options to bring down electricity costs in jamaica … table of contents executive summary i 1...

Options to Bring Down the Cost of Electricity in Jamaica

Final Report 23 June 2011

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Disclaimer This report was financially supported by Jamaica Public Service Company Limited (JPS) and prepared following interviews conducted with staff members of JPS, as well as several members 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 be attributed to JPS, the Government of Jamaica or any of its agencies, or to any of the individuals interviewed.

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Table of Contents Executive Summary i

1 Introduction 1

2 Electricity Tariffs in Jamaica 2

3 Option 1: Changing the Main Fuel 4

3.1 Using a Cheaper Fuel 4

3.2 Change in Cost of Electricity Generation Resulting from Using a Cheaper Fuel 5

3.2.1 Unit cost of generation from NGCC plant 5

3.2.2 Reduction in total cost of electricity generation when using NGCC plant and converted combined cycle plant 7

3.3 Impact on the Cost of Electricity 14

4 Option 2: Increasing the Use of Renewable Energy 16

4.1 Description of the Reform 16

4.2 Evidence of Benefits and Costs—Utility-Scale Technologies 17

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

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

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

4.3 Evidence of Benefits and Costs—Distributed Scale Technologies 35

5 Option 3: Reducing System Losses 40


5.1.1 Definition of system losses 40

5.2 Potential for Electricity Loss Reduction in Jamaica 41

5.2.1 Net electricity losses in Jamaica 41


6 Option 4: Increasing the Use of Energy Efficient Technologies 48


6.2 Evidence of Benefits and Costs 48

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6.3 Impact on the Cost of Electricity to Consumers 52

7 Option 5: Forcing Vertical and Horizontal Disaggregation of the Electricity Sector 55



7.2.1 Experience with Wholesale and Retail Competition in 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 from Restructuring the Jamaican Electricity Sector 70

7.3 Summary 74

8 Option 6: Enabling Competition in Generation and Supply to Large Users 75




9 Option 7: Creating an Independent System Operator 79


9.2 Benefits and Costs of the Proposed Reform 82


10 Conclusion and Recommendations 84

Tables Table 1.1: Summary of Reform Options iv

Table 3.1: Estimation of Unit Cost of Electricity Generation for the New NGCC Plant (constant 2010 US$, no escalation) 6

Table 3.2: Estimation of Unit Cost of Electricity Generation using the Converted Combined Cycle Plant at Bogue 7

Table 3.3: Short-Run Marginal Cost of Plants Currently on the System (March 2011 Fuel Prices) 10

Table 3.4: Short-Run Marginal Cost of Generation Plants Planned for 2014 (with LNG) 13

Table 4.1: Renewable Energy Technologies—Description, Costs and Potential in Jamaica 19

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Table 4.2: System Weighted Average Marginal Cost of Generation 24

Table 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 Fuel Prices) 30

Table 4.5: Marginal Cost of Plants on the System (with Renewables and LNG plants) 33

Table 4.6: Key Information on Distributed Renewable Energy Technologies 35

Table 6.1: Energy Efficient Technologies and Estimated Costs 49

Table 6.2: Potential Net Financial Savings for Different Customer Classes from Energy Efficient Technologies—Current Tariff Levels 51

Table 6.3: Potential Net Financial Savings for Different Customer Classes—Projected Tariff Levels 52

Table 6.4: Potential Net Saving in Electricity Bills from Increased Use of Energy Efficient Technologies 53

Table 7.1: Size of Electricity Markets 61

Table 7.2: Short-Run Marginal Cost of Plants on the System (March 2011 Fuel Prices) 63

Table 7.3: Short-Run Marginal Cost of Plants on the System in 2014 (Based on Average Projected Fuel Prices for the Period 2010-2029) 67

Table 8.1: Estimation of Unit Cost of Electricity Generation using a Small Diesel Generator 76

Table 10.1: Reducing Electricity Costs in Jamaica—Current Efforts and Recommendations 85

Figures Figure 2.1: Electricity Tariffs in the Caribbean, Mauritius, Hawaii and Florida (Dec. 2010) 3

Figure 3.1: Merit Order Dispatch for Typical Week Day (Based on 2009 Load Profile) 11

Figure 3.2: Merit Order Dispatch for Typical Week Day (Based on 2009 Load Profile)—Capacity Planned for 2014 14

Figure 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 Week Day in Jamaica and Short-Run Marginal Cost of Plants 22

Figure 4.3: Economic Viability of Utility-Scale Renewable Energy Technologies in Jamaica 25

Figure 4.4: Merit Order Dispatch on a Typical Week Day in Jamaica 26

Figure 4.5: Economic Viability of Utility-Scale Renewables Given Capacity Planned for 2014 28

Figure 4.6: Merit-Order Dispatch with Viable Utility-Scale Renewables 31

Figure 4.7: Merit-Order Dispatch with Viable Utility-Scale Renewables 34

Figure 4.8: Commercial Viability of Distributed Renewable Energy Technologies 36

Figure 4.9: Comparison of Avoided Costs Provided under Different Contracts 39

Figure 5.1: System Losses in Jamaica (Rolling Average for 2005-2010) 41

Figure 5.2: Composition of JPS’s Electricity Losses, December 2010 42

Figure 5.3: Recent Trends in System Losses at JPS 43

Figure 5.4: Impact of Net Electricity Losses on the Fuel Cost Pass Through Component of Electricity Tariffs in Jamaica 46

Figure 7.1: Possible Structure of the Electricity Sector under Vertical and Horizontal Disaggregation 57

Figure 7.2: Dispatching Profile for Typical Week Day 64

Figure 7.3: Wholesale Electricity Prices under Single Buyer (Current System) and Wholesale Competitive Power Markets, US$/kWh 65

Figure 7.4: Dispatching Profile for Typical Week Day 68

Figure 7.5: Wholesale Electricity Prices under Single Buyer (Current Market Structure) and Wholesale Competitive Power Markets, US$/kWh 69

Figure 9.1: Current Arrangement for System Dispatch in Jamaica 79

Figure 9.2: Dispatch of Electricity with a New, Independent System Operator 81

Boxes Box 3.1: Assumptions for Calculating the Cost of Electricity Generation 8

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Box 4.1: Net Billing vs. Net Metering 37

Box 5.1: Residential Automated Metering Infrastructure 43

Box 6.1: Assumptions for calculating potential net savings from using more energy efficient technologies in Jamaica 50

Box 6.2: How can the Government help achieve these savings? 54

Box 7.1: Price Spikes in Wholesale Electricity Markets 58

Box 7.2: Electricity Sector Disaggregation in Dominican Republic 73

Box 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 this document. Castalia is a part of the worldwide Castalia Advisory Group.

Acronyms ADO Automotive Diesel Oil

CEO 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-ampere

kW 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 following exchange 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 as the competitiveness of businesses and industries throughout the country. Amid such concerns, JPS engaged Castalia to provide an independent evaluation of a range of possible reforms as suggested by various stakeholders, from improving current electricity system operations to restructuring the electricity sector. In this report we identify the reform options that would enable an effective reduction in electricity prices in Jamaica, and provide recommendations on what can be done to implement these reforms effectively.

Table 1.1 below summarizes the reform options we evaluate, as well as our estimates regarding the potential impact of implementing each option on electricity costs to consumers in Jamaica, and our recommendations as to which options should be prioritized in order to reduce 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 reduce electricity 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 around US$0.10 per kWh for all customers

2. Implementing viable renewable energy projects—bagasse cogeneration, wind power and landfill gas-to-energy all have a cost lower than the short-run marginal cost 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 be economic if LNG was used as a fuel for electricity generation

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

4. 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 system

losses. This estimate does not account for other effects of decreasing system losses on tariffs. For example, a reduction in system losses and particularly non-technical losses would result in an increase in electricity sales, as some people who used to steal electricity would become customers and start paying for their own consumption. The increase in electricity sales would mean that fuel costs for electricity generation would be spread across more customers. Over time, these savings should translate into lower tariffs to consumers through the performance-based rate setting mechanism contained in the JPS licence. Therefore, our estimate is conservative and likely underestimates the true potential reduction in tariffs from reducing system losses.

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industrial customers to reduce their consumption of electricity at a cost lower than the current electricity tariffs. In other words, using these technologies will save customers money by reducing their electricity bills and expenses. We find that residential customers could achieve net savings equivalent to 16 percent of their electricity bills, given current electricity tariffs. Commercial customers could achieve net savings equivalent to 14 percent of their current electricity bills, and large commercial and industrial customers could achieve net savings equivalent to 8 percent of their current electricity bills.

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

Forcing vertical and horizontal separation of electricity services with open access—this would involve restructuring the market similarly to what has been done in New Zealand, the Philippines and Dominican Republic—namely to unbundle the generation, transmission and distribution of electricity, and letting various firms trade electricity in a wholesale power market through bilateral contracts and a spot market.

Introducing competition in the electricity sector has proven successful in several countries—including the United Kingdom, the United States and Australia. However, the benefits from implementing such reform can only be achieved in markets that are large enough to accommodate sufficient generators to compete with each other. With a small system of the size of Jamaica’s, there is little scope for attracting more than a few generators; thereby resulting in an oligopoly, with prices much higher than under competition. In fact, we find that restructuring Jamaica’s electricity sector as a competitive market would lead to higher costs than under the current regulatory and market structure—we estimate that costs could increase by US$0.11 per kWh, compared with current costs, under a market structure similar to New Zealand’s. Implementing this reform would also entail a risk of increasing system losses, and prevent investment in new capacity—such problems have occurred in electricity markets in New Zealand, the Philippines, and Dominican Republic

Enabling competition in generation and supply to large users—this would enable large commercial and industrial electricity customers to buy electricity from suppliers other than JPS, and pay JPS a wheeling charge for the power transmitted and distributed. This type of reform would be unlikely to lead to large or widespread reductions in costs for large electricity users. Perhaps more importantly, any reduction in JPS’s energy sales would be to the detriment of smaller residential and commercial customers. Electricity tariffs are determined in a way that allows JPS to recover the cost of operating the electricity network, given a determined level of performance and efficiency, from all the end users. If several large customers opted out of buying power from the JPS system, the company would still have to maintain the same transmission and distribution system and almost the same generating capacity and therefore, any loss in its revenue would eventually result in a rise in tariffs to all of the remaining customers

Creating an independent system operator—this would involve setting up a new entity that would be responsible for dispatching the power produced by independent power 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 is supplied in a way that minimizes costs. However, creating an independent system operator would entail transaction costs and increased overheads that would need to be borne by customers. Additionally, that independent operator would still need to be monitored to ensure that it was in fact fulfilling its mandate. Ensuring least-cost dispatch can be achieved at lower cost by simply making small additions to the OUR current monitoring practices.

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

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

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Table 1.1: Summary of Reform Options

Option Description Impact on electricity costs

Recommendations With current capacity With NGCC plant*

1. Change main fuel for electricity generation

Using LNG or coal to generate a large portion of the electricity in Jamaica

n/a

Reduction of US$0.10/kWh across all customer categories from the commissioning of 360MW Natural Gas Combined Cycle (NGCC) plant, conversion of the combined cycle plant at Bogue to LNG, and assuming that JPS’s oil-fired steam units are no longer used for regular dispatch

Top priority to pursue

2. Increasing the use of renewable energy

Implementing economically viable utility-scale renewable energy projects, and increasing or enabling the use of commercially viable distributed generation technologies

Reduction of US$0.02/kWh across all customer categories

Reduction of US$0.001/kWh across all customer categories Second priority

3. Reducing system losses

Reducing technical and non-technical losses in the electricity system

A reduction in losses by 5 percentage points would enable a reduction of US$0.01/kWh in electricity tariffs across all customer categories

A reduction in losses by 5 percentage points would enable a reduction of US$0.006 per kWh in electricity tariffs across all customer categories

Third priority

4. Increasing the use of energy efficient technologies

Promoting the use of technologies that would enable customers to save electricity at a cost lower than the electricity tariff

Net savings equivalent to: 16% of electricity bills for residential customers 14% of electricity bills for commercial customers 8% of electricity bills for large commercial and industrial customers

Net savings equivalent to: 6% of electricity bills for residential customers 6% of electricity bills for commercial customers 2% of electricity bills for large commercial and industrial customers

Fourth priority

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Option Description Impact on electricity costs Recommendations

5. Forcing vertical and horizontal separation of electricity services with open access

Separating the generation, transmission and distribution of electricity, and introducing competition in electricity generation and retailing

Increase of US$0.11/kWh across all customer categories if competition was introduced amongst current generation assets

Increase of US$0.12/kWh across all customer categories Implementing this reform may prevent financing of the NGCC plant, thereby forfeiting the potential saving of US$0.10 per kWh

Do not implement

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

6. Enabling competition in generation and supply for large electricity users

Enabling large electricity users to buy electricity from suppliers other than JPS, and pay JPS a wheeling charge for transmitting and distributing the power

Unlikely reduction in cost for large industrial users Increase in costs for residential and small commercial customers

No reduction in cost for large industrial users Increase in costs for residential and small commercial customers

Do not implement

7. Creating an independent system operator

Creating a new, separate entity that would be responsible for the dispatch of the various generators on the system

No impact or increase: There is no evidence to confirm that JPS is manipulating the dispatching to its advantage The OUR is already monitoring the dispatching Setting up a new system operator would involve transaction costs and increase in overheads and administration costs, in order to achieve the same result as what can be done with effective monitoring.

Do not implement

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

In this report we start by reviewing current electricity tariffs in Jamaica, and benchmarking these against tariffs in other countries. We then examine seven possible reform options and evaluate 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 if implemented, and what it would change in the sector. We then evaluate the costs and benefits of each option compared to the status quo, and determine the impact on electricity costs and service in Jamaica.

