Options to Bring Down Electricity Costs in Jamaica_Castalia[1]

8/6/2019 Options to Bring Down Electricity Costs in Jamaica_Castalia[1]

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Options to

Bring Down theCost ofElectricity inJamaica

Final Report

23 June 2011


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Disclaimer

This report was financially supported by Jamaica Public Service Company Limited (JPS) andprepared following interviews conducted with staff members of JPS, as well as severalmembers of the private sector, and Government agencies in Jamaica. However, the views,findings, and conclusions expressed herein are entirely those of Castalia, and should not beattributed to JPS, the Government of Jamaica or any of its agencies, or to any of theindividuals interviewed.


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Table of Contents

Executive Summary i1 Introduction 12 Electricity Tariffs in Jamaica 23 Option 1: Changing the Main Fuel 4

3.1 Using a Cheaper Fuel 43.2 Change in Cost of Electricity Generation Resulting from

Using a Cheaper Fuel 53.2.1 Unit cost of generation from NGCC plant 53.2.2 Reduction in total cost of electricity generation

when using NGCC plant and converted combinedcycle plant 7

3.3 Impact on the Cost of Electricity 144 Option 2: Increasing the Use of Renewable Energy 16

4.1 Description of the Reform 164.2 Evidence of Benefits and CostsUtility-Scale Technologies 17

4.2.1 Economic viability of adding utility-scale renewablesto the current system 21

4.2.2 Economic viability of renewables once LNG is usedas the main fuel 25

4.2.3 Reduction in electricity costs from implementingutility-scale renewable energy technologies 28

4.3 Evidence of Benefits and CostsDistributed Scale Technologies

5 Option 3: Reducing System Losses 405.1 Description of the Reform 40

5.1.1 Definition of system losses 405.2 Potential for Electricity Loss Reduction in Jamaica 41

5.2.1 Net electricity losses in Jamaica 415.3 Impact on the Cost of Electricity 44

6 Option 4: Increasing the Use of Energy Efficient Technologies 6.1 Description of the Reform 486.2 Evidence of Benefits and Costs 48


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6.3 Impact on the Cost of Electricity to Consumers 527 Option 5: Forcing Vertical and Horizontal Disaggregation of

the Electricity Sector 55

7.1 Description of the Reform 557.2 Evidence of Benefits and Costs 59

7.2.1 Experience with Wholesale and Retail Competitionin Island Countries 59

7.2.2 Estimation of Wholesale Electricity Prices in Jamaica with a Disaggregated Sector Structure 61

7.2.3 Other Costs and Possible Problems Arising fromRestructuring the Jamaican Electricity Sector 70

7.3 Summary 748 Option 6: Enabling Competition in Generation and Supply to

Large Users 758.1 Description of the Reform 758.2 Evidence of Benefits and Costs 758.3 Impact on the Cost of Electricity 77

9 Option 7: Creating an Independent System Operator 799.1 Description of the Reform 799.2 Benefits and Costs of the Proposed Reform 829.3 Impact on the Cost of Electricity 83

10 Conclusion and Recommendations 84

Tables Table 1.1: Summary of Reform Options ivTable 3.1: Estimation of Unit Cost of Electricity Generation for the

New NGCC Plant (constant 2010 US$, no escalation) 6Table 3.2: Estimation of Unit Cost of Electricity Generation using theConverted Combined Cycle Plant at Bogue 7Table 3.3: Short-Run Marginal Cost of Plants Currently on theSystem (March 2011 Fuel Prices) 10Table 3.4: Short-Run Marginal Cost of Generation Plants Planned for2014 (with LNG) 13Table 4.1: Renewable Energy TechnologiesDescription, Costs andPotential in Jamaica 19


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Table 4.2: System Weighted Average Marginal Cost of Generation 24Table 4.3: Weighted Average Marginal Cost of Combined Cycle and

Slow Speed Diesel Plants 27

Table 4.4: Short-Run Marginal Cost of Plants (March 2011 FuelPrices) 30Table 4.5: Marginal Cost of Plants on the System (with Renewablesand LNG plants) 33Table 4.6: Key Information on Distributed Renewable Energy Technologies Table 6.1: Energy Efficient Technologies and Estimated Costs 49Table 6.2: Potential Net Financial Savings for Different Customer

Classes from Energy Efficient TechnologiesCurrent Tariff Levels 51

Table 6.3: Potential Net Financial Savings for Different CustomerClassesProjected Tariff Levels 52Table 6.4: Potential Net Saving in Electricity Bills from IncreasedUse of Energy Efficient Technologies 53 Table 7.1: Size of Electricity Markets 61Table 7.2: Short-Run Marginal Cost of Plants on the System (March2011 Fuel Prices) 63Table 7.3: Short-Run Marginal Cost of Plants on the System in 2014(Based on Average Projected Fuel Prices for the Period 2010-2029) 67Table 8.1: Estimation of Unit Cost of Electricity Generation using aSmall Diesel Generator 76Table 10.1: Reducing Electricity Costs in JamaicaCurrent Effortsand Recommendations 85

Figures

Figure 2.1: Electricity Tariffs in the Caribbean, Mauritius, Hawaiiand Florida (Dec. 2010) 3Figure 3.1: Merit Order Dispatch for Typical Week Day (Based on2009 Load Profile) 11Figure 3.2: Merit Order Dispatch for Typical Week Day (Based on2009 Load Profile)Capacity Planned for 2014 14Figure 4.1: Avoided Cost for Firm Renewable Energy Technologies, Wind Power and Solar Photovoltaic (2011-2014) 21


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Figure 4.2: Dispatching of Generation Capacity on a Typical WeekDay in Jamaica and Short-Run Marginal Cost of Plants 22Figure 4.3: Economic Viability of Utility-Scale Renewable Energy Technologies in Jamaica 25Figure 4.4: Merit Order Dispatch on a Typical Week Day in Jamaica 26Figure 4.5: Economic Viability of Utility-Scale Renewables GivenCapacity Planned for 2014 28Figure 4.6: Merit-Order Dispatch with Viable Utility-ScaleRenewables 31Figure 4.7: Merit-Order Dispatch with Viable Utility-ScaleRenewables 34Figure 4.8: Commercial Viability of Distributed Renewable Energy Technologies Figure 4.9: Comparison of Avoided Costs Provided under DifferentContracts 39Figure 5.1: System Losses in Jamaica (Rolling Average for 2005-2010) 41Figure 5.2: Composition of JPSs Electricity Losses, December 2010 42Figure 5.3: Recent Trends in System Losses at JPS 43Figure 5.4: Impact of Net Electricity Losses on the Fuel Cost Pass Through Component of Electricity Tariffs in Jamaica 46Figure 7.1: Possible Structure of the Electricity Sector under Verticaland Horizontal Disaggregation 57Figure 7.2: Dispatching Profile for Typical Week Day 64Figure 7.3: Wholesale Electricity Prices under Single Buyer (CurrentSystem) and Wholesale Competitive Power Markets, US$/kWh 65Figure 7.4: Dispatching Profile for Typical Week Day 68Figure 7.5: Wholesale Electricity Prices under Single Buyer (CurrentMarket Structure) and Wholesale Competitive Power Markets,US$/kWh 69Figure 9.1: Current Arrangement for System Dispatch in Jamaica 79Figure 9.2: Dispatch of Electricity with a New, Independent SystemOperator 81

BoxesBox 3.1: Assumptions for Calculating the Cost of ElectricityGeneration 8


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Box 4.1: Net Billing vs. Net Metering 37Box 5.1: Residential Automated Metering Infrastructure 43Box 6.1: Assumptions for calculating potential net savings from usingmore energy efficient technologies in Jamaica 50Box 6.2: How can the Government help achieve these savings? 54Box 7.1: Price Spikes in Wholesale Electricity Markets 58Box 7.2: Electricity Sector Disaggregation in Dominican Republic 73Box 9.1: Is JPS manipulating dispatch out of merit-order? 81


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Copyright Castalia Limited. All rights reserved. Castalia is not liable for any loss caused by reliance on thisdocument. Castalia is a part of the worldwide Castalia Advisory Group.

Acronyms

ADO Automotive Diesel OilCEO Chief Executive Officer

HFO Heavy Fuel Oil

FSRU Floating Storage & Re-gasification Terminal

IPP Independent Power Producer

JEP Jamaica Energy Partners

JPS Jamaica Public Service Company Limited

JPPC Jamaica Private Power Company Limited

kVA Kilovolt-amperekW Kilowatt

kWh Kilowatt-hours

LRMC Long-Run Marginal Cost

LNG Liquefied Natural Gas

MMBtu Million British Thermal Unit

MW Megawatt

NGCC Natural Gas Combined Cycle

O&M Operation and Maintenance

OUR Office of Utilities Regulation

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SRMC Short-Run Marginal Cost

US$ United States Dollar

WKP West Kingston Power

All figures in this report are in US$ (unless specified otherwise), using the followingexchange rate: 1US$=85.75 J$ (March 2011).


