed that natural gas would be available from
January 1st 2017. The maximum off-take was assumed to be 28 mmscf/day.
2.4.2.1 Natural Gas Pricing Methodology
Based on current information, the delivered natural gas price is expected to
comprise fixed and variable cost components. Fixed cost includes costs for transport
and maintenance of transport infrastructure while variable cost refers to the actual
cost of the gas.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 44
The gas pricing assumptions used are based on the most current pricing information
provided by proponents of the various transportation modes, with the gas pipeline
company being the most advanced at the time of preparing the report.
In determining the price forecast for natural gas, the following methodology was
used:
Based on the best estimates available, a fixed cost of $128,762,000 was used
in the base case for this study.
A fixed cost of $178,286,000 was used in the high case.
A fixed cost of $99,048,000 was used in the low case.
Based on the best estimates available to BL&P regarding natural gas prices,
a base gas price of $11.93/ mmBtuLHV was used in the study.
A high gas price of $16.51/ mmBtuLHV was used.
A low gas price of $9.17/ mmBtuLHV was used.
The real year-on-year escalation rates based on the projections of the crude
oil forecast in the AEO 2012 report6was used to escalate gas prices
throughout the forecast.
2.4.2.2 Natural Gas Price Forecast
Using the methodology outlined above, Table 12 and Figure 9 show the natural gas
price projections for the base, high and low scenarios without the fixed cost.
6 AEO 2012 Report - http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0-
AEO2012&table=12-AEO2012®ion=0-0&cases=ref2012-d020112c
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 45
Year
Bds$/mmbtuLHV
Year
Bds$/mmbtuLHV
Base High Low Base High Low
2012 2025 13.18 18.25 10.14
2013 2026 13.28 18.38 10.21
2014 2027 13.36 18.50 10.28
2015 2028 13.46 18.64 10.36
2016 11.93 16.51 9.17 2029 13.63 18.87 10.48
2017 12.22 16.92 9.40 2030 13.77 19.07 10.60
2018 12.33 17.08 9.49 2031 13.91 19.26 10.70
2019 12.45 17.24 9.58 2032 14.04 19.44 10.80
2020 12.60 17.45 9.69 2033 14.16 19.60 10.89
2021 12.73 17.63 9.79 2034 14.30 19.80 11.00
2022 12.87 17.82 9.90 2035 14.42 19.97 11.09
2023 12.98 17.97 9.98 2036 14.54 20.13 11.18
2024 13.08 18.11 10.06
Table 12: Natural Gas price Forecast Scenarios without Fixed Costs (2012 $)
Figure 9: Natural Gas Price Forecast without Fixed Costs (2012 $)
0.00
5.00
10.00
15.00
20.00
25.00
2012 2017 2022 2027 2032 2037
Na
tura
l G
as
Fo
rec
as
t ($
/mm
btu
)
Natural Gas Price Forecasts
Natural Gas Forecast - Base Case Natural Gas Forecast - High Case Natural Gas Forecast - Low Case
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 46
2.4.3 Biomass
Biomass burning plant is one of the candidate technologies considered in this study.
Consequently, a forecast of biomass prices was prepared. Indications currently
suggest that biomass can either be obtained locally or imported. Local biomass will
consist of bagasse, which is one of the by-products of the sugar production process,
supplemented with Leucaena (referred to locally as “river tamarind”) which is not
currently purpose-grown. Biomass could also be imported in the form of pellets or
wood chips. Current estimates show that the delivered cost of imported biomass is in
the range of three to five times the projected cost for local biomass, largely due to
transportation costs.
2.4.3.1 Local Biomass Pricing Methodology
In determining the price forecast for local biomass, the following methodology was
used:
Based on the best estimates available to BL&P regarding local biomass
prices, a base price of $6.72/ mmBtuLHV was used in the study.
A high price of $8.06/ mmBtuLHV was used in the study.
A low price of $5.38/ mmBtuLHV was used in the study.
The real year-on-year escalation rates were based on the projections of the
crude oil forecast in the AEO 2012 report7.
2.4.3.2 Local Biomass Price Forecast
Using the methodology outlined in section 2.4.3.1, Table 13 and Figure 10 shows
the local biomass price projections for the base, high and low scenarios.
7 AEO 2012 Report - http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0-
AEO2012&table=12-AEO2012®ion=0-0&cases=ref2012-d020112c
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 47
Year
Bds$/mmbtuLHV
Year
Bds$/mmbtuLHV
Base High Low Base High Low
2012 6.72 8.06 5.38 2025 9.40 11.28 7.52
2013 7.36 8.83 5.89 2026 9.47 11.36 7.58
2014 7.87 9.44 6.29 2027 9.53 11.44 7.62
2015 8.29 9.95 6.63 2028 9.60 11.52 7.68
2016 8.51 10.21 6.81 2029 9.72 11.66 7.78
2017 8.72 10.46 6.97 2030 9.82 11.79 7.86
2018 8.80 10.56 7.04 2031 9.92 11.90 7.94
2019 8.88 10.66 7.11 2032 10.01 12.01 8.01
2020 8.99 10.78 7.19 2033 10.10 12.12 8.08
2021 9.08 10.90 7.26 2034 10.20 12.24 8.16
2022 9.18 11.02 7.34 2035 10.28 12.34 8.23
2023 9.26 11.11 7.40 2036 10.37 12.44 8.30
2024 9.33 11.20 7.46
Table 13: Local Biomass Price Forecast Scenarios (2012 $)
Figure 10: Local Biomass Price Forecast (2012 $)
0.00
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
18.00
20.00
2012 2017 2022 2027 2032 2037
Lo
ca
l B
iom
ass P
rice
Fo
reca
st ($
/mm
btu
)
Year
Biomass Forecast - Base Case Biomass Forecast - High Case Biomass Forecast - Low Case
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 48
2.4.3.3 Imported Biomass Pricing Methodology
In determining the price forecast for imported biomass, the following methodology
was used:
Based on market prices for wood pellets, a base price of US$150 /ton, high
price of US$175 /ton and low price of US$125 /ton were used in determining
delivered biomass prices.
Transportation costs were determined based on the wood pellets being
supplied in 40 ft. containers.
Based on the best information available to BL&P regarding imported biomass
prices, a base price of $26.79/ mmBtuLHV was used in the study.
A high price of $30.04/ mmBtuLHV was used in the study.
A low price of $23.54/ mmBtuLHV was used in the study.
The real year-on-year escalation rates were based on the projections of the
crude oil forecast in the AEO 2012 report8.
2.4.3.4 Imported Biomass Price Forecast
Using the methodology outlined in section 2.4.3.3, Table 14 and Figure 11 show the
imported biomass price projections for the base, high and low scenarios.
8 AEO 2012 Report - http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0-
AEO2012&table=12-AEO2012®ion=0-0&cases=ref2012-d020112c
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 49
Year
Bds$/mmbtuLHV
Year
Bds$/mmbtuLHV
Base High Low Base High Low
2012 26.79 30.04 23.54 2025 37.49 42.04 32.95
2013 29.33 32.89 25.78 2026 37.75 42.33 33.17
2014 31.37 35.17 27.56 2027 38.00 42.61 33.39
2015 33.07 37.08 29.06 2028 38.29 42.94 33.65
2016 33.92 38.03 29.80 2029 38.76 43.46 34.06
2017 34.76 38.98 30.54 2030 39.17 43.92 34.42
2018 35.07 39.33 30.82 2031 39.55 44.35 34.75
2019 35.42 39.71 31.12 2032 39.92 44.76 35.08
2020 35.83 40.18 31.48 2033 40.26 45.15 35.38
2021 36.20 40.59 31.81 2034 40.67 45.60 35.74
2022 36.61 41.05 32.16 2035 41.01 45.98 36.03
2023 36.91 41.38 32.43 2036 41.35 46.36 36.33
2024 37.21 41.72 32.69
Table 14: Imported Biomass Price Forecast Scenarios (2012 $)
Figure 11: Imported Biomass Price Forecast (2012 $)
20.00
25.00
30.00
35.00
40.00
45.00
50.00
2012 2017 2022 2027 2032 2037
Imp
ort
ed
Bio
ma
ss P
rice
Fo
reca
st ($
/mm
btu
)
Year
Imported Biomass Forecast - Base Case Imported Biomass Forecast - High Case Imported Biomass Forecast - Low Case
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 50
2.4.4 Landfill Gas
Reciprocating engines burning landfill gas is one of the candidate technologies being
considered in this study. At this time however, no indication is available of the price
that would be charged for landfill gas. Consequently, no cost was attributed to the
landfill gas used in this study. Further information on landfill gas costs would be
needed for additional analysis.
2.4.5 Calorific Values
Table 15 shows the Lower Heating Values (LHV) calorific values for all the fuels
considered that were used in determining the fuel forecast for this study.
Fuel
Calorific Values
(LHV) Units
Bunker C 17591 Btu/lb
Diesel 18337 Btu/lb
Jet A1 18639 Btu/lb
Natural Gas 38314 Btu/cu.m.
Biomass – Bagasse 3611 Btu/lb
Biomass - River Tamarind 5311 Btu/lb
Biomass - Imported Wood Pellets 7290 Btu/lb
Table 15: Calorific Values Used In Study
2.5 System Criteria
2.5.1 System Reliability
The reliable operation of the electric power grid is critical to any country’s economic
and social welfare. The cost of an electricity outage to an economy is normally a
multiple of the cost of electricity that would otherwise have been supplied during that
outage (Khatib, 2003).Setting too low a reliability target during the resource planning
process will lead to under-investment in generating capacity, low generating reserve
margins and increased economic costs to the country from electricity outages.
Conversely, too high a reliability target leads to over-investment and increased
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 51
operating costs which translate to higher costs to customers. An efficient reliability
target is therefore one where the benefits from improved reliability are balanced by
the cost of providing that additional reliability.
Electricity reliability can be defined in a number of ways, but for the purpose of the
IRP, it is considered to be the adequacy of electrical generating capacity to meet
system electricity demand at specified voltages and frequency. In this context, the
reliability of the electric power system is established by ensuring that there is
sufficient generating reserve capacity to meet the system demand in the event of a
generator failure or other supply disruption.
There are three common measures of reliability used in electricity system planning:
Largest Unit Contingency – Additional generating capacity is installed to
ensure that single or double contingency criteria is satisfied, i.e. electricity
service is uninterrupted in the event of the single largest generator (N-1) or
two largest generators (N-2) being out of service.
Reserve Margin - This is the difference between the installed generating
capacity and the capacity required to meet the peak demand, expressed as a
percentage of the peak demand. A minimum reserve margin is set at which
new generating capacity is required.
Loss of Load Probability (LOLP) – This is the probability that the system
demand will exceed the generating capacity during a given period. It is often
expressed as the number of days per year in which the peak demand is
expected to exceed the available generating capacity, which is more
accurately referred to as Loss of Load Expectation (LOLE). The two terms
are, however, often used interchangeably. LOLP takes into consideration the
stochastic nature of system behaviour, and therefore provides a more robust
measure of system reliability than the previous two deterministic measures.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 52
BL&P has historically used a reliability standard of one (1) day per year LOLE for
expansion planning. The relationship between LOLE and reserve margin is not linear
and varies depending on the number, size and operating performance
characteristics of the generating units installed on the system. Based on a review of
past expansion studies and the characteristics of existing plant, the one (1) day per
year LOLE standard has been found to be approximately equivalent to a reserve
margin limit of 32% for BL&P’s system.
Table 16 summarizes the electricity planning reliability criteria used in a number of
countries regionally and internationally.
At the time of preparing the IRP report, the Plexos software that was used to model
the system was capable of reporting LOLP for the expansion plans but could only
optimize on reserve margin. A minimum reserve margin of 32% was therefore used
in the IRP study as the reliability standard for expansion modeling and simulation.
The LOLP for the optimized plans were subsequently reviewed for compliance with
the one (1) day per year LOLP standard.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 53
Reliability Criteria
Country LOLP Reserve
Margin (%) Loss of
Unit References
USA / Canada 2.4 hours/year
PJM Interconnection (October 2003)
Curacao 3.0
Carilec (2010)
Hawaii 5.3 hours/year
HECO (February 2011)
Ireland 8.0 hours/year
EirGrid (January 2013)
Trinidad 12.0hours/year
Clarke (2010)
Barbados 1 day/year 32% *
Jamaica 2 days/year 25%
Argonne National Laboratory (July 1999)
Belize 48 hours/year 20%
Carilec (2010)
Bermuda
N-3 Carilec (2010)
Cayman Islands
N-3 Carilec (2010)
St. Lucia
N-2 Carilec (2010)
Dominica
N-2 Carilec (2010)
Grand Bahamas
N-2 Carilec (2010)
Bangladesh 192 hours/year
Bangladesh Power Development Board
Kenya 240hours/year
Republic of Kenya (March 2011)
* Minimum reserve margin derived from past expansion studies using an LOLP of 1 day per year
Table 16: Generation Reliability Standards in Select Countries
2.5.1.1 Evaluation of Reliability Criterion
Reliability standards are often based on past practice and general notions regarding
the quality of service that would be acceptable to electricity users. However, as
described in section 2.5.1, an optimal reliability level is achieved when the marginal
benefits of providing improved reliability is equal to the marginal cost of expansion.
The cost of improving reliability can be determined by comparing the cost of
expansion plans at varying levels of target reserve margins. The benefits of
improving reliability are more difficult to determine, but can be estimated by
multiplying the reduction in unserved energy, resulting from the improved reserve
margin target, by the estimated Cost of Unserved Energy.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 54
The Cost of Unserved Energy (COUE) is a difficult number to estimate, but a
methodology for doing so and an estimate for Barbados is presented in Appendix F.
The unserved energy at different levels of reserve margin were calculated in the
planning model and a summary of the costs and benefits for increasing levels of
reserve margin, based on the $5 per kWh COUE estimate derived in Appendix F,
are presented in Table 17. Plotting the unserved energy against the reserve margin,
the equation that best represented the relationship between reserve margin and
unserved energy was determined and used to estimate the unserved energy and
hence the cost of unserved energy for other reserve margin levels. Similarly, a plot
of NPV of the plan against reserve margin was created and the equation that best
represented the relationship between reserve margin and NPV determined and used
to estimate the NPV for different reserve margins.
The optimal reserve margin is represented by the point at which the net benefit of
the reserve margin improvement equals zero, i.e. when the marginal benefits and
costs of improving reliability are equal. The results are graphically presented in
Figure 12.
The results suggest that the optimal reserve margin for the system is around 38%.
The results presented in Table 17 are indicative, as COUE cannot be measured
directly and will vary significantly by type of customer and outage timing.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 55
Table 17: Cost/Benefit Analysis of Generation Reliability
Actual Estimate Actual Estimate
15 25.098 24.767 123,834 4,698,797 4,715,023 4,838,857
16 23.301 116,506 7,328 4,716,341 1,318 6,010 4,832,847
17 21.922 109,611 6,894 4,717,685 1,343 5,551 4,827,296
18 20.625 103,125 6,486 4,719,054 1,369 5,117 4,822,178
19 19.404 97,022 6,103 4,720,448 1,394 4,708 4,817,470
20 18.256 91,281 5,741 4,721,868 1,420 4,322 4,813,149
21 17.176 85,879 5,402 4,723,313 1,445 3,956 4,809,193
22 16.159 80,797 5,082 4,724,784 1,471 3,611 4,805,581
23 15.203 76,016 4,781 4,726,281 1,496 3,285 4,802,297
24 14.303 71,517 4,498 4,727,803 1,522 2,976 4,799,320
25 14.253 13.457 67,285 4,232 4,711,412 4,729,350 1,547 2,685 4,796,635
26 12.661 63,303 3,982 4,730,923 1,573 2,409 4,794,227
27 11.911 59,557 3,746 4,732,522 1,598 2,148 4,792,079
28 11.315 11.207 56,033 3,524 4,714,032 4,734,146 1,624 1,900 4,790,179
29 10.543 52,717 3,316 4,735,795 1,649 1,666 4,788,512
30 9.919 49,597 3,120 4,737,470 1,675 1,445 4,787,067
31 9.332 46,662 2,935 4,739,170 1,700 1,235 4,785,833
32 9.153 8.780 43,901 2,761 4,718,056 4,740,896 1,726 1,035 4,784,798
33 8.261 41,303 2,598 4,742,648 1,751 846 4,783,951
34 7.772 38,859 2,444 4,744,425 1,777 667 4,783,284
35 6.324 7.312 36,559 2,300 4,722,723 4,746,227 1,802 497 4,782,787
36 6.879 34,396 2,163 4,748,055 1,828 336 4,782,451
37 6.472 32,361 2,035 4,749,909 1,853 182 4,782,269
38 5.881 6.089 30,446 1,915 4,727,347 4,751,788 1,879 36 4,782,233
39 5.729 28,644 1,802 4,753,692 1,904 (103) 4,782,336
40 5.390 26,949 1,695 4,755,622 1,930 (235) 4,782,571
41 5.071 25,354 1,595 4,757,577 1,955 (361) 4,782,932
42 5.482 4.771 23,854 1,500 4,734,931 4,759,558 1,981 (481) 4,783,412
43 4.488 22,442 1,412 4,761,565 2,006 (595) 4,784,007
44 4.223 21,114 1,328 4,763,597 2,032 (704) 4,784,711
45 3.973 19,865 1,249 4,765,654 2,057 (808) 4,785,519
46 3.738 18,689 1,176 4,767,737 2,083 (907) 4,786,426
47 3.517 17,583 1,106 4,769,846 2,108 (1,002) 4,787,429
48 3.309 16,543 1,041 4,771,980 2,134 (1,093) 4,788,522
49 3.113 15,564 979 4,774,139 2,159 (1,181) 4,789,703
50 2.929 14,643 921 4,776,324 2,185 (1,264) 4,790,967
Total Cost
($'000)
Net benefit
($'000)
Reserve
Margin (%)
CUM PV of Unserved
Energy (GWh)Cost of
unserved
Energy ($'000)
Delta Cost to
Economy
($'000)
Delta Annual
Cost ($'000)
CUM PV of Annual Costs
($'000)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 56
Figure 12: Marginal & Total Costs vs. Reserve Margin
Figure 13: Reserve Margin for Recommended Plan
500
1,500
2,500
3,500
4,500
5,500
6,500
7,500
8,500
4,750,000
4,760,000
4,770,000
4,780,000
4,790,000
4,800,000
4,810,000
4,820,000
4,830,000
4,840,000
15 20 25 30 35 40 45 50
Mar
gin
al c
ost
of
Un
serv
ed E
ner
gy, E
xpan
sio
n P
lan
($
'00
0)
Tota
l Co
st (
$'0
00
)
Reserve Margin (%)
Total Cost ($'000)
Marginal Cost of Unserved Energy ($'000)
Marginal Cost of Expansion Cost ($'000)
0
10
20
30
40
50
60
70
80
90
0
0.5
1
1.5
2
2.5
3
Cap
acit
y R
ese
rve
Mar
gin
(%
)
LOLE
(d
ays)
Year
Annual Maximum LOLE (days)
LOLE Target
Capacity Reserve Margin (%)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 57
2.5.1.2 Reserve Margin Criteria
Based on the foregoing, the 32% minimum reserve margin used in the IRP study
was considered reasonable. The actual reserve margins for the recommended plan
remain over 40% between 2016 and 2021, as shown in
Figure 13, since expansion in these early years is driven by the cost minimization
objective of the IRP rather than the 32% minimum reserve margin constraint. The
short-term recommendations are therefore not sensitive to changes in the reserve
margin constraint between 30% and 40%.