Finally, in Section 10 we summarize the results and provide practical recommendations on what 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, and excluding taxes) are:

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

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

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

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

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

Stakeholders within the Government and the residential, commercial and industrial sectors are concerned about electricity tariffs levels and their impact on the national economy. High electricity tariffs are affecting the country’s entire population from small, low income households, to small businesses and large firms.

Some people in Jamaica think that electricity tariffs in Jamaica are the highest in the Caribbean—Figure 2.1 below shows that this is not true. The figure compares electricity tariffs for residential, commercial and industrial customers across various countries of the Caribbean, 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 increases in fuel costs), but the latest data available across all countries dates from December 2010—we use it for consistent comparison.

2 Tariffs levels estimated based on the new tariffs provided in: Office of Utilities Regulation (2011). Jamaica Public Service

Company Limited – Annual Tariff Adjustment 2011; and adjusted using the fuel and IPP charge and exchange rate adjustment for 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 of 10,470 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/), Florida Power and Light Company (http://www.fpl.com/), Castalia

The figure above shows that electricity tariffs in Jamaica are in fact about the same as tariffs in several countries of the Caribbean, including Barbados, the Bahamas, and Saint Lucia. For example, the residential tariff in Jamaica in December 2010 (US$0.30 per kWh) was the same as 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 the tariffs in Dominica, Cayman and Turks and Caicos. For example, in Cayman Island the residential tariff in December 2010 was US$0.41 per kWh. In Turks and Caicos the residential 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 Jamaica—and the figure shows that this could be a problem particularly for firms competing against other firms located in Trinidad and Florida, for example.

The reason that electricity costs are high in Jamaica and most countries of the Caribbean is that these countries are heavily reliant on oil-based fuels, such as Heavy Fuel Oil and diesel oil. There are opportunities for reducing costs by changing the main fuel used for electricity generation to cheaper fuels, such as coal or natural gas. For example, although Mauritius has a smaller power system than Jamaica (with a peak demand of about 380MW in 2008), it has been 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 to consumers through changing the main fuel used for generating electricity, as well as a range of other sector reform options.

0.000.050.100.150.200.250.300.350.400.45

US$/kWh

Residential tariff Commercial tariff Industrial tariff

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3 Option 1: Changing the Main Fuel In this section we examine the option of changing the main fuel used for generating electricity to a cheaper fuel. Diesel oil and heavy fuel oil (HFO) are the main fuels currently being 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 OUR recently 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 was made available in Jamaica and this plant was commissioned, JPS would also convert its existing combined cycle plant at Bogue (‘Bogue plant’), near Montego Bay to use LNG as fuel.

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

Alternatively, there are other fuel options which, although not examined in detail in this report, may enable cost savings in Jamaica. For example, commissioning a large coal plant of 360MW 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 reveal to be viable options that can reduce electricity costs in Jamaica, they should be considered for electricity generation.

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

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

At current prices, LNG is substantially less expensive than diesel fuel: in 2010, the OUR estimated that the price of LNG delivered at plant site would be US$8.50 per MMBtu,3 compared 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 more cleanly than other hydrocarbon fuels such as oil and coal, and produces less carbon dioxide per unit of energy released. Combined cycle power generation using natural gas is thus the cleanest source of power available using hydrocarbon fuels, and this technology is widely used 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). The gas will then be distributed through a pipeline network. Recently, the industry trend has been to ship LNG in larger vessels to effect economies of scale—this has led to an oversupply of smaller 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 FSRU approach to landing LNG in Jamaica is technically sound, and there are several projects around the world which demonstrate this.

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

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

In this section we estimate the cost of electricity generation when using a cheaper fuel in Jamaica. In particular, we examine the option of using LNG as a fuel, on the basis this is the option currently being pursued. We base our assumptions on the OUR’s Generation Expansion Plan 2010, which recommends the commissioning of three NGCC units of 120MW each in 2014, and another 120MW unit in 2016, and also recommends that JPS’s existing oil-fired units are no longer dispatched regularly, but kept in reserve in case of emergency. In addition, we assume that JPS would convert its existing combined cycle plant located at Bogue (‘Bogue plant’) to use LNG as fuel, using cost estimates from JPS.5

3.2.1 Unit cost of generation from NGCC plant

Table 3.1 below demonstrates how we calculate the Long-Run Marginal Cost (LRMC) and Short-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 SRMC includes 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 recovery factor per kWh, and fixed O&M costs.

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

The figures for the NGCC plant are based on figures provided in the OUR’s 2010 Generation Expansion Plan. The estimates for capital cost and fixed operation and maintenance cost do not appear to be market-specific for Jamaica (given local duties, taxes and construction costs), and therefore are likely to be lower than the actual cost of commissioning and operating a NGCC plant in Jamaica. However, these figures should provide a sense of the order 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 OUR’s approach of using 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 and

when LNG becomes available. This could result in an even greater reduction in electricity generation costs and electricity tariffs than the reductions we estimate in this section. The estimates of reduction in electricity costs 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 LNG will 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), and adding 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 days Source: 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 Converted Combined 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




Availability (h) % 90

Typical output per year (j = c*h) kWh/kW/year 7,884

Annualized 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


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

*Derived from projected LNG prices over the period 2010-2029 (from the Generation Expansion Plan), and adding US$2.5/MMBtu for freight and transport charges to the plant. We assume that the cost of LNG would be 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 of the 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 of 120MW 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 avoiding the need to run expensive HFO and diesel plants. In other words, we calculate how much less these expensive plants would be used, and hence what the savings in fuel cost would be

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Below we demonstrate how we calculate the cost of electricity generation with the current generation capacity, and the cost of generation once the NGCC plant comes in and the existing 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 order to see how much that cost would be reduced when the NGCC plant comes in and the existing Bogue plant is converted to LNG. We find that once these new plants are commissioned, the slow speed diesel, oil-fired steam, and combustion turbine plants would not 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 that when LNG plant becomes available, the most expensive plants will be the ones that stop running. We also assume that the oil-fired steam plants will be decommissioned once the NGCC 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 currently installed and being operated by JPS and IPPs in Jamaica (ordered in terms of short-run marginal cost per kWh generated, from the cheapest to the most expensive—the short-run marginal cost includes fuel cost, and variable operation and maintenance costs). The table shows two additional plants:

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

JPS’s 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 45 percent 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 of introducing LNG as a fuel for electricity generation (from introducing the new NGCC plant and converting the Bogue plant to LNG).

For each plant, the table indicates effective capacity, type and current price of fuel used, and heat 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 variable operation and maintenance (O&M) cost of each plant—adding these together gives the short-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, and

confirmed by JPS.

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Table 3.3: Short-Run Marginal Cost of Plants Currently on the System (March 2011 Fuel 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 Generation Expansion Plan 2010), and assuming dispatching based on merit order of short-run marginal costs, we determine the ‘dispatching profile’ of the system on a typical day—this is illustrated in Figure 3.1 below.

Effective capacity

Average heat rate

Current fuel

price**

Variable O&M cost

Fuel cost Short-run marginal

costMW 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 Rockfort Slow Speed Diesel HFO 19.2 0.0095 16.90 0.008 0.16 0.17

Old Harbour Oil Fired Steam HFO 61.8 0.0122 16.70 0.007 0.20 0.21 Old Harbour Oil Fired Steam HFO 65.1 0.0123 16.70 0.007 0.21 0.21

Hunts Bay Oil Fired Steam HFO 65.1 0.0124 16.79 0.007 0.21 0.21 Old 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 Bogue Combustion Turbine ADO 19.9 0.0169 23.75 0.005 0.40 0.41 Bogue Combustion Turbine ADO 21.4 0.0170 23.75 0.005 0.40 0.41

Hunts Bay Combustion Turbine ADO 32.1 0.0179 23.75 0.005 0.43 0.43 Bogue Combustion Turbine ADO 17.9 0.0180 23.75 0.005 0.43 0.43 Bogue Combustion Turbine ADO 17.9 0.0180 23.75 0.005 0.43 0.43 Bogue Combustion Turbine ADO 17.9 0.0212 23.75 0.005 0.50 0.51

Location/IPP name Type of plantType of

fossil 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 in

this figure. Some of the oil-fired steam units are more expensive than the combined cycle plant—therefore, 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 sufficient electricity to meet demand throughout a typical week day in Jamaica, given the current system plus the additional medium speed diesel plant (included as “West Kingston Power” on 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 each plant used to meet this demand (given the effective capacity of each plant). For example, the figure shows that hydropower and wind plants are dispatched first, as they incur a SRMC of zero. Then the JPPC, JEP, West Kingston Power and slow speed diesel plants are used, as they represent the next cheapest options (with a SRMC of US$0.14, $0.16, and $0.17 per kWh, respectively). The oil-fired steam plant is then used, and when demand grows beyond the capacity of all these plants at about 11:00 am, the more expensive combined cycle plant is added. The combustion turbines are kept in reserve.

Using this order of dispatch, we calculate the average variable cost of the system throughout the day. We do this by adding the SRMC of all plants operating on the system at half-hour intervals 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 made available in Jamaica. To estimate this cost, we need to make assumptions about what plants would 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 average

cost of JPPC’s plant is US$0.14 times 14 percent ([60/420]*100), or US$0.0198.

0

100

200

300

400

500

600

700

MW

Time of the day

Combined Cycle

Oil‐Fired Steam

Slow Speed Diesel

JEP

West Kingston Power

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 OUR 2010 Generation Expansion Plan)

Convert its existing combined cycle plant located at Bogue in order to use LNG as 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 OUR’s Generation Expansion Plan 2010. This means that the estimated variable cost of electricity generation may not pick up the pure effect of using LNG to generate electricity in Jamaica. Indeed, the oil-fired steam plants are cheaper to run than the combustion turbines (which are the next alternative available), therefore our estimation may understate the likely savings from using LNG for electricity generation because under the ‘LNG scenario’ the combustion turbines would need to be used instead of the oil-fired plants. 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 avoid the use of combustion turbines, and even slow speed diesel units.

The resulting capacity would therefore be a mix of hydropower (including the hydropower plant at Maggotty), wind power, slow speed diesel, medium speed diesel, and combustion turbines, 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 turbines occasionally 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 each of 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 OUR’s estimated average fuel price 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 OUR’s estimated average fuel price over the period 2010-2029 (US$16.67 per MMBtu), adjusted using Petrojam’s pricing formulae for fuel delivery to the various power plants

US$21.33 per MMBtu for ADO: including an estimated average fuel price of US$19.29 per MMBtu over the period 2010-2029, adjusted using Petrojam’s pricing 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 JPS—assuming that the conversion of the plant would increase capacity by 1 percent 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 in reality, 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 they are designed for base or intermediate load.8 Therefore the marginal cost of this plant may increase if it was 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 and when LNG becomes available. This could result in an even greater reduction in electricity generation costs and electricity tariffs than the reductions we estimate in this section.


Figure 3.2 below shows the typical daily dispatching of the system—again, using the typical weekday load profile for 2009 provided in the OUR Generation Expansion Plan, and based on 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 priceVariable

O&M cost




JPS Hydropower Hydropower n/a 13.4 n/a 0.00 0.000 - - 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 0.0129 21.33 0.005 0.28 0.28 Hunts Bay Combustion Turbine ADO 21.4 0.0165 21.33 0.005 0.35 0.36

Bogue Combustion Turbine ADO 19.9 0.0169 21.33 0.005 0.36 0.37 Bogue 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


fossil fuel used

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

Using the order of dispatch shown in Figure 3.2, we calculate the average variable cost of the system throughout the day. We do this by adding the SRMC of all plants operating on the system half-hour intervals throughout the day, weighted by their contribution to total generation, 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 variable cost of US$0.08 per kWh, JPS will first need to invest in the new capacity. As the owner of a new plant (and like any other IPPs), JPS will therefore need to recover this capital cost. To account 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 the plant at Bogue, we use a LRMC of US$0.10 per kWh, based on estimates for conversion and pipeline 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 per kWh generated for the plants running on LNG) would be US$0.10 per kWh.

3.3 Impact on the Cost of Electricity We estimate the impact on the cost of electricity to JPS’s 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 0.008859

MMBtu/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

Time of the day

JEP

West Kingston Power

JPPC

Converted combined cycle at Bogue

Natural gas combined cycle

Wind

New hydro

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 generating electricity 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 variable costs and capital costs per kWh generated for the plants that are running on LNG) 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 (about 4,137 GWh)10

2. Multiply the variable cost of generation with the system capacity before using LNG 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$313 million.

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 this reduction equally.

10 Although we used the 2009 load profile to estimate the system average short-run marginal cost, 2010 figures for total

electricity generation and sales are very close to those of 2009, therefore using the more recent figures should not create a significant discrepancy.

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

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

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

We find that distributed scale renewable energy technologies such as small solar photovoltaic system 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 net billing framework in Jamaica would be an effective and appropriate way of enabling customers 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 comes down. The OUR is currently working on a net billing framework, but there is scope to improve over current plans.

Bagasse cogeneration, wind power and landfill gas-to-energy have a higher Long-Run Marginal Cost than the NGCC plant and Bogue plant converted to LNG. However, the renewable energy technologies could still reduce electricity costs after the natural gas plants are commissioned. The reason is that the plants running on natural gas would not be the only plants on the system (some of the high cost plant will be kept, such as the medium speed diesel and slow speed diesel). Because the renewable energy technologies are cheaper than these plants, adding these technologies to the system could therefore reduce electricity generation costs. Nevertheless, because of the limited capacity of bagasse cogeneration, wind power and landfill gas to energy available in Jamaica, the reduction in electricity generation costs would probably not be significant—about US$0.001 per kWh. Below we provide a description of the reform (4.1), examine the costs and benefits of implementing economically viable renewable energy projects (4.2), and examine the costs and benefits of increasing the use of distributed generation technologies (4.3).