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Executive Summary

High electricity prices are a concern in Jamaica, and impact on the life of residents, as well asthe competitiveness of businesses and industries throughout the country. Amid suchconcerns, JPS engaged Castalia to provide an independent evaluation of a range of possiblereforms as suggested by various stakeholders, from improving current electricity systemoperations to restructuring the electricity sector. In this report we identify the reform optionsthat would enable an effective reduction in electricity prices in Jamaica, and providerecommendations on what can be done to implement these reforms effectively.

Table 1.1 below summarizes the reform options we evaluate, as well as our estimatesregarding the potential impact of implementing each option on electricity costs to consumersin Jamaica, and our recommendations as to which options should be prioritized in order toreduce costs. Sections 1 to 9 of this report demonstrate how we arrived at each of these

estimates and recommendations.The results shown in the table indicate that there are four things that can be done to reduceelectricity costs to consumers in Jamaica:

1. Changing the main fuel for generating electricity to Liquefied Natural Gas(LNG), or coal we find that this could reduce electricity costs by aroundUS$0.10 per kWh for all customers

2. Implementing viable renewable energy projectsbagasse cogeneration, windpower and landfill gas-to-energy all have a cost lower than the short-run marginalcost of most oil-based generation plants that are currently on the system.Implementing these projects could reduce electricity costs by around US$0.02 per

kWh, compared to the current generation capacity mix, and could still beeconomic if LNG was used as a fuel for electricity generation

3. Reducing system losseswhen considering the effect of target system losseson the fuel cost pass-through component of electricity tariffs, we find that eachpercentage point reduction in system losses could reduce electricity tariffs by 0.8percent on average (given a target heat rate of 10,470 kJ per kWh, and given thecurrent fuel mix).1 A reduction in system losses percent of 5 percentage pointscould reduce electricity tariffs by around US$0.01 per kWh for all customers if thecurrent fuel mix is maintained. A reduction in system losses of 5 percentagepoints could reduce tariffs by about US$0.006 per kWh if a large LNG plant wascommissioned and if the existing combined cycle plant was converted to LNG,

keeping all else equal4. Increasing the use of energy efficient technologies amongst end-users

there are many technologies that would enable residential, commercial and

1 This is estimated using the OUR formula examining the sensitivity of the fuel cost component of the tariffs to systemlosses. This estimate does not account for other effects of decreasing system losses on tariffs. For example, a reduction insystem losses and particularly non-technical losses would result in an increase in electricity sales, as some people whoused to steal electricity would become customers and start paying for their own consumption. The increase in electricitysales would mean that fuel costs for electricity generation would be spread across more customers. Over time, thesesavings should translate into lower tariffs to consumers through the performance-based rate setting mechanismcontained in the JPS licence. Therefore, our estimate is conservative and likely underestimates the true potentialreduction in tariffs from reducing system losses.


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industrial customers to reduce their consumption of electricity at a cost lowerthan the current electricity tariffs. In other words, using these technologies willsave customers money by reducing their electricity bills and expenses. We find

that residential customers could achieve net savings equivalent to 16 percent oftheir electricity bills, given current electricity tariffs. Commercial customers couldachieve net savings equivalent to 14 percent of their current electricity bills, andlarge commercial and industrial customers could achieve net savings equivalent to8 percent of their current electricity bills.

In this report, we also analyze other options for reforming the sector, but find that theseoptions would not lead to a reduction in electricity costs in Jamaica. These options are:

Forcing vertical and horizontal separation of electricity services with openaccessthis would involve restructuring the market similarly to what has been donein New Zealand, the Philippines and Dominican Republicnamely to unbundle the

generation, transmission and distribution of electricity, and letting various firms tradeelectricity in a wholesale power market through bilateral contracts and a spot market.

Introducing competition in the electricity sector has proven successful in severalcountriesincluding the United Kingdom, the United States and Australia.However, the benefits from implementing such reform can only be achieved inmarkets that are large enough to accommodate sufficient generators to compete witheach other. With a small system of the size of Jamaicas, there is little scope forattracting more than a few generators; thereby resulting in an oligopoly, with pricesmuch higher than under competition. In fact, we find that restructuring Jamaicaselectricity sector as a competitive market would lead to higher costs than under thecurrent regulatory and market structurewe estimate that costs could increase by

US$0.11 per kWh, compared with current costs, under a market structure similar toNew Zealands. Implementing this reform would also entail a risk of increasingsystem losses, and prevent investment in new capacitysuch problems haveoccurred in electricity markets in New Zealand, the Philippines, and DominicanRepublic

Enabling competition in generation and supply to large users this wouldenable large commercial and industrial electricity customers to buy electricity fromsuppliers other than JPS, and pay JPS a wheeling charge for the power transmittedand distributed. This type of reform would be unlikely to lead to large or widespreadreductions in costs for large electricity users. Perhaps more importantly, anyreduction in JPSs energy sales would be to the detriment of smaller residential and

commercial customers. Electricity tariffs are determined in a way that allows JPS torecover the cost of operating the electricity network, given a determined level ofperformance and efficiency, from all the end users. If several large customers optedout of buying power from the JPS system, the company would still have to maintainthe same transmission and distribution system and almost the same generatingcapacity and therefore, any loss in its revenue would eventually result in a rise intariffs to all of the remaining customers

Creating an independent system operatorthiswould involve setting up a newentity that would be responsible for dispatching the power produced by independentpower producers and JPS unto the JPS-owned transmission and distribution system


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for distribution to customers. It is crucial to ensure that electricity in Jamaica issupplied in a way that minimizes costs. However, creating an independent systemoperator would entail transaction costs and increased overheads that would need to

be borne by customers. Additionally, that independent operator would still need tobe monitored to ensure that it was in fact fulfilling its mandate. Ensuring least-costdispatch can be achieved at lower cost by simply making small additions to the OURcurrent monitoring practices.

In this report we examine each of these options in detail, and provide some practicalrecommendations regarding what stakeholders can do to effectively reduce electricity costsin Jamaica.

We recommend all parties to concentrate their efforts on four things: changing the main fuelfor electricity generation, implementing cost-effective renewable energy projects, reducingsystem losses, and improving energy efficiency at the consumer end.


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Table 1.1: Summary of Reform Options

Option DescriptionImpact on electricity costs

With current capacity With NGC

1. Change mainfuel forelectricitygeneration

Using LNG or coal togenerate a large portion of theelectricity in Jamaica

n/a

Reduction of US$0.10/all customer categoriescommissioning of 360MWCombined Cycle (NGCCconversion of the combinat Bogue to LNG, and asJPSs oil-fired steam unitlonger used for regular di

2. Increasing theuse of

renewableenergy

Implementing economicallyviable utility-scale renewableenergy projects, and increasing

or enabling the use ofcommercially viabledistributed generationtechnologies

Reduction of US$0.02/kWh across all

customer categories

Reduction of US$0.001

all customer categories

3. Reducingsystem losses

Reducing technical and non-technical losses in theelectricity system

A reduction in losses by 5 percentagepoints would enable a reduction ofUS$0.01/kWh in electricity tariffsacross all customer categories

A reduction in losses by points would enable a reUS$0.006 per kWh in elacross all customer categ

4. Increasing theuse of energy

efficienttechnologies

Promoting the use oftechnologies that would

enable customers to saveelectricity at a cost lower thanthe electricity tariff

Net savings equivalent to:

16% of electricity bills for residentialcustomers

14% of electricity bills forcommercial customers

8% of electricity bills for largecommercial and industrial customers

Net savings equivalent to

6% of electricity billscustomers

6% of electricity billscommercial customers

2% of electricity billscommercial and industr


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Option Description Impact on electricity costs

5. Forcingvertical and

horizontalseparation ofelectricityservices withopen access

Separating the generation,

transmission and distributionof electricity, and introducingcompetition in electricitygeneration and retailing

Increase of US$0.11/kWh across allcustomer categories if competition was

introduced amongst current generationassets

Increase of US$0.12/kWcustomer categories

Implementing this reformfinancing of the NGCC pforfeiting the potential saUS$0.10 per kWh

Electricity costs would also increase further due to transaction and rcosts, and increased overhead and administration costs

6. Enablingcompetition ingenerationand supplyfor largeelectricity

users

Enabling large electricity usersto buy electricity fromsuppliers other than JPS, andpay JPS a wheeling charge fortransmitting and distributing

the power

Unlikely reduction in cost for largeindustrial users

Increase in costs for residential andsmall commercial customers

No reduction in cost foindustrial users

Increase in costs for ressmall commercial custo

7. Creating anindependentsystemoperator

Creating a new, separate entitythat would be responsible forthe dispatch of the variousgenerators on the system

No impact or increase:

There is no evidence to confirm that JPS is manipulating the dispaadvantage

The OUR is already monitoring the dispatching

Setting up a new system operator would involve transaction costs in overheads and administration costs, in order to achieve the samwhat can be done with effective monitoring.