No upper limit was placed on the reserve margin, thereby allowing the model to
determine the least cost solution without constraints on the maximum allowable
reserve margin. Consequently, reserve margins of as much as 92% were observed
in some scenarios.
To analyze the impact of an upper limit on the reserve margin, scenario 3 (LF + NGr
+ RE) in the base case was used to determine the impact on the plan net present
value with an upper reserve margin of 55%. Table 18 shows the reserve margin for
this scenario with and without the upper limit on reserve margin. The net present
value for the plan without the upper limit is $4.213 billion while that for the plan with
the upper limit is $4.248 billion. Consequently, it can be concluded that if an upper
limit is set on the reserve margin, the overall cost of the plan would increase. For this
reason, no upper limit was set on the reserve margin in the model.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 58
Table 18: Comparison of impact of upper limit on reserve margin
2.5.2 System Stability
2.5.2.1 Intermittent Renewable Energy There is no inherent energy storage capacity in electric grids. Electricity demand
must therefore be instantaneously matched by electricity generation in order to
maintain a stable system frequency. BL&P operates with a minimum spinning
reserve requirement of 5MW to cater to small supply/demand imbalances associated
with system faults, and employs an under-frequency load-shedding scheme to
prevent system overloads and grid collapse in the event of significant generation
Capacity Reserve
Margin (%) LOLP (%)
Capacity Reserve
Margin (%) LOLP (%)
2012 37.3 0.205 37.3 0.205
2013 37.9 0.205 37.9 0.205
2014 37.4 0.205 37.4 0.205
2015 37.7 0.205 37.7 0.205
2016 36.2 0.252 36.2 0.252
2017 85.3 0.000 54.6 0.145
2018 84.4 0.000 53.9 0.008
2019 53.6 0.008 43.9 0.052
2020 51.3 0.011 51.4 0.012
2021 48.9 0.016 49.0 0.016
2022 40.4 0.089 40.6 0.082
2023 38.5 0.115 38.7 0.113
2024 36.7 0.154 46.3 0.020
2025 33.3 0.298 33.5 0.292
2026 32.5 0.307 32.6 0.318
2027 38.7 0.059 36.2 0.140
2028 35.8 0.097 33.3 0.189
2029 33.8 0.127 32.1 0.265
2030 32.8 0.133 39.6 0.047
2031 39.6 0.034 37.7 0.075
2032 37.8 0.043 36.0 0.092
2033 36.0 0.064 34.2 0.149
2034 34.2 0.090 32.4 0.156
2035 32.3 0.107 38.5 0.0332036 33.5 0.141 33.3 0.141
Without Upper Limit With Upper Limit of 55%
Datetime
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 59
losses. High penetrations of intermittent RE resources present reliability and stability
challenges for small island grids which lack the interconnections and ‘infinite’ grid9
characteristics typical of utilities on continents. The primary issues introduced by
high intermittent RE levels involve the magnitude and distribution of spinning
reserves/operating reserves across conventional generating units, unit ramping and
cycling capabilities, limitations of existing unit control systems, voltage control and
maintenance scheduling considerations.
Studies on other island grids have indicated that for high intermittent RE penetration
levels, additional reserves of up to 30% of the intermittent RE capacity may be
required to provide capacity reserves for contingency conditions (BEW Engineering,
2012).
The capability of conventional generating units to ramp up and down as the RE and
customer load varies is another issue. For example, wind speed data collected by
BL&P shows the average hourly up ramp at 55% of the wind turbine capacity and a
down ramp at 74%. In other words, if BL&P installed 20 MW of wind turbine
capacity, the hourly up ramp could be as high as 11 MW, while the down ramp could
be 15 MW, excluding ramping for load variability. The exact ramping requirement
could be lower due to the diversity and distribution of the wind turbine installations
over the land space. This will have to be modeled in a stability study taking into
account the distribution of RE at various substation buses. On the other hand, the
generators need to respond to variations in seconds and minutes, so the ramping
may be higher than the average hourly values. Consequently, the high ramping of
wind turbines may require modifications to the conventional generating units’ control
systems to increase unit response times. The control systems for certain RE
systems may also be required to meet prescribed design criteria.
9An ‘infinite” grid is one which has a capacity that is infinite in comparison to the individual generator capacities on the grid.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 60
Similarly, short term variations in solar PV output must also be smoothed out by
conventional generators or storage technologies to maintain system stability. Figure
14shows an example of solar PV output and system electricity demand, expressed
on a per-unit basis, for one-minute intervals on March 15th2013. The aggregate
output of multiple solar PV systems spread across the island is expected to exhibit
less variability, however further research will be required to determine the smoothing
effect of geographic diversity.
Storage technologies have been explored with a view to understanding how these
technologies can be deployed to (i) absorb excess energy supplied by the distributed
RE; (ii) cope with fast balance or imbalance changes and (iii) provide ride through
between the failure of the utility grid and startup of a backup generator. These are
described in section 3.2.3.11.
Other critical issues are voltage, frequency, flicker, harmonics and transient and
dynamic stability under various contingency conditions. Rapid change in wind or
solar generation may cause a sudden change in voltage and frequency as the
generating units are ramping up or down. This can cause existing solar inverters
and wind turbines to trip off line which causes the system condition to become more
unstable.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 61
Figure 14: Comparison of Typical Daily Electricity Demand and Solar PV Output
The final issues relate to maintenance scheduling of generating units and
transmission/distribution switching routines. Depending on the penetration of RE
resources, maintenance scheduling of conventional generating units may need
modifications. The season of the highest RE variability may impact the scheduling
since specific units, as determined by a stability study, will be required to be on-line
during these periods. Also, time periods having minimum wind generation require
units to remain on-line and alter maintenance scheduling. Utilities have discovered
that the old, existing scheduling routines of transmission and distribution circuits may
not be adequate for high RE penetrations.
2.5.2.2 Intermittent RE Limit
The type of analyses required to determine potential penetrations limits depend on
the RE resource types and location. For high penetrations of distributed RE, the
analysis must begin at the distribution level. The distributed RE resources could be
central plant (connected to the distribution feeder directly) or a customer owned RE
system like those existing on BL&P’s RE Rider behind the meter. Connecting RE
alters loss performance of distribution networks. Small penetrations of RE tend to
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
6:0
0 A
M
7:0
0 A
M
8:0
0 A
M
9:0
0 A
M
10
:00
AM
11
:00
AM
12
:00
PM
1:0
0 P
M
2:0
0 P
M
3:0
0 P
M
4:0
0 P
M
5:0
0 P
M
6:0
0 P
M
7:0
0 P
M
1-Minute System Demand & Solar PV Output
Per UnitSystemDemand
Per UnitSolar PVOutput
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 62
reduce network power flows and thus reduce losses. When RE penetration is high
then there will be power export to the grid which may cause an increase in losses.
The distribution feeders will have to be studied first, to determine the maximum
distributed RE that can be connected to the individual feeders and to the substation.
Some island utilities, such as Hawaii, have set 15% of each individual feeder peak
demand as the maximum trigger value before conducting detailed transient and
dynamic stability studies to determine the maximum penetration value that can be
connected to the feeder. When a proposed single or multiple RE installation has a
generating capacity that exceeds the trigger value, a detailed study must be
conducted to determine the potential impact to the feeder and the mitigation
measures. The individual maximum peak demands are non-coincident between
feeders. This is an important factor when studying individual feeders and total
system RE penetrations. In either case, the determination of the maximum feeder
RE penetration is determined through distribution feeder studies.
If a substation has multiple feeders, the summation of the individual feeder limits
does not always equal the substation limit. The substation limit could be lower than
the summation of the individual feeder limits. The substation or system total peak
demand is a coincident peak, while the individual feeder peaks are non-coincident
peak demands. The entire substation and feeders must be studied to determine
potential substation transformer tap changer impacts or voltage issues on adjoining
feeders connected to the same common bus. This analysis must be conducted for
all feeders and substations on the island utility. Given these results, a study of the
relay protection is then required to determine if the relays will operate correctly under
different contingency and feeder switching routines.
After conducting the feeder analysis, the transmission system must be studied. The
projected distributed RE resources are added to the transmission power flow base
case and different transmission system RE penetrations are developed and studied.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 63
These studies are normally conducted for the system peak time, maximum daytime
peak demand and the minimum peak demand. This sets the limits for penetrations
on the transmission grid. The transmission and distribution penetrations may not be
coincident in time so adjustments must be made to the final limitations. For the
Hawaiian utilities of HECO, MECO and HELCO, the total system RE penetration
limit is currently set to 20% of the system coincident peak demand. When this
limitation is reached, then the Hawaiian utilities must conduct a detailed study to
determine the upper level of potential RE penetration.
The foregoing analyses focus on load flow analysis and relay protection. Production
cost analysis must also be considered to determine the impacts to the conventional
generating units on the system. The production cost analysis determines the
reserve requirements, ramping requirements, fuel usage, start-up costs, emissions
and other factors. The final RE resource penetration is derived from the various
studies described above, and is likely to result in a mixture of individual feeder,
transmission and system limitations.
BL&P will be conducting an Intermittent RE Penetration study for Barbados in 2013.
In the interim, an intermittent RE penetration limit of 10% of the annual peak demand
was used in the recommended plan. Based on internal analyses, this penetration
level is not expected to cause stability problems or require additional spinning
reserve. It is also consistent with intermittent RE levels existing in other island
states, as summarized in Table 19.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 64
Table 19: Intermittent RE Penetration Levels on Other Island Grids
2.5.2.3 Largest Generating Unit
The level of system overload experienced when a generator trips, is directly
proportional to the size of the generator. Generators which are very large relative to
overall system demand create system overload conditions, when they trip, that could
lead to system instability and outages.
This has been the BL&P’s experience, where trips of unit sizes greater than 20% of
peak load have resulted in major operational challenges on BL&P’s grid. This is
exacerbated at minimum load demands. For example, using this criterion for a peak
of 160 MW, the maximum unit size allowed for selection would be 32 MW which
would represent 36% of a system minimum load of 90 MW.
Based on past operating experience, in order to maintain frequency stability, BL&P
determined that the maximum generating unit size on the network should not exceed
20% of the projected peak demand. Consistent with previous expansion studies, the
maximum allowable individual generating unit size was set at 20% of the projected
peak demand.
Intermittent RE
Penetration(% of peak
demand)
Maui 30 4.6 204 17% YesHawaii DEBDT (2012);
HECO (2010)
Hawaii 31 6.8 203 19% YesHawaii DEBDT (2012);
HECO (2010)
Crete 106 0 605 18% No Karapidakis (2011)
Mauritius 39 0 389 10% No Castalia (2011)
Jamaica 38 0 644 6% No Jamaica OUR (2010)
ReferencesIsland
Wind
Penetration
(MW)
Distributed
RE
Penetration
(MW)
Peak
Demand
(MW)
Storage
Installed
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 65
2.5.2.4 Generation Spinning Reserve
Generating Spinning Reserve is the on-line generating reserve capacity which is
available to maintain balance between electricity supply and demand in emergency
situations.
In 2000, BL&P conducted a spinning reserve study to determine the appropriate
spinning reserve that should be maintained on the system. The study concluded that
the optimal spinning reserve on BL&P’s current system was between 2MW and
6MW depending on the system demand, with the higher end of the range required
for lower system demands. In practice, BL&P maintains a minimum spinning reserve
of 5MW throughout the day for operational flexibility and security. For this study, the
minimum spinning reserve requirement was set to 5MW.
In the model, spinning reserve is specified as a constraint that must be satisfied at
every hour over the planning period. To analyze the impact of increased levels of
spinning reserve on the model, the spinning reserve requirement was increased
from 5MW to 10MW on the recommended plan. For a spinning reserve of 5MW the
net present value of the plan over the planning horizon was $4.741 billion while the
net present value for 10MW was $4.779 billion. In addition, the build schedule for the
two levels of spinning reserve also changed due to the need to have additional
capacity available to supply this requirement.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 66
3 GENERATING TECHNOLOGIES
3.1 Existing Plant
The existing generating system comprises three power stations, these are: Spring
Garden, Seawell and Garrison Hill. A brief overview of the existing generating
stations is provided in the following subsections.
3.1.1 Spring Garden Generating Station
The Spring Garden generating station was first developed in 1967. This station is the
main generating station for the Barbados system and is the location for the
Generation Central Control Room. With the addition of the Low Speed Diesel Station
‘B’ in 2005, BL&P has determined that the site cannot accommodate any more units
without the retirement of existing units. The administrative offices of the Generation
Department are also located on this site.
The site is divided into three main stations; Steam Station (Units S1 & S2); Low
Speed Diesel Station ‘A’ (Units D10-D13) and the new Low Speed Diesel Station ‘B’
(Units D14 & D15) commissioned in 2005. One gas turbine unit (GT01) is also
located at this site but has been officially retired. Due to the time required to
construct new capacity, the earliest retirement date for the steam station is January
2017.
The total installed capacity at the Spring Garden site is 153.1 MW.
3.1.2 Seawell Generating Station
The Seawell generating station is located near the Grantley Adams International
Airport, approximately 12km south east of Bridgetown. The station has one 13MW
gas turbine unit (GT03) installed in 1996 and three gas turbines (GT04 – GT06) with
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 67
a nominal capacity of 20MW each, added to the system in 1999, 2001 and 2002
respectively. This site is currently fully developed.
The retirement dates assumed for these units are the end of 2021, 2024, 2026 and
2027 respectively. Units GT03, GT04 and GT06 have been refueled to burn diesel
instead of Jet A1. Seawell is an unmanned station that is monitored and controlled
remotely via a fiber optic link from the Central Control Room at Spring Garden where
the units are dispatched as required. Also located on this site is an 11/24kV
substation, which is monitored and controlled via the SCADA Control Room, located
at Garrison Hill.
The total installed capacity at the Seawell site is 73.0MW.
3.1.3 Garrison Hill Generating Station
The Garrison Hill site is of historic and architectural significance. Furthermore, due to
the limited space available and other constraining factors relating to the adjacent
properties, no future development of this site is considered within this study.
The gas turbine unit, GT02, located at the Garrison Hill generating station was
installed in 1990 and operates on diesel fuel. It is assumed that unit GT02 will
continue to provide capacity until it is retired at the end of 2016.
The installed capacity of this unit is 13.0MW.
3.1.4 Cost and Performance Parameters
Table 20 presents a summary of the latest cost and performance parameters
adopted for this study. Further information is included in the following sub-sections.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 68
Table 20: Cost & Performance Parameters for Existing Plant
3.1.4.1 Retirement Dates
In this study, the retirement dates that will be used are based on the expected
lifetime of the units (Table 20). No life extension measures will be considered or
proposed as part of this study.