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

A 34.7MW wind farm in Manchester (owned and operated by an Independent Power Producer, Wigton Windfarm Ltd.)—Wigton Windfarm Ltd. is also planning 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 and operated 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 landfill

gas-to-energy. Given current costs, waste-to-energy technology would also be viable, however we do not account for this technology as it would become non-viable with the addition of a NGCC plant on the system (and conversion of the Bogue plant to LNG)—by non-viable, we mean that the waste-to-energy plant would generate electricity at a cost higher than the avoided cost of the system. Hydropower is not considered for utility-scale renewable energy generation, because most 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 is potential for expanding renewable energy generation further through the use of viable utility-scale technologies, as well as small-scale, distributed generation technologies (generation that is located in close proximity to the load being served).

We look at two reforms. The first involves building large renewable power plants feeding the grid (‘utility-scale technologies’). The second involves distributed renewable generation serving 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 estimate their impact on electricity costs in Jamaica.

4.2 Evidence of Benefits and Costs—Utility-Scale Technologies In this sub-section we examine the economic viability of utility-scale technologies given the generation capacity planned for the near future. This includes all plants that are currently on the system, in addition to the new medium-speed diesel plant to be commissioned by West Kingston Power, and a new hydropower plant at Maggotty (to be commissioned by JPS in 2013). We then examine the viability of these technologies in the context of using LNG as a main fuel source. For this, we consider the viability of renewable energy technologies compared to the generation capacity ‘mix’ that the OUR has planned for 2014, which includes the addition of a 360MW natural gas combined cycle plant, the conversion of the combined cycle plant at Bogue to use natural gas as fuel. Furthermore, we assume that JPS would stop dispatching its oil-fired steam plants regularly, and simply hold them in reserve for 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, and commercial-scale solar photovoltaic. We do not consider hydropower because, although it is a mature technology, recent evidence suggests that resources for utility-scale hydropower projects are already used.14 While there may be some potential for mini hydropower, we do not examine this potential here, as the contribution of a mini hydropower plant to total generation would be insignificant.

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

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

14 In response to the OUR’s competitive tender for renewable energy BOO in 2008, JPS submitted bids for two

hydropower plants: the Maggotty Project, with an installed capacity of 6.37MW, and the Great River Project, with an installed capacity of 8MW. The bid for the Maggotty Project was accepted, and the project is scheduled for completion in 2013.14 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 11.95 percent for utility-scale renewable energy projects, as recommended in the OUR’s Generation Expansion Plan 2010 and Declaration of Indicative Generation Avoided Costs.

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Table 4.1: Renewable Energy Technologies—Description, Costs and Potential in Jamaica

Technology Description Potential capacity,

MW

Potential capacity factor, %

Capital cost, US$/kW

LRMC, US$/kWh

Bagasse cogeneration

Uses fuel to generate both heat and electricity with combined heat and power plants

60MW 85% $3,000 $0.12 *

Wind power (2 MW turbines)

Captures the kinetic energy in surface winds with blades, and uses the mechanical power generated by the rotation of the blades to turn a generator, converting kinetic power into electrical energy

70MW 30% $2,640 $0.15**

Landfill gas to energy

Uses the gas produced from landfills to generate electricity. The technology for extracting landfill gas is mature and widely available

1.3 MW 80% $3,800 $0.15 ***

Waste to energy Converts waste matter into heat or various forms of fuel that can be used to generate electricity. A proven, commercial technology used in more than 25 countries

65MW 85% $8,250 (incineration technology)

$0.24 ****

Concentrated solar power

Converts the sun’s energy into high temperature heat using various mirror or lens configurations. This heat is then transformed into mechanical energy through a boiler that powers a steam turbine, and then into electricity (or directly into electricity using micro-turbines)

n/a 45% (solar tower) 65% (parabolic trough)

$8,000 (solar tower) $12,000 (parabolic trough)

$0.32 (solar tower) US$0.30 (parabolic trough)

Commercial-scale solar photovoltaic

Transforms solar radiation into electricity. The basic component is the PV cell, a semiconductor device that converts solar radiation into direct-current electricity

n/a 20% $5,000 (high efficiency) $4,000 (thin film)

US$0.48 (high efficiency) US$0.48 (thin film)

*As disclosed by the Sugar Industry Authority on the basis of recent feasibility studies for bagasse cogeneration projects. This estimate is consistent with prices of electricity purchased by the utility in Mauritius from independent power producers operating bagasse cogeneration plants; **Based on capital cost of the 14MW extension of the Wigton wind farm (US$47.5 million for 14MW); *** OUR estimate of levelized cost of a 1.3MW plant proposed as part of the OUR’s tender for renewable energy generation in 2008; **** discussion with Petroleum Corporation of Jamaica Source: Government of Jamaica (2010) National Renewable Energy Policy; Castalia; Wigton Windfarm Ltd; http://www.pcj.com/wigton/about/factsheet.html;

Petroleum Corporation of Jamaica; Sugar Industry Authority; JPS

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

Bagasse cogeneration and waste-to-energy technologies are ‘firm technologies’; they can be depended on to generate electricity at any time, just like a conventional generation unit. Therefore, the relevant avoided cost should be the SRMC of electricity generation of the marginal plants on the existing system, plus the capital cost of deferred capacity

Wind energy is considered ‘non-firm’. This means that there needs to be a conventional generator on standby that is used as ‘firming’ supply when the wind is not blowing. Every unit of energy (kWh) generated by wind technologies will save 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 the electricity system as the avoided cost

Solar photovoltaic and Concentrated Solar Power are also non-firm, but generate power in daylight hours only. Therefore, we use the SRMC of the specific plant that constitutes the marginal plant on the system during this timeframe (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 to LNG, the relevant avoided costs would decrease, nevertheless each of these technologies except for waste-to-energy would remain viable (the avoided cost relevant to waste-to-energy would decrease to a level below the LRMC of that technology)

Figure 4.1 below shows the reduction in the avoided costs relevant to wind, solar and firm renewable energy technologies resulting from the commissioning of the NGCC 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 and Solar Photovoltaic (2011-2014)

4.2.1 Economic viability of adding utility-scale renewables to the current system

In this section we compare the costs of renewable energy technologies to the relevant avoided costs, given existing capacity and fuel costs. To determine avoided costs we use the 2009 load profile and merit-order dispatching profile for a typical week day in Jamaica—as presented 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, Landfill Gas to Energy Wind Solar

Commissioning of new NGCC plant and conversion of plant

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Figure 4.2: Dispatching of Generation Capacity on a Typical Week Day in Jamaica and 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 about US$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 plants together. Some of the oil-fired steam units are in fact more expensive than the combined cycle plant—therefore, 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

Time of the day

Combined Cycle

Oil‐Fired Steam

Slow Speed Diesel

JEP

West Kingston Power

JPPC

Wind

HydroUS$0.14/kWh

US$0.16/kWh

US$0.17/kWh

US$0.22/kWh


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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 marginal cost of electricity generation of the existing system plus the capital cost of deferred capacity. As illustrated in Figure 4.2, the marginal plant on the system is always either the oil-fired steam plant, or the combined cycle plant (that is running on ADO). We calculate the weighted average SRMC as shown in Table 4.2. The OUR Generation Expansion Plan 2010 shows that the next capacity addition to the system will be a natural gas combined cycle plant in 2014 (with a further unit in 2016), then a gas turbine unit in 2017. Since the OUR has already started engaging in the procurement of the NGCC plant for 2014, we assume that firm renewables would only displace the gas turbine unit. We estimate the capital cost of this plant to 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 total avoided cost for firm renewables is therefore US$0.24 per kWh

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

For solar photovoltaic we use the weighted average of the marginal cost of the system between 6:00 am and 6:00 pm as the relevant avoided cost (this is also US$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 we

consider 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 the

margin**

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 0.22

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 0.22

*Given a price of US$0.24 per MMBtu for ADO and US$0.17 per MMBtu delivered to the plants (March 2011 price 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 of potential technologies for renewable generation in Jamaica. The figure shows the Long Run Marginal Cost (LRMC, or all-in cost) of generation (US$ per kWh) for the renewable energy technologies, and compares these against the relevant avoided costs.

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

Figure 4.3 shows the LRMC of each technology in US$ per kWh, compared to the relevant avoided 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 figure shows that bagasse cogeneration, wind power, and landfill gas to energy are currently economically viable in Jamaica, and waste-to-energy may be viable. Solar PV and CSP have a LRMC well above the relevant avoided cost, and therefore not considered economically viable.

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

4.2.2 Economic viability of renewables once LNG is used as the main fuel

In this section we examine the viability of utility-scale renewable energy technologies given the 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 it’s oil-fired steam plants regularly (as planned by the OUR in the Generation Expansion Plan 2010).

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

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

Solar PV (High‐Efficiency, fixed, commercial)

Solar PV (thin film, fixed, commercial)

CSP (Solar Tower, w/storage)

CSP (Parabolic Trough, w/storage)

Waste to Energy (incineration)

Wind (2MW turbines)

Landfill gas to energy (internal combustion)


US$/kWh

Avoided cost (firm): US$0.24/kWh

Avoided cost (wind): US$0.22/kWh

Avoided cost (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 new generation mix, we use the same LRMC estimates for renewable energy technologies as in the previous subsection. However, given the addition of a large natural gas plant to the system, the avoided costs are expected to decrease—we estimate the relevant avoided costs as follows:

For firm technologies, we use an avoided cost of US$0.17 per kWh, calculated by adding the weighted average marginal cost of the combined cycle, JPPC and West Kingston Power and JEP plants (shown in Table 4.3 below) to the capacity cost of 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 and converted Bogue plants during daylight hours (US$0.16 per kWh, as shown in Table 4.3 below).

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

MW

Time of the day

JEP

West Kingston Power

JPPC



Wind

New hydro

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 Speed Diesel Plants

Type of plant Short-run marginal cost

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

% of time that the plant is on the

margin

Weighted average marginal cost,

US$/kWh

Weighted Average Marginal Cost throughout the Day

Converted Combined Cycle

0.09 19% 0.02

JPPC 0.15 19% 0.03

West Kingston Power and JEP

0.16 63% 0.010

Total 0.15

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


0.09 4% 0.004

JPPC 0.15 29% 0.04

West Kingston Power and JEP

0.16 67% 0.11

Total 0.16

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 technologies for utility-scale renewable energy generation in Jamaica. The figure shows that bagasse cogeneration 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 the avoided cost would decrease well below the LRMC of the plant (avoided cost of US$0.17 per 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 Planned for 2014

4.2.3 Reduction in electricity costs from implementing utility-scale renewable

energy technologies

In the previous subsection we found that three types of renewable energy technologies would 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 likely remain viable once LNG is used as a main fuel for electricity generation. Waste-to-energy may currently be viable, but would not remain viable once LNG is used for electricity generation.

In this section we estimate the potential reduction in electricity costs from implementing these viable technologies. We consider the addition of the full potential capacity estimated for bagasse cogeneration, wind power and landfill gas-to-energy technologies in Jamaica as indicated in Table 4.1—that 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-energy plant, 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 day given 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 day if the renewable energy plants were added to the system. This cost should be lower 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

Solar PV (High‐Efficiency, fixed, commercial)


CSP (Solar Tower, w/storage)

CSP (Parabolic Trough, w/storage)

Waste to Energy (incineration)

Wind (2MW turbines)

Landfill gas to energy (internal combustion)


US$/kWh

Avoided cost (wind): US$0.15/kWh

Avoided cost (firm): US$0.17/kWh

Avoided cost (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 in electricity generation costs resulting from the use of renewable energy technologies

4. We estimate the impact on the cost of electricity to JPS’s customers using the same 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-fired steam plants are no longer dispatched regularly, with and without the renewable energy plants.

Reduction in prices from adding renewable energy technologies to the current system

In section 3.2.2 we demonstrated how we calculate the average variable cost of electricity generation using the current capacity—we 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 the system, we use the data provided in Table 4.4 below, which shows the short-run marginal cost 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 data available on variable O&M costs for such plants in Jamaica, we approximated these costs to zero. This should not change the results, however, as these costs are typically very small.

Figure 4.6 below shows the typical daily dispatching of the system—again, using the typical weekday load profile for 2009 provided in the OUR Generation Expansion Plan, and based on 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 fuel plants. The figure also shows that with the addition of these renewable energy plants, the expensive combustion turbine plants would not be required as much to satisfy electricity demand on a daily basis.

Effective capacity

Average heat rate

Current fuel

price**

Variable O&M cost





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 - - JPPC Slow Speed Diesel HFO 54.6 0.008 16.9 0.010 0.13 0.14 JEP Medium Speed Diesel HFO 111.9 0.008 17.5 0.020 0.14 0.16



Hunts Bay Oil Fired Steam HFO 65.1 0.012 16.8 0.007 0.21 0.21 Old Harbour Oil Fired Steam HFO 57.0 0.013 16.7 0.007 0.21 0.22

Bogue Combined Cycle ADO 111.0 0.009 23.9 0.006 0.21 0.22 Bogue Combustion Turbine ADO 19.9 0.013 23.8 0.005 0.31 0.31




fossil fuel used*

* 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 OUR Generation Expansion Plan 2010, and March

2011 fuel prices provided by JPS For simplicity, this figure shows the average short-run marginal cost of all oil-fired steam plants together. Some of the oil-fired steam units are in fact more expensive than the combined cycle plant—therefore, 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 the system throughout the day. We do this by:

1. Multiplying the short-run marginal cost of all plants operating on the system by their contribution to total generation at half-hour intervals throughout the day

2. Taking the average of the weighted-average cost of all plants over the entire day.

We find that the average variable cost of electricity generation would decrease to US$0.14 per kWh.

To achieve this reduction in variable costs, investment in renewable energy capacity would be required, and the owners of the renewable energy plants will need to recover their capital cost. To account for the capital costs of the new plants, we account for the Long-Run Marginal Cost (LRMC) of the renewable energy plants (shown in Table 4.1).