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1 IntroductionHigh electricity prices are a concern in Jamaica, and affect the life of residents, as well as thecompetitiveness of businesses and industries throughout the country. Amid such concerns,JPS engaged Castalia to provide an independent evaluation of a range of possible reforms assuggested by various stakeholders, from improving current electricity system operations torestructuring the electricity sector. The aim of this report is to identify the reform optionsthat would enable an effective reduction in electricity prices in Jamaica, and providerecommendations on what can be done to implement these reforms effectively.

In this report we start by reviewing current electricity tariffs in Jamaica, and benchmarkingthese against tariffs in other countries. We then examine seven possible reform options andevaluate their effectiveness in reducing electricity costs in Jamaica. These options are:

1. Changing the main power fuel to a cheaper fuel, such as Liquefied Natural Gas

(LNG) or coal (Section 3)

2. Increasing the use of renewable energy (Section 4)

3. Reducing system losses (Section 5)

4. Increasing the use of energy efficient technologies (Section 6)

5. Forcing vertical and horizontal separation of electricity services with open access(Section 7)

6. Enabling competition in generation for large electricity users (Section 8)

7. Creating an Independent System Operator (Section 9).

For each of these options, we describe the reform, explain what it would look like ifimplemented, and what it would change in the sector. We then evaluate the costs andbenefits of each option compared to the status quo, and determine the impact on electricitycosts and service in Jamaica.

Finally, in Section 10 we summarize the results and provide practical recommendations onwhat stakeholders can focus on to effectively reduce electricity costs in the country.


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2 Electricity Tariffs in Jamaica The current electricity tariffs in Jamaica (including fuel rates and non-fuel rates, andexcluding taxes) are:

US$0.35 per kWh for residential customers with a monthly consumption of 100kWh

US$0.39 per kWh for residential customers with a monthly consumption of 300kWh

US$0.39 for small commercial customers (R20 rate) with a monthly consumptionof 1,000

US$0.33 for large commercial and industrial customers (R40 rate) with a monthlyconsumption of 35,000 kWh and a maximum demand of 100 kVA

US$0.32 for industrial customers (R50 rate) with a monthly consumption of500,000 kWh and a maximum demand of 1,500kVA.2

Stakeholders within the Government and the residential, commercial and industrial sectorsare concerned about electricity tariffs levels and their impact on the national economy. Highelectricity tariffs are affecting the countrys entire population from small, low incomehouseholds, to small businesses and large firms.

Some people in Jamaica think that electricity tariffs in Jamaica are the highest in theCaribbeanFigure 2.1 below shows that this is not true. The figure compares electricitytariffs for residential, commercial and industrial customers across various countries of theCaribbean, as well as Hawaii (for the island of Oahu), Mauritius and Florida, in December

2010. Electricity tariffs have increased in Jamaica and other countries since (due to increasesin fuel costs), but the latest data available across all countries dates from December 2010we use it for consistent comparison.

2 Tariffs levels estimated based on the new tariffs provided in: Office of Utilities Regulation (2011). Jamaica Public ServiceCompany Limited Annual Tariff Adjustment 2011; and adjusted using the fuel and IPP charge and exchange rate adjustmentfor April 2011, given a base exchange rate of US$1:J$86, actual exchange rate of US$1:US$85.7, a target heat rate of10,470 kJ/kWh, and target losses of 17.5%.


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Figure 2.1: Electricity Tariffs in the Caribbean, Mauritius, Hawaii and Florida (Dec.2010)

Note: The tariffs shown for Florida represent tariffs for March 2011

Source: Carilec Tariff Survey (December 2010), Central Electricity Board (http://ceb.intnet.mu/), FloridaPower and Light Company (http://www.fpl.com/), Castalia

The figure above shows that electricity tariffs in Jamaica are in fact about the same as tariffsin several countries of the Caribbean, including Barbados, the Bahamas, and Saint Lucia. Forexample, the residential tariff in Jamaica in December 2010 (US$0.30 per kWh) was the sameas the residential tariff in the Bahamas (also US$0.30 per kWh), and slightly lower than the

residential tariff in Barbados (US$0.31 per kWh). Tariffs in Jamaica were lower than thetariffs in Dominica, Cayman and Turks and Caicos. For example, in Cayman Island theresidential tariff in December 2010 was US$0.41 per kWh. In Turks and Caicos theresidential tariff was US$0.44 per kWh and the commercial tariff was US$0.50 per kWh,compared to a commercial tariff of US$0.35 in Jamaica.

This does not change the fact that tariff levels are a problem in Jamaicaand the figureshows that this could be a problem particularly for firms competing against other firmslocated in Trinidad and Florida, for example.

The reason that electricity costs are high in Jamaica and most countries of the Caribbean isthat these countries are heavily reliant on oil-based fuels, such as Heavy Fuel Oil and dieseloil. There are opportunities for reducing costs by changing the main fuel used for electricitygeneration to cheaper fuels, such as coal or natural gas. For example, although Mauritius hasa smaller power system than Jamaica (with a peak demand of about 380MW in 2008), it hasbeen able to achieve much lower power costs by opting for bagasse and coal generation.

In the following sections we examine how Jamaica could reduce its power costs toconsumers through changing the main fuel used for generating electricity, as well as a rangeof other sector reform options.

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.400.45

US$/kWh

Residentialtariff Commercialtariff Industrialtariff


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3 Option 1: Changing the Main FuelIn this section we examine the option of changing the main fuel used for generatingelectricity to a cheaper fuel. Diesel oil and heavy fuel oil (HFO) are the main fuels currentlybeing used in Jamaica. Liquefied Natural Gas (LNG) and coal both constitute cheaper fuels.In this section we examine the effect of using LNG as a main fuel source, as the OURrecently tendered for a 480MW new plant (including a first block of capacity of 360MW),and a natural gas-fired option was the only bid submitted. We also consider that if LNG wasmade available in Jamaica and this plant was commissioned, JPS would also convert itsexisting combined cycle plant at Bogue (Bogue plant), near Montego Bay to use LNG asfuel.

We find that using LNG as a fuel for electricity generation in Jamaica could lead to areduction in electricity tariffs of around US$0.10 per kWh.

Alternatively, there are other fuel options which, although not examined in detail in thisreport, may enable cost savings in Jamaica. For example, commissioning a large coal plant of360MW could lead to a reduction in electricity prices at least as great as with an LNG plant.Plants running on petcoke may also enable similar cost savings. Should these options revealto be viable options that can reduce electricity costs in Jamaica, they should be consideredfor electricity generation.

Below we describe the option of changing the main fuel for electricity generation to acheaper fuel (3.1). We then estimate the cost of electricity generation from using a cheaperfuel (3.2), and determine the impact on electricity prices to customers (3.3).

3.1 Using a Cheaper FuelNatural gas is a major source of electricity generation worldwide, through the use of gasturbines and steam turbines. Power plants combining gas turbines with a steam turbine incombined cycle mode (Natural Gas Combined Cycle, NGCC) can achieve very highefficiency.

At current prices, LNG is substantially less expensive than diesel fuel: in 2010, the OURestimated that the price of LNG delivered at plant site would be US$8.50 per MMBtu, 3compared to a current price of about US$24 per MMBtu for Automotive Diesel Oil (ADO),and US$17 per MMBtu for Heavy Fuel Oil (HFO).4 Furthermore, natural gas burns morecleanly than other hydrocarbon fuels such as oil and coal, and produces less carbon dioxideper unit of energy released. Combined cycle power generation using natural gas is thus thecleanest source of power available using hydrocarbon fuels, and this technology is widelyused wherever gas can be obtained at a reasonable price.

The Government is well advanced in its plans to make natural gas available in Jamaica.Under current plans, the gas will be purchased in liquefied form (LNG) on world markets,and will enter the country through a floating or seaside re-gasification terminal (FSRU). Thegas will then be distributed through a pipeline network. Recently, the industry trend has beento ship LNG in larger vessels to effect economies of scalethis has led to an oversupply ofsmaller LNG tankers which are serviceable, but economically obsolete as LNG tankers.

3 Office of Utilities Regulation (2010). Generation Expansion Plan 2010. p.40.

4 Prices for March 2011, including cost of delivery to power plants


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These vessels are therefore available as FSRUs. The Government concluded that the FSRUapproach to landing LNG in Jamaica is technically sound, and there are several projectsaround the world which demonstrate this.