3.1.4.2 Heat Rates
Periodically, BL&P conducts heat rate tests on its units. The heat rates shown in
Table 20 are based on the heat rate tests that were conducted in 2009. The gross
heat rate relates to the heat rate at gross capacity of the plant using the lower
S1 S2 D10 D11 D12 D13 D14 D15
Installed Capacity (MW) 20.0 20.0 12.5 12.5 12.5 12.5 29.7 29.7
Retirement Date 01/01/17 01/01/17 01/01/19 01/01/19 01/01/19 01/01/19 01/01/36 01/01/36
Fuel Type HFO HFO HFO HFO HFO HFO HFO HFO
Gross Heat Rate (Btu/kWh)12,325 12,325 8,063 8,063 8,063 8,063 7,456 7,456
Average Annual Maintenance
(Days) 74 74 35 35 35 35 41 41
FoR (%) 5.7 5.7 6.1 6.1 6.1 6.1 2.0 2.0
Annual Availability (%) 74.0 74.0 84.3 84.3 84.3 84.3 86.8 86.8
Auxilary Power Consumption
(%) 6.9 6.9 4.1 4.1 4.1 4.1 3.8 3.8
Fixed O&M (Bds$/ kW/ month)19.21 19.21 13.89 13.89 13.89 13.89 9.24 9.24
Variable O&M
Bds$/ MWh 18.13 18.13 33.65 33.65 33.65 33.65 10.38 10.38
CG01 CG02 GT02 GT03 GT04 GT05 GT06
Installed Capacity (MW) 1.5 2.2 13.0 13.0 20.0 20.0 20.0
Retirement Date 01/01/19 01/01/36 01/01/17 01/01/22 01/01/25 01/01/27 01/01/28
Fuel Type Diesel Diesel Diesel Av-Jet Diesel
Gross Heat Rate (Btu/kWh) 13,276 13,276 11,134 11,134 11,134
Average Annual Maintenance
(Days) 56 51 67 39 27 27 27
FoR (%) 12.4 5.0 17.5 2.6 4.3 4.3 4.3
Annual Availability (%) 72.3 81.0 64.1 86.7 88.3 88.3 88.3
Auxilary Power Consumption
(%) 1.0 0.8 1.0 1.0 1.0
Fixed O&M (Bds$/ kW/ month)4.74 3.43 0.89 0.89 0.89
Variable O&M
Bds$/ MWh 52.09 34.86 104.65 104.65 104.65
Low Speed Diesels
Cogen Gas Turbines
Steam
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 69
heating value (LHV) of fuel. While Table 20 shows the heat rate at full load and
minimum load, the actual heat rate curves were used in the model.
3.1.4.3 Annual Maintenance Rate
Annual maintenance rate is the number of hours the unit is unavailable for planned
or corrective maintenance divided by the total number of hours in the year.
Information in respect of the annual maintenance rate for the existing units was
reviewed and average values over the 5-year period (2007 – 2011) determined
based on the units’ historical data.
3.1.4.4 Forced Outage Rate
Forced outage rate is the number of hours the unit is unavailable due to emergency
outages divided by the total number of hours the unit is available. Information in
respect of the forced outage rate for the existing units was reviewed and average
values over the 5-year period (2007 – 2011) determined based on the units’
historical data.
3.1.4.5 Auxiliary Power Consumption
The auxiliary power consumption is the amount of energy used within the plant
during the production of electricity. Information in respect of the auxiliary power
consumption for the existing units was reviewed and average values over the 5-year
period (2007 – 2011) determined based on the units’ historical data.
3.1.4.6 Fixed Operating and Maintenance Cost
Information in respect of the fixed operating and maintenance cost was reviewed
and average values over a 3-year period determined based on the units’ historical
data.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 70
3.1.4.7 Variable Operating and Maintenance Cost
Information in respect of the variable operating and maintenance cost was reviewed
and average values over a 3-year period determined based on the units’ historical
data.
3.1.4.8 Nat Gas Conversion of D14/D15
When natural gas becomes available, units D14 and D15 can be converted to dual
fuel operation meaning that 92% of the units’ energy would be produced from natural
gas while the remaining 8% of the units’ energy would be produced from the pilot oil
(HFO) when the units are generating at full load. Should the gas supply be
interrupted the engines can continue operation on HFO.
For scenarios where natural gas is available, D14 and D15 are assumed to be
converted to dual fuel operation in 2017. Based on the information available, the
conversion of each unit is assumed to take three months at a cost of BDS $12.5
million per unit. The cost and performance characteristics of these units, following
the conversion, are assumed to be the same as those prior to the conversion as
outlined in Table 20.
3.2 Candidate Plant
The generating technologies considered as future generating options in this study
have been categorized into conventional fossil fuel technologies and renewable
technologies.
3.2.1 General Requirements
For the 2012 Integrated Resource Plan, only commercially and technically proven
generating technologies were considered.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 71
Commercially and technically proven technologies are those that have been
designed, constructed and operated on a commercial scale (not a pilot plant or
research facility) for at least three years in a reliable manner.
3.2.2 Conventional Candidate Plant
The choice of future supply options presented in this report is primarily based on
technologies applicable to the available fuel. Candidate plant comprises low speed
diesel units (LSD), medium speed diesel units (MSD), combined cycle plant (CCGT)
and open cycle gas turbine units (OCGT). These technologies will be modeled as
single and dual fired units.
Capital cost estimates are based upon data obtained by BL&P during an industry
scan with manufacturers10and financial lending agencies11conducted between July
and September 2012. In addition, data from The Institution of Diesel and Gas
Turbine Engineers (which collects operational and performance data on diesel and
gas turbine units around the world), the Lazard's Levelized Cost of Energy Analysis-
June 2011 report and information from BL&P’s consultant who conducted the
previous Generation Expansion Study in 2010 was considered. Performance
parameters were obtained from manufacturers during the industry scan and from
operational reports for similar plants operating in various locations around the world.
Historical data on BL&P’s plant operation has been considered when estimating cost
and performance parameters for candidate plant. Performance parameters have all
been adjusted from ISO conditions to take account of ambient conditions in
Barbados.
10
Discussions held with Man B&W, Wartsilla, BWSC, Doosan Engineering, Hyundai Heavy Industries 11
European Investment Bank, Inter-American Developmental Bank, International Financial Corporation
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 72
3.2.2.1 Low Speed Diesel Units
Low speed diesel units have been considered as candidate plant in this study. The
inclusion of these units is as a result of, but not limited to, the following reasons:
As a prime mover for electricity generation, two-stroke low speed diesels offer
very high fuel efficiencies in the range of power outputs under consideration
compared with other thermal generating plant.
Their ability to burn cheap low quality fuels while maintaining relatively high
levels of availability and reliability.
BL&P’s familiarity with two-stroke low speed diesel technology.
Compared with other reciprocating plant, two-stroke low speed diesel units have
higher installed capital costs per kilowatt, but lower operating costs per unit of
energy generated. In island utility environments, where land area for the
development of power plants is limited, these units offer a high ratio of installed
power per unit of land, but their construction times can be up to twice as long as
medium speed diesel units.
Modern low speed diesel units have thermal efficiencies in the range of 46% to 50%.
The efficiencies of these units are relatively constant across their output range and
they are not subject to significant de-rating as a result of the ambient conditions in
which they operate.
Dual fuel operation means that 92% of the unit's energy will be generated from
burning natural gas with the remaining 8% of the unit's energy being produced from
the pilot oil (HFO or diesel oil) at full load. Should the gas supply be interrupted, the
engine can continue its operation on HFO.
Based upon the selected planning criteria, the sizes of low speed diesel plant
considered are 17 MW, 30 MW and 38 MW.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 73
The low speed diesel units being considered incorporate a waste heat recovery
boiler and a turbine representing approximately 1MW of the overall plant capacity.
The cost and performance assumptions of these units have been determined with
this consideration.
The cost assumptions adopted for the low speed diesel units in the liquid case
assume that the units are designed to allow for conversion to dual-fueled operation
with minimum time and effort in the future.
Cost and performance parameters adopted for candidate plant for the liquid fuel
case are set out in Table 21 whilst the corresponding values for the dual-fueled
scenario are given in Table 22. These tables are shown at the end of this Section.
3.2.2.2 Medium Speed Diesel Units
HFO-fired as well as dual-fueled medium speed diesel units were considered as
candidate plant for the IRP study. Depending on the capacity required, multiple unit
configurations may be required due to the fact that these units are presently limited
to a maximum size of less than 20 MW. This would, therefore, require BL&P to
allocate a larger area of land per unit of capacity for medium speed units than for low
speed diesel units.
Medium speed diesel units are not as efficient as equivalent low speed diesel units
so the associated fuel costs with this type of unit are higher. Operating and
maintenance costs are also higher for medium speed units owing to their multiple
cylinder configurations and their associated maintenance schedule.
For the medium speed diesel units, dual fuel operation means that 99% of the unit's
energy will be generated from burning natural gas with the remaining 1% of the unit's
energy being produced from the pilot oil (HFO) at full load.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 74
Should the gas supply be interrupted, the engine can continue its operation on HFO.
We have included HFO-fired units for the liquid fuel scenario and the dual-fueled
units for the natural gas scenario. The cost assumptions adopted for the medium
speed diesel units in the liquid case assume that the units are designed to allow for
conversion to dual-fueled operation with minimum time and effort in the future.
Cost and performance parameters adopted for candidate plant for the liquid fuel
case are set out in Table 21 while the corresponding values for the dual-fueled
scenario are given in Table 22. These tables are shown at the end of this Section.
3.2.2.3 Open Cycle Gas Turbines
Open cycle gas turbines (OCGT) plant falls into two categories: industrial units and
aero-derivative units. The gas turbines currently operated by BL&P are classed as
industrial units. These units are of a proven design with open cycle efficiencies
between 29%and 34%. The capacity range available for this type of generation plant
is appropriate for the unit sizes to be considered for this IRP study.
Industrial OCGTs are of a robust design with high availability and low specific
maintenance costs. BL&P is already familiar with this technology and the majority of
maintenance can be done on the island with the appropriate maintenance tools.
Exceptions to this are highly specialized maintenance functions, such as refurbishing
blades.
Aero-derivative gas turbine units, as the name suggests, are land-based adaptations
of the units used in aircraft jet propulsion. These units require a smaller area for
installation (smaller footprint) and offer marginally higher open cycle efficiencies and
faster start times than industrial units. Typical efficiencies for aero-derivative units, in
the range under consideration, are between 38%and 42%.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 75
While aero-derivative gas turbine units offer advantages over the industrial units,
their overall lifecycle costs are higher due to their specialized maintenance
requirements. The typical maintenance pattern would require a spare gas generator
section, which would be installed when the main unit is undergoing repairs. This
calls for a leasing or unit exchange agreement with the vendor which, in itself, is not
a complicated arrangement but would leave BL&P exposed to higher maintenance
costs during overhauls.
For the purpose of this IRP study, we have selected 20 MW, 30 MW and 40 MW
industrial gas turbines as candidate plant.
Cost and performance parameters adopted for liquid-fired candidate gas turbines
are set out in Table 21, while the corresponding values for dual-fueled units are
given in Table 22. These tables are shown at the end of this Section.
3.2.2.4 Combined Cycle Gas Turbines
Combined cycle gas turbines (CCGTs) have specific capital costs that are
approximately 30% higher than OCGTs. They also have a much higher lifecycle
operating and maintenance costs. These higher costs are offset by the significantly
higher unit efficiencies, which are in excess of 48%.
Compared to a simple open cycle gas turbine, CCGT plant is more complex to
operate because of the presence of the additional steam cycle. CCGT units also
require large quantities of treated water for use in its boiler.
For the purpose of this generation planning study, we have selected the nominal
sizes of 30 MW and 40 MW combined cycle generating units as candidate plant.
Recognizing the relatively small unit sizes, all units are assumed to be single shaft
units in a 1+1 configuration.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 76
Cost and performance parameters adopted for liquid and gas fired candidate
combined cycle gas turbines are set out in Table 21and Table 22 respectively.
Table 21: Financial & Performance Data for Liquid Fuel Candidate Plant
Table 22: Financial &Performance Data for Natural Gas Candidate Plant
Medium
Speed Diesel
LSD17 LSD30 LSD38 MSD17 GT20 GT30 GT40 CCGT30 CCGT40
Installed Capacity (MW) 18.5 31.7 38.5 17.1 21.0 31.0 39.8 30.2 42.1
Lifetime (yrs) 30 30 30 25 25 25 25 25 25
Max No. of units built in
planning horizon20 20 20 20 20 20 20 20 20
Max No. of units built per year 3 3 3 3 3 3 3 3 3
Earliest Build Date 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017
Fuel Type HFO HFO HFO HFO Diesel Diesel Diesel Diesel Diesel
Gross Heat Rate (Btu/kWh) 7,358 7,355 7,318 7,779 10,383 9,427 9,720 7,200 6,941
Average Annual Maintenance
(Days)37 37 37 44 15 15 17 20 20
FoR (%) 3.0 3.0 3.0 4.0 4.5 4.5 4.5 5.0 5.0
Annual Availability (%) 86.9 86.9 86.9 83.9 91.4 91.4 90.8 89.5 89.5
Auxilary Power Consumption
(%)4.7 4.7 4.7 4.0 0.3 0.7 1.0 2.3 2.3
Overnight Cap.Cost 2012
($/kW)2,853 2,853 2,955 2,344 2,261 1,829 1,786 3,698 3,114
Fixed O&M (Bds$/ kW/ month) 9.58 9.17 8.75 13.75 2.17 2.17 2.17 9.17 8.75
Variable O&M
Bds$/ MWh12.00 12.00 11.00 18.00 80.00 80.00 80.00 10.00 10.00
10% variation was assumed for high and low case sensitivities on the capital, fixed and variable O & M costs
Low Speed Diesel OC Gas Turbines CC Gas Turbines
Medium
Speed
Diesel
NG-LSD17 NG-LSD30 NG-LSD38 NG-MSD17 NG-GT20 NG-GT30 NG-GT40 NG-CCGT30 NG-CCGT40
Installed Capacity (MW) 17.6 31.7 38.5 17.1 21.0 32.0 41.0 30.3 43.5
Lifetime (yrs) 30 30 30 25 25 25 25 25 25
Max No. of units built in
planning horizon20 20 20 20 20 20 20 20 20
Max No. of units built per
year3 3 3 3 3 3 3 3 3
Earliest Build Date 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017 1/1/2017
Fuel Type92% NG
8% HFO
92% NG
8% HFO
92% NG
8% HFO
99% NG
1% HFONG NG NG NG NG
Gross Heat Rate (Btu/kWh) 7,358 7,355 7,318 7,659 10,353 9,392 9,575 7,162 6,923
Average Annual Maintenance
(Days)37 37 37 44 15 15 17 20 20
FoR (%) 6.0 6.0 6.0 5.0 4.5 4.5 4.5 5.0 5.0
Annual Availability (%) 83.9 83.9 83.9 82.9 91.4 91.4 90.8 89.5 89.5
Auxilary Power Consumption
(%)6.0 6.0 6.0 5.0 1.0 1.0 1.0 2.5 2.5
Overnight Cap.Cost 2012
($/kW)3,261 3,261 3,363 2,649 2,269 1,786 1,742 3,129 2,555
Fixed O&M (Bds$/ kW/
month)9.58 9.17 8.75 13.75 0.92 0.92 0.92 9.17 8.75
Variable O&M
Bds$/ MWh12.00 12.00 11.00 18.00 80.00 80.00 80.00 10.00 10.00
10% variation was assumed for high and low case sensitivities on the capital, fixed and variable O & M costs
OC Gas Turbines CC Gas TurbinesLow Speed Diesel
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 77
3.2.3 Renewable Energy Technologies
In determining the RE technologies to be included in this IRP study, a review was
conducted of available renewable technologies and their current state of
development. Results of this review are summarized in Table 23. Only utility scale
RE technologies are included as candidate plant in the IRP. The impact of
distributed RE technologies can be accounted for under the low electricity demand
world.
Table 23: Overview of Renewable Technology Characteristics
A brief overview of each of these RE technologies is provided in the following
sections.
3.2.3.1 Solar PV
Solar photovoltaic (PV) panels are used to convert sunlight to electricity directly.
Photovoltaic conversion is the direct conversion of sunlight into electricity with no
intervening heat engine. When light photons of sufficient energy strike a solar cell,
Technology
Carbon
Neutral
State of
Technology
Customer
Located
Central
Station Intermittent Peaking
Load-
Following Base Load
Solar PV Commercial /
Evolving
Solar Thermal Emerging
Biomass Direct * Mature
Wind Mature
Geothermal Mature
MSW-to-Energy Commercial /
Evolving
Landfill Gas-to-Energy Commercial
Biogas Commercial
Tidal Barrage Emerging
Tidal Current R&D
OTEC R&D
Wave R&D
* Provided bio-crops sustainably harvested
Location Dispatch
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 78
electrons move within the silicon crystal structure, resulting in a voltage between
electrodes.
Solar photovoltaic panels are solid-state. At present, panels based on crystalline and
polycrystalline silicon solar cells are the most common. Thin-film solar panels,
especially cadmium telluride (CdTe) and copper indium gallium diselenide (CIGS)
based cells, are gaining market share because of their lower costs and increased
efficiencies. For example, the efficiencies of multi-junction cells and concentrating
PV have been reported to be as high as 40% and most panels available in the
market have efficiencies of the order of 15%.
Solar cells are arranged together on a solar module, which is installed on the roofs
of houses or in large ground mounted installations. Solar modules generate Direct
Current (DC) electricity, which needs to be converted into Alternating Current (AC)
before it can be fed into the electricity grid and used in homes and businesses. The
device used to convert DC to AC is called an inverter and thus, the two key
components of PV generation, are the modules and the inverter.
3.2.3.2 Solar Thermal
Concentrating Solar Power (CSP) plants produce electric power by converting the
sun's energy into high-temperature heat using various mirror configurations. The
heat is then channeled through a conventional generator. The plants consist of two
parts - one that collects solar energy and converts it to heat and another that
converts heat energy to electricity.
CSP systems can be sized for village power (10 kilowatts) or grid-connected
applications (up to 100 megawatts). Some systems use thermal storage during
cloudy periods or at night. The amount of power generated by a concentrating solar
power plant depends on the amount of direct sunlight. Like concentrating
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photovoltaic concentrators, these technologies use only direct-beam sunlight, rather
than diffuse solar radiation.