When accounting for the capital costs of the renewable energy plants, we find that the total cost of the system (including variable costs and capital costs per kWh generated of the new renewable energy plants) would be US$0.16 per kWh.

We then estimate the impact on the cost of electricity to JPS’s customers as follows: =

0

100

200

300

400

500

600

700

MW

Time of the day

Combined Cycle

Oil‐Fired Steam

Slow Speed Diesel

JEP

New JEP

JPPC


Bagasse

New Wind

Existing Wind

Hydro

US$0.14/kWh

US$0.17/kWh

US$0.16/kWh

US$0.21/kWh

US$0.16/kWh

US$0.22/kWh

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Where ‘reduction in generation costs’ is the annual reduction in the cost of generating electricity resulting from implementing the viable renewable energy projects, in US$. To calculate this, we:

1. Multiply the average variable cost of generation of the system with the viable renewable energy capacity (including the capital cost of renewable energy plants—that is US$0.16 per kWh) by the electricity generated in 2010 (about 4,137 GWh)

2. Multiply the system average variable cost of generation without the renewables by electricity generated in 2010


We find that the annual reduction in electricity generation costs would be about US$51 million.

We then divide this figure by total electricity sold in 2010 (about 3,235 GWh).17

We find that the average reduction in electricity prices is US$0.02 per kWh.

Reduction in prices from adding renewable energy technologies to the system planned for 2014

In this section we compare the estimated cost of electricity generation once LNG is used as a main fuel for electricity generation (that is, once the NGCC plant is commissioned, the CC plant at Bogue has been converted to use LNG, and the oil-fired steam plants no longer dispatched regularly), with the cost of electricity generation if the viable renewable energy plants were added to that system.

In section 3.2.2 we demonstrated how we calculate the average variable cost of electricity generation using the capacity planned for 2014—we estimate this cost to be US$0.08 per kWh.

To calculate how this cost would change as a result of adding more renewables to the system, we use the data provided in Table 4.5 below, which shows the effective capacity and short-run-marginal cost of all plants that would be on the system, including the NGCC plant, converted CC plant, and the new bagasse cogeneration, wind power and landfill gas to energy plants.

17 2010 generation and sales figures provided by JPS.

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Table 4.5: Marginal Cost of Plants on the System (with Renewables and LNG plants)

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 data available on variable O&M costs for such plants in Jamaica, we approximated these costs to zero. This should not change the results, however, as these costs are typically very small.

Figure 4.7 below shows the typical daily dispatching of the system—again, using the typical weekday load profile for 2009 provided in the OUR Generation Expansion Plan 2010, and based on merit order of the marginal cost of each plant.

The figure shows that the new renewable energy plants would be dispatched before the NGCC plant (as they incur a short-run marginal cost of zero). The figure also shows that with the addition of these renewable energy plants, JEP’s medium-speed diesel plant would not be used as much on a daily basis to satisfy electricity demand. The renewable energy plants would also enable fuel cost savings, as the JPPC, JEP and West Kingston Power plants would not be needed as much (see Figure 3.2 in comparison).

Effective capacity

Average heat rate

Current fuel

price**

Variable O&M cost



Wigton Wind farm n/a 10.4 n/a 0.00 0.000 0.00 - Munro Wind farm n/a 0.9 n/a 0.00 0.000 0.00 -

JPS Hydropower Hydropower n/a 13.4 n/a 0.00 0.000 0.00 - JPS Maggotty Hydropower n/a 2.8 n/a 0.00 0.000 0.00 -

New wind Wind farm n/a 21.0 n/a 0.00 0.000 0.00 - Bagasse Bagasse cogeneration Bagasse 51.0 n/a 0.00 0.000 0.00 -

Landfill gas Lanfill gas-to-energy Landfill gas 1.0 n/a 0.00 0.000 0.00 - NGCC Natural Gas Combined Cycle LNG 323.6 0.01 8.96 0.003 0.07 0.07

Bogue (converted) Combined Cycle LNG 100.9 0.009 9.0 0.006 0.08 0.09 JPPC Slow Speed Diesel HFO 54.6 0.008 18.32 0.01 0.14 0.15 JEP Medium Speed Diesel HFO 111.9 0.008 18.32 0.020 0.14 0.16

West Kingston Power Medium Speed Diesel HFO 58.5 0.008 18.32 0.020 0.14 0.16 Rockfort Slow Speed Diesel HFO 19.2 0.009 18.32 0.008 0.17 0.18 Rockfort Slow Speed Diesel HFO 19.2 0.009 18.32 0.008 0.17 0.18 Bogue Combustion Turbine ADO 19.9 0.01 21.33 0.01 0.28 0.28




fossil fuel used*

* HFO = Heavy Fuel Oil, ADO = Automotive Diesel Oil ** Based on projected fuel prices for the period 2010-2029Note: 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. For the Combined Cycle plant, we assume that the heat rate remains the same as the current heat rate.

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Figure 4.7: Merit-Order Dispatch with Viable Utility-Scale Renewables

Note: Figure based on 2009 load profile and projected fuel prices for the period 2010-2029 provided in the

OUR Generation Expansion Plan 2010

Using the order of dispatch shown above, we calculate the average variable cost of the system throughout the day. We do this by multiplying the short-run marginal cost of all plants operating on the system by their contribution to total generation at half-hour intervals throughout the day. We then take the average of the weighted-average cost of all plants over the entire day. We find that the cost of electricity generation would decrease to US$0.06 per kWh.

When accounting for the capital costs per kWh generated of the renewable energy plants and of the NGCC and CC plants, the average cost of electricity generation (including variable costs of all plants, and capital costs per kWh generated of the new plants) would increase to about US$0.09 per kWh.

We then estimate the impact on the cost of electricity to JPS’s customers as follows: =

Where ‘reduction in generation costs’ is the annual reduction in the cost of generating electricity resulting from implementing the viable renewable energy projects, in US$. To calculate this, we:

1. Multiply the average cost of generation of the system with the viable renewable energy capacity (taking into account the capital and fixed O&M costs of the new plants—US$0.09 per kWh) by the electricity generated in 2010

2. Multiply the cost of generation with projected capacity (with NGCC plant, converted combined cycle plant and no oil-based steam plant—including capital and fixed O&M costs) by electricity generated in 2010


0

100

200

300

400

500

600

700

MW

Time of the day

West Kingston Power

JPPC


Natural Gas Combined Cycle


Bagasse

New Wind

Existing Wind

Hydro

US$0.07/kWh

US$0.09/kWh

US$0.16/kWhUS$0.14/kWh

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We find that the annual reduction in electricity generation costs would be about US$1.9 million.

We then divide this figure by total electricity sold in 2010—this results in an average reduction in electricity prices of US$0.001 per kWh.

4.3 Evidence of Benefits and Costs—Distributed Scale Technologies In this section we examine the commercial viability of three distributed renewable energy technologies in Jamaica: small wind turbines, small thin film solar photovoltaic panels (fixed), and high-efficiency solar photovoltaic panels (fixed). We use cost estimates for these technologies from other countries of the Caribbean, which should be a reasonable approximation given the similar geographical and climate conditions. Table 4.6 below shows the typical size, capacity factor and capital cost and LRMC for each of these technologies. We use a 15 percent discount rate (compared to 11.95 percent for utility-scale technologies), because distributed renewable energy technologies are typically implemented by hotels, businesses and households—who have a higher cost of capital than utilities.

Table 4.6: Key Information on Distributed Renewable Energy Technologies

Technology Typical

size, kW

Potential capacity

factor

Capital cost, US$/kW

Long-Run Marginal Cost,

US$/kWh

Thin film solar photovoltaic, fixed (small)

2 21% 5,000 0.48

Thin film solar photovoltaic, fixed (commercial)

50 21% 4,000 0.38

Small wind turbine 10 30% 6,000 0.41

High-efficiency solar photovoltaic, fixed (small)

3 19% 6,000 0.63

High-efficiency solar photovoltaic, fixed (commercial)

50 19% 5,000 0.52

Figure 4.8 below compares the LRMC of each of these technologies to current tariffs for residential and small commercial customers in Jamaica. The figure also displays the projected tariffs in 2014—to calculate these tariffs we use our estimation of tariff reductions as a result of using LNG as a main fuel source for generating electricity (US$0.09 per kWh), as calculated in section 3.2.2 of this report.

The figure shows that of all these technologies, the commercial-sized thin film fixed solar photovoltaic is the only technology that can be considered commercially viable given the March 2011 electricity tariffs in Jamaica—in other words, this technology is the only one that can generate electricity at a cost that is lower than the relevant electricity tariff. However, this technology would be unlikely to remain commercially viable once LNG is used as a main fuel for electricity generation, as the addition of this plant to the system is likely to reduce electricity tariffs significantly (down to US$0.30 per kWh for small commercial customers with a consumption of 1000 kWh per month), as shown in the figure below and demonstrated in section 3.2.2.

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Implementing such technologies would not generate any savings to customers and therefore it is unlikely that many people will invest in these technologies over the next few years. Given the small size of these technologies and the limited expected uptake, the potential for generating electricity from these technologies in Jamaica is very limited.

Figure 4.8: Commercial Viability of Distributed Renewable Energy Technologies

Nevertheless, some people may wish to use these technologies to generate their own power, even if at a high cost. In addition, possible further reductions in the cost of such technologies mean that more consumers may start to find it attractive to install these technologies on their own premises. Distributed-scale renewable generation can also be advantageous not only to individual customers, but on a nation-wide level—provided that there are adequate frameworks in place to avoid compromising on electricity cost, safety, quality and reliability. Potential benefits of distributed-scale renewable generation include minimizing transmission and distribution losses, reducing network congestion, deferring investments in utility-scale generation capacity or network upgrading, reducing greenhouse gas emissions, and improving system security.

For these reasons, we think that it would be beneficial in the long run to set up a framework governing the installation and operation of such technologies, and the sale of excess distributed generation to the grid. We understand that the OUR is currently preparing a framework and standard contract for enabling net billing in Jamaica. We think that the general principle of the net billing approach is sound and appropriate for Jamaica (as explained in Box 4.1 below) and, if implemented effectively, should not result in any increase in the price of electricity to customers. However, there is scope to improve the design of the net billing system currently being proposed by the OUR. Below we provide some recommendations on designing an effective net billing contract in Jamaica.

0.63

0.52

0.48

0.41

0.38

‐ 0.10 0.20 0.30 0.40 0.50 0.60 0.70

Solar PV (High‐Efficiency, fixed, small)

Solar PV (High‐Efficiency, fixed,commercial)

Solar PV (thin film, fixed, small)

Wind (10kW distributed scale turbines)


US$/kWh

Current residential tariff (300kWh/month): US$0.39/kWh

Current tariff for small commercial customers (1000kWh/month): US$0.39/kWh

Projected tariff for small commercialcustomers (1000kWh/month, 2014): US$0.29/kWh

Projected tariff for residential customers (300kWh/month, 2014): US$0.29/kWh

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Box 4.1: Net Billing vs. Net Metering

When customers of electric utilities invest in distributed generation, their consumption of the power that utilities generate will decrease. At the same time, because distributed renewable power is intermittent, it will often not fully meet the customers’ demands. Therefore the customers will continue to demand that utilities maintain their connection to the power grid, and will expect utilities to supply them with power when generation from the customer’s own unit is not enough. Customers will also at times generate power in excess of their own needs. This power can be made available to the grid, and customers will expect to be paid for it. To enable distributed generation it is therefore necessary to meter the power that the customers buy from utilities, and the power that utilities buy from customers. This would require an investment in metering, and new rules for the types of meters to be used, who is to pay for them, and how they are to be read. Some countries use a ‘net-metering’ approach to avoid the need for investment in additional meters. Under this approach, the electricity supplied back into the grid by the customer simply runs the meter backward, effectively subtracting kilowatt hours from the customer’s recorded consumption. This approach is economically questionable, because it is equivalent to letting customers sell their power to utilities at the retail rate—which includes the cost of electricity generation, transmission and distribution—even though the customers only generate electricity and the utilities still incur the cost of electricity transmission and distribution. The result is that the utility pays considerably more than avoided cost for power, and so the total cost of the electricity supply goes up. The ultimate effect of net metering, then, is that those customers who do not have distributed generation end up subsidizing those who do. In the long-term, net-metering therefore tends to increase the total cost of electricity supply by promoting inefficient distributed generation. Under net billing, electricity consumed and produced is measured separately, thereby enabling utilities to buy distributed power from customers at a tariff that is lower than the retail tariff. This approach is particularly suitable for countries that wish to enable distributed renewable generation with an objective of reducing electricity costs (such as Jamaica), rather than simply developing renewable generation (such as in European countries). The key is then to set a tariff that promotes efficient investment in distributed scale renewable generation, and design appropriate contracts for distributed renewable energy.

The OUR recently drafted a Standard Offer Contract for Net Billing in Jamaica.18 The Standard Offer Contract is a 5 year renewable contract offering qualifying facilities with a capacity under 100kW a payment equivalent to the long-run avoided cost (estimated over a 20 year period), plus a 15 percent premium. The Declaration of Indicative Generation Avoided Costs (December 2010) provides the OUR’s latest estimate for the long-run avoided cost for qualifying facilities without guaranteed capacity—US$0.0933 per kWh, which is equivalent to about US$0.107 per kWh when accounting for the 15 percent premium.

We think that the OUR could improve the design of this contract by:

Extending the contract duration to 20 years—this would provide further certainty to customers (given that most distributed renewable energy technologies

18 JPS (15 March 2011). JPSCo Ltd Standard Offer Contract for the Purchase of As-Available Energy from Intermittent Renewable Energy

Facilities up to 100kW between Qualifying Entity and JPS.