Another option that could be considered to generate electricity at a lower cost would consistof commissioning coal plants and using imported coal. Coal-fired power plants can generatebaseload power at a very low cost relative to other fuel cycles. In addition, coal could beimported easily and at a relatively low cost in Jamaica, given that it is already abundant inCaribbean trade, with supplies readily available from the United States and Colombia.

3.2 Change in Cost of Electricity Generation Resulting from Using aCheaper Fuel

In this section we estimate the cost of electricity generation when using a cheaper fuel inJamaica. In particular, we examine the option of using LNG as a fuel, on the basis this is theoption currently being pursued. We base our assumptions on the OURs Generation ExpansionPlan 2010, which recommends the commissioning of three NGCC units of 120MW each in2014, and another 120MW unit in 2016, and also recommends that JPSs existing oil-firedunits are no longer dispatched regularly, but kept in reserve in case of emergency. Inaddition, we assume that JPS would convert its existing combined cycle plant located atBogue (Bogue plant) to use LNG as fuel, using cost estimates from JPS.5

3.2.1 Unit cost of generation from NGCC plantTable 3.1 below demonstrates how we calculate the Long-Run Marginal Cost (LRMC) andShort-Run Marginal Cost (SRMC) of new NGCC capacity, and Table 3.2 demonstrates how we calculate the LRMC and SRMC of the Bogue plant converted to LNG. The SRMCincludes the fuel (LNG) cost, plus any other variable costs that result from operating a plant.

The LRMC includes fuel cost and variable O&M cost, as well as the capital cost recoveryfactor per kWh, and fixed O&M costs.

A key component of the LRMC is the capital-related charge which depends on the requiredrate of return in electricity generation projects. We use a discount rate of 11.95 percent,based on the OURs estimation of the Weighted Average Cost of Capital for the electricitysector in 2009.

The figures for the NGCC plant are based on figures provided in the OURs 2010 GenerationExpansion Plan. The estimates for capital cost and fixed operation and maintenance cost donot appear to be market-specific for Jamaica (given local duties, taxes and constructioncosts), and therefore are likely to be lower than the actual cost of commissioning andoperating a NGCC plant in Jamaica. However, these figures should provide a sense of theorder of magnitude for the LRMC and SRMC of a NGCC plant in Jamaica.

In this section and throughout the rest of this report, we follow the OURs approach ofusing constant real prices.

5 There is a possibility that JEP may also convert its medium speed diesel plant to use LNG as a fuel, if andwhen LNG becomes available. This could result in an even greater reduction in electricity generation costsand electricity tariffs than the reductions we estimate in this section. The estimates of reduction in electricitycosts provided in this section are therefore based on conservative assumptions.


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We assume that once commissioned, the NGCC plant and Bogue plant converted to LNGwill be available 90 percent of the time.

Table 3.1: Estimation of Unit Cost of Electricity Generation for the New NGCC Plant(constant 2010 US$, no escalation)

Average price of natural gas for the period 2010-2029* (a) US$/MMBtu 8.96

Plant heat rate** (b) MMbtu/kWh 0.007255

Installed capacity (c) kW 120,000

Unit capital cost*** (d) US$/kW 1,317

Fixed O&M costs (e) US$/kW/month 1.07

Variable O&M cost (f) US$/kWh 0.00253

Lifetime (g) Years 25

Availability**** (h) % 90

Typical output per year (j = c*h) kWh/kW/year 7,873.2

Total capacity cost (k = c*d) US$ 158,040,000

Annualized capital cost (l ) US$/year 20,080,225

Annual fixed O&M cost (m = e*c*12) US$/year 1,540,800

Typical annual output (n = c*j) kWh/year 944,784,000

Capital cost recovery factor (o = l/n) US$/kWh 0.021

O&M cost per kWh (p) US$/kWh 0.002

LNG cost per kWh (q) US$/kWh 0.065

LRMC (=o+p+q+f) US$/kWh 0.09

SRMC (f+q) US$/kWh 0.07

*Derived from projected LNG prices over the period 2010-2029 (from the Generation Expansion Plan), andadding US$2.5/MMBtu for freight and transport charges to the plant**Converted from a heat rate of 7,654kJ/kWh using a conversion factor of 1,055 MJ per MMBtu***Includes interest during construction, but is unlikely to include local duties, taxes and construction costs****Assuming a forced outage rate of 3 percent and 26 planned outage daysSource: Office of Utilities Regulation (2010). Generation Expansion Plan 2010.


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Table 3.2: Estimation of Unit Cost of Electricity Generation using the ConvertedCombined Cycle Plant at Bogue

Average price of natural gas for the period 2010-2029* (a) US$/MMBtu 8.96

Plant heat rate** (b) MMbtu/kWh 0.008859

Installed capacity*** (c) kW 112,110

Total cost of conversion and pipeline**** (d) US$/kW 97,400,000

Fixed O&M costs (e) US$/kW/month 0.99

Variable O&M cost (f) US$/kWh 0.006

Lifetime (g) Years 25

Availability (h) % 90

Typical output per year (j = c*h) kWh/kW/year 7,884Annualized capital cost (k) US$/year 12,375,436

Annual fixed O&M cost (l = e*c*12) US$/year 1,331,867

Typical annual output (m = c*j) kWh/year 883,875,240

Capital cost recovery factor (o = k/m) US$/kWh 0.014

Fixed O&M cost per kWh (p) US$/kWh 0.002

LNG cost per kWh (q) US$/kWh 0.079

LRMC (=o+p+q+f) US$/kWh 0.101

SRMC (=f+q) US$/kWh 0.085

*Derived from projected LNG prices over the period 2010-2029 (from the Generation Expansion Plan), andadding US$2.5/MMBtu for freight and transport charges to the plant. We assume that the cost of LNG wouldbe the same as for the new NGCC plant.

**Assuming that the conversion would lead to a 0.5 percent improvement compared to the current heat rate ofthe plant; ***Assuming that the conversion would lead to a 1 percent increase in the capacity of the plant;****Cost estimate provided by JPS

Source: JPS; OUR (2010). Generation Expansion Plan 2010.

In the following section we estimate the impact of commissioning three NGCC units of120MW each on the cost of electricity generation in 2014, and converting the Bogue plant to

LNG.3.2.2 Reduction in total cost of electricity generation when using NGCC plant and

converted combined cycle plant

To calculate the reduction in the cost of electricity generation, we:

1. Calculate how much the NGCC plant and Bogue plant would save by avoidingthe need to run expensive HFO and diesel plants. In other words, we calculatehow much less these expensive plants would be used, and hence what the savingsin fuel cost would be


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Below we demonstrate how we calculate the cost of electricity generation with the currentgeneration capacity, and the cost of generation once the NGCC plant comes in and theexisting Bogue plant is converted to LNG.

Cost of electricity generation given existing generation capacity

In this section we estimate the cost of generating power using the existing capacity, in orderto see how much that cost would be reduced when the NGCC plant comes in and theexisting Bogue plant is converted to LNG. We find that once these new plants arecommissioned, the slow speed diesel, oil-fired steam, and combustion turbine plants wouldnot be run. So the cost saving is the savings in fuel cost from not running those plants.

In order to work this out, we need to know the cost of each plant. We also assume thatwhen LNG plant becomes available, the most expensive plants will be the ones that stoprunning. We also assume that the oil-fired steam plants will be decommissioned once theNGCC plant comes in, as outlined in the Generation Expansion Plan 2010.

As an input to calculate the cost of each plant, Table 3.3 below lists the plants currentlyinstalled and being operated by JPS and IPPs in Jamaica (ordered in terms of short-runmarginal cost per kWh generated, from the cheapest to the most expensivethe short-runmarginal cost includes fuel cost, and variable operation and maintenance costs). The tableshows two additional plants:

A new medium speed diesel plant with a total installed capacity of 65MW, whichWest Kingston Power (a subsidiary of JEP) expects to commission by 2012. Weassume that the plant (which we call West Kingston Power throughout thisreport) will be available 90 percent of the time, and use a similar heat rate, fuelcost and variable operation and maintenance cost as for JEPs existing medium-

speed diesel plant JPSs new hydropower plant at Maggotty, which JPS expects to commission in

2013. The installed capacity of this plant will be 6.3MW, and we assume a 45percent capacity factor for the plant on average6

We calculate the average cost of electricity generation using all existing plants as well as these two plants, in order to subsequently strictly isolate the effect ofintroducing LNG as a fuel for electricity generation (from introducing the newNGCC plant and converting the Bogue plant to LNG).

For each plant, the table indicates effective capacity, type and current price of fuel used, andheat rate. The table also shows the fuel cost per kWh (which is calculated, for each plant, as

the heat rate in MMBtu per kWh times the fuel price in US$ per MMBtu) and variableoperation and maintenance (O&M) cost of each plantadding these together gives theshort-run marginal cost of each plant, in US$ per kWh.

6 Capacity factor estimate provided by JPS to the OUR for the Renewable Energy Generation BOO Tender in 2008, andconfirmed by JPS.