CSP technology utilizes three alternative technological approaches: trough systems,
power tower systems and dish/engine systems. For each of these, various design
variations or different configurations exist.
3.2.3.3 Biomass
Biomass is any organic matter that is available on a renewable or recurring basis
and includes forest and mill residues, agricultural crops and wastes, wood and wood
wastes, animal wastes, livestock operation residues, aquatic plants and municipal
and industrial wastes. Biomass can be used in solid form or converted into gaseous
or liquid form before use.
The biomass sector is varied both from a technological and an input fuel
perspective. The technologies range from those that are proven commercially (for
example, solid fuel combustion), through to those that are entering commercial
demonstration and proving commercial reliability (for example, gasification).
To effectively develop productive energy from biomass resources, a number of
considerations need to be addressed such as availability of resources, economics of
collection, storage and transportation and evaluating and delivery of technical,
environmental and publicly acceptable options for conversion into useful electricity
(and heat). The availability of the feedstock in close proximity to the biomass power
project, is a critical factor in the efficient utilization of this resource and will often
dictate the technology and size of the proposed project, in addition to dramatically
impacting on the financial model (for example, quantity of fuel needed, maintenance
cycle, cost of fuel/gate fee).
The main biomass fuels available include:
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Energy crops
Crop residues: cane trash
Stemwood: hardwood and softwood tree trunks
Forestry residues: wood chips from branches, tips and poor quality stemwood
Sawmill co-product: wood chip, sawdust and bark
Arboricultural arisings: stemwood, wood chips, branches and foliage
Waste wood: clean and contaminated
Organic waste: paper/card, food/kitchen, garden/plant and textiles wastes
Sewage sludge: from waste water treatment
Animal manures/slurry: from cattle, pigs, sheep and poultry
Landfill gas: captured from biodegradable waste decomposition
First generation bio-fuels: ethanol (from sugar and starch crops), bio-diesel
from oil crops
Algae: oil and biomass from photosynthetic algae (are emerging as a
potential fuel source).
Biomass can be converted into electric power through several methods. The most
common is direct combustion of biomass material, such as agricultural waste or
woody materials. Other options include gasification, pyrolysis, and anaerobic
digestion. Gasification produces a synthesis gas, with usable energy content, by
heating the biomass with less oxygen than needed for complete combustion.
Pyrolysis yields bio-oil by rapidly heating the biomass in the absence of oxygen.
Anaerobic digestion produces a renewable natural gas when organic matter is
decomposed by bacteria in the absence of oxygen.
Different methods work best with different types of biomass. Typically, woody
biomass such as wood chips, pellets, and sawdust are combusted or gasified to
generate electricity. Very wet wastes, like animal and human wastes, are converted
into a medium-energy content gas in an anaerobic digester. In addition, most other
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types of biomass can be converted into bio-oil through pyrolysis, which can then be
used in boilers and furnaces.
Compared to many other renewable energy options, biomass has the advantage of
dispatchability, meaning it is controllable and available when needed, similar to fossil
fuel electric generation systems. The disadvantage of biomass for electricity
generation however, is that the fuel needs to be procured, delivered, and stored.
Also, biomass combustion produces emissions, which must be carefully monitored
and controlled to comply with regulations.
The efficiency of a direct combustion or biomass gasification system is influenced by
a number of factors, including biomass moisture content, combustion air distribution
and amounts (excess air), operating temperature and pressure and flue gas
(exhaust) temperature.
The biomass application being investigated for Barbados is a fixed-bed direct
combustion system with cane bagasse and Leucaena (referred to locally as “river
tamarind”) as the fuel sources.
3.2.3.4 Anaerobic Digestion / Biogas
Anaerobic Digestion (AD) is a process whereby bacteria break down organic
feedstocks in the absence of oxygen to produce a gas that is rich in methane. The
resulting biogas can be used in direct combustion to generate heat and/or power, or
be further refined to produce bio-methane for vehicle fuel or injection into the gas
grid network. The by-product is an organic digestate that has potential to be returned
to the land as soil improver.
The technological developments in AD are not so much associated with the
generation equipment, but more with the Digester technology and the clean-up of
the resultant gases before combustion. Electricity generation from biomass is often
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achieved using gas engine generators, which are largely based upon established
diesel technology. Only relatively minor adjustments are necessary for the different
fuel types. Leading gas engine suppliers offer an energy conversion efficiency of up
to 42% and no significant efficiency increases are expected in the future.
3.2.3.5 Landfill Gas-to-Energy
Landfill gas is generated through the degradation of municipal solid waste (MSW) by
microorganisms. The quality of the gas is highly dependent on the composition of
the waste, presence of oxygen, temperature, physical geometry and time elapsed
since waste disposal. In anaerobic conditions, as is typical of landfills, methane and
CO2 are produced in equal amounts. Methane (CH4) is the important component of
landfill gas as it has a calorific value of 33.95 MJ/Nm3 which gives rise to energy
generation benefits. The amount of methane that is produced varies significantly
based on the composition of the waste. Most of the methane produced in MSW
landfills is derived from food waste, composite paper and corrugated cardboard. The
rate of landfill gas production varies with the age of the landfill.
Landfill gas is gathered from landfills through extraction wells placed, depending on
the size of the landfill. Landfill gas must be treated to remove impurities, condensate,
and particulates. The treatment system depends on the end use. Minimal treatment
is needed for the direct use of gas in boiler, furnaces, or kilns. Using the gas in
electricity generation typically requires more in-depth treatment. If the landfill gas
extraction rate is large enough, a gas turbine or internal combustion engine could be
used to produce electricity to sell commercially or use on site.
3.2.3.6 Wind Energy
Wind power is the conversion of wind energy into a useful form of energy, such as
using wind turbines to make electrical power, windmills for mechanical power, wind
pumps for water pumping or drainage, or sails to propel ships. A wind farm consists
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of several individual wind turbines which are connected to the electric power
transmission network.
On-shore wind is a mature renewable technology, which appears to have converged
on a horizontal axis (generally three-blade) machine. The basic equipment varies
little between sites and scales, with steel tubular towers being the predominant
support for wind turbine generators (WTG) above 1 MW.
Offshore-wind is at an early stage of deployment, with only a decade since the first
commercial installation in Denmark. Offshore wind farms can harness more frequent
and powerful winds than are available to land-based installations and have less
visual impact on the landscape, but construction costs are considerably higher and
they must be installed in relatively shallow water.
3.2.3.7 Waste-to-Energy (WtE)
Waste-to-Energy (WtE) technologies range from the mature application of direct
incineration to emerging technologies which process the waste to another form for
combustion to avoid direct combustion.
The dominant WtE technology is incineration, chiefly because of its relatively low
capital cost and operating risks. Some separation or pre-processing of the waste
may be required for the various processes. The main incineration technologies
utilized worldwide are moving grate, fluidized bed and rotary kiln combustion
chambers. Exhaust gas boilers, steam turbines, turbo alternators and flue gas
cleaning systems complete the electricity generation process. These incineration
systems form the majority of the world’s WtE facilities.
Alternative thermal WtE technologies are, at this stage, more expensive and carry
greater operating risks.
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3.2.3.8 Tidal Barrage
Tidal power is a form of hydropower derived from tidal flows and currents. Tidal
power may be tapped by two main means.
Tidal barrage technologies: these employ potential energy by entrainment of tidal
floods to capture water for the movement of low-head turbines.
Tidal stream technologies: these employ kinetic energy by harnessing currents to
move turbines in a manner similar to wind turbines.
Tidal barrage technology is one of the most mature technologies available for
harnessing tidal energy. It is best suited for regions where the local geography
results in a large tidal range in a suitable channel.
The development of tidal barrage systems has been hampered by the large
infrastructural cost of such projects, their long construction times as well as
opposition to their environmental impacts.
Tidal stream technology is immature, with most prototypes having been deployed
only within the last ten (10) years but is being facilitated by the increasing availability
of test berths and hubs.
3.2.3.9 Ocean Thermal Energy Conversion (OTEC)
OTEC uses the temperature difference between cooler deep and warmer shallow, or
surface ocean waters, to run a heat engine and produce useful work, usually in the
form of electricity. However, if the temperature differential is small, this impacts the
economic feasibility of ocean thermal energy for electricity generation. OTEC plants
pipes in hot and cold seawater and run them through heat exchangers and water
condensers, in the process spinning turbines that generate electricity. It can only be
done efficiently where the thermal gradient within the upper 1,000 meters of the
ocean is more than 20° Celsius.
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The most commonly used heat cycle for OTEC is the Rankine cycle using a low-
pressure turbine. Systems may be either closed-cycle or open-cycle. Closed-cycle
engines use working fluids that are typically thought of as refrigerants such as
ammonia or R-134a. Open-cycle engines use vapour from the seawater itself as the
working fluid.
OTEC can also supply quantities of cold water as a by-product. This can be used for
air conditioning and refrigeration and the fertile deep ocean water can feed biological
technologies. Another by-product is fresh water, distilled from the sea.
Demonstration plants were first constructed in the 1880s and continue to be built,
but no large-scale commercial plants are in operation.
3.2.3.10 Wave Energy
Wave power is distinct from the diurnal flux of tidal power and the steady gyre of
ocean currents. Wave-power generation is not currently a widely employed
commercial technology, although there have been attempts to use it since at least
1890.
Wave power devices are generally categorized by the method used to capture the
energy of the waves, by location and by the power take-off system. Method types
are point absorber or buoy; surfacing following or attenuator, oriented parallel to the
direction of wave propagation; terminator, oriented perpendicular to the direction of
wave propagation; oscillating water column and overtopping. Locations are
shoreline, near shore and offshore. Types of power take-off include hydraulic ram,
elastomeric hose pump, pump-to-shore, hydroelectric turbine, air turbine and linear
electrical generator. Some of these designs incorporate parabolic reflectors as a
means of increasing the wave energy at the point of capture. These capture systems
use the rise and fall motion of waves to capture energy. Once the wave energy is
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captured at a wave source, power must be carried to the point of use or to a
connection to the electrical grid by transmission power cables.
3.2.3.11 Energy Storage Options
There are three battery storage options available for consideration: Flow Battery
(Vanadium-Mixed Acid), Lead Acid and Sodium Sulfur (NaS). Other forms of energy
storage, like compressed air and hydro pumped storage, are not considered in this
evaluation due to geographical limitations on the island. The three batteries have
significantly different capital and operating costs but provide the same level of
generation. All batteries have an efficiency of 70%. The estimates presented here
are representative in nature. Concept design and quotes from vendors would be
required to get accurate cost estimates.
Table 24 provides a comparison of cost and technical characteristics for these three
battery options to provide firm capacity for wind energy in the IRP model (BEW
Engineering, 2012).
Flow Battery Lead Acid Sodium Sulfur
Capital Cost ($/kW) 700 600 200
Energy Rate ($/kWh) 150 250 570
O&M ($/yr) 6,400 32,000 32,000
Mean Time to Repair 2 N/A N/A
Life (years) 20 20 20
Efficiency (%) 70 70 70
Table 24: Cost & Technical Characteristics of Battery Storage Options (Source: BEW Engineering, 2012)
In evaluating the option of coupling storage with wind or solar technologies, the
approach taken was to first evaluate a storage option coupled with the most
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economical intermittent RE option, i.e. wind energy. The cost of storage required to
provide firm capacity with wind generation is less than that associated with
equivalent solar capacity. This is because solar energy is only available for half of
the day and therefore has a lower capacity factor. The “wind with storage” option
was found to be uneconomic and therefore the “solar with storage” option was not
considered.
Table 25 shows the amount of battery storage needed to support 10%, 20% and
30% firm capacity for a 1MW wind turbine, based on wind speed characteristics at
the proposed Lamberts wind farm site. For a 100 kW battery, there are about four (4)
days of low wind that require 7.64 MWh of battery energy. The battery cost varies
from $1.21 million to $4.35 million, depending on the battery type. For a 300 kW
battery, the number of days increases to seven (7) and the capital costs increase
about five to six times the 100 kW battery. The 100kW (10%) flow battery storage
option was modeled in the IRP.
Size
(KW)
Energy
(MWh)
Flow Lead Acid Sodium Sulfur
100 7.64 $1.21 million $1.9 million $4.35 million
200 22.46 $3.5 million $5.7 million $12.8 million
300 39.42 $6.1 million $10.0 million $22.5 million
Table 25: Battery Cost Estimates (Source: BEW Engineering, 2012)
3.2.3.12 Geothermal
Geothermal power is generated by using steam or a hydrocarbon vapour to turn a
turbine generator set to produce electricity. There are currently three main types of
geothermal power plants:
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Dry steam plants using steam from underground wells to rotate a turbine, which
activates a generator to produce electricity. Dry steam power plants systems
were the first type of geothermal power generation plants built.
Flash steam plants using hot-water resources, which are ‘flashed’ by reducing
the pressure, to produce steam (normally in the 15% - 20% dryness range).
Some plants use double and triple flash to improve the efficiency. The steam is
then used to power a generator and any leftover water and condensed steam is
returned to the reservoir.
Binary Cycle or Organic Rankine Cycle (ORC) plants using the heat from
lower temperature reservoirs to boil a working fluid, which is then vaporized in a
heat exchanger and used to power a generator. Usually, a wet or dry cooling
tower is used to condense the vapour after it leaves the turbine, to maximize the
temperature and pressure drop between the incoming and outgoing vapour and
thus increase the efficiency of the operation. The hot water, which never comes
into direct contact with the working fluid, is then injected back into the ground to
be reheated.
Geothermal energy is not available in Barbados. The potential for geothermal
development does, however, exist in neighboring islands, which could present an
opportunity for energy import by subsea cables in the future.
3.2.3.13 Subsea DC Cables
Subsea High Voltage Direct Current (HVDC) cables, when installed, form the
backbone of an electric power system. They combine high reliability with a long
useful life. The core component is the power converter, which serves as the
interface to the AC transmission system. The conversion from AC to DC and vice
versa, is done by controllable electronic switches in a three-phase bridge
configuration. Two advantages HVDC has over AC transmission are there is no
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technical limit to the length of a HVDC cable connection (the upper limit on AC
submarine transmission is around 110km) and there is no requirement that the
linked systems run in synchronism.
The four closest islands to Barbados for which submarine electrical cable
interconnections might be considered are St. Lucia, St. Vincent, Grenada and
Trinidad & Tobago (T&T). The first three predominantly use diesel for electricity
generation, but the potential for geothermal electricity production exists. No
geothermal feasibility studies have been to date done in any of these three islands,
so the true potential remains uncertain. An electrical connection to T&T would
provide potential access to relatively low cost natural gas fired generation. The
distance between T&T and Barbados is well over the upper limit for viable AC
submarine transmission and therefore HVDC would be required. The water depth
between the two islands exceeds6000 feet in areas which exceed current record set
by the SAPEI in the Mediterranean Sea at depths of up to 1,600 metres.
In 2010, the World Bank commissioned a study on ‘Caribbean Regional Electricity
Generation, Interconnection and Fuels Supply Strategy’ conducted by Nexant, which
screened energy interconnection options between islands in the Caribbean.
Potential submarine cable interconnections were evaluated for several Caribbean
islands. However, for Barbados, the report focused primarily on the potential for a
natural gas pipeline link between T&T and Barbados and did not consider any
submarine cable links in any detail.
3.2.4 RE Technology Assumptions
In the IRP study, only commercially and technically proven RE generating
technologies were considered. Commercially and technically proven technologies
are defined as those that have been designed, constructed and operated on a
commercial scale (not a pilot plant or research facility) for at least three years in a
reliable manner.
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The RE technologies that were considered in the current study are listed in Table 26.
The technologies that will not be considered in the current study are identified in
Table 27. These technologies will continue to be monitored and will be included in
future studies when technically and commercially proven.
Technology Scale
Capacity of each
installation (MW) Notes
Solar PV Utility 1
Distributed <0.15 This will be considered as part of the DSM initiatives.
Wind Utility 1
Distributed <0.15 This will be considered as part of the DSM initiatives.
Biomass Utility 25
Anaerobic Digestion Utility 1.25
Waste-to-Energy Utility 13.5
Landfill Gas-to-Energy Utility 2
Wind With Storage Utility 1
Wind with 10% storage from flow batteries. 10% of capacity treated as firm.
Table 26: Summary of RE Technologies Included In Study
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Technology Firm cap
State of Technology
Indigenous Resource Notes
OTEC Yes R&D Yes No commercial applications. High Risk.
Subsea DC cable from neighboring islands Yes
Commercial/ Evolving No
Water depths between Barbados and neighboring islands around 6,000 feet. Deepest existing submarine cable (SAPEI) at 5,200 feet and 260 miles.
Off shore wind No Evolving Yes
Water depths beyond 1 mile of Barbados coast exceed limit for commercially available technologies (<100’ depths)
Solar Thermal No Emerging Yes
Wave No R&D Yes
Tidal Barrage No Emerging Yes Future potential low due to small tidal variations.
Tidal Current No R&D Yes Future potential low due to small tidal variations.
Table 27: RE Technologies Excluded From IRP Study
An industry scan12 was conducted to determine the cost and performance
parameters for the RE technologies modeled in the IRP. Information on the sources
utilized can be found in Appendix H. Cost estimates from technology providers were
also used in determining some of the assumptions.
The RE assumptions used in the current IRP study are summarized in
Table 28.