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have an average lifetime of 20 years) and minimize transaction and processing costs (JPS and customers would only need to sign one contract over a 20 year period, rather than having to renew the contract every five years—this could also minimize the risk and potential for disputes over contract renewals)

Offering two options to qualifying facilities:

1. Providing the long-run avoided cost and 15 percent premium, fixed for a period of 20 years—under this contract, customers would sell their excess generation to JPS at a price fixed at the long-run avoided cost for a period of 20 years. The OUR has estimated the long-run avoided cost as US$0.0933; adding a 15 percent premium gives a total of US$0.1073 per kWh. This cost is slightly lower than (but close to) the average cost of electricity generation that we estimated for the whole system with a NGCC plant and converted combined cycle plant (US$0.10 per kWh – as shown in section 3.2.2). However, this long-run avoided cost does not compare with the avoided cost that we estimated for non-firm renewable energy with the NGCC and converted combined cycle plant (we estimated this cost as US$0.16 per kWh, as shown in section 4.2.3—with a 15 percent premium, this would amount to about US$0.18 per kWh), as shown in Figure 4.9 below. We recommend that the OUR provides further information regarding the calculation and determination of the avoided cost. Either way, under this contract, the price at which customers would sell their excess power to JPS would be fixed for a period of 20 years

2. Providing the current short-run avoided cost for a period of 3 years,19 with the OUR resetting the avoided cost to actual short-run avoided cost on an annual basis—Under this contract, for the first three years customers would be able to sell their excess power to JPS at the current avoided cost—which we estimate at around US$0.22 per kWh. If a 15 percent premium were added (as is suggested in the current Standard Offer Contract), this would amount to about US$0.25 per kWh. This is higher than the long-run avoided cost set in the other contract, because the electricity generation is more costly now compared to when the NGCC plant comes in and the CC plant converted to LNG. Once LNG is used as the main fuel for electricity generation, the OUR would then reset the avoided cost to actual avoided cost on an annual basis—the avoided cost would therefore decrease. However, the avoided cost may increase or decrease in subsequent years, depending on the evolution of gas, ADO and HFO prices (as illustrated in Figure 4.9 below). Therefore, under this contract, customers would always sell their power to JPS at the short-run avoided cost—this would be higher than the long-run avoided cost over the next three years, and may be similar to, higher or lower than the long-run avoided cost in the long-term.

19 We choose a period of three years because the cost of electricity generation is unlikely to change significantly until 2014,

given the OUR’s current Generation Expansion Plan

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Figure 4.9: Comparison of Avoided Costs Provided under Different Contracts

0

0.05

0.1

0.15

0.2

0.25

0.3

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

US$/kWh

Year

Long‐run avoided cost + 15% premium (OUR)

Short‐run avoided cost estimate + 15% premium (Castalia)

Avoided cost estimate + 15% premium when LNG used as main fuel (Castalia)

Avoided cost may increase or decrease in the future, depending on gas and oil prices

Option 1

Option 2

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5 Option 3: Reducing System Losses In this section we examine the option of reducing electricity losses from the transmission and distribution system to reduce electricity supply costs. We find that, all else being equal, a reduction of electricity losses by one percentage point would enable an average reduction in electricity tariffs of 0.8 percent. A reduction in losses by 5 percentage points would lead to a reduction in tariffs of US$0.01 per kWh compared to current tariffs, for all customer categories. We also estimate that reducing losses by 5 percentage points on projected tariffs (after the commissioning of a large NGCC plant and conversion of the existing combined cycle plant to natural gas) would lead to a reduction of US$0.006 per kWh for all customers.

Below we briefly describe what the reform of reducing losses would entail, and summarize the current status of losses in Jamaica (5.1). We then estimate the potential for reducing losses, taking into account what JPS is already doing, as well as further actions that the Government and JPS could take (5.2). We then examine the impact of reducing electricity losses on electricity prices to customers (5.3).

5.1 Description of the Reform In this section we provide some general information about system losses. We then summarize the current status of electricity losses in Jamaica.

5.1.1 Definition of system losses

Transmission and distribution losses are the difference between electricity produced (as recorded of the power plants) and electricity sold to end customers (as recorded by the customers’ energy meters, and billed by the utility). In other words, the total amount of kilowatt-hours sent out from the generating stations is greater than the corresponding values consumed, because of losses in the system. Transmission and distribution network losses occur in the lines, substations, and transformers. These losses are referred to as technical losses.

Electricity losses also include non-technical losses, which result from theft and unmetered consumption. Non-technical losses are caused by deficiencies in billing and meter reading, as well as by consumption not captured by meters such as theft, meter errors, non-billing and-under billing of legal accounts. Non-technical losses represent the difference between electricity supplied to customers and electricity billed. High levels of non-technical losses at the distribution level mean that honest consumers have to bear the burden caused by dishonest consumers who steal electricity.

The difference between units sent out of the power stations and units sold (as appearing in the billing statement) are the net system losses consisting of the sum of the two components, technical and non-technical losses.

The reduction of these net system losses will result in a reduction of the utility’s overall cost of operations. These cost savings will translate into lower tariffs to the consumer through the performance-based rate setting mechanism (PBRM) contained in the JPS licence.20

20 The PBRM places a cap on the costs resulting from losses that the company can be compensated for through the tariff.

It also requires that, to the extent that JPS’s costs are reduced by a lowering of non-technical losses, these reductions are shared between JPS and the consumer because the tariff is reset annually to take account of the actual losses performance in the previous period.

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metering on approximately 80 secondary circuits; and installation of new current transformers and potential transformers at approximately 85 metering points island-wide.

Box 5.1: Residential Automated Metering Infrastructure

The Residential Automated Metering Infrastructure (RAMI) is a recent innovation by JPS which installs a metering unit in a cabinet attached to the low voltage bushings of the distribution transformer. The metering takes place within the cabinet and is remotely displayed in the customer’s premises by way of a signal communicated from the electronic meter to the display unit via a 110Volt plug outlet. Up to 24 customer meters are contained within each cabinet. The customer, or other persons who would steal electricity, therefore has no access to the low voltage circuit as all of the connections to customer locations are within the cabinet which will disconnect if it is tampered with in any way. The facility can offer the possibility of “pre-payment” arrangements similar to that used by cellular telephones, help to conserve energy by allowing consumers to monitor their own energy usage, and a way for JPS to provide information to customers on monthly bills, disconnection dates, and advice and notification of outages. Source: JPS

Thanks to the implementation of RAMI and other strategies, JPS has already achieved reductions in system losses since the beginning of 2010, as shown in Figure 5.3 below.

Figure 5.3: Recent Trends in System Losses at JPS

Source: JPS

The Loss Control Division has set an overall target to reduce system losses by 5.2 percentage points over the next five years. The Division expects that this can be achieved by a combination of reduction in non-technical losses, increased sales, and reduction in outages.

23 .3 2%23 .2 5%

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21 .8 1%

20 .50%

21 .00%

21 .50%

22 .00%

22 .50%

23 .00%

23 .50%

24 .00%

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The Division expects to achieve this through energy recovery resulting from audits and a reduction in net generation by anti-theft network construction. Further reduction will also be achieved through increased energy sales resulting from a reduction of the SAIDI and SAIFI indices, which will translate to more energy being sold to legitimate customers. Energy sales may also increase through the addition of new large customers as the economy returns to a growth path.

Achieving further loss reduction

So far, JPS has concentrated the major part of its efforts to reduce system losses on the reduction of non-technical losses—this makes sense, since non-technical losses represent more than half of total losses. However, there is also scope for reducing technical losses in Jamaica.

For example, JPS could reduce technical losses by adding voltage regulators for feeders, upgrading high voltage distribution lines from 12kV to 24kV, and possibly by interconnecting different feeders. The Government could also do the following in order to reduce non-technical losses (and therefore related electricity costs to consumers) in Jamaica:

Increase the legislative penalties for theft of electricity

Allow JPS to charge penalties for meter tampering and breaking meter seals

Implement a “name and shame” programme to publicize the names of individuals and companies found to be stealing electricity, such as the programme implemented for helping to reduce tax evasion

Formalize procedures allowing JPS to back-bill for stolen electricity, and to charge interest to customers for late or non-payments

Work further on the Community Renewal Programme (CRP),22 to guide the design and implementation of violence reduction and community development projects in 100 of the most vulnerable areas across the country.

Government could also assist in reducing technical losses in Jamaica by educating the public at all levels about the need for, and the national economic benefits to be derived from, energy conservation and efficiency.

5.3 Impact on the Cost of Electricity In this section we estimate how a reduction in net electricity losses would impact the cost of electricity to customers. We first examine the relationship between electricity losses and tariffs, and then estimate by how much electricity tariffs could decrease as a result of a reduction in system losses of 5 percentage points (from 17.5 percent to 12.5 percent). We first examine the effect of reducing system losses on current tariffs, then on projected tariffs once LNG is used as a main fuel for generating electricity (that is, assuming a reduction in tariffs of US$0.10 per kWh, as estimated in section 3.2.2).

The sensitivity of system fuel costs to net electricity losses can be described as:

22 The CRP will seek to promote interventions aimed at building capacity for self-empowerment at the individual and

community levels in the targeted areas. Implementation of the programme, arose from the results of a study undertaken by the PIOJ’s Growth Secretariat, established to bring focus to the recovery, growth, modernization and global competitiveness of the Jamaican economy.

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ℎ ℎ = × × (1 + )(1) Where the fuel cost is the actual fuel cost in US$ per MMBtu, the heat rate is the target heat rate in kJ per kWh, and the system losses are the target system losses determined by the OUR annually, expressed in percentage of net generation—given that the OUR determines target system losses annually based on actual performance and system losses.

The OUR sets fixed targets for heat rates and system losses when reviewing electricity tariffs annually. The current target for system losses as of June 1, 2011 is 17.5 percent—meaning that JPS is using a figure of 17.5 percent for system losses to calculate the fuel cost pass through. We therefore use this figure as the baseline for calculating changes in the fuel cost pass through. We also use the current heat rate target (set for June 2011) of 10,470 kJ per kWh.

We calculate the sensitivity of electricity tariffs (including the non-fuel rate and the fuel cost pass through) to system losses given the relationship described above, and where: =− × 1 + 0.76 × . .. + ℎ ℎ(2)

Where “Ex. Rate Current” represents the current exchange rate (we use an exchange rate of US$1:J$85.7), and “Ex. Rate Base” represent the base exchange rate provided in the latest tariff determination of 2011 (US$1:J$86.5).

We use the non-fuel rates (in US$/kWh) provided in the latest tariff determination.23 We calculate the fuel cost pass-through as demonstrated in equation (1). Impact on electricity costs given current tariffs

Figure 5.4 below shows the sensitivity of current residential, commercial and industrial electricity tariffs (including the non-fuel rate and the fuel cost pass through) to electricity losses, when considering the effect of system losses on the fuel cost pass-through only.

The figure shows that even with no electricity losses, the residential, commercial and industrial tariffs would remain at about US$0.31, $0.35 and $0.28 per kWh respectively—this is because electricity generation still incurs a fuel cost, even if there are no system losses.

Given the current target for system losses (17.5 percent of net generation), the fuel cost pass through is about US$0.24 per kWh. The figure shows that given this current target, the electricity tariff for a residential customer with a monthly consumption of 100 kWh is US$0.35 per kWh. The tariff for a commercial customer with a monthly consumption of 1,000 kWh per month is US$0.39 per kWh, and the tariff for an industrial customer with a consumption of 500MWh per month and demand of 1,500 kVA per month is US$0.32 per kWh.

Based on the sensitivity of the fuel cost pass-through to system losses shown in Figure 5.4, we find that each percentage point reduction in system losses could reduce electricity tariffs by 0.8 percent on average.

Reducing system losses by 5 percentage points could reduce the fuel cost pass through to US$0.23 per kWh. 23 Office of Utilities Regulation (2011). Jamaica Public Service Company Limited – Annual Tariff Adjustment 2011.

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This could lower the residential, commercial and industrial tariffs to US$0.34, $0.38 and $0.31 per kWh—that is, a reduction of US$0.01 per kWh.24

Figure 5.4: Impact of Net Electricity Losses on the Fuel Cost Pass Through Component of Electricity Tariffs in Jamaica

Note: Calculation based on a heat rate target fixed at 10,470 kJ/kWh, base exchange rate of US$1:J$86.5, and

actual exchange rate of US$1:J$85.7.

Source: Office of Utilities Regulation (2011). Jamaica Public Service Company Limited – Annual Tariff Adjustment 2011; JPS

Impact on electricity costs given projected tariffs

In section 3.2.2 we estimated that electricity generation costs would decrease from US$0.17 per kWh to US$0.10 per kWh as a result of commissioning the NGCC plant and converting the existing combined cycle plant to LNG. This represents a reduction in average electricity generation costs of 43 percent.

To calculate the reduction in tariffs resulting from a reduction of 5 percentage point in system losses once this new capacity is commissioned, we multiply the average reduction in tariffs from reducing system losses given current capacity (US$0.01 per kWh) by the average reduction in generation costs from introducing the new natural gas plants on the system (43 percent). The result is US$0.006 per kWh.

24 This is estimated using the OUR formula examining the sensitivity of the fuel cost component of the tariffs to system

losses. This estimate does not account for other effects of decreasing system losses on tariffs. For example, a reduction in system losses and particularly non-technical losses would result in an increase in electricity sales, as some people who used to steal electricity would become customers and start paying for their own consumption. The increase in electricity sales would mean that fuel costs for electricity generation would be spread across more customers. Over time, these savings should translate into lower tariffs to consumers through the performance-based rate setting mechanism contained in the JPS licence. Therefore, our estimate is conservative and likely underestimates the true potential reduction in tariffs from reducing system losses.