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Table 3.3: Short-Run Marginal Cost of Plants Currently on the System (March 2011Fuel Prices)

Note: For the JPPC plant, we assume same HFO prices as those for Hunts Bay (given location proximity).For JEP and West Kingston Power, we assume same HFO prices as for Old Harbour.

We assume an availability of 90 percent for the JEP plant, and 89 percent for the JPPC plant.

Source: OUR (2010), Generation Expansion Plan 2010; JPS

Using the typical weekday load profile for 2009 (provided by the OUR in the GenerationExpansion Plan 2010), and assuming dispatching based on merit order of short-run marginalcosts, we determine the dispatching profile of the system on a typical daythis is illustratedin Figure 3.1 below.

Effectivecapacity

Averageheat rate

Currentfuel

rice**

VariableO&M

cost

Fuel cost Short-runmarginal

cost

MW MMBtu/kWh US$/MMBtu US$/kWh US$/kWh US$/kWh

Wigton Wind farm n/a 10.4 n/a 0.00 0.000 - -

Munro Wind farm n/a 0.9 n/a 0.00 0.000 - -

JPS Hydropower Hydropower n/a 13.4 n/a 0.00 0.000 - -

JPS Maggotty Hydropower n/a 2.8 n/a 0.00 0.000 - -

JPPC Slow Speed Diesel HFO 54.6 0.0077 16.90 0.010 0.13 0.14

JEP Medium Speed Diesel HFO 111.9 0.0078 17.53 0.020 0.14 0.16

West Kingston Power Medium Speed Diesel HFO 58.5 0.0078 17.53 0.020 0.14 0.16

Rockfort Slow Speed Diesel HFO 19.2 0.0093 16.90 0.008 0.16 0.16


Old Harbour Oil Fired Steam HFO 61.8 0.0122 16.70 0.007 0.20 0.21


Hunts Bay Oil Fired Steam HFO 65.1 0.0124 16.79 0.007 0.21 0.21Old Harbour Oil Fired Steam HFO 57 0.0126 16.70 0.007 0.21 0.22

Bogue Combined Cycle ADO 111 0.0089 23.88 0.006 0.21 0.22

Bogue Combustion Turbine ADO 19.9 0.0129 23.75 0.005 0.31 0.31

Hunts Bay Combustion Turbine ADO 21.4 0.0165 23.75 0.005 0.39 0.40







Location/IPP name Type of plantType offossil fuel

used*

* HFO = Heavy Fuel Oil, ADO = Automotive Diesel Oil

** Based on March 2011 prices of fuel delivered at each plant.


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Figure 3.1: Merit Order Dispatch for Typical Week Day (Based on 2009 Load Profile)

Note: For simplicity, we consider the average short-run marginal cost of all oil-fired steam plants together inthis figure. Some of the oil-fired steam units are more expensive than the combined cycle planttherefore, in reality these particular units should be dispatched after the combined cycle plant.

The above figure shows how different plants would be chosen to generate sufficientelectricity to meet demand throughout a typical week day in Jamaica, given the currentsystem plus the additional medium speed diesel plant (included as West Kingston Poweron the figure), and the hydropower plant at Maggotty (included as Hydro on the figure).

The entire colored area shows total electricity demand in MW, and the dispatching of eachplant used to meet this demand (given the effective capacity of each plant). For example, thefigure shows that hydropower and wind plants are dispatched first, as they incur a SRMC ofzero. Then the JPPC, JEP, West Kingston Power and slow speed diesel plants are used, asthey represent the next cheapest options (with a SRMC of US$0.14, $0.16, and $0.17 perkWh, respectively). The oil-fired steam plant is then used, and when demand grows beyondthe capacity of all these plants at about 11:00 am, the more expensive combined cycle plantis added. The combustion turbines are kept in reserve.

Using this order of dispatch, we calculate the average variable cost of the system throughoutthe day. We do this by adding the SRMC of all plants operating on the system at half-hourintervals throughout the day, weighted by their contribution to total generation, 7 and taking

the average of this total weighted-average cost over the entire day.We find that the average variable cost of generation is US$0.17 per kWh.

Cost of generation when using LNG as the main fuel for electricity generation

In this section we estimate the variable cost of electricity generation after LNG is madeavailable in Jamaica. To estimate this cost, we need to make assumptions about what plantswould be added to the system. We assume that JPS would:

7 For example, if at 6:00 am demand is 420MW, and JPPC is operating 60MW of its plant capacity, the weighted averagecost of JPPCs plant is US$0.14 times 14 percent ([60/420]*100), or US$0.0198.

0

100

200

300

400

500

600

700

MW

Timeoftheday

CombinedCycle

OilFiredSteam

SlowSpeedDiesel

JEP

WestKingstonPower

JPPC

Wind

HydroUS$0.14/kWh

US$0.16/kWh

US$0.17/kWh

US$0.22/kWh

US$0.21/kWh(average)

US$0.16/kWh


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Add a 360MW NGCC plant to the system in 2014 (as specified in the OUR2010Generation Expansion Plan)

Convert its existing combined cycle plant located at Bogue in order to use LNGas a fuel in 2014.

In addition, we assume that from 2014 JPS would hold its oil-fired steam plants units (OB2,OB3, OB4 and B6, all running on HFO) in reserve, rather than dispatching them regularly,as prescribed in the OURs Generation Expansion Plan 2010. This means that the estimated variable cost of electricity generation may not pick up the pure effect of using LNG togenerate electricity in Jamaica. Indeed, the oil-fired steam plants are cheaper to run than thecombustion turbines (which are the next alternative available), therefore our estimation mayunderstate the likely savings from using LNG for electricity generation because under theLNG scenario the combustion turbines would need to be used instead of the oil-firedplants. However, this issue turns out to be irrelevant because the NGCC plant and converted

combustion turbine available under the LNG scenario would be sufficiently large to avoidthe use of combustion turbines, and even slow speed diesel units.

The resulting capacity would therefore be a mix of hydropower (including the hydropowerplant at Maggotty), wind power, slow speed diesel, medium speed diesel, and combustionturbines, as well as the combined cycle plant at Bogue (converted to use natural gas as fuel),and the new NGCC plant. We assume that JPS would only use the combustion turbinesoccasionally as peaking units, as these represent the most expensive plants on the system.

Table 3.4 below provides information on the capacity, efficiency and marginal cost for eachof these plants.

To calculate the fuel cost of each plant we use the following fuel prices:

US$8.96 per MMBtu for LNG: this includes the OURs estimated average fuelprice over the period 2010-2029, plus a delivery cost of US$2.50 per MMBtu

US$18.32 per MMBtu for HFO: this includes the OURs estimated average fuelprice over the period 2010-2029 (US$16.67 per MMBtu), adjusted usingPetrojams pricing formulae for fuel delivery to the various power plants

US$21.33 per MMBtu for ADO: including an estimated average fuel price ofUS$19.29 per MMBtu over the period 2010-2029, adjusted using Petrojamspricing formulae for fuel delivery to the various power plants.


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Table 3.4: Short-Run Marginal Cost of Generation Plants Planned for 2014 (with LNG)

*Based on data provided by JPSassuming that the conversion of the plant would increase capacity by 1percent of initial capacity, and improve the heat rate of the plant by 0.5 percent.

Note: LNG = Liquefied Natural Gas, HFO = Heavy Fuel Oil, ADO = Automotive Diesel Oil

Fuel prices based on average projected prices between 2010 and 2019, as projected by the OUR

We assume the same price of natural gas for the Bogue plant and the NGCC plant (although inreality, the price of gas at Bogue plant is likely to be slightly more expensive).

For the Combined Cycle plant, we assume that the heat rate remains the same as the current heat rate.However, Combined Cycle units tend to become less efficient when used as peaking plants, as theyare designed for base or intermediate load.8 Therefore the marginal cost of this plant may increase if itwas used as a peaking plant.

There is a possibility that JEP may also convert its medium speed diesel plant to use LNG as a fuel, if andwhen LNG becomes available. This could result in an even greater reduction in electricity generationcosts and electricity tariffs than the reductions we estimate in this section.

Source: OUR (2010), Generation Expansion Plan 2010; JPS

Figure 3.2 below shows the typical daily dispatching of the systemagain, using the typicalweekday load profile for 2009 provided in the OUR Generation Expansion Plan, and basedon merit order of short-run marginal costs.