12
Discussions held with Uriel Renewables, Barbados Cane Industry Corporation, European Investment Bank,
Inter-American Developmental Bank, International Financial Corporation
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Table 28: RE Technology Assumptions
ANAEROBIC
DIGESTIONBIOMASS
IMPORTED
BIOMASS
LANDFILL
GASSOLAR
WASTE
TO
ENERGY
WINDWIND WITH
STORAGE
Capacity per unit
(MW)1.3 25.0 25.0 1.5 1.0 13.5 1.0 1.0
Firm Capacity (MW) 1.3 25.0 25.0 1.5 0.0 13.5 0.0 0.1
Max No. of units built
in planning horizon2 1 1 (Note 1) 1 20 (Note 2) 1 12 (Note 3) 12 (Note 3)
Max No. of units built
per year1 1 1 1 1 1 5 5
Earliest Build Date 1/1/2016 1/1/2018 1/1/2020 1/1/2016 1/1/2016 1/1/2018 1/1/2016 1/1/2016
Configuration Digester
Steam
Turbine,
Biomass
boiler
Steam
Turbine,
Biomass
boiler
Reciprocati
ng Engine
Ground
Mounted
Boiler &
Turbine
Lifetime (yrs) 20 30 30 20 20 30 20 20
Output
22.1 MW-
7months/yr;
18.5 MW-
3 months/yr
Modeled
using solar
profile
Modeled
using wind
profile
Modeled
using wind
profile
Capacity Factor 75.0 90.0 90.0 85.0 85.0 32.0 32.0
Fuel
Farm, Food,
Brewery
Waste
Bagasse/
BiomassBiomass Landfill Gas
Landfill
Material
Heat Rate (Btu/kWh) 10,250 13500 13500 10,060
Forced Outage Rate
(%)8.0 3.0 3.0 8.0 6.0 3.0 3.0
Average Annual
Maintenance (Days)14 28 28 14 1 30 4 4
Auxiliary Power
Consumption (%)11.6 11.6 4.0 7.0 1.9 1.9
Overnight Capital
Cost ($/kW)
11,000 -
19,000
7,000 -
10,000
7,000 -
10,000
4,500 -
7,500
3,000 -
6,000
18,000 -
25,000
4,500 -
7,500
8,518 -
11,518
Fixed O & M Cost
($/kW/yr)300 - 1,500 200 - 300 200 - 300 400 - 1,200
50.00 -
80.00
700 -
1,40060 - 150 125 - 215
Variable O & M
($/MWh)15
12.00 -
18.0012.00 - 18.00
15.00 -
20.00
Note 1 - An additional imported biomass plant is available for selection from 1/1/2025 in the LF + Ref + NGr scenario in the high demand world.
Note 2 - 50 solar units are available for selection in the LF + Ref + NGr scenario in the high demand world.Note 3 - Wind and Wind with storage units available for selection as follows: 2 units - 1/1/2016; 5 units -1/1/2018; 12
units - 1/1/2020.
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3.2.5 Environmental Criteria
Several of the technologies used to generate electricity result in CO2 being
produced. From an environmental perspective it is useful to determine the amount of
CO2 produced by each expansion scenario. The volume of CO2 produced from each
of the generating technologies considered in this study were derived using the
carbon coefficients from the U.S. Environmental Protection Agency (2004) along
with the average heat rate values for existing and candidate technologies.
Different technologies have different land area requirements. For this reason it is
useful to report the land requirements for different expansion scenarios. Industry
publications along with BL&P’s own experience were used in arriving at the land
requirement areas for the different technologies. Some of these assumptions were
also determined based on information supplied by stakeholders during the
stakeholder consultations. The land requirements for existing units, along with that
for previously contemplated projects, were also considered. Publications used
included CEC (2005); correspondence from suppliers of medium and low speed
diesel units and solar generators and feasibility reports prepared for BL&P.
According to PAHO (2013), Barbados is ranked as the 15thwater scarce country in
the world. As a result it is prudent to determine the amount of water required for
each expansion scenario. Water consumption for the technologies included in the
study was determined using industry performance reports along with BL&P’s
operating experience. Publications referenced included NREL (2011), Mielkeet. al
(2010) and CEC (2005).
The assumptions for CO2, land usage and water usage used in the study are shown
in Table 29.
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Technology
CO2 Coefficient (kg CO2/MWh)
Land Usage acres/MW
Water Usage (gal/MWh)
Existing Generation
Steam – HFO 1048.0 N/A 73
Low Speed Diesel – HFO 630.4 N/A 10
Gas Turbine 881.3 N/A 1
Candidate Conventional
Low Speed Diesel – HFO 734.4 0.06 10
Low Speed Diesel - Natural Gas 551.8 0.06 10
Medium Speed Diesel – HFO 514.1 0.08 10
Medium Speed Diesel - Natural Gas 371.4 0.08 10
Gas Turbine – Diesel 575.2 0.03 1
Gas Turbine - Natural Gas 376.7 0.03 1
Combined Cycle Gas Turbine - Diesel 591.0 0.05 30
Combined Cycle Gas Turbine - Natural Gas 387.3 0.05 30
Candidate Renewables
Biomass N/A 0.06 553
Solar N/A 5.5 2
Wind N/A 30 0
Anaerobic Digestion N/A 3.75 235
Waste to Energy N/A 12 553
Landfill Gas N/A 3.75 350
Table 29: Environmental Impact Assumptions
3.3 Levelized Costs
The Levelized Cost of Energy (LCOE) is a methodology used to compare the life-
cycle cost of producing a unit of electricity from various technologies. It is defined by
the US Energy Information Administration as “the present value of the total cost of
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building and operating a generating plant over an assumed financial life and duty
cycle, converted to equal annual payments and expressed in terms of real dollars to
remove the impact of inflation”13. According to the US EIA14, it provides a convenient
summary measure of the overall competitiveness of different generating
technologies. It serves as a useful tool for policy discussions, but evaluates
technologies on a ‘stand-alone’ basis and therefore cannot be used as the basis for
determining expansion requirements.
Levelized costs for the various technologies considered in the IRP were calculated
using the Economic and Candidate Plant Assumptions for 2017 as outlined in
Appendix G. The results are presented in Figure 15, with the ranges reflecting the
low and high sensitivity values for capital (including interest during construction),
O&M and fuel costs. The results shown on the chart are expressed in terms of net
generation and bus bar costs.
The specific formulae used in the levelized cost calculations are as follows:
LCOE = I + O&M + F
Where, I = annualized investment cost (BDS$/kWh)
O&M = operation and maintenance cost (BDS$/kWh)
F = fuel cost (BDS$/kWh)
and I = Capital cost x Capital Recovery Factor
Capital Recovery Factor = i(1+i)n
(1+i)n-1
13
http://www.eia.gov/forecasts/aeo/pdf/2016levelized_costs_aeo2011.pdf 14
http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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Figure 15: Levelized Costs Based On Base Assumptions
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4 MODELING METHODOLOGY
4.1 Worlds and Scenarios
Specific plans will always be subject to uncertainty and changes in input
assumptions. Prudence therefore dictates that plans be developed and evaluated
across a range of plausible input assumptions and external market conditions. To
assess the inherent risks and uncertainties, a scenario planning approach was used
in the development of the IRP and final recommendation.
The IRP study considered three possible electricity demand growth ‘worlds’ derived
from the econometric model described in Section 2.3. These are:
High Demand (3.0% avg. annual growth)
Base Demand (1.2% avg. annual growth)
Low Demand (-0.4% avg. annual growth)
For each of these demand worlds, five scenarios representing plausible future paths,
relating to fuel types and technologies used, were evaluated, resulting in a total of
fifteen scenario and world combinations. The planning model was then allowed to
select the least-cost mix of resources for each scenario and world combination.
Further uncertainty surrounding input assumptions were addressed, by conducting
sensitivity tests to examine the impacts that changes in capital costs, fuel costs and
discount rates had on the twelve least-cost plans.
As to be expected, the time and effort involved in completing the study is
proportional to the number of scenario and world combinations modeled. Careful
consideration was therefore given to the following factors when selecting the
scenarios and worlds:
Plausibility – How likely is it to occur?
Uniqueness – How different is it from other Worlds and Scenarios?
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Stress test – Does it place sufficient stress on the resource selection
process?
Stakeholder interests – Does it capture key stakeholders’ interests?
Regulatory & Policy – Is it consistent with regulatory and policy requirements?
The five scenarios selected for the IRP are defined around the fuel type and
technologies used in the generation of electricity.
Scenario 1 represents a future in which only liquid fuels (i.e. HFO, diesel and Jet
A1) along with renewable energy options described in section 3.2.4 are available for
selection in the expansion plan. This scenario is abbreviated ‘Scenario 1: LF+RE’ in
the IRP.
Scenario 2 builds on the first scenario by introducing the availability of imported
natural gas and consequently the model is permitted to select dual-fuel gas burning
reciprocating engines and simple and combined cycle gas turbines in addition to the
generating options in scenario 1. This scenario is abbreviated ‘Scenario 2:
LF+RE+NG’ in the IRP.
Scenario 3 represents a variation of Scenario 2 in which the model is restricted from
selecting simple and combined cycle gas turbines. This scenario was introduced as
a hedge against the fuel price shocks that would occur in the event that there were
gas supply interruptions, requiring gas turbines to switch from natural gas to diesel.
Diesel prices in the model are projected to be around 75% higher than natural gas
prices. This scenario is abbreviated ‘Scenario 3: LF+RE+NGr’ in the IRP.
Scenario 4 is a variation of Scenario 3, in which the model is forced to achieve 29%
renewable energy generation by 2029, based on the indicative target identified in the
SEFB report. This scenario was introduced because the indicative target was not
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 99
being achieved in scenarios 1 to 3. This scenario is abbreviated ‘Scenario 4:
LF+REf+NGr’ in the IRP.
Scenario 5 is a variation of Scenario 1, in which the model is forced to achieve 29%
renewable energy generation by 2029, based on the indicative target identified in the
SEFB report. This scenario was introduced because the indicative target was not
being achieved in scenario 1.This scenario is abbreviated ‘Scenario 5: LF+REf’ in
the IRP.
A summary of the five scenarios and their associated fuels and technologies is
presented in Table 30.
Table 30: Scenario Matrix of Fuels & Technologies
4.2 Sensitivities
Sensitivity studies are usually undertaken to assess the impact of uncertainties that
are inherent within the assumptions employed. Sensitivity tests were conducted as
part of this study.
After determining the optimal plan using the base assumptions for each scenario,
sensitivities were performed on the optimal plans. Sensitivities were conducted in
relation to:
Fuel: Base, High and Low fuel projections as identified in the Fuel
Assumptions in Section 2.4.
Scenario 1:
LF+RE
Scenario 2:
LF+RE+NG
Scenario 3:
LF+RE+NGr
Scenario 4:
LF+REf+NGr 1
Scenario 5:
LF+Ref 1
Liquid Fuel (LF)
Natural Gas (NG) x x
Renewable Energy (RE)
Gas Turbines 2
x x
Notes
1. The model is forced to install 29% RE by 2029 in scenarios 4 & 5.
2. Gas turbines excluded in scenarios 3 & 4 due to high gas interruption cost
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 100
Cost: Base, High and Low capital and O&M costs as identified in the
Technology Assumptions in Section 3.2.
Discount Rate: Base, High and Low discount rates as identified in the Economic
Assumptions in Section 2.2.1.
The NPV results for the sensitivities are reported in Section 5.2.
4.3 Software Model
The software package used during the study was the PLEXOS 6.208R08Utility
Planning and Risk Management Software by Energy Exemplar. The Plexos software
is used by utilities, the ISO, consulting firms and regulatory agents for operations,
planning and market and transmission analyses. Plexos is a Mixed Integer
Programming (MIP) energy market simulation and optimization software package,
which is licensed in the United States, Europe, Asia-Pacific, Russia and Africa and
used at over 100 sites.
The software seeks to minimize the net present value of forward-looking costs (i.e.
capital and production costs), subject to fuel mix constraints including renewable
energy targets, reliability and security of supply criteria and normal operating
constraints.
The planning horizon fuel and demand forecasts, typical load duration curve,
existing plant and candidate plant data, reliability criteria as well as other criteria and
constraints are inputted into the model and used in determining the least-cost plan.
Using the Plexos software, a model was built to model BL&Ps current system, along
with assumptions for the candidate plant. Energy Exemplar was contracted to
perform an independent review of the completed model to ensure that it reflected the
assumptions being model. The report of the review is included in Appendix AA.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 101
5 RESULTS
5.1 Expansion Plans
Table 31 shows the net present value results for the fifteen scenarios in the base,
high and low electricity demand ‘worlds.’
Worlds Scenarios Description NPV ($000)
Base
Scenario 1 LQ + RE 4,985,051
Scenario 2 LQ + RE + NG 4,227,676
Scenario 3 LQ + RE + NGr 4,457,170
Scenario 4 LQ + REf + NGr 4,645,222
Scenario 5 LQ + REf 5,035,424
High
Scenario 1 LQ + RE 5,961,262
Scenario 2 LQ + RE + NG 4,937,955
Scenario 3 LQ + RE + NGr 5,185,558
Scenario 4 LQ + REf + NGr 5,365,404
Scenario 5 LQ + REf 6,095,605
Low
Scenario 1 LQ + RE 4,112,078
Scenario 2 LQ + RE + NG 3,904,750
Scenario 3 LQ + RE + NGr 3,942,138
Scenario 4 LQ + REf + NGr 4,080,506
Scenario 5 LQ + REf 4,113,915
Table 31: NPV Results for Worlds and Scenarios
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 102
Table 32 summarizes the performance of each scenario’s least-cost expansion plan
in relation to several additional criteria.
Table 32: Characteristics of Least-Cost Plans
5.1.1 Base Demand World
In the base world, the electricity demand is predicted to grow at an average of 1.2%,
per annum, over the planning period.
The liquid +RE scenario requires the installation of 314.2 MW of new capacity over
the planning period according to the build schedule shown in Table 33. Landfill gas,
anaerobic digestion, wind and solar renewable technologies all feature in the optimal
plan, representing 20.0% of energy generated in 2036. The net present value of this
plan is $4.985 billion.
Worlds Scenarios NPV ($000)
C02
(million
MT)
Water
(million
Ga)
Land Use
(acres)
Fuel
Diversity
Foreign
Exchange
($000) Achievability
2017 Gas
Interruption
Cost ($000)
Renew %
in 2029
Renew % in
2036
LQ + RE 4,985,051 18,316 2,512 523 35.94% 4,452,779 High 0 20.8% 20.0%
LQ + RE + NG 4,227,676 13,889 769 70 42.78% 3,916,366 Medium 97,864 0.9% 3.3%
LQ + RE + NGr 4,457,170 15,589 430 31 47.58% 4,074,542 Medium 51,947 1.7% 2.3%
LQ + REf + NGr 4,645,222 13,556 2,480 687 71.11% 4,105,925 Low 39,485 29.0% 29.0%
LQ + REf 5,035,424 17,615 2,958 749 42.78% 4,464,125 Medium 0 29.5% 29.0%
LQ + RE 5,961,262 23,698 2,587 842 31.35% 5,376,707 High 16.6% 15.0%
LQ + RE + NG 4,937,955 16,672 1,819 708 59.37% 4,499,457 Medium 15.8% 14.6%
LQ + RE + NGr 5,185,558 20,461 1,752 993 64.32% 4,687,628 Medium 14.3% 19.8%
LQ + REf + NGr 5,365,404 17,263 3,264 972 71.28% 4,800,408 Low 19.4% 29.0%
LQ + REf 6,095,605 22,109 3,718 952 43.67% 5,452,355 Medium 29.0% 29.0%
LQ + RE 4,112,078 13,711 2,447 344 41.47% 3,616,876 High 27.8% 27.4%
LQ + RE + NG 3,904,750 11,728 289 17 50.83% 3,625,233 Medium 1.3% 2.3%
LQ + RE + NGr 3,942,138 12,009 304 14 50.78% 3,614,724 Medium 1.3% 1.2%
LQ + REf + NGr 4,080,506 10,865 1,817 281 72.94% 3,302,322 Low 29.0% 29.0%
LQ + REf 4,113,915 13,615 2,471 337 43.56% 3,614,519 Medium 29.0% 29.0%
Base
High
Low
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 103
Table 33: Build Schedule for Liquid + RE Scenario in Base Demand World
In the Liquid +NatGas+ RE scenario, 284.0 MW of new capacity is required over the
planning period which is made up predominately by open cycle and combined cycle
gas turbines, as shown in Table 34. RE technologies begin to feature in this plan in
2033, with the installation of one 1.5 MW landfill gas unit and one 1.0 MW solar unit.