0.000.050.100.150.200.250.300.350.400.45

0% 5% 10% 15% 20% 25%

Tariff, US$/kWh

System Losses, %

Residential tariff (R10, 100kWh/month)

Commercial tariff (R20, 1000kWh/ month)

Industrial tariff (R50, 500MWh/month; 1,500kVA/month)

Current system loss target: 17.5%

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Summary

When examining the sensitivity of the fuel-cost pass through component of electricity tariffs only, we find that each percentage point reduction in system losses can reduce electricity tariffs by 0.8 percent on average. Reducing electricity losses by 5 percentage points compared to the current target for system losses could reduce electricity tariffs by US$0.01 per kWh, given the current mix of electricity generation capacity on the system, and by US$0.006 per kWh, given the mix of generation capacity planned for 2014.

The reduction in tariffs from reduced system losses should be proportionate across all categories of customers.

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6 Option 4: Increasing the Use of Energy Efficient Technologies

In this section we examine the potential for electricity customers to reduce their electricity bills through an increased use of energy efficient technologies. We find that there are several energy efficient technologies which would enable all types of customers to save electricity at a lower cost than the current electricity tariffs, and that there is substantial scope for customers to reduce their electricity bills by using these technologies.

Below we provide a brief description of this reform (6.1) and evidence of the benefits and costs of implementing this reform (6.2). We then examine the impact of implementing this reform on electricity prices in Jamaica (6.3).

6.1 Description of the Reform Under this reform, electricity customers would increase their use of commercially viable energy efficient technologies in order to reduce their electricity bills. By ‘commercially viable’ we mean technologies that could save electricity at a lower cost than the current applicable electricity tariff.

6.2 Evidence of Benefits and Costs Castalia recently conducted a detailed study of energy efficiency technologies and potential uptake in Barbados, which the Government of Barbados is now implementing with assistance from the Inter-American Development Bank. The study showed that several energy efficient technologies were commercially viable in Barbados.

Table 6.1 below provides information from that study on commercially viable technologies and estimated ‘levelized cost of power saved’—that is, how much it costs for each technology to reduce one kWh of electricity consumption. We use a 15 percent discount rate, to reflect the higher cost of capital for hotels, businesses and households compared to utilities.

Using data on the cost of the technologies listed in Table 6.1, and comparing these costs with current electricity tariffs in Jamaica, we can estimate the potential savings in electricity bills for different electricity customer categories in Jamaica.

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Table 6.1: Energy Efficient Technologies and Estimated Costs

Below we estimate the potential savings for different customers given current electricity tariffs, and then examine how these results would change when the NGCC plant is commissioned and existing CC plant converted to LNG (using our estimate of reduction in tariffs calculated in section 3.3). Box 6.1 provides some information regarding the assumptions we make to estimate the potential net savings.

EE Technology Description

Levelized Cost of Power Saved,

US$/kWhCompact

Fluorescent Lamps (CFLs)

Efficient light bulbs that replace conventional incandescent ones. More efficient (more power converted to light, less to heat), more luminous for any given installed capacity, and up to 10-20 times more long-lasting.

0.02

Power Monitors Handheld devices that provide real-time information on energy consumption

and expenditure. Their use increases awareness on energy efficiency, and achieves behavioral changes for a more efficient consumption of energy.

0.07

Magnetic Induction Street Lighting

High-efficiency street lights that replace conventional ones and provide higher efficiency, better luminosity, longer lifetime, and lower costs 0.31

Premium Efficiency Motors

Efficient motors that replace conventional motors. Higher actual power for the same electrical motor load and rated power. 0.11

Efficient Window Air Conditioning Systems

A/C systems for window installation that are more efficient than conventional ones. Same or better performance, lower electrical load. 0.12

Variable Frequency Drives

Add-on device that adjusts motor speed to make motor output meet actual demand (no unnecessary extra output). 0.12

Efficient Split Air Conditioning Systems

A/C systems with indoor unit for air emission separate from outdoor condensing unit, more efficient than conventional systems. One system can cool multiple rooms. Same or better performance, lower electrical load.

0.31

T8 Fluorescent Lamps with Occupancy Sensor

Efficient fluorescent lights for offices that replace older fluorescent lights, achieving better lighting with lower energy consumption. Occupancy sensors turn lights on or off based on detecting people in a room, reducing ‘on’ time.

0.25

Efficient Chillers Industrial cooling devices with efficient compressors incorporating VFD

technology. They replace conventional chillers with traditional compressors operating at constant speed.

0.15

T5 High Output Fluorescent Lamps

Lighting fixtures for indoor applications, mostly in the industrial sector. They replace conventional metal halide bulbs. Brighter and higher quality light with lower energy consumption.

0.32

LCD Computer Monitors

Liquid Crystal Display monitors that replace conventional Cathode Ray Tube (CRT) monitors for computers. 0.32

Efficient Residential Refrigerators

Efficient fridges for homes that replace conventional ones. Lower power draw, and better insulation. 0.34

Efficient Retail Refrigerators (Condensing Unit)

Condensing units with more efficient cooling performance for commercial refrigerators used in stores, supermarkets, and restaurants. Replacement is limited to the condensing unit to contain costs. 0.53

Solar Water Heaters Use solar radiation to heat water, and are composed of a storage tank, and a

solar collector (flat plate panels and evacuated glass tube collectors are the two main types of solar collectors)

0.15-0.17

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Box 6.1: Assumptions for calculating potential net savings from using more energy efficient technologies in Jamaica

The assumptions we make regarding electricity consumption in each customer category are: Residential customers: about 45 percent of a residential customer’s consumption is for

refrigeration, 21 percent for lighting, 10 percent for other appliances such as televisions, and 24 percent for heating water

Commercial customers (small): about 30 percent of average consumption is for lighting, 12 percent for refrigeration, 50 percent for air conditioning, and 8 percent for other appliances (we assume that half of this consumption for other appliances is for heating water)

Industrial and large commercial customers: about 28 percent of consumption is for motors, 10 percent for lighting, 19 percent for refrigeration, 15 percent for air conditioning and 28 percent for other appliances (we assume that half of this consumption for other appliances is for heating water, for large commercial customers only)

Using these consumption ‘breakdowns’, we estimate how much electricity could be saved by using relevant energy efficient technologies. Although energy efficient technologies could be used in any sector, we did not consider application in a sector when it would be negligible. For example, commercial companies could in some cases benefit from premium efficiency motors, but these would only represent a small portion of overall energy use in the sector, compared to the industrial sector where energy from motors is a significant portion of energy use. We find that electricity consumption could be reduced by 26 percent in the residential sector, 23 percent in the commercial sector, and 12 percent for large commercial customers and 12 percent for industrial customers over a 20 year period. Next, we calculate the weighted average cost of saving each kWh using energy efficient technologies. We do this by multiplying the ‘savings cost’ of each technology by its share in total potential consumption reduction. We derive two different estimates: For residential and small commercial customers, we calculate the weighted average

savings cost given the use of a small (2kW) solar water heater. The resulting average savings cost is US$0.21 per kWh

For large commercial and industrial customers, we calculate the weighted average savings cost given the installation of a 70kW solar water heater. The resulting weighted average savings cost is US$0.18 per kWh.

Source: Castalia; A. Binger (August 2010). Energy Efficiency Potential in Jamaica: Challenges, Opportunities and Strategies for Implementation—Report to the Economic Commission for Latin America and the Caribbean, and Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ); Demand Side Energy Consultants Inc. (1998). JPSCo. Large Commercial retrofit Programme—Final Summary Report

Table 6.2 shows the potential net savings that an average customer in each type of category could make on electricity bills each year, as a result of using more energy efficient technologies (based on the assumptions listed in Box 6.1). By ‘net savings’ we mean the savings resulting from spending less money on electricity bills as a result of a lower consumption in electricity, minus the average cost of saving each kWh.

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Table 6.2: Potential Net Financial Savings for Different Customer Classes from Energy Efficient Technologies—Current Tariff Levels

*2008 figures from OUR (2010). Electricity Peak and Energy Demand Forecast 2010-2030; **Based on non-fuel rates provided in OUR (2011). JPSCo Ltd Annual Tariff Adjustment 2011, adjusted using April 2011 fuel prices and exchange rate adjustment, and calculated for each customer category using 2008 average annual consumption figures; ***Based on Castalia's assumptions for end-use consumption in each sector shown in Box 6.1, and Castalia’s estimates for potential reduction in electricity consumption from increased use of energy efficiency technologies; ****Based on an weighted average cost of energy efficient technologies of US$0.24 per kWh saved

Note: Electricity tariffs are calculated using the non-fuel charges indicated in the latest tariff review for JPS, as well as data on fuel and IPP charges, and exchange rate adjustment from JPS for March 2011.

These estimations include the potential for installing small solar water heaters in the residential sector and small commercial sector, and 50kW heaters in the large commercial sector.

The table above shows that by increasing their use of energy efficient technologies, residential customers could reduce their annual consumption of electricity by about 26 percent, and save about US$86 per year on electricity bills. Small commercial customers could reduce their consumption by 23 percent and save US$446 per year on electricity bills. Large commercial customers could on average save more than US$8,000 on their electricity bills each year, and industrial customers could save more than US$100,000 each year on average.

Table 6.3 below shows how much customers could potentially save by using energy efficient technologies once the new medium speed diesel, hydropower and NGCC plants are commissioned, and the combined cycle plant is converted to natural gas.25

25 To estimate the reduction in current electricity tariffs, we estimate the average reduction in electricity generation costs

from introducing the West Kingston Power plant, hydropower and NGCC plants on the system, and converting the combined cycle plant to natural gas, compared to the average cost of electricity generation using the current system (which does not yet include the medium speed diesel plant and Maggotty plant). We find that the average reduction in electricity tariffs would be about US$0.10 per kWh, assuming a LRMC of US$0.12 per kWh for the new hydropower plant at Maggotty, and a LRMC of US$0.22 per kWh for the new medium speed diesel plant.

Category of customer

Average annual consumption*

Current tariff** Typical annual electricity bill

Potential reduction in electricity

consumption***

Potential net savings****

kWh/year US$/kWh US$/year % per year US$/yearResidential 1,971 0.37 739 26% 86 Commercial (small) 10,746 0.39 4,235 23% 446 Commercial (large) 489,000 0.32 156,639 12% 8,255 Industrial 6,301,770 0.32 2,008,220 12% 105,131

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Table 6.3: Potential Net Financial Savings for Different Customer Classes—Projected Tariff Levels

*2008 figures from OUR (2010). Electricity Peak and Energy Demand Forecast 2010-2030; **Based on non-fuel rates provided in OUR (2011). JPSCo Ltd Annual Tariff Adjustment 2011, adjusted using April 2011 fuel prices and exchange rate adjustment, and calculated for each customer category using 2008 average annual consumption figures; ***Based on Castalia's assumptions for end-use consumption in each sector shown in Box 6.1, and Castalia’s estimates for potential reduction in electricity consumption from increased use of energy efficiency technologies; ****Based on an weighted average cost of energy efficient technologies of US$0.24 per kWh saved

6.3 Impact on the Cost of Electricity to Consumers Increasing the use of energy efficient technologies amongst end-users in Jamaica would not have a direct impact on electricity tariffs. However, by using these technologies consumers can reduce the quantity of electricity they use, thereby reducing their electricity bills. Consumption curtailment provides an effective way for consumers to hedge against volatility in electricity prices.

We find that by using energy efficient technologies, typical residential, commercial and large customers could achieve net savings equivalent to 16 percent, 14 percent and 8 percent of their current electricity bills respectively, on average. As shown in Table 6.4 below, customers would still benefit from savings equivalent to between 2 and 6 percent of their current electricity bills even if electricity tariffs decreased by US$0.10 per kWh (as a result of using a cheaper fuel for generating electricity).


Average annual consumption*

Projected tariff** Typical annual electricity bill

Potential reduction in

electricity consumption***

Potential net savings

kWh/year US$/kWh US$/year % per year US$/yearResidential 1,971 0.27 541 26% 33 Commercial (small) 10,746 0.29 3,156 23% 203 Commercial (large) 489,000 0.22 107,533 12% 2,347 Industrial 6,301,770 0.22 1,375,383 12% 29,000

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Table 6.4: Potential Net Saving in Electricity Bills from Increased Use of Energy Efficient Technologies


Typical annual electricity bill

Potential net savings

Potential net savings compared

to current electricity bill

US$/year US$/year %With current tariffResidential 541 86 16%Commercial (small) 3,156 446 14%Commercial (large) 107,533 8,255 8%Industrial 1,375,383 105,131 8%With projected tariff (when NGCC plant comes in)Residential 541 33 6%Commercial (small) 3,156 203 6%Commercial (large) 107,533 2,347 2%Industrial 1,375,383 29,000 2%

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Box 6.2: How can the Government help achieve these savings? The Government of Jamaica is already working on promoting energy efficiency in Jamaica: the Ministry of Energy and Mining recently issued a National Energy Conservation and Efficiency Policy for Jamaica for 2010-2030, which outlines the strategy that the Government intends to focus on. In addition, the Government is investing in the implementation of programmes throughout the country, including through loans from the Inter-American Development Bank and the World Bank. Given the analysis shown in this section, there are several energy efficient technologies in Jamaica that can help reduce electricity costs to consumers in Jamaica. Specific things that the Government could do to save energy, in addition to what is already being done, are the following: Increase uptake of efficient technologies other than lighting. The Government is

already promoting the use of efficient lighting. However, as shown in Table 6.1, there are many other technologies that would enable customers in the residential, commercial, and industrial sectors to reduce their electricity bills. The government could increase uptake of these technologies by: (i) informing the public about the costs and benefits of key energy-saving technologies; (ii) increasing the availability of these technologies in Jamaica, including through import of equipment that meets adequate performance standards; (iii) helping to finance their implementation

Procure an ESCO for retrofitting public buildings, and for marketing to large consumers. ESCOs are companies that (i) develop, finance, and implement energy efficiency projects on a turnkey basis; (ii) guarantee a contracted amount of savings to clients, assuming the risk for these savings’ actual realization; and (iii) earn returns over time from the financial savings the projects create. This type of model may be helpful to overcome any lack of finance or incentives for implementing energy efficient programme within the public sector. The Government could increase the attractiveness of an ESCO deal for retrofitting public buildings by letting the selected ESCO do a “trade show” to market its services to large energy consumers in the industrial and commercial sectors

Negotiate an arrangement for retrofitting street lights. The Government could structure a deal for using efficient technologies for street lighting, such as magnetic induction lights, or (if cost-effective) LED lights

Implement a standard and labeling programme for appliances. This could be an effective way of informing consumers about the quality and performance of appliances. The Government has already started working on a labeling programme, but recognized the need to expand it, to ensure that it is effective. Developing standards for key appliances could serve to prepare better labeling, and determine eligibility for other fiscal or customs incentives

Restrict import of non-efficient equipment, or provide a preferential customs regime for energy efficient equipment. This would have a direct impact on the type of technologies used in Jamaica. Standards could be used to ensure that sub-standard energy efficient equipment is not eligible for preferential customs treatment, or is banned from imports

Review the building code to mandate energy efficiency measures, solar water heaters, and efficient design in new buildings. This mandate would affect builders much the same way that any other building rule does. Energy standards for buildings provide a degree of control over building design, and encourage energy conscious design in building. Inefficiencies could be reduced over time if the building code required energy efficient design and materials in new buildings and major renovations. Many industrialized countries have included such requirements in their buildings codes. Solar water heaters could be mandated in new buildings so that when a water heater is installed it could be a solar water heater, and one compliant with a Caribbean certification such as one used in Jamaica, Barbados, or Saint Lucia.