8 Chase, D.L. (2000). Combined Cycle Development Evolution and Future. GE Power Systems GER-4206.

Effective

capacity

Average

heat rate

Fuel price

Variable

O&M

cost

Fuel cost

Short-run

marginal

cost





Maggotty Hydropower n/a 2.8 n/a 0.00 0.000 - -

LNG Natural Gas Combined Cycle LNG 323.6 0.0073 8.96 0.003 0.07 0.07

Bogue (converted)* Combined Cycle LNG 100.9 0.0089 8.96 0.006 0.08 0.09








Bogue Combustion Turbine ADO 19.9 0.0169 21.33 0.005 0.36 0.37Bogue Combustion Turbine ADO 21.4 0.0170 21.33 0.005 0.36 0.37





LNG = Liquefied Natural Gas, HFO = Heavy Fuel Oil, ADO = Automotive Diesel Oil

Fuel prices based on average projected fuel prices between 2010 and 2019, as projected by the OUR

Location/IPP name Type of plant

Type of

fossil fuelused


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Figure 3.2: Merit Order Dispatch for Typical Week Day (Based on 2009 LoadProfile)Capacity Planned for 2014

Using the order of dispatch shown in Figure 3.2, we calculate the average variable cost of thesystem throughout the day. We do this by adding the SRMC of all plants operating on thesystem half-hour intervals throughout the day, weighted by their contribution to totalgeneration, then taking the average of this total weighted-average cost over the entire day.

We find that the average variable cost of electricity generation for the system would be

US$0.08 per kWh.

To generate electricity using LNG as a main fuel and achieve this system average variablecost of US$0.08 per kWh, JPS will first need to invest in the new capacity. As the owner of anew plant (and like any other IPPs), JPS will therefore need to recover this capital cost. Toaccount for the capital costs of the new plants, we account for the Long-Run Marginal Cost(LRMC) of the NGCC plant, and of the conversion of the combined cycle plant at Bogue.For the NGCC plant, we use the LRMC derived in Table 3.1. For the conversion of theplant at Bogue, we use a LRMC of US$0.10 per kWh, based on estimates for conversion andpipeline costs provided by JPS.9

When accounting for the capital costs of the NGCC plant and the conversion of the plant at

Bogue, we find that the total cost of the system (including variable costs and capital costs perkWh generated for the plants running on LNG) would be US$0.10 per kWh.

3.3 Impact on the Cost of ElectricityWe estimate the impact on the cost of electricity to JPSs customers as follows:

=

9 Assuming a capital cost of US$97.4 million, fixed O&M costs of US$0.99 per kW per month, heat rate of 0.008859MMBtu/kWh, a discount rate of 11.95 percent and availability of 90 percent.

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

MW

Timeoftheday

JEP

WestKingstonPower

JPPC

ConvertedcombinedcycleatBogue

Naturalgascombinedcycle

Wind

Newhydro

Hydro

US$0.07/kWh

US$0.09/kWh

US$0.15/kWh

US$0.16/kWh


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Where reduction in generation costs is the annual reduction in the cost of generatingelectricity resulting from operating the NGCC plant and Bogue plant converted to LNG(and retiring the oil-fired plant) in US$.

To calculate this, we:

1.Multiply the average variable cost of generation of the system (including variablecosts and capital costs per kWh generated for the plants that are running onLNG) with the planned NGCC plant and Bogue plant converted to LNG(US$0.10 per kWh) by the total amount of electricity generated in 2010 (about4,137 GWh)10

2.Multiply the variable cost of generation with the system capacity before usingLNG as a main fuel by electricity generated in 2010

3.Take the difference between 1 and 2 above.

We find that the annual reduction in electricity generation costs would be about US$313million.

We then divide this figure by total electricity sold in 2010 (about 3,235 GWh).11

We find that the average reduction in electricity prices is US$0.10 per kWh.

All customers (whether residential, commercial or industrial) could benefit from thisreduction equally.

10 Although we used the 2009 load profile to estimate the system average short-run marginal cost, 2010 figures for totalelectricity generation and sales are very close to those of 2009, therefore using the more recent figures should not create asignificant discrepancy.

11 2010 electricity generation and sales figures provided by JPS (2011).


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4 Option 2: Increasing the Use of Renewable EnergyIn this section we examine the potential for reducing electricity prices by implementingadditional economically viable utility-scale renewable energy projects, and increasing the useof commercially viable distributed-scale renewable energy technologies in Jamaica.

We find that bagasse cogeneration, wind power, and landfill gas to energy are cheaper thanthe current plant on the system. Adding these to the system now could reduce electricitycosts by about US$0.02 per kWh.12

We find that distributed scale renewable energy technologies such as small solar photovoltaicsystem and small wind turbines are unlikely to be generally commercially viable in Jamaica,and therefore expect a limited uptake over the short-term. Nevertheless, setting up a netbilling framework in Jamaica would be an effective and appropriate way of enablingcustomers who want to generate their own power, and the use of such framework may

increase over the medium term as the cost of distributed generation technologies comesdown. The OUR is currently working on a net billing framework, but there is scope toimprove over current plans.

Bagasse cogeneration, wind power and landfill gas-to-energy have a higher Long-RunMarginal Cost than the NGCC plant and Bogue plant converted to LNG. However, therenewable energy technologies could still reduce electricity costs after the natural gas plantsare commissioned. The reason is that the plants running on natural gas would not be theonly plants on the system (some of the high cost plant will be kept, such as the mediumspeed diesel and slow speed diesel). Because the renewable energy technologies are cheaperthan these plants, adding these technologies to the system could therefore reduce electricitygeneration costs. Nevertheless, because of the limited capacity of bagasse cogeneration, windpower and landfill gas to energy available in Jamaica, the reduction in electricity generationcosts would probably not be significantabout US$0.001 per kWh. Below we provide adescription of the reform (4.1), examine the costs and benefits of implementingeconomically viable renewable energy projects (4.2), and examine the costs and benefits ofincreasing the use of distributed generation technologies (4.3).

4.1 Description of the ReformThere are already a few renewable energy technologies being used in Jamaica, including:

A 34.7MW wind farm in Manchester (owned and operated by an IndependentPower Producer, Wigton Windfarm Ltd.)Wigton Windfarm Ltd. is alsoplanning another 4MW extension to this farm

A 3MW farm in Munro, owned and operated by JPS

Eight small hydropower plants with a combined capacity of 23MW, owned andoperated by JPS.13 We understand that JPS is also at an advanced stage of planning

12 This estimate accounts for the addition of 60MW of bagasse cogeneration, 70MW of wind power, and 1.3MW of landfillgas-to-energy. Given current costs, waste-to-energy technology would also be viable, however we do not account for thistechnology as it would become non-viable with the addition of a NGCC plant on the system (and conversion of theBogue plant to LNG)by non-viable, we mean that the waste-to-energy plant would generate electricity at a cost higherthan the avoided cost of the system. Hydropower is not considered for utility-scale renewable energy generation, becausemost resources for utility-scale hydropower projects in Jamaica are already used.

13 Ministry of Energy (August 2010).National Renewable Energy Policy.


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a new hydropower plant with a capacity of 6.4MW at Maggotty in St. Elizabeth,and aiming to commission this plant in 2013.

The Government of Jamaica and various stakeholders in the sector recognize that there ispotential for expanding renewable energy generation further through the use of viable utility-scale technologies, as well as small-scale, distributed generation technologies (generation thatis located in close proximity to the load being served).

We look at two reforms. The first involves building large renewable power plants feeding thegrid (utility-scale technologies). The second involves distributed renewable generationserving the customers own needs and selling any excess power into the grid.

In the following section we examine each of these reforms in further detail, and estimatetheir impact on electricity costs in Jamaica.

4.2 Evidence of Benefits and CostsUtility-Scale TechnologiesIn this sub-section we examine the economic viability of utility-scale technologies given thegeneration capacity planned for the near future. This includes all plants that are currently onthe system, in addition to the new medium-speed diesel plant to be commissioned by WestKingston Power, and a new hydropower plant at Maggotty (to be commissioned by JPS in2013). We then examine the viability of these technologies in the context of using LNG as amain fuel source. For this, we consider the viability of renewable energy technologiescompared to the generation capacity mix that the OUR has planned for 2014, whichincludes the addition of a 360MW natural gas combined cycle plant, the conversion of thecombined cycle plant at Bogue to use natural gas as fuel. Furthermore, we assume that JPSwould stop dispatching its oil-fired steam plants regularly, and simply hold them in reservefor generating only in case of emergency. Finally, we estimate the impact of adding

economically viable technologies to the system on electricity costs in Jamaica. We examine the viability of the following utility-scale technologies: bagasse cogeneration, wind power, landfill gas to energy, waste to energy, concentrated solar power, andcommercial-scale solar photovoltaic. We do not consider hydropower because, although it isa mature technology, recent evidence suggests that resources for utility-scale hydropowerprojects are already used.14 While there may be some potential for mini hydropower, we donot examine this potential here, as the contribution of a mini hydropower plant to totalgeneration would be insignificant.