Additional RE capacity is added in the period 2034 to 2036 with landfill gas, solar,
Capacity Retired Total Capacity Peak Demand Reserve Margin1
LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 11.5
L/fill Gas – 1 x 1.5 MW
Wind – 2 x 1 MW
Solar - 8 x 1 MW 250.6 158.6 37.2 0.209
2017 53 70.6
LSD30 – 1 x 30 MW
LSD17 – 2 x 17 MW
L/fill Gas – 1 x 1.5 MW 268.2 160.3 48.1 0.017
2018 26
Biomass - 1 x 25 MW
Wind – 1 x 1 MW 294.2 161.1 61.0 0.001
2019 51.5 31.7 LSD17 – 1 x 17 MW 274.4 164.6 49.3 0.022
2020 274.4 167.2 46.9 0.028
2021 1 Wind – 1 x 1 MW 275.4 169.9 44.6 0.052
2022 13 262.4 172.4 36.2 0.223
2023 262.4 174.7 34.4 0.278
2024 262.4 177.0 32.6 0.362
2025 20 32
GT30 – 1 x 30 MW
Wind – 1 x 1 MW 274.4 179.2 37.1 0.230
2026 274.4 181.5 35.4 0.278
2027 20 18.7 LSD17 – 1 x 17 MW 273.1 184.1 32.5 0.323
2028 20 31 GT30 – 1 x 30 MW 284.1 186.7 36.5 0.240
2029 1 Wind – 1 x 1 MW 285.1 189.5 34.4 0.264
2030 285.1 192.1 32.6 0.289
2031 18.7 LSD17 – 1 x 17 MW 303.8 194.7 40.1 0.124
2032 1 Wind – 1 x 1 MW 304.8 197.2 38.3 0.184
2033 304.8 199.8 36.5 0.222
2034 304.8 202.5 34.7 0.246
2035 304.8 205.4 32.8 0.287
2036 73.1 70.95
LSD38 – 1 x 38 MW
LSD17 – 1 x 17 MW
Wind – 7 x 1 MW
L/fill Gas – 1 x 1.5 MW
Solar - 4 x 1 MW
Ana. Digestion – 1 x 1.25 MW
Retire
Wind – 2 x 1 MW
L/fill Gas – 1 x 1.5 MW
Solar - 8 x 1 MW 302.65 208.1 32.4 0.402
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 104
anaerobic digestion and wind with storage units being added to the system. By the
end of the planning period, RE technologies account for 7.25 MW. Overall, RE
technologies account for 3.3% of the energy generated in 2036. This scenario, at a
cost of $4.228billion, has the lowest net present value cost of all the base world
scenarios.
Table 34: Build Schedule for Liquid + NatGas + RE Scenario in Base Demand World
Table 35 shows the build schedule for the Liquid + Natural Gas Restricted + RE
scenario, which requires a total of 293.3MW of new capacity over the planning
period, made up predominately of natural gas and HFO burning reciprocating
engines. Landfill gas generating technologies are included in the optimal plan from
2026 and account for 3.0 MW of installed capacity by 2030. The RE technologies in
Capacity Retired Total Capacity Peak Demand Reserve Margin1LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 239.1 158.6 36.2 0.252
2017 53 122.9
NG-CCGT30 – 3 x 30 MW
NG-GT30 – 1 x 30 MW 309 160.3 79.8 0.013
2018 309 161.1 78.9 0.001
2019 51.5 257.5 164.6 48.3 0.132
2020 257.5 167.2 46.0 0.207
2021 257.5 169.9 43.6 0.302
2022 13 244.5 172.4 35.2 0.477
2023 30.3 NG-CCGT30 – 1 x 30 MW 274.8 174.7 50.4 0.104
2024 274.8 177.0 48.4 0.143
2025 20 254.8 179.2 35.5 0.502
2026 254.8 181.5 33.8 0.509
2027 20 31 GT30 – 1 x 30 MW 265.8 184.1 37.8 0.515
2028 20 30.3 NG-GT30 – 1 x 30 MW 276.1 186.7 41.1 0.543
2029 276.1 189.5 39.0 0.543
2030 276.1 192.1 37.2 0.543
2031 276.1 194.7 35.3 0.543
2032 276.1 197.2 33.6 0.543
2033 2.5
L/fill Gas – 1 x 1.5 MW
Solar - 1 x 1 MW 278.6 199.8 32.6 0.543
2034 2.75
L/fill Gas – 1 x 1.5 MW
Ana. Digestion - 1 x 1.25 MW 281.35 202.5 32.2 0.543
2035 18.7 LSD17 - 1 x 17 MW 300.05 205.4 39.1 0.530
2036 61.6 45.5
NG-CCGT40 – 1 x 40 MW
Solar – 1 x 1 MW
wind w/storage - 1 x 1 MW 283.95 208.1 32.0 1.910
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 105
this plan account for 2.3% of the energy generated in 2036. The net present value of
this plan is $4.458 billion.
Table 35: Build Schedule for Liquid + NatGas Restricted + RE Scenario in Base Demand World
In the Liquid + Natural Gas Restricted + RE forced scenario, renewable technologies
are selected in order to attain the target of 29% of energy generated by renewables
by 2029. Table 36 shows the build schedule for this plan, which requires a total of
313.6 MW of new capacity. Biomass, landfill gas, wind, anaerobic digestion, wind
coupled with battery storage, waste to energy and imported biomass technologies
feature in this plan which represent 29% of the energy generated in 2029 and 2036.
The net present value of this plan is $4.645 billion.
Capacity Retired Total Capacity Peak Demand Reserve Margin1LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 239.1 158.6 36.2 0.252
2017 53 136.7
NG-LSD30 – 1 x 30 MW
NG-LSD17 – 3 x 17 MW
NG-MSD17 – 3 x 17 MW 322.8 160.3 85.3 0.000
2018 322.8 161.1 84.4 0.000
2019 51.5 271.3 164.6 53.6 0.008
2020 271.3 167.2 51.3 0.011
2021 271.3 169.9 48.9 0.016
2022 13 258.3 172.4 40.4 0.089
2023 258.3 174.7 38.5 0.115
2024 258.3 177.0 36.7 0.154
2025 20 17.6 NG-MSD17 – 1 x 17 MW 255.9 179.2 33.3 0.298
2026 1.5 L/fill Gas – 1 x 1.5 MW 257.4 181.5 32.5 0.307
2027 20 36.3
LSD17 – 1 x 17 MW
NG-MSD17 – 1 x 17 MW 273.7 184.1 38.7 0.059
2028 20 18.7 LSD17 – 1 x 17 MW 272.4 186.7 35.8 0.097
2029 272.4 189.5 33.8 0.127
2030 1.5 L/fill Gas – 1 x 1.5 MW 273.9 192.1 32.8 0.133
2031 17.6 NG-MSD17 – 1 x 17 MW 291.5 194.7 39.6 0.034
2032 291.5 197.2 37.8 0.043
2033 291.5 199.8 36.0 0.064
2034 291.5 202.5 34.2 0.090
2035 291.5 205.4 32.3 0.107
2036 61.6 63.4 NG-LSD30 – 2 x 30 MW 293.3 208.1 33.5 0.141
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 106
Table 36: Build Schedule for Liquid + NatGas Restricted + RE Forced Scenario in Base Demand World
For the Liquid + RE forced scenario, biomass, landfill gas, wind, anaerobic digestion,
wind coupled with battery storage, waste to energy and imported biomass
technologies feature in this plan which represent 29% of the energy generated in
2029 and 2036. The plan requires an addition of 318.2 MW of new capacity as
shown in Table 37. The net present value of this plan is $5.035 billion.
Capacity Retired Total Capacity Peak Demand Reserve Margin1
LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 1.5 L/fill Gas – 1 x 1.5 MW 240.6 158.6 37.2 0.209
2017 53 119.3
NG-LSD30 – 1 x 30 MW
NG-LSD17 –2 x 17 MW
NG-MSD17 – 3 x 17 MW 306.9 160.3 76.0 0.002
2018 306.9 161.1 75.2 0.000
2019 51.5 255.4 164.6 44.6 0.048
2020 25 Biomass – 1 x 25 MW 280.4 167.2 55.6 0.004
2021 280.4 169.9 53.1 0.007
2022 13 267.4 172.4 44.5 0.034
2023 267.4 174.7 42.6 0.046
2024 1.5 L/fill Gas – 1 x 1.5 MW 268.9 177.0 41.6 0.048
2025 20 19.6
NG-MSD17 – 1 x 17 MW
Wind – 2 x 1 MW 268.5 179.2 38.2 0.095
2026 1 Wind –1 x 1 MW 269.5 181.5 36.4 0.130
2027 20 19.95
LSD17 – 1 x 17 MW
Ana. Digestion – 1 x 1.25 MW 269.45 184.1 34.2 0.164
2028 20 19.95
LSD17 – 1 x 17 MW
Ana. Digestion – 1 x 1.25 MW 269.4 186.7 32.0 0.241
2029 21.5
Waste to energy - 1 x 13.5MW
Wind – 8 x 1 MW 290.9 189.5 36.7 0.089
2030 2 Wind –2 x 1 MW 292.9 192.1 34.8 0.106
2031 2 Wind w/ storage –2 x 1 MW 294.9 194.7 33.1 0.147
2032 25 Imp. Biomass – 1 x 25 MW 319.9 197.2 42.7 0.018
2033 319.9 199.8 40.8 0.025
2034 319.9 202.5 38.9 0.034
2035 1 Wind – 1 x 1 MW 320.9 205.4 37.0 0.046
2036 63.1 54.3
NG-MSD17 – 3 x17 MW
L/fill Gas – 1 x 1.5 MW
Retire
L/fill Gas – 1 x 1.5 MW 312.1 208.1 33.6 0.084
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 107
Table 37: Build Schedule for Liquid + RE Forced Scenario in Base World
Further details of the results of the scenarios in the base demand world are included
in Appendix I.
Capacity Retired Total Capacity Peak Demand Reserve Margin1LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 4.5
L/fill Gas – 1 x 1.5 MW
Solar - 1 x 1 MW
Wind – 2 x 1 MW 243.6 158.6 37.2 0.209
2017 53 70.6
LSD30 – 1 x 30 MW
LSD17 – 2 x 17 MW
L/fill Gas – 1 x 1.5 MW
261.2 160.3 48.1 0.017
2018 28
Biomass - 1 x 25 MW
Wind – 3 x 1 MW 289.2 161.1 61.0 0.001
2019 51.5 31.7 LSD30 – 1x 30 MW 269.4 164.6 49.3 0.022
2020 5 Wind – 5 x 1 MW 274.4 167.2 46.9 0.028
2021 1 Wind – 1 x 1 MW 275.4 169.9 44.6 0.052
2022 13 262.4 172.4 36.2 0.223
2023 262.4 174.7 34.4 0.278
2024 262.4 177.0 32.6 0.362
2025 20 32
GT30 – 1 x 30 MW
Wind – 1 x 1 MW 274.4 179.2 37.1 0.230
2026 1.25 Ana. Digestion - 1 x 1.25MW 275.65 181.5 36.0 0.264
2027 20 18.7 LSD17 – 1 x 17 MW 274.35 184.1 33.1 0.303
2028 20 22.25
GT20 – 1 x 20 MW
Ana. Digestion - 1 x 1.25MW 276.6 186.7 32.4 0.355
2029 13.5 Waste to energy - 1 x 13.5MW 290.1 189.5 37.1 0.189
2030 1 Wind w/ storage – 1 x 1 MW 291.1 192.1 35.3 0.236
2031 1 Wind w/ storage – 1 x 1 MW 292.1 194.7 33.6 0.283
2032 25 Imp. Biomass - 1 x 25 MW 317.1 197.2 43.1 0.044
2033 317.1 199.8 41.2 0.056
2034 317.1 202.5 39.3 0.083
2035 1 Wind – 1 x 1 MW 318.1 205.4 37.4 0.122
2036 66.1 61.7
LSD38 – 1 x 38 MW
LSD17 – 1 x 17 MW
Wind – 3 x 1 MW
L/fill Gas – 1 x 1.5 MW
Retire
Wind – 2 x 1 MW
Solar 1 x 1 MW
L/fill Gas – 1 x 1.5 MW 313.7 208.1 36.3 0.214
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 108
5.1.2 High Demand World
In the high world, electricity demand is predicted to grow at an average of 3.0% per
annum over the planning period. Consequently, the actual reserve margin is
expected to be below the planning criteria of 32% from 2013 until new generation
comes on-line in 2017.
In the Liquid +RE scenario, 472.6 MW of new capacity is required over the planning
period. Solar, wind and landfill gas technologies feature in the plan from 2016, while
biomass and anaerobic digestion technologies start to feature in the plan from 2018
and 2034 respectively. Overall, biomass accounts for 25.0 MW, landfill gas –
3.0MW, anaerobic digestion –1.25MW, solar – 14.0 MW and wind –20.0 MW. By
2036, RE technologies account for 15.0% of the energy generated. The net present
value of this plan is $5.961 billion.
Over the planning horizon, the Liquid + NatGas + RE scenario requires the addition
of 451.2 MW of capacity. While natural gas features heavily in this plan, HFO and
diesel continue to feature throughout the plan due to the limit of 28 mmscf/day
assumed for natural gas. RE technologies included in this plan are landfill gas, wind,
anaerobic digestion, biomass and solar technologies. These technologies represent
14.6% of the energy generated in 2036. The net present value of this plan is $4.938
billion.
The Liquid + Natural Gas Restricted + RE scenario requires a total of 456.0 MW of
new capacity over the planning period, made up predominately of natural gas and
HFO burning reciprocating engines. Landfill gas, biomass, anaerobic digestion,
solar, wind and waste to energy technologies also feature in the plan and account
for 19.8% of the energy generated in 2036. The cost of this plan is $5.186billion.
In the Liquid + Natural Gas Restricted + RE forced scenario, all renewable
technologies with the exception of wind with storage are included in order to attain
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 109
the target of 29% of energy generated by renewables by 2029. The total new
capacity required over the planning horizon is 454.9 MW. The net present value of
this plan is $5.365 billion.
In the liquid +RE forced scenario, 448.2 MW of new capacity is required over the
planning period. All of the candidate renewable technologies are included in order to
attain the target of 29% of energy generated by renewables by 2029. The net
present value of this plan is $6.096 billion.
Further details of the results of the scenarios in the high demand world are included
in Appendix J.
5.1.3 Low Demand World
In the low world, electricity demand is forecasted to decrease at an average of 0.4%,
per annum, over the planning horizon.
In the liquid +RE scenario, 215.4 MW of new capacity is required over the planning
period. Wind, solar and landfill gas technologies feature in the plan from 2016, while
biomass features in the plan from 2018. In 2036, RE technologies account for 27.4%
of the energy generated. The net present value of this plan is $4.112 billion.
Over the planning horizon, the Liquid +NatGas + RE scenario requires the addition
of 191.1 MW of capacity. This plan requires the installation of two 20 MW OCGT
units in 2016 along with three 17.0 MW medium speed units all utilizing natural gas.
No other plant is required in this plan until 2027. The only renewable energy
technology included in this plan is one 1.5 MW landfill gas generator being selected
in 2035. This represents 2.3% of the energy generated in 2036. The net present
value of this plan is $3.905 billion.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 110
Over the planning horizon, the Liquid + Natural Gas Restricted + RE scenario
requires a total of 193.9 MW of new capacity to be added to the system. One
hundred and five megawatts of reciprocating natural gas burning capacity is added
to the system in 2017 with a further 17.0 MW in 2027 and 17.0 MW in 2028. Fifty-
four megawatts of reciprocating capacity is the final addition to the system in 2036.
RE technologies do not feature in this plan. The cost of this plan is $3.942 billion.
In the Liquid + Natural Gas Restricted + RE forced scenario, biomass, landfill gas,
anaerobic digestion, wind and wind with storage technologies are included in the
plan in order to attain the target of 29% of energy generated by renewables by 2029.
The total new capacity required over the planning horizon is 217.8 MW. The net
present value of this plan is $4.081 billion.
In the Liquid + RE forced scenario, biomass, landfill gas, anaerobic digestion and
wind technologies are included in the plan in order to attain the target of 29% of
energy generated by renewables by 2029. The total new capacity required over the
planning horizon is 214.9 MW. The net present value of this plan is $4.114 billion.
Further details of the results of the scenarios in the base demand world are included
in Appendix K.
5.2 Sensitivities
After determining the optimal plan using the base assumptions for each scenario,
sensitivities were performed on the optimal plans. Figure 16 shows the results of the
NPV sensitivity tests performed on the optimal plans for each scenario, in relation to
fuel price, capital price and discount rate. Further details are included in Appendix L.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 111
Figure 16: NPV Sensitivities on Optimal Plans for each Scenario
5.3 Analysis
The net present value results (NPV) presented in Table 31, all represent least-cost
plans for the respective scenarios. The scenario which results in the lowest NPV
over the planning horizon is Scenario 2, in which the model was permitted to select
freely between all conventional and renewable generating technologies. Additionally,
as shown in Figure 16, this scenario remained the lowest across all demand worlds
(low, base and high) and sensitivity test runs (discount rates, capital and fuel costs).
The NPV ranking of the scenarios also remain fixed for all sensitivity tests. However,
these NPV results on their own are insufficient for decision making, as they do not
capture all of the risks associated with each scenario.
1,500,000
2,500,000
3,500,000
4,500,000
5,500,000
6,500,000
7,500,000
8,500,000
Scen
. 1: L
Q +
RE
Scen
. 2: L
Q +
RE
+ N
G
Scen
. 3: L
Q +
RE
+ N
Gr
Scen
. 4: L
Q +
REf
+ N
Gr
Scen
. 5: L
Q +
Ref
Scen
. 1: L
Q +
RE
Scen
. 2: L
Q +
RE
+ N
G
Scen
. 3: L
Q +
RE
+ N
Gr
Scen
. 4: L
Q +
REf
+ N
Gr
Scen
. 5: L
Q +
Ref
Scen
. 1: L
Q +
RE
Scen
. 2: L
Q +
RE
+ N
G
Scen
. 3: L
Q +
RE
+ N
Gr
Scen
. 4: L
Q +
REf
+ N
Gr
Scen
. 5: L
Q +
Ref
BASE HIGH LOW
NP
V (
$0
00
)
Base
Fuel - High
Fuel - Low
Capital - High
Capital - Low
Discount - High
Discount - Low
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 112
The primary risks associated with the five scenarios are the timing and availability of
imported natural gas and biomass.