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7 Option 5: Forcing Vertical and Horizontal Disaggregation of the Electricity Sector

Some stakeholders in Jamaica have suggested that the Jamaican electricity sector should be unbundled so as to increase competition in electricity generation and retailing. The rationale behind this suggestion is that increased competition creates an incentive for firms to reduce their costs and prices, thereby leading to an overall reduction in electricity prices. These effects have been demonstrated in wholesale competition and retail markets following successful reforms in many countries, such as the United Kingdom, United States and Australia.

In this section we examine the option of restructuring the electricity sector by forcing a vertical and horizontal disaggregation of the utility so as to introduce competition in electricity generation and retailing.

We find that such reform would be unlikely to result in any decrease of electricity prices, but would rather lead to a significant increase in electricity prices (increase of US$0.11 per kWh if competition was introduced amongst existing generation capacity, and of US$0.12 per kWh if competition was introduced after the NGCC plant is commissioned and the CC plant is converted to LNG). This increase arises mostly as a result of the lack of potential for competition in electricity generation for a system of the size of Jamaica’s. In addition, a sector disaggregation would likely involve additional costs in electricity distribution and retail, due to the duplication of overhead costs, in addition to transaction and restructuring costs.

In this section we describe what Jamaica’s electricity sector would look like if it was vertically and horizontally disaggregated (7.1). We then evaluate the potential benefits and costs arising from implementing this reform, and estimate the impact of this reform on electricity prices in Jamaica (7.2).

7.1 Description of the Reform This reform would involve restructuring the sector from a single buyer model (under which JPS ensures the generation, transmission and distribution of electricity, and enters into power purchase agreements with independent power producers), to a retail competition model. Under a retail competition model, the generation, transmission and distribution of electricity are unbundled, and firms trade electricity in a wholesale power market through bilateral contracts and a spot market, and various firms can compete in the supply and sale of power to consumers.

Below we describe what the Jamaican electricity sector would look like under a retail competition model. We assume that electricity would be traded in an ‘energy only market’ (such as the markets developed in New Zealand, the Philippines, and Singapore). Under an energy only market, generators submit price and quantity (supply) offers at regular intervals to meet instantaneous demand. Energy only markets are driven by the spot price of electricity.

Given the current size of the system and the system expansion planned by the OUR, we anticipate that if the Jamaican electricity sector was to be disaggregated, it would likely comprise:

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At most five or six competitors in generation: These may include the three existing Independent Power Producers (Wigton Windfarm Ltd., JEP including West Kingston Power, and JPPC), and one firm operating the new LNG plant (JPS). JPS’s current generation assets could be separated to create two generation companies

One transmission company: Electricity transmission is a natural monopoly—meaning that one firm can supply the entire market at a lower cost than multiple firms serving the market—and therefore would remain as a single company

One system operator: The transmission grid through which electricity flows would also need to be physically managed to ensure that operating constraints are satisfied, therefore the market would also need a system operator, who would be responsible for the physical operation of the grid, and its quality and security of supply. The system operator would coordinate the actions of grid-connected parties by contracting with generators to supply capacity, or purchasers to allow short-notice interruption of supply, to ensure that an adequate voltage and frequency of electricity is maintained

One market operator: Under a disaggregated model, generators and purchasers would trade electricity in a spot wholesale market, which could comprise real-time electricity trading, and bilateral trading. The market operator would be responsible for administrating the market, aggregating the information from suppliers and purchasers of electricity to determine the price at which proposed supply meets demand at least cost, while satisfying technical constraints relating to grid availability and security

Three distribution companies: the network could be separated to allow three companies to operate in different areas—for example, Distribution Company A could operate the distribution network located in the Western side of the country, Distribution Company B in the North and North-East, Distribution Company C in the South and South-East. We assume that each of these companies would be responsible for distributing electricity in their respective areas, as well as retailing electricity, although some companies may also be able to provide retailing services to customers in other distributed areas through competing carriage competition. Electricity retailing would involve entering contracts with the transmission and distribution companies, buying power on the wholesale market, to sell electricity to individual consumers through contracts. Because wholesale electricity markets can be volatile, retailers may also wish to enter into long-term contracts with generators, in order to hedge their energy purchases and mitigate the effect of price spikes (as discussed in Box 7.1 below).

Figure 7.1 below illustrates the possible location and separation of generation, transmission and distribution assets under a sector disaggregation.

FiguDisa

ure 7.1: Possaggregation

sible Structn

ture of the E

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Electricity S

al

Sector undeer Vertical aand Horizoontal

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Box 7.1: Price Spikes in Wholesale Electricity Markets Electricity prices in wholesale markets can vary extensively from day to day and hour to hour, depending on electricity demand, and the short-term availability of supply. Experience in existing wholesale electricity markets suggests that large spikes in the price of electricity can occur frequently. To protect themselves and their customers from such variations in wholesale price of electricity, electricity retailers often enter into long-term, fixed-price contracts with electricity generators. Regulators may also decide to cap wholesale electricity prices or offers, to limit the extent to which prices can rise. The figure below shows price spikes that occurred in Hayward, New Zealand between January and May 2003, in NZ$ per MWh. The figure shows that electricity prices rose to more than NZ$1,000 per MWh—about US$0.78 per kWh—three times during that period. The second figure below shows the volatility of nation-wide wholesale electricity prices in New Zealand over the past seven years. Spot Electricity Prices in Hayward, New Zealand, January-May 2003

New Zealand Electricity Price Index, 2003-2011 (7-day Demand-Weighted Rolling Average, NZ$/MWh)

Source: Norske Skog Tasman Limited (October 2007). Comments on the Review of Reserve Energy Policy Consultation Paper; New Zealand Electricity Authority (January 2011). Wholesale Electricity Prices: December 2010.

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7.2 Evidence of Benefits and Costs Below we examine whether the introduction of competition in the electricity sector in Jamaica would likely result in positive effects on electricity costs. We do this by reviewing experience with wholesale electricity market reforms in island countries, and by analyzing how restructuring the Jamaican electricity sector would affect prices. We then examine the costs that would likely arise as a result of implementing this reform. We conclude that introducing competition in the electricity sector would be likely to result in an increase in electricity prices in Jamaica, due to the limited size of the market.

7.2.1 Experience with Wholesale and Retail Competition in Island Countries

Economic theory suggests that competition encourages efficiency and leads to lower prices compared to markets with no competition. Under competition, commercial firms strive to capture a greater share of a market by lowering their costs and prices and/or developing new products, services and technologies. In practice, this theory has proven correct across many countries and sectors, including the electricity sector. Indeed, since the 1980s several countries have reformed their electricity sector to enable wholesale and retail competition, and have benefited from improvements in efficiency and lower prices—examples include the United Kingdom, the United States (despite problems in California), and Australia. However, most of these countries have large power systems which can accommodate numerous competitive generators and retailers, while retaining sufficient economies of scale.

In this section we review experience with electricity wholesale and retail competition in smaller countries, including New Zealand, the Philippines, and Dominican Republic, in order to identify potential issues that may arise if such reform was implemented in Jamaica.

Experience with wholesale and retail competition in small and island countries has shown mixed results. Attempts to introduce competition have often resulted in oligopolies, where a few participants dominate a large share of the market and are able to set prices higher than in perfectly competitive markets. As a result, allegations of anti-competitive conduct and abuse of market power are seen as a recurrent problem in small-sized, unbundled electricity markets. For example:

In New Zealand—since the creation of a wholesale electricity market (New Zealand Electricity Market), electricity generation in New Zealand has been dominated by five companies, who supply more than 90 percent of total electricity.26 These five companies also serve more than 90 percent of the retailing market.27 Problems with perceived anti-competitive behavior in the generation and retailing market are raised regularly in New Zealand. For example Genesis Energy, one of the largest generators and retailers in New Zealand, is currently being investigated by the Electricity Authority (the entity responsible for the efficient operation of the market), with regards to a spike in wholesale electricity prices (from about US$80 per MWh to more than US$15,700 per MWh) which occurred on April 26, 2011. The Authority has led numerous other anti-competitive investigations over the past few years—and some studies have shown

26 New Zealand Ministry of Economic Development (2006). http://www.med.govt.nz/templates/Page____13481.aspx 27 New Zealand Electricity Commission (2010). About the New Zealand Electricity Sector.

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that electricity prices in New Zealand are on average higher than they would be in a perfectly competitive market.28

In the Philippines—upon the establishment of the Wholesale Electricity Spot Market in 2006, two companies (National Power Corporation and PSALM) held nearly 90 percent of the country’s supply of electricity, and one company accounted for 70 percent of demand in one area (Luzon). Since the establishment of the market, frequent spikes in the price of electricity have been a recurring problem, and the Energy Regulatory Commission has had to investigate several allegations of market abuse and anti-competitive behavior by generators (including, for example, an alleged price manipulation in February 2010 that caused spikes in the price of electricity29)30

In Dominican Republic—the vertically integrated electricity utility was unbundled in 1997, and in 2000 the Government established an open generation market under which distributors and generators could trade electricity. By 2008 there were more than a dozen generators, a transmission company and three regional distribution companies operating in the sector (although the Government of Dominican Republic has purchased two of these distribution companies back)—however, the lack of competition in electricity generation was identified as a problem in the sector, contributing to high electricity tariffs.31

Overall, experience with wholesale electricity markets in these countries suggests that sector disaggregation can only lead to price reductions if the power system is large enough to attract a sufficient level of competition. Given that Jamaica’s power system is significantly smaller than the systems in these countries, with an installed capacity ten times smaller than that in New Zealand, and about twenty times smaller than that in the Philippines, as shown in Table 7.1 below, there is good reason to believe that unbundling the Jamaican electricity sector would not result in sufficient competition to reduce electricity prices. In the following sub-section we examine whether this would really be the case, by estimating average wholesale electricity costs in Jamaica under a disaggregated sector structure with unregulated wholesale market pricing.

28 Murray, K. (August 2004). Analysis of the State of Competition and Investment and Entry Barriers to New Zealand’s Wholesale and

Retail Electricity Markets. Report prepared for the Electricity Commission. 29 Corsino, N. (August 2010). Energy Regulatory Commission Still to Probe alleged WESM Price Spikes. GMA News, 06 August

2010. http://www.gmanews.tv/story/192918/erc-still-to-probe-alleged-wesm-price-spikes 30 Pascual, M. D. (February 2011). Why Competition in WESM Causes Costly “Kuryente”. http://www.manilatimes.net/sunday-

times/special-report/why-competition-in-wesm-causes-costly-%E2%80%98kuryente%E2%80%99/ 31The World Bank (April 2008). Project Appraisal Document on a Proposed Loan to the Dominican Republic for an Electricity Distribution Rehabilitation Project.

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Table 7.1: Size of Electricity Markets

Country Population,

million Total installed capacity, MW

Peak Demand, MW

Ratio to Peak Demand in

Jamaica

New Zealand (2009) 4.3 9,100 6,500 10.5

Philippines (2010) 91.9 15,881 10,231 16.5

Dominican Republic (2009) 10.1 3,000 1,800 2.9

Jamaica* (2010) 2.7 830 620 -

Sources: World Bank Development Indicators; JPS; New Zealand Electricity Commission (2009). About the

New Zealand Electricity Sector; Office of Utilities Regulation (2010). Generation Expansion Plan.; Asirit, J. P. M. (March 2011). Investment Opportunities in the Philippines Energy Sector. Presentation at the PPP Conference in Makati Shangri-La Hotel, March 2, 2011; ADIE (June 2010). The Electricity Sector in the Dominican Republic.

7.2.2 Estimation of Wholesale Electricity Prices in Jamaica with a Disaggregated

Sector Structure

In this section we examine the impact of disaggregating the Jamaican electricity sector on wholesale electricity prices. Electricity generation accounts for about 77 percent of current electricity rates.32 The remaining 20 percent of the costs is determined by transmission and distribution (about 18 percent), and customer service and administration costs (about 5 percent). Disaggregating the electricity sector could not affect transmission and distribution costs, because the transmission and distribution of electricity is a natural monopoly—and therefore competition could not be introduced in the sector. Therefore, about 18 percent of the cost of electricity cannot be affected by the sector disaggregation.

We therefore examine the potential for reducing electricity generation costs by disaggregating the electricity sector in Jamaica. We estimate and compare the average variable cost of electricity generation under the current market structure (a single buyer model), and under a wholesale competition structure.