Table 4.1 below summarizes key information on each of these technologies. The tableprovides a brief description of these technologies, and information on their potentialcapacity in Jamaica, potential capacity factor, capital costs and Long-Run Marginal Cost(LRMCwhich includes capital, and operating and maintenance costs). Wherever possible, we use estimates of the Long-Run Marginal Cost (which includes capital costs, fixed andvariable operating costs) from feasibility studies specific to projects in Jamaica.

For solar photovoltaic, wind power and concentrated solar power, we use our existingknowledge of the various projects implemented or considered in other countries in the

14 In response to the OURs competitive tender for renewable energy BOO in 2008, JPS submitted bids for twohydropower plants: the Maggotty Project, with an installed capacity of 6.37MW, and the Great River Project, with aninstalled capacity of 8MW. The bid for the Maggotty Project was accepted, and the project is scheduled for completion in2013.14 However, the Great River Project was rejected, on the grounds that the proposed tariff was too high.


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region, such as Barbados and the Turks and Caicos Islands. We use a discount rate of 11.95percent for utility-scale renewable energy projects, as recommended in the OURs GenerationExpansion Plan 2010 and Declaration of Indicative Generation Avoided Costs.


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We define a technology as economically viable if its LRMC is equal to, or lower than, therelevant avoided cost. The relevant avoided cost for a particular technology depends on thetype of conventional generation that the technology is displacing:

Bagasse cogeneration and waste-to-energy technologies are firmtechnologies; they can be depended on to generate electricity at any time, just likea conventional generation unit. Therefore, the relevant avoided cost should be theSRMC of electricity generation of the marginal plants on the existing system, plusthe capital cost of deferred capacity

Wind energy is considered non-firm. This means that there needs to be aconventional generator on standby that is used as firming supply when the windis not blowing. Every unit of energy (kWh) generated by wind technologies willsave fuel and variable O&M costs, but it will not save the fixed costs of capacity(because the firming technology capacity would also be needed). For wind power,

we therefore use the weighted average SRMC of the marginal plants on theelectricity system as the avoided cost

Solar photovoltaic and Concentrated Solar Power are also non-firm, butgenerate power in daylight hours only. Therefore, we use the SRMC of thespecific plant that constitutes the marginal plant on the system during thistimeframe (daylight hours) as the relevant avoided cost

Overall, we find that bagasse cogeneration, wind power, landfill gas-to-energy and waste-to-energy would be economically viable given the current avoided costs.Once the NGCC plant is commissioned and the existing CC plant converted toLNG, the relevant avoided costs would decrease, nevertheless each of these

technologies except for waste-to-energy would remain viable (the avoided costrelevant to waste-to-energy would decrease to a level below the LRMC of thattechnology)

Figure 4.1 below shows the reduction in the avoided costs relevant to wind, solarand firm renewable energy technologies resulting from the commissioning of theNGCC plant and converting the CC plant to LNG in 2014.


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Figure 4.1: Avoided Cost for Firm Renewable Energy Technologies, Wind Power andSolar Photovoltaic (2011-2014)

4.2.1 Economic viability of adding utility-scale renewables to the current systemIn this section we compare the costs of renewable energy technologies to the relevantavoided costs, given existing capacity and fuel costs. To determine avoided costs we use the2009 load profile and merit-order dispatching profile for a typical week day in Jamaicaaspresented in section 3.2.2, and illustrated again in Figure 4.2 below.

0.00

0.05

0.10

0.15

0.20

0.25

0.30

2011 2012 2013 2014 2015 2016

Bagasse,LandfillGastoEnergy Wind Solar

Commissioning ofnewNGCC

plantandconversionofplant


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Figure 4.2: Dispatching of Generation Capacity on a Typical Week Day in Jamaicaand Short-Run Marginal Cost of Plants

Note: Figure based on 2009 load profile and March 2011 fuel prices

Marginal cost figures based on prices of fuel delivered to power plants in March 2011 of aboutUS$0.17 per MMBtu for HFO, and US$0.24 per MMBtu for ADO (prices provided by JPS).

For simplicity, this figure shows the average short-run marginal cost of all oil-fired steam plantstogether. Some of the oil-fired steam units are in fact more expensive than the combined cycleplanttherefore, in reality these particular units should be dispatched after the combined cycle plant.

Source: Developed using data from: OUR (2010). Generation Expansion Plan 2010, and JPS

0

100

200

300

400

500

600

700

MW

Timeoftheday

CombinedCycle

OilFiredSteam

SlowSpeedDiesel

JEP

WestKingstonPower

JPPC

Wind

HydroUS$0.14/kWh

US$0.16/kWh

US$0.17/kWh

US$0.22/kWh

US$0.21/kWh(average)


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We estimate avoided costs as follows:

For bagasse cogeneration, Concentrated Solar Power (CSP)15 and waste-to-

energy technologies the relevant avoided cost should be the average marginalcost of electricity generation of the existing system plus the capital cost ofdeferred capacity. As illustrated in Figure 4.2, the marginal plant on the system isalways either the oil-fired steam plant, or the combined cycle plant (that is runningon ADO). We calculate the weighted average SRMC as shown in Table 4.2. TheOURGeneration Expansion Plan 2010 shows that the next capacity addition to thesystem will be a natural gas combined cycle plant in 2014 (with a further unit in2016), then a gas turbine unit in 2017. Since the OUR has already started engagingin the procurement of the NGCC plant for 2014, we assume that firm renewableswould only displace the gas turbine unit. We estimate the capital cost of this plantto be around US$0.02 per kWh (assuming a capital cost of US$1,279 per kW,plant lifetime of 25 years, and a discount rate of 11.95 percent).16 The totalavoided cost for firm renewables is therefore US$0.24 per kWh

For wind power, we use the weighted average marginal cost of the electricitysystem throughout the day (US$0.22 per kWh, as shown in Table 4.2) as theavoided cost

For solar photovoltaicwe use the weighted average of the marginal cost of thesystem between 6:00 am and 6:00 pm as the relevant avoided cost (this is alsoUS$0.22 per kWh, as shown in Table 4.2).

15 For the purpose of this analysis, we consider CSP as a firm technology in spite of being a solar technology because weconsider energy storage solutions associated with these plants

16 Estimate of capital cost provided by JPS


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Table 4.2: System Weighted Average Marginal Cost of Generation

Type of plant

Short-run marginal cost

(fuel and variable O&M),US$/kWh*

% of time that the

plant is on themargin**

Weighted average

marginal cost,US$/kWh

Weighted Average Marginal Cost for the Day

Oil-Fired Steam 0.21 60% 0.13

Combined Cycle 0.22 40% 0.09

Total

Weighted Average Marginal Cost between 6:00 am and 6:00pm

Oil-Fired Steam 0.21 54% 0.12

Combined Cycle 0.22 46% 0.10

Total

*Given a price of US$0.24 per MMBtu for ADO and US$0.17 per MMBtu delivered to the plants (March 2011price provided by JPS)

**Calculated as the number of hours that each plant is running, divided by the total number of hours in a day(24) and multiplied by 100

Source: OUR (2010). Generation Expansion Plan 2010.

Figure 4.3 below shows our assessment of the economic and commercial viability ofpotential technologies for renewable generation in Jamaica. The figure shows the Long RunMarginal Cost (LRMC, or all-in cost) of generation (US$ per kWh) for the renewable energytechnologies, and compares these against the relevant avoided costs.


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Figure 4.3: Economic Viability of Utility-Scale Renewable Energy Technologies inJamaica

Figure 4.3 shows the LRMC of each technology in US$ per kWh, compared to the relevantavoided costs. For example, technologies with costs highlighted in grey represent the firm

technologies, and should be compared with the avoided cost highlighted in grey. The figureshows that bagasse cogeneration, wind power, and landfill gas to energy are currentlyeconomically viable in Jamaica, and waste-to-energy may be viable. Solar PV and CSP have aLRMC well above the relevant avoided cost, and therefore not considered economicallyviable.

In section 4.2.3 we analyze how implementing these projects would affect the cost ofelectricity in Jamaica.

4.2.2 Economic viability of renewables once LNG is used as the main fuelIn this section we examine the viability of utility-scale renewable energy technologies giventhe commissioning of a 360MW NGCC plant, the conversion of the CC plant at Bogue to

use LNG as a fuel, and assuming that JPS stops dispatching its oil-fired steam plantsregularly (as planned by the OUR in the Generation Expansion Plan 2010).

We use the dispatching profile that we estimated in section 3.2.2as shown in Figure 4.4below. The figure shows that given this new mix of capacity on the system, the marginalplants are the JPPC plant, the converted combined cycle plant at Bogue, and the WestKingston Power plantsthis is because the oil-fired steam plant would no longer be usedfor dispatching, and the natural gas plants would also displace the slow speed diesel plantand high-cost combustion turbines (these plants would therefore not be needed for meetingdemand).