5.3.1 Natural Gas Availability & Interruption Risk
Scenarios 2, 3 and 4 all assume that imported natural gas is available in the future
for power generation. At present there are small volumes of locally produced natural
gas available on the island, but this is used by domestic and small commercial
customers and none is available for power generation. A source of imported natural
gas will therefore be required to support Scenarios 2 to 4. The Government of
Barbados has been pursuing a number of options for the importation of natural gas
from Trinidad & Tobago over the past several years. At the time of writing,
discussions on a potential subsea gas pipeline were the most advanced, but
investigations into compressed natural gas (CNG) and micro liquefied natural gas
(micro-LNG) were also ongoing.
Given the uncertainty in timing of these natural gas supply options and the supply
interruption risks, made that much more acute by the likely dependence on a single
supplier and transportation method, any gas burning generating capacity that is
installed in Scenarios 2 to 4 must be capable of operating on an alternative fuel. For
combustion turbines the alternative fuel would be either diesel or Jet A1; for
reciprocating engines the alternative fuel would be heavy fuel oil. The risk of delays
in the natural gas supply, or gas never becoming available over the planning
horizon, can therefore be measured in two ways: firstly, by the impact that operating
on the alternative fuel for the duration of the delay has on the NPV of the least-cost
plan in each scenario and secondly by the increase in generating cost that results
from the delay. Additionally, the impact on electricity rates due to a sudden increase
in the fuel clause adjustment if the natural gas supply is interrupted must also be
considered.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 113
One key distinguishing feature between the liquid fuel and restricted gas plans (i.e.
Scenarios 1, 3, 4 & 5) and the unrestricted gas plan (Scenario 2) is the mix of
combustion turbines and reciprocating engines in each. In the unrestricted gas plan
(Scenario 2), a significantly higher proportion of combustion turbines make up the
overall generation mix when compared to the liquid fuel and restricted gas plans.
Consequently, Scenario 2 experiences the greatest increases in fuel operating costs
when gas is delayed or interrupted in the model. Figure 17 shows the proportion of
generation technologies installed over the planning period in Scenarios 1, 2 and 3.
The specific impact of natural gas supply delays on the NPV of Scenario 2 and 3 is
shown in Figure 18. The fuel cost in Scenario 1 is independent of gas and therefore
remains fixed for gas interruptions. Scenario 2 remains the least-cost option for
delays in natural gas supply up to around the year 2024, and Scenario 3 is least-cost
for delays beyond 2024 up to around 2030. However as the chart shows, the NPV of
Scenario 2 and 3 are 12.6% and 5.3% higher than that of Scenario 1 over the entire
planning period if gas is unavailable.
Figure 17: Proportion of Installed Generating Technologies in scenarios 1, 2 & 3
Proportion of Installed Generating Technologies in Scenarios 1, 2 & 3
Renewable Reciprocating Engines Combustion Turbines
20%
18% 62%
Scenario 1 Liquid Fuel
97%
3%
Scenario 2 Natural Gas
1%
99%
Scenario 3 Natural Gas Restricted
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 114
Figure 18: Impact of Delayed in Natural Gas Availability on NPV
Figure 19 illustrates the impact of natural gas supply delays on the overall electricity
generating cost between 2017 and 2025. Operation of the combustion turbine units
installed under Scenario 2 when gas is delayed, results in annual generating costs
that are between 14% and 23% higher than those in Scenario 1.
Figure 19: Impact of Delayed Natural Gas Availability on Total Generation Cost
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
5,500,000
Gas availablefrom 2017
Gas delayeduntil 2020
Gas delayeduntil 2025
Gasunavailable
NP
V (
20
12
BB
D$
00
0)
Impact of Delayed Natural Gas Availability:NPV Comparison of Liquid Fuel & Natural Gas Scenarios
Scenario 1 NPV (Liquid Fuel)Scenario 2 NPV (Natural Gas)Scenario 3 NPV (Natural Gas Restricted)
0.20
0.25
0.30
0.35
0.40
0.45
2017 2018 2019 2020 2021 2022 2023 2024 2025
Ge
ne
rati
ng
Co
st (
BB
D$
/kW
h)
Impact of Delayed Natural Gas Availability on theAnnual Generating Cost of Liq. Fuel & Nat. Gas Scenarios
Scenario 2 Generating Cost (Gas Delayed)Scenario 2 Generating Cost (Gas Available)Scenario 1 Generating Cost (Liquid Fuel)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 115
The impact of natural gas interruptions on the fuel cost of Scenarios 2 and 3 are
shown in Figure 20. The fuel cost in Scenario 1 is independent of gas and therefore
remains fixed for gas interruptions. There is a significant fixed cost associated with
the importation of natural gas, which is expected to be reflected in a ‘take-or-pay’
component of the gas supply contract. The generating plant would not be expected
to pay this fixed cost for supply interruptions caused by the gas supplier and/or
transporter; however it would apply in circumstances where the generator is at fault
– for example, a failure in gas handling equipment on the generator’s side of the
custody transfer point. The impact of both gas interruption cases are therefore
shown in Figure 20.
Figure 20: Impact of 1-Year Gas Interruption in 2018 on Fuel Cost
The calculations have been done for a one-year interruption in the year 2019, but
would also be representative of the average monthly fuel cost impact for a one-
month interruption during the year. In Scenario 2, an interruption is expected to
increase fuel costs by 34.5% excluding the fixed ‘take-or-pay’ price for gas and
61.6% if the fixed price is included. In Scenario 3, the impact of gas interruptions are
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
Gas Available Gas Interrupted(excl. fixed cost)
Gas Interrupted(incl. fixed cost)
Fue
l Co
st (
20
12
BB
D$
/kW
h)
Impact of a 1-Year Natural Gas Interruption in 2019on Fuel Cost
Scenario 1 FCA (Liquid Fuel)Scenario 2 FCA (Natural Gas)Scenario 3 FCA (Natural Gas Restricted)
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 116
significantly lower since the reciprocating generators in that plan switch to heavy fuel
oil rather than the diesel alternative used by gas turbines in Scenario 2.
The calculations and data used to create the charts shown in Figures 18, 19 and 20
are tabulated in Appendix N. Scenarios 4 and 5 are higher-cost ‘forced RE’
variations of Scenarios 3 and 1 respectively, and were therefore not included on the
charts. However, similar results for these scenarios are also tabulated in Appendix
N.
Government’s efforts to secure an imported supply of natural gas for the island have
been on-going for well over ten years. At the time of writing, the Government of
Barbados was in discussion with a number of potential developers for the supply of
natural gas by pipeline, LNG or CNG, but no firm proposals or quotations had been
received and no agreements reached. It is therefore very difficult to judge the likely
timing of natural gas becoming available and the possibility exists that it will not be
available during the planning period. In the current circumstances, the least cost
plan for Scenario 1, in which only liquid fuels and renewable energy options are
available, is the preferred option. This scenario allows for migration to Scenario 3 in
the event that gas becomes available, by switching the reciprocating units to gas.
Scenario 3 has a higher NPV than Scenario 2, but is the preferred gas scenarios,
since it mitigates the significant rate shock associated with a gas supply interruption
in Scenario 2.
5.3.2 Biomass Availability & Risks
The developer of the proposed 25MW biomass plant, the Barbados Cane Industry
Corporation, has indicated that they are targeting a commissioning date of 2016 for
the plant. Based on a review of the schedule and feedback from stakeholders
received during public consultations, BL&P is of the view that 2018 is a more
realistic in-service date given the current status of the project and the requirement
for conducting trials to validate assumptions made for the proposed alternative
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 117
biomass fuel Leucaena. The earliest installed date for the biomass plant was
therefore set at 2018 in the production cost simulation model. If the biomass plant
does become available in 2016, there would be an overall decrease in the NPV of
$24.755 million or 0.50% for the liquid + Re scenario in the base world. This is
0.03% higher than the optimized plan if the model were allowed to select it for
installation in 2016 (provided in Appendix M). However, given the relatively low
likelihood of this occurring and the low NPV impact, this risk is considered
acceptable.
If the plans for biomass do not materialize within the study planning period,
reciprocating engines are the likely least-cost replacement. This will be evaluated in
a subsequent IRP update if the biomass project does not proceed.
5.3.3 Renewable Energy Policy Indicative Target
The Government of Barbados has issued a draft National Sustainable Energy Policy
(NSEP) for Barbados in March 2012with the stated objectives of reducing energy
costs, improving energy security and enhancing environmental sustainability. The
draft NSEP identifies “an indicative target of about 29% of all electricity consumption
to be generated by renewable sources by 2029”. Although identified as indicative,
Scenarios 4 and 5 were created to determine the least-cost plans for achieving this
target. In a liquid fuel future, forcing the model to achieve the policy target (i.e.
Scenario 5) results in an increase in NPV of 1.0% over the optimum plan in Scenario
1.In a natural gas future, forcing the model to achieve the policy target (i.e. Scenario
4) results in an increase in NPV of 5.1% over the optimum plan in Scenario 3.
5.3.4 Proposed Waste to Energy Facility
The Government of Barbados has announced plans to develop up to 60 MW of
waste-to-energy (WTE) capacity. WTE was not selected as a least-cost option in the
five initial scenarios modeled in the IRP, however Government has advised that it
will form part of the island’s waste management strategy going forward. At the time
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 118
of writing, firm details on the cost, capacity and operating characteristics of the WTE
plant under consideration were not available from Government. However, BL&P was
advised that plasma arc gasification technology was proposed and the plant could
be in service by 2018. In the absence of further information from project proponents,
plant assumptions for this technology were drawn from references which were found
for a similar plant under construction in the UK (Westinghouse Plasma Corporation,
2012) and are presented in Table 38.
Table 38: Waste-to-Energy (Plasma Arc) Assumptions
In order to determine the impact that this development would have on short-term
expansion requirements, a derivative of Scenario 1 was created in which 60 MW of
WTE generating capacity was forced into service in 2018, and the expansion model
allowed to re-optimize. The resulting expansion plan for this new scenario (Scenario
6: Liquid Fuel + RE + WTE), is shown in Table 39. The net present value of this plan
is $5.334 billion. This represents the highest net present value of all of the scenarios
modeled. Under this plan 52.8% of energy in 2029 is generated by RE technologies.
WASTE TO
ENERGY -
(PLASMA ARC)
Capacity per unit (MW) 30.0
Firm Capacity (MW) 30.0
No. of units built 2
Build Date 1/1/2018
Lifetime (yrs) 30
Capacity Factor 85.0
Forced Outage Rate (%) 6.0
Average Annual Maintenance (Days) 30
Auxiliary Power Consumption (%) 7.0
Overnight Capital Cost ($/kW) 18,000 - 25,000
Fixed O & M Cost ($/kW/yr) 700 - 1,400
Variable O & M ($/MWh) 15.00 - 20.00
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 119
Table 39: Build Schedule for Liquid + WtE Forced Scenario in Base World
In this new scenario, the least-cost plan calls for the installation of 47 MW of
reciprocating capacity in 2017 coincident with the retirement of the steam units in
2017.
The NPV for all six scenarios is summarized in Table 40.
Capacity Retired Total Capacity Peak Demand Reserve Margin1
LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 11.5
L/fill Gas – 1 x 1.5 MW
Wind – 2 x 1 MW
Solar - 8 x 1 MW 250.6 158.6 37.2 0.209
2017 53 51.9
LSD30 – 1 x 30 MW
LSD17 – 1 x 17 MW
L/fill Gas – 1 x 1.5 MW 249.5 160.3 36.8 0.151
2018 86
Biomass - 1x 25 MW
Waste to energy - 2 x 30 MW
Wind – 1 x 1 MW 335.5 161.1 84.5 0.000
2019 51.5 284 164.6 53.8 0.027
2020 284 167.2 51.4 0.031
2021 1 Wind – 1 x 1 MW 285 169.9 49.0 0.047
2022 13 272 172.4 40.5 0.257
2023 272 174.7 38.6 0.344
2024 18.7 LSD17 – 1 x 17 MW 290.7 177.0 47.0 0.054
2025 20 1 Wind – 1 x 1 MW 271.7 179.2 34.2 0.433
2026 271.7 181.5 32.5 0.444
2027 20 31 GT30 – 1 x 30 MW 282.7 184.1 36.5 0.381
2028 20 18.7 LSD17 – 1 x 17 MW 281.4 186.7 33.6 0.391
2029 2.25
Wind – 1 x 1 MW
Ana. Digestion – 1 x 1.25 MW 283.65 189.5 32.3 0.439
2030 21 GT20 – 1 x 20 MW 304.65 192.1 41.3 0.139
2031 304.65 194.7 39.4 0.213
2032 1 Wind – 1 x 1 MW 305.65 197.2 37.7 0.284
2033 305.65 199.8 35.9 0.378
2034 305.65 202.5 34.1 0.417
2035 305.65 205.4 32.2 0.478
2036 73.1 70.95
LSD30 – 1 x 38 MW
LSD17 - 1 x 17 MW
Wind – 5 x 1 MW
L/fill Gas – 1 x 1.5 MW
Wind w/ storage - 5 x 1 MW
Solar - 1 x 1 MW
Ana. Digestion – 1 x 1.25 MW
Retire
Wind – 2 x 1 MW
L/fill Gas – 1 x 1.5 MW
Solar - 8 x 1 MW 303.5 208.1 32.0 0.680
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 120
Worlds Scenarios Description NPV ($000)
Base
Scenario 1 LQ + RE 4,985,051
Scenario 2 LQ + RE + NG 4,227,676
Scenario 3 LQ + RE + NGr 4,457,170
Scenario 4 LQ + REf + NGr 4,645,222
Scenario 5 LQ + REf 5,035,424
Scenario 6 LQ + RE + WtEf 5,334,102
High
Scenario 1 LQ + RE 5,961,262
Scenario 2 LQ + RE + NG 4,937,955
Scenario 3 LQ + RE + NGr 5,185,558
Scenario 4 LQ + REf + NGr 5,365,404
Scenario 5 LQ + REf 6,095,605
Scenario 6 LQ + RE + WtEf 6,310,660
Low
Scenario 1 LQ + RE 4,112,078
Scenario 2 LQ + RE + NG 3,904,750
Scenario 3 LQ + RE + NGr 3,942,138
Scenario 4 LQ + REf + NGr 4,080,506
Scenario 5 LQ + REf 4,113,915
Scenario 6 LQ + RE + WtEf 4,465,421
Table 40: NPV Results for the Six Scenarios
5.3.5 Other Policy Considerations
In addition to the NPV analysis, policy makers may wish to consider a broad range
of economic, social and environmental factors associated with the expansion plan.
These might include criteria such as the foreign exchange impact of each scenario,
land, water and CO2 impacts, energy security and fuel import vulnerability. The draft
NSEP indicates that “where a sustainable energy measure could increase energy
security and environmental sustainability, but would also increase costs to the
economy, the Government of Barbados will pursue it when the energy security,
environmental sustainability, and other local economic benefits (including other
positive economic externalities, contribution to the country’s economy and quality of
life) exceed the economic costs”.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 121
While it is possible to attribute costs to criteria such as those listed above and
include these in the NPV optimization, these costs should be based on the economic
value the country places on each criteria as determined by policy makers. For
example, the purchase price of water in Barbados may not accurately reflect its
economic value given the island’s water scarcity. Similarly, international market
prices for CO2 may not be applicable in all scenarios, since ‘additionality’ (a criteria
for eligibility for CO2 financing15) of the generating projects that are least-cost options
may be difficult to prove.
The approach of internalizing external costs, also known as External Cost Analysis
(ECA), is practiced among some electric utility regulators, who for example require
utilities to put a cost on emissions and include these in the NPV calculations, to
determine total societal costs (ECO Northwest, 1993). While there are some benefits
to this approach, which is rooted in welfare economics, it has the following
disadvantages (Hobbs & Meier, 2000):
Some basic principles of welfare economics are not universally accepted, e.g.
net benefits matter with no consideration of distribution among stakeholders.
Fundamental value judgments could become buried in calculations rather
than explicitly considered by decision makers.
Multicriteria Decision methods address some of the deficiencies of ECA methods,
based on their ability to make the tradeoffs between criteria more explicit and the
greater insight and input they provide to stakeholders and decision makers.
Table 41summarizes the performance of each scenario’s least-cost expansion plan
in relation to several criteria in addition to NPV. A sample multicriteria decision
analysis methodology is provided in Appendix Q for the consideration of policy
makers.
15
http://cdmrulebook.org/84
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 122
Table 41: Characteristics of Least-Cost Plans
5.4 Recommendation
Currently, natural gas is unavailable and the timeline for its availability remains
uncertain. Therefore, amongst Scenarios 1 to 5, Scenario 1 (Liquid + RE), is the
preferred plan with conventional generating technology units being configured to
permit dual-fuel conversion to natural gas when it becomes available. However,
given Government’s stated plans to develop up to 60 MW of WTE capacity, a
derivative of Scenario 1, in which WTE is forced into service in 2018 (i.e. Scenario 6:
liquid fuel + RE + WTE), was modeled. At the time of writing, there was uncertainty
surrounding the specific capacity and technology for the WTE plant that will
eventually be selected by Government. However, in order to mitigate against
potential over-capacity should the WTE generating capacity be commissioned as
planned, short-term expansion should be based on Scenario 6.
Table 42 shows the build schedule for Scenario 6.While the table identifies specific
reciprocating diesel units, it is recommended that the engine type and size to meet
the required reciprocating generating capacity be determined through a tendering
process. The net present value of this plan is $5.334 billion.
Worlds Scenarios NPV ($000)
C02
(million
MT)
Water
(million
Ga)
Land Use
(acres)
Fuel
Diversity
Foreign
Exchange
($000) Achievability
2017 Gas
Interruption
Cost ($000)
Renew %
in 2029
Renew % in
2036
LQ + RE 4,985,051 18,316 2,512 523 35.94% 4,452,779 High 0 20.8% 20.0%
LQ + RE + NG 4,227,676 13,889 769 70 42.78% 3,916,366 Medium 97,864 0.9% 3.3%
LQ + RE + NGr 4,457,170 15,589 430 31 47.58% 4,074,542 Medium 51,947 1.7% 2.3%
LQ + REf + NGr 4,645,222 13,556 2,480 687 71.11% 4,105,925 Low 39,485 29.0% 29.0%
LQ + REf 5,035,424 17,615 2,958 749 42.78% 4,464,125 Medium 0 29.5% 29.0%
LQ + WTEf 5,334,102 13,141 6,485 1,318 71.95% 4,371,522 Low 0 52.8% 49.1%
LQ + RE 5,961,262 23,698 2,587 842 31.35% 5,376,707 High 16.6% 15.0%
LQ + RE + NG 4,937,955 16,672 1,819 708 59.37% 4,499,457 Medium 15.8% 14.6%
LQ + RE + NGr 5,185,558 20,461 1,752 993 64.32% 4,687,628 Medium 14.3% 19.8%
LQ + REf + NGr 5,365,404 17,263 3,264 972 71.28% 4,800,408 Low 19.4% 29.0%
LQ + REf 6,095,605 22,109 3,718 952 43.67% 5,452,355 Medium 29.0% 29.0%
LQ + WTEf 6,310,660 18,531 6,548 1,562 63.26% 5,295,430 Low 40.2% 34.8%
LQ + RE 4,112,078 13,711 2,447 344 41.47% 3,616,876 High 27.8% 27.4%
LQ + RE + NG 3,904,750 11,728 289 17 50.83% 3,625,233 Medium 1.3% 2.3%
LQ + RE + NGr 3,942,138 12,009 304 14 50.78% 3,614,724 Medium 1.3% 1.2%
LQ + REf + NGr 4,080,506 10,865 1,817 281 72.94% 3,302,322 Low 29.0% 29.0%
LQ + REf 4,113,915 13,615 2,471 337 43.56% 3,614,519 Medium 29.0% 29.0%
LQ + WTEf 4,465,421 8,575 2,039 1,078 80.54% 3,389,178 Low 71.2% 70.0%
Base
High
Low
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 123
Table 42: Build Schedule for Recommended Plan in Base Demand world
5.5 Avoided Generating Costs
The definition of avoided cost, applicable to our analysis, is adopted from the United
States Public Utility Regulatory Policy Act (PURPA). According to the definition of
Capacity Retired Total Capacity Peak Demand Reserve Margin1
LOLP
MW MW Type MW MW % %
2012 239.1 157.4 37.3 0.205
2013 239.1 156.7 37.9 0.205
2014 239.1 157.2 37.4 0.205
2015 239.1 156.9 37.7 0.205
2016 11.5
L/fill Gas – 1 x 1.5 MW
Wind – 2 x 1 MW
Solar - 8 x 1 MW 250.6 158.6 37.2 0.209
2017 53 51.9
LSD30 – 1 x 30 MW
LSD17 – 1 x 17 MW
L/fill Gas – 1 x 1.5 MW 249.5 160.3 36.8 0.151
2018 86
Biomass - 1x 25 MW
Waste to energy - 2 x 30 MW
Wind – 1 x 1 MW 335.5 161.1 84.5 0.000
2019 51.5 284 164.6 53.8 0.027
2020 284 167.2 51.4 0.031
2021 1 Wind – 1 x 1 MW 285 169.9 49.0 0.047
2022 13 272 172.4 40.5 0.257
2023 272 174.7 38.6 0.344
2024 18.7 LSD17 – 1 x 17 MW 290.7 177.0 47.0 0.054
2025 20 1 Wind – 1 x 1 MW 271.7 179.2 34.2 0.433
2026 271.7 181.5 32.5 0.444
2027 20 31 GT30 – 1 x 30 MW 282.7 184.1 36.5 0.381
2028 20 18.7 LSD17 – 1 x 17 MW 281.4 186.7 33.6 0.391
2029 2.25
Wind – 1 x 1 MW
Ana. Digestion – 1 x 1.25 MW 283.65 189.5 32.3 0.439
2030 21 GT20 – 1 x 20 MW 304.65 192.1 41.3 0.139
2031 304.65 194.7 39.4 0.213
2032 1 Wind – 1 x 1 MW 305.65 197.2 37.7 0.284
2033 305.65 199.8 35.9 0.378
2034 305.65 202.5 34.1 0.417
2035 305.65 205.4 32.2 0.478
2036 73.1 70.95
LSD30 – 1 x 38 MW
LSD17 - 1 x 17 MW
Wind – 5 x 1 MW
L/fill Gas – 1 x 1.5 MW
Wind w/ storage - 5 x 1 MW
Solar - 1 x 1 MW
Ana. Digestion – 1 x 1.25 MW
Retire
Wind – 2 x 1 MW
L/fill Gas – 1 x 1.5 MW
Solar - 8 x 1 MW 303.5 208.1 32.0 0.680
1 - Reserve Margin based on net capacity and demand.
Capacity AddedYear
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 124
PURPA, avoided cost is the fixed and running costs of an electric utility system
which can be avoided by obtaining energy or capacity from qualifying facilities. The
avoided cost is the forward looking change in cost, alternatively referred to as
marginal or incremental cost, which occurs as a consequence of installing a
particular generating resource.
Avoided costs for the BL&P electric grid have been defined as the costs to the
electric utility of energy or capacity, or both, which, but for the purchase from the
qualifying facility or qualifying facilities, the utility would generate itself or purchase
from other sources. Avoided costs, therefore, incorporate projections of future year-
by-year BL&P system costs.
The pertinent costs considered for the avoided costs calculations are:
generation fixed costs (capacity costs);
generation variable costs (energy costs).
Generation fixed costs (capacity) include capital costs for new generation capacity to
be installed over the planning period and the fixed operation and maintenance costs
for these facilities. These costs are dependent on the characteristics of the
generation plants. Variable (energy) costs include fuel costs and variable operation
and maintenance costs.
Calculations of generation avoided costs, for BL&P, must be consistent with the IRP
planning methodologies, in order to identify the most cost-efficient resources and to
minimize the cost of providing energy to consumers. To this end, the Plexos Utility
Planning software was employed to simulate the various generation options, based
on potential new technology fuel types, fuel prices and projected demand growth for
the 25-year period.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 125
Avoided costs were calculated for renewable technologies considered in this study.
Scenario 1 (liquid + renewables) was used to calculate the avoided cost for the
technologies. The avoided cost for technologies which contribute firm capacity to the
plan would have a capacity and energy component while technologies which are
non-firm would only possess an energy component.
For the firm technologies, namely biomass, waste to energy, landfill gas and
anaerobic digestion, an optimal plan was first determined without the technology for
which the avoided cost was being calculated. The NPV for fuel, fixed and variable
operating and maintenance cost and capital cost was determined. The technology
under consideration was then added with zero capital, operating and maintenance
cost to the model as a candidate plant. A new optimal plan was generated by the
model. The difference in NPV of the capital and fixed operating and maintenance
cost, divided by the unit capacity and number of years of operation, is the capacity
component of the avoided cost for the technology. The difference in NPV of the fuel
and variable operating and maintenance cost, divided by the NPV of the energy
generated by the unit, is the energy component of the avoided cost for the
technology.
For the non-firm technologies, namely wind and solar, an optimal plan was first
determined without the technology for which the avoided cost was being calculated.
The NPV for fuel and variable operating and maintenance cost was determined. The
technology under consideration was then added with zero capital, operating and
maintenance cost to the model from the year the technology is available without re-
optimization. The difference in NPV of the fuel and variable operating and
maintenance cost, divided by the NPV of the energy generated by the unit, is the
energy component of the avoided cost for the technology.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 126
The avoided costs for the technologies considered in this study are shown in Table
43. Further details on the avoided cost calculations for the technologies are shown in
Appendix P.
Table 43: Avoided Cost of Renewable Technologies
It is important to note, that the avoided generating costs calculated above, are
indicative based on the assumptions used in this study, exclude T&D costs and are
expressed in real 2012 dollars. The avoided cost may not be equivalent to the
avoided revenue requirement, as the avoided revenue requirement includes avoided
energy and capacity costs, as well as other factors (e.g., taxes). Consequently, the
avoided generating costs may not represent the negotiated price from an
Independent Power Producer.
Technology
Capacity
MW
Installation
Year
Capacity Cost
$/kW/yr
Energy C ost
$/MWh
Anearobic Digestion 2.5 2016 43.08 373.29
Biomass 25.0 2018 135.64 272.81
Landfill Gas 3.0 2016 151.48 350.38
Waste to Energy 13.5 2018 81.01 323.44
Solar 1.0 2016 - 429.32
Wind 1.0 2016 - 381.62
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 127
6 SUMMARY AND CONCLUSION
System expansion planning at BL&P has traditionally focused on identifying the
least-cost generation expansion plan from a range of generating supply options.
Integrated Resource Planning (IRP) enhances this process by taking into
consideration demand side resource options, as well as additional evaluation criteria
like energy security and environmental impact.
The expansion recommendation is based on an evaluation of the least-cost plans
identified by the production cost model for each demand world and fuel scenario
combination. The recommendation also takes into consideration the risks presented
by potential delays and/or interruptions in the future availability of natural gas and
biomass, and includes Government’s stated plan for a waste-to-energy generating
plant as part of the island’s waste management strategy. Other risks and
uncertainties associated with variables like fuel price and electricity demand growth
were addressed through sensitivity and scenario analyses. A broad range of
additional economic, social and environmental factors associated with each of the
least-cost plans were also calculated. These are presented in Appendix Q, along
with a sample multicriteria decision analysis methodology for the consideration of
policy makers.
The study was conducted in accordance with IRP best practices (Tellus Institute)
and provides a roadmap, outlining the options to be used in meeting future electricity
demands cost effectively and in compliance with regulatory requirements. A
transparent and participatory approach was employed throughout the process. The
recommendations have been informed by broad consultations with stakeholders who
participated in the process by reviewing assumptions and preliminary results and
providing input into the planning decision.
The IRP was developed using models that incorporate the best information at the
time of planning and will be updated periodically or as conditions change materially.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 128
Technologies which are not technically or commercially viable and Transmission and
Distribution (T&D) expansion requirements were excluded from the scope of the
IRP.
6.1 Sustainable Energy Framework for Barbados
In July 2010, the Government of Barbados (GoB) completed a study titled
‘Sustainable Energy Framework for Barbados’ (SEFB). The objective of the study,
which was conducted by Castalia Strategic Advisors and financed by the IDB, was to
identify viable investments in renewables and energy efficiency to reduce Barbados’
dependency on fossil fuels and thus reduce energy costs, improve energy security
and enhance environmental sustainability. These objectives were also captured in a
draft National Sustainable Energy Policy (NSEP) issued by the Government of
Barbados in March 2012.
Both the SEFB report and the draft NSEP identified indicative targets for renewable
energy (RE) and energy efficiency (EE) of 29% and 22% respectively by 2029.
Scenario 1, the preferred plan amongst scenario 1 to 5 as described in section 5.4,
achieves RE levels of 20.8% by 2029 for the base demand forecast world. Forcing
this scenario to achieve 29% RE by 2029 will increase the NPV of the plan by 1%.
The recommendation, based on Scenario 6 which includes Government’s plan to
develop up to 60 MW of WTE, achieves 52.8% RE by 2029, while increasing the
NPV by 7.0% over Scenario 1.The potential impact of EE measures are accounted
for in the low demand forecast world, which allows for up to 28.3% reductions
through EE by 2029.
Also arising out of the SEFB report, were recommendations relating to legislative
and regulatory changes aimed at promoting the development of viable renewable
energy and energy efficiency resources. At the time of writing, the draft energy policy
and legislative changes were under review, but not yet finalized, by the GoB.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 129
However, the IRP study takes the proposed changes into account and follows a
methodology which is consistent with the recommendations of the SEFB report.
6.2 Recommendation
To assess the risks and uncertainties associated with external market conditions, the
IRP study examined five initial scenarios representing plausible future paths relating
to fuel types and technologies used. The specific fuels and technologies represented
by each scenario are summarised in Table 44.
Table 44: Scenario Matrix of Fuels & Technologies
Each of these scenarios were evaluated using three possible electricity demand
growth ‘worlds’, resulting in a total of fifteen plans being evaluated. Sensitivities for
changes in capital costs, fuel costs and discount rates were also conducted on each
of the fifteen plans.
Natural gas is currently unavailable for power generation and the timeline for its
availability remains uncertain. Amongst Scenarios 1 to 5, Scenario 1 is the preferred
scenario as it allows for the migration to the lower NPV Scenario 3 in the event that
gas becomes available in the future, by switching the reciprocating units to gas.
Scenario 3 has a higher NPV than Scenario 2, but is the preferred gas scenario,
since it mitigates the significant rate shock associated with a gas supply interruption
in Scenario 2.
Scenario 1:
LF+RE
Scenario 2:
LF+RE+NG
Scenario 3:
LF+RE+NGr
Scenario 4:
LF+REf+NGr 1
Scenario 5:
LF+Ref 1
Liquid Fuel (LF)
Natural Gas (NG) x x
Renewable Energy (RE)
Gas Turbines 2
x x
Notes
1. The model is forced to install 29% RE by 2029 in scenarios 4 & 5.
2. Gas turbines excluded in scenarios 3 & 4 due to high gas interruption cost
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 130
Scenario 6 was introduced given Government’s stated plans to develop up to 60 MW
of WTE capacity. Scenario 6 is a derivative of Scenario 1 in which WTE is forced
into service in 2018 (i.e. Scenario 6: liquid fuel + RE + WTE). At the time of writing,
there was uncertainty surrounding the specific capacity and technology for the WTE
plant that will eventually be selected by Government. However, in order to mitigate
against potential over-capacity should the WTE generating capacity be
commissioned as planned, short-term expansion should be based on Scenario 6.
The first ten years of the resulting least-cost plan for Scenario 6 are displayed in
Table 45.
If Government’s plans for the WTE plant are cancelled or modified from the
assumptions used in the IRP, this scenario will have to be remodeled and revised
accordingly.
Year Demand
GWh
Supply-side Resources Demand-side Resources
Retire New Capacity
2012 981
2013 980
2014 979
2015 984
2016 993 L/fill Gas –1.5 MW
Solar – 8 MW
Wind – 2 MW
2017 1005 S1, S2 – 40 MW
GT02 – 13 MW
Reciprocating Engines – 47 MW
L/fill Gas –1.5 MW
2018 1018 Biomass –25 MW
Waste to Energy – 60 MW
Wind – 1 MW
2019 1036 D10, D11, D12,
D13 – 50 MW
WH01 – 1.5 MW
2020 1054
2021 1074 Wind – 1 MW
Table 45: Scenario 6: Least-cost Integrated Resource Plan
Future DSM
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 131
The model assumes that all plant retirements take place at 00:00hrs on January 1st
of the years identified in the table. In practice, an overlap of around six (6) months
may be required between retired and replacement capacity to ensure a reliable
transition and allow for any teething problems with the new plant to be addressed.
Figure 21 shows the contribution to total generation by generating technology for the
recommended plan over the planning period. The annual generation for the
recommended plan is shown in Figure 27 of Appendix O.
Figure 21: Generation by Energy Source for Recommended Plan
The IRP recommendations are contingent on the following:
Acquiring land access for the development of wind energy and/or successful
negotiation of Power Purchase Agreements with Independent Power
Producers (IPPs) for wind energy.
0
200
400
600
800
1000
1200
1400
1600
20
12
20
13
20
14
201
5
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
202
5
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
203
5
20
36
Ene
rgy
(GW
h)
Year
Solar
Anearobic Digestion
Landfill Gas
Wind
Biomass
Waste to Energy
New Gas Turbines
New LSD & MSD
Gas Turbine
Cogen
LSD
Steam
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 132
Access to a secure supply of biomass, municipal solid waste and landfill gas
at the prices used in the IRP.
The generating capacity and timing of waste-to-energy and biomass is
achieved. If there are variations in the scope and timing of these projects, the
retirement schedule of existing units could be affected.
Extension of BL&P’s franchise which currently expires in 2028.
Compliance with legislative requirements.
The plan laid out in Table 1 provides a roadmap of expansion options to be used in
meeting future electricity demands cost effectively, given the constraints and
assumptions used in Scenario 6. Investment plans by the utility and potential
Independent Power Producers should be guided by the IRP, while taking into
consideration licensing, land availability and location specific development costs.
Two key issues were identified during the IRP process which will require additional
work:
As identified in the IRP Terms of Reference, Demand Side Management
(DSM) options evaluated in the IRP study were to be derived from the energy
efficiency recommendations made in the SEFB study conducted by IDB for
the Government of Barbados. However, based on subsequent feedback
received from the consultants who conducted the SEFB study, the energy
efficiency measures were found to be insufficiently well defined for modeling
in the IRP. A DSM study will be completed in 2014 to identify specific DSM
measures for implementation. It is important to note however, that the short-
term expansion recommendations (2013 to 2018) remain unchanged in the
low demand forecast world and is therefore compatible with the indicative EE
targets identified in the SEFB.
Based on a preliminary review of system impacts and practices in other island
grids, an intermittent Renewable Energy (RE) limit of 10% of peak demand
has been used in the study. An Intermittent RE Penetration study will be
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 133
completed in 2014 to further evaluate the issues associated with intermittent
RE and allowable limits.
Barbados Light & Power Co. Ltd. - 2012 Integrated Resource Plan 134
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