0.52

0.38

0.32

0.30

0.24

0.15

0.15

0.12

0.10 0.20 0.30 0.40 0.50 0.60

SolarPV(HighEfficiency,fixed,commercial)

SolarPV(thinfilm,fixed,commercial)

CSP(SolarTower,w/storage)

CSP(ParabolicTrough,w/storage)

WastetoEnergy(incineration)

Wind(2MWturbines)

Landfillgastoenergy(internalcombustion)

Bagassecogeneration

US$/kWh

Avoidedcost(firm):US$0.24/kWh

Avoidedcost(wind):US$0.22/kWh

Avoidedcost(solar):US$0.22/kWh


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Figure 4.4: Merit Order Dispatch on a Typical Week Day in Jamaica

Note: Figures based on 2009 load profile, and projected fuel prices for the period 2010-2019

To determine the economic viability of renewable energy technologies given the newgeneration mix, we use the same LRMC estimates for renewable energy technologies as inthe previous subsection. However, given the addition of a large natural gas plant to thesystem, the avoided costs are expected to decreasewe estimate the relevant avoided costsas follows:

For firm technologies, we use an avoided cost of US$0.17 per kWh, calculated byadding the weighted average marginal cost of the combined cycle, JPPC and WestKingston Power and JEP plants (shown in Table 4.3 below) to the capacity costof the natural gas combustion turbine that would be displaced (US$0.02 per kWh)

For wind power, we use the weighted average marginal cost of slow speed diesel,JEP and combined cycle plants throughout the day (US$0.15 per kWh)

For solar power we use the weighted average marginal cost of the JPPC, JEP andconverted Bogue plants during daylight hours (US$0.16 per kWh, as shown inTable 4.3 below).

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

MW

Timeoftheday

JEP

WestKingstonPower

JPPC

ConvertedcombinedcycleatBogue

Naturalgascombinedcycle

Wind

Newhydro

Hydro

US$0.07/kWh

US$0.09/kWh

US$0.15/kWh

US$0.16/kWh


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Table 4.3: Weighted Average Marginal Cost of Combined Cycle and Slow SpeedDiesel Plants

Type of plantShort-run marginal cost

(fuel and variable O&M),US$/kWh*

% of time that theplant is on the

margin

Weighted averagemarginal cost,

US$/kWh

Weighted Average Marginal Cost throughout the Day

Converted CombinedCycle

0.09 19%0.02

JPPC 0.15 19% 0.03

West Kingston Powerand JEP

0.16 63% 0.010

Total

Weighted Average Marginal Cost during Daylight Hours (between 6:00 am and 6:00 pm)

Converted CombinedCycle

0.09 4%0.004

JPPC 0.15 29% 0.04

West Kingston Powerand JEP

0.16 67% 0.11

Total

Note: We assume that the JEP plant and West Kingston Power plant have the same characteristics and costs

Source: Data from OUR (2010). Generation Expansion Plan 2010

Figure 4.5 below shows our assessment of the economic viability of potential technologiesfor utility-scale renewable energy generation in Jamaica. The figure shows that bagassecogeneration and landfill gas to energy technologies would remain economically viable, and wind power may be viable. However, waste-to-energy would become non-viable, as theavoided cost would decrease well below the LRMC of the plant (avoided cost of US$0.17per kWh, compared to LRMC of US$0.24 per kWh).


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Figure 4.5: Economic Viability of Utility-Scale Renewables Given Capacity Plannedfor 2014

4.2.3 Reduction in electricity costs from implementing utility-scale renewableenergy technologies

In the previous subsection we found that three types of renewable energy technologieswould be viable given the current fuel prices and generation capacity: bagasse cogeneration,wind power and landfill gas to energy. We also found that these technologies would likelyremain viable once LNG is used as a main fuel for electricity generation. Waste-to-energymay currently be viable, but would not remain viable once LNG is used for electricitygeneration.

In this section we estimate the potential reduction in electricity costs from implementingthese viable technologies. We consider the addition of the full potential capacity estimatedfor bagasse cogeneration, wind power and landfill gas-to-energy technologies in Jamaica asindicated in Table 4.1that is: 60MW of bagasse cogeneration, 70MW of wind power, and a

1.3MW landfill gas-to-energy plant. We do not consider the addition of the waste-to-energyplant, as the plant would not be able to recover its LRMC from 2014 onwards.

We calculate the reduction in the cost of electricity generation as follows:

1.We estimate the average variable cost of electricity generation throughout the daygiven the baseline generation capacity mix (which we already did in section 3.2.2)

2.We calculate the average variable cost of electricity generation throughout the dayif the renewable energy plants were added to the system. This cost should belower than the cost calculated in step 1, because the renewable energy plants would avoid the need to run expensive plants running on diesel and HFO,thereby enabling savings in fuel costs

0.52

0.38

0.32

0.30

0.24

0.15

0.15

0.12

0.10 0.20 0.30 0.40 0.50 0.60

SolarPV(HighEfficiency,fixed,commercial)

SolarPV(thinfilm,fixed,commercial)

CSP(SolarTower,w/storage)

CSP(ParabolicTrough,w/storage)

WastetoEnergy(incineration)

Wind(2MWturbines)

Landfillgastoenergy(internalcombustion)

Bagassecogeneration

US$/kWh

Avoidedcost(wind):US$0.15/kWh

Avoidedcost(firm):US$0.17/kWh

Avoidedcost(solar):US$0.16/kWh


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3. We subtract the costs calculated in step 1 and 2, to give us the reduction inelectricity generation costs resulting from the use of renewable energytechnologies

4. We estimate the impact on the cost of electricity to JPSs customers using thesame method as in section 3.2.2; that is:

= 5.We then repeat this process to compare the cost of electricity generation when the

NGCC plant comes in, and the CC plant converted to LNG, and the oil-firedsteam plants are no longer dispatched regularly, with and without the renewableenergy plants.

Reduction in prices from adding renewable energy technologies to the currentsystem

In section 3.2.2 we demonstrated how we calculate the average variable cost of electricitygeneration using the current capacitywe estimate this cost to be US$0.17 per kWh.

To calculate how this cost would change as a result of adding more renewables to thesystem, we use the data provided in Table 4.4 below, which shows the short-run marginalcost of all existing plants, and of the new renewable energy plants added to the system.


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Table 4.4: Short-Run Marginal Cost of Plants (March 2011 Fuel Prices)

Note: Landfill gas-to-energy and bagasse cogeneration would involve some variable O&M costs. Nevertheless,such costs are typically insignificant compared to the fixed O&M costs, and because there was no specific dataavailable on variable O&M costs for such plants in Jamaica, we approximated these costs to zero. This shouldnot change the results, however, as these costs are typically very small.

Figure 4.6 below shows the typical daily dispatching of the systemagain, using the typicalweekday load profile for 2009 provided in the OUR Generation Expansion Plan, and basedon merit order of short-run marginal costs. The figure shows that the new renewable energy

plants would be used at all times, given that they are less costly than the existing fossil fuelplants. The figure also shows that with the addition of these renewable energy plants, theexpensive combustion turbine plants would not be required as much to satisfy electricitydemand on a daily basis.

Effective

capacity

Average

heat rate

Current

fuel

rice**

Variable

O&M

cost

Fuel cost

Short-run

marginal

cost





JPS Maggotty Hydropower n/a 2.8 n/a 0.00 0.000 - -

New wind Wind farm n/a 21.0 n/a 0.0 0.000 - -

Bagasse Bagasse cogeneration Bagasse 51.0 n/a 0.0 0.000 - -

Landfill gas Lanfill gas-to-energy Landfill gas 1.0 n/a 0.0 0.000 - -








Hunts Bay Oil Fired Steam HFO 65.1 0.012 16.8 0.007 0.21 0.21


Bogue Combined Cycle ADO 111.0 0.009 23.9 0.006 0.21 0.22









Location/IPP name Type of plant

Type of

fossil fuelused*

* HFO = Heavy Fuel Oil, ADO = Automotive Diesel Oil

** Based on March 2011 prices of fuel delivered at each plant.

Note: for the JPPC plant, we assume same HFO prices as those for Hunts Bay (given location proximity). For JEP and West Kingston Power,we assume same HFO prices as for Old Harbour


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Figure 4.6: Merit-Order Dispatch with Viable Utility-Scale Renewables

Note: Figures based on 2009 load profile provided in the OURGeneration Expansion Plan2010, and March2011 fuel prices provided by JPS

For simplicity, this figure shows the average short-run marginal cost of all oil-fired steam plantstogether. Some of the oil-fired steam units are in fact more expensive than the combined cycleplanttherefore, in reality these particular units should be dispatched after the combined cycle plant.

Using the order of dispatch shown above, we calculate the average variable cost of thesystem throughout the day. We do this by:

1.Multiplying the short-run marginal cost of all plants operating on the system bytheir contribution to total generation at half-hour intervals throughou

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