For both structures, we assume that the market operates under a marginal cost structure where generators with units available for dispatch are put in order of merit based on their variable cost (the variable cost includes fuel cost, and variable operating and maintenance cost). This enables us to extract the difference in electricity costs to consumers simply as a result of changing the structure of the market.

We estimate variable generation costs for both types of market structures under two scenarios:

1. With current generation assets—that is, we estimate average variable costs under the current framework, as well as under a wholesale competitive model, given current demand and existing generation assets (assuming that the Maggotty hydropower plant and West Kingston Power plant are already commissioned)

32 JPS (2011)

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2. With generation assets planned for 2014—given the OUR and JPS’s planned changes in generation capacity (that is, the addition of a 360MW LNG plant to the system, the conversion of the Bogue plant to LNG, and assuming that JPS no longer uses oil-fired steam plants for regular dispatch).

For both scenarios we use the typical weekday load profile for Jamaica’s power system in 2009, provided in the OUR Generation Expansion Plan 2010.33 In other words, we assume that there is no growth in demand, so that electricity demand today and in 2014 are the same as that in 2009. This enables us to compare both scenarios more easily, as we can examine changes in prices resulting strictly from changing the type of generation assets being used.

For both scenarios and market structures we use data on current and planned capacity provided in the OUR Generation Expansion Plan 2010.34

Our estimates confirm that Jamaica’s electricity system is too small to accommodate a sufficient number of generators on the market to reduce electricity prices. Wholesale electricity prices would be much higher under a wholesale competition structure, because generators would be able to price their electricity at a cost higher than their actual marginal cost. We find that wholesale electricity prices would increase by an average of US$0.08 per kWh if competition was introduced among the various plants existing on the system, as well as the Maggotty hydropower plant and the new medium speed diesel plant. Wholesale prices would increase by US$0.06 per kWh under a competition structure compared to a single buyer structure, if the 360MW natural gas plant was commissioned and the oil-fired steam plant was decommissioned. Below we outline how we estimated these prices under each scenario.

Scenario 1—Electricity generation costs given the current mix of generation assets

Table 7.2 below lists the plants currently installed and being operated by JPS and IPPs in Jamaica (ordered in terms of variable cost per unit of generation, from the cheapest to the most expensive). For each plant, the table indicates effective capacity, type and current price of fuel used, and heat 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 variable O&M cost of each plant—adding these together gives total short-run marginal costs, in US$ per kWh.

33 Office of Utilities Regulation (2010). Generation Expansion Plan 2010. Figure 3.5-2 – Typical Weekday Load Profile for

Jamaica’s Power System. p.32. 34 Office of Utilities Regulation (2010). Generation Expansion Plan 2010. Table 6.7-1—Capabilities and Performance

Characteristics of the Existing Thermal Generating Units, p.54. Table 9.4.1-1—Demand/Capacity Requirements for 2010 to 2019 (Natural Gas Strategy), p/70.

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Table 7.2: Short-Run Marginal Cost of Plants on the System (March 2011 Fuel 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


Using the typical weekday load profile provided by the OUR, and assuming dispatching based on merit order of variable costs, we determine the typical daily ‘dispatching profile’ of the system—this is shown in Figure 7.2 below.

Effective capacity

Average heat rate

Current fuel

price**

Variable O&M cost








Hunts Bay Oil Fired Steam HFO 65.1 0.0124 16.79 0.007 0.21 0.21 Old 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




fossil 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 7.2: Dispatching Profile for Typical Week Day

Note: Figures based on 2009 load profile provided in the OUR Generation Expansion Plan 2010, and March

2011 fuel prices provided by JPS

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

The above figure shows that the wind, hydropower, JPPC, JEP, West Kingston Power, slow speed diesel and oil-fired steam plants are always operating to meet electricity demand. The combined cycle is also operating between 11am and 6:30pm, and between 7.30pm and 11:30pm to meet peak demand.

Using this information, we calculate the variable cost of the system throughout the day under the two different market structures. For the single buyer model (which is the current market structure), we use the same methodology and figures as shown in section 3.2.2.

With a wholesale competition market structure, generators send out bids or offers on the market at regular intervals (say every 30 minutes). Each bid defines the minimum price that the generator would accept to run the plant in the given half hour, and these bids serve as the guide for the dispatch. In a system where there are enough competitors so that each generator assumes that it will not be determining the marginal plant, then the optimal bid for each generator is the true marginal cost.35 However, with only eight different types of plants on the system, generators are able to maximize profit by bidding just below the cost of the plant on the margin. Every half hour, generators will receive the short-run marginal cost price for the total quantity of energy supplied in that half hour. In other words, all generators receive the same price for the electricity they supply.

For example, at 10:00 p.m. the plant on the margin is the combined cycle plant, which generates at a SRMC of US$0.22 per kWh. Therefore the generator operating the oil-fired steam plant can bid at, say US$0.21 per kWh, in order to undercut the combined cycle plant, 35 Hogan, W. (1998). Competitive Electricity Market Design: A Wholesale Primer. Center for Business and Government, John F.

Kennedy School of Government. Harvard University. p. 5.

0

100

200

300

400

500

600

700

MW

Time of the day

Combined Cycle

Oil‐Fired Steam

Slow Speed Diesel

JEP

West Kingston Power

JPPC

Wind

HydroUS$0.14/kWh

US$0.16/kWh

US$0.17/kWh

US$0.22/kWh


US$0.16/kWh

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while extracting as much profit as possible. During peak hours, the combined cycle plant must be used. The next cheapest plant available is a combustion turbine with a SRMC of US$0.31 per kWh (as shown in Table 7.2), so the operator of the combined cycle plant is able to bid at US$0.30 per kWh.

On this basis, we assume that:

When the combined cycle plant is on the margin, the oil-fired steam generator bids at US$0.01 per kWh lower than the cost of the combined cycle plant—that is, US$0.21 per kWh, and all generators (except the combined cycle and combustion turbine generators, who do not generate electricity) are paid that price for each unit of electricity they generate

During times of peak demand, the combined cycle generator bids for US$0.30 per kWh, and all generators are paid US$0.30 for each kWh they generate.

The price of wholesale electricity under each structure is shown in Figure 7.3 below, for 30 minute intervals in a typical weekday. The figure shows that the wholesale price of electricity would be on average about twice as high under a ‘competitive’ market than under a single buyer market structure (with an average price of US$0.26 per kWh compared to US$0.17 per kWh).

Figure 7.3: Wholesale Electricity Prices under Single Buyer (Current System) and Wholesale Competitive Power Markets, US$/kWh

To estimate the changes in electricity prices to consumers arising from introducing competition in the electricity market, we use the same methodology as in section 3.2.2—that is: =

0.00

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US$/kWh

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Wholesale price with single buyer structure Average, US$/kWh Wholesale price with wholesale competition structure

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where ‘reduction in generation costs’ is the annual reduction in the cost of generating electricity resulting from changing the market structure to a competitive market, in US$. To calculate the reduction in generation costs, we:

1. Multiply the average cost of generation of the system with the competitive market structure (US$0.26 per kWh) by the electricity generated in 2010

2. Multiply the cost of generation with the current (single buyer) market structure (US$0.17 per kWh) by electricity generated in 2010


Assuming that total electricity generation is 4,137 GWh and electricity sold is 3,235 GWh, we find that electricity tariffs would increase by about US$0.11 per kWh under a wholesale competition structure.

Scenario 2—Electricity generation costs with new generation mix

In this section we examine the wholesale price of electricity under the single-buyer market structure and wholesale competition market structure, given the generation capacity planned for the year 2014.

Table 7.3 below provides information on the capacity, efficiency and variable cost for each unit of capacity planned for 2014. The table shows the SMRC of the NGCC plant and converted combined cycle plant—however, we use the Long-Run Marginal Cost of generation for these plants when examining generation costs instead, as the owner of this plant will need to recoup the capital cost.

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Table 7.3: Short-Run Marginal Cost of Plants on the System in 2014 (Based on Average Projected Fuel Prices for the Period 2010-2029)


Figure 7.4 shows the typical daily dispatching of the system, again using the typical weekday load profile for 2009 provided in the OUR Generation Expansion Plan. The figure shows that the JPPC, West Kingston Power, and JEP plants would become the marginal plants on the system. This is because the oil-fired plants would be decommissioned, and the NGCC plant and converted combined cycle plant would have sufficient capacity to displace (at least temporarily) the slow speed diesel plants, and expensive combustion turbines.

Effective capacity

Average heat rate

Fuel priceVariable

O&M cost




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


West Kingston Power Medium Speed Diesel HFO 58.5 0.0078 18.32 0.020 0.14 0.16 Rockfort Slow Speed Diesel HFO 19.2 0.0093 18.32 0.008 0.17 0.18 Rockfort Slow Speed Diesel HFO 19.2 0.0095 18.32 0.008 0.17 0.18 Bogue Combustion Turbine ADO 19.9 0.0129 21.33 0.005 0.28 0.28



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


fossil fuel used

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Figure 7.4: Dispatching Profile for Typical Week Day

Note: Figures based on 2009 load profile and fuel prices projected for the period 2010-2029, as provided in

the OUR’s 2010 Generation Expansion Plan.

To calculate the wholesale electricity price, we use the same assumptions for pricing under each structure as in the previous ‘scenario’. That is, under the single buyer structure, the wholesale electricity price at a given time is the weighted average SRMC of all plants running on the system at that time.

Under a competitive market structure, the wholesale electricity price is the price of the marginal plant on the system at the time. When the JPPC is on the margin (between 01:30 am and 08:30am), we assume that the wholesale electricity price is US$0.14 per kWh (US$0.005 per kWh lower than the SRMC of the JPPC plant). When the West Kingston Power and JEP plant are the marginal plants, we assume that the wholesale electricity price is US$0.155 per kWh (slightly lower than the SRMC of the marginal plant). When the JEP or West Kingston Power plants are running, we assume that the wholesale electricity price is US$0.175 per kWh (US$0.005 per kWh lower than the cost of the slow speed diesel plants).

Figure 7.5 below shows the wholesale prices under each market structure on a typical week day. The figure shows that, with the commissioning of the natural gas plant, the average price of wholesale electricity would be about US$0.11 per kWh (compared to US$0.17 per kWh under a single buyer market structure with the current capacity). Under a competition market structure, the wholesale electricity price would be around US$0.18 per kWh—that is an increase in the wholesale electricity price of about US$0.7 per kWh compared to the current market structure. Below we estimate how this increase in wholesale electricity prices would affect electricity prices to consumers.

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

MW

Time of the day

JEP

West Kingston Power

JPPC



Wind

New hydro

Hydro

US$0.07/kWh

US$0.09/kWh

US$0.15/kWh

US$0.16/kWh

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Figure 7.5: Wholesale Electricity Prices under Single Buyer (Current Market Structure) and Wholesale Competitive Power Markets, US$/kWh

To estimate the changes in electricity prices to consumers arising from introducing competition in the electricity market, we use the same methodology as in section 7.2.2—that is: =

Assuming that total electricity generation is 4,137 GWh and electricity sold is 3,235 GWh, we find that electricity tariffs would increase by about US$0.12 per kWh if competition was introduced after the NGCC is commissioned and combined cycle plant converted to natural gas.

In section 3.2.2 we found that if LNG was used as the main fuel for electricity generation, the cost of electricity generation would decrease, leading to a decrease in electricity tariffs of US$0.10 per kWh. This means that if LNG was used as a main fuel for generating electricity and the market structure was changed to a competitive structure, electricity generators would take in all of the benefits from the reduction in electricity generation costs—instead of decreasing by US$0.10 per kWh, electricity prices to consumers would increase by US$0.12 per kWh.

Summary

Experience with introducing wholesale and retail competition in island countries has shown that in such countries, the limited scope for attracting sufficient competition levels has led to issues of market power abuse, and higher electricity prices. In the above section, we have demonstrated that this would indeed be a relevant issue in Jamaica, and that disaggregating the sector would lead to a significant increase in electricity costs to customers.

One way of addressing this problem would be to regulate electricity prices—but in that case, the electricity market would not be a free market. Furthermore, it is difficult to envisage any

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benefit from breaking up the electricity system and then regulating each company separately, when the OUR already regulates all the activities in generation, transmission and distribution anyway.

7.2.3 Other Costs and Possible Problems Arising from Restructuring the Jamaican Electricity Sector

In the previous section we showed that electricity prices would increase substantially under a wholesale competition market structure, compared to a single buyer market. In addition to this increase in wholesale prices, changing the market structure to a wholesale competition model would involve various costs.

We estimate that a disaggregation of the sector could:

Increase prices by US$0.11 per kWh given the current generation capacity on the system, or US$0.12 per kWh given planned generation capacity (with a NGCC plant)

Involve high transaction and restructuring costs

Increase administration and overhead costs

Prevent financing of the large new plant needed to allow a change of fuel, and therefore forfeit the corresponding saving in electricity cost of US$0.10 per kWh from using LNG as a main fuel for electricity generation

Risk undermining the investment climate in the sector, potentially resulting in rolling blackouts such as the many blackouts that have plagued the Dominican Republic since the sector was restructured in 2000

Risk reducing incentive and ability to maintain the transmission and distribution networks, thereby affecting electricity tariffs for residential and commercial customers (an increase in losses to 25 percent would lead to an increase of electricity costs by US$0.02 per kWh to these customers)

Risk eliminating the ability to cross-subsidize tariffs from richer areas to poor and rural areas.

Below we examine each of these points in further detail.

Transactions and restructuring costs

Until its licence expires in 2027, JPS has:

“the exclusive right to provide service within the framework of an All-Island Electric Licence and the All-Island Electrical System. […] The Licensee shall have the exclusive right to transmit, distribute and supply electricity throughout Jamaica for a period of 20 years.”36

Therefore, unbundling the generation, transmission, distribution and retail of electricity in Jamaica would involve transaction costs related to terminating this licence, setting a new framework for providing licences, and attracting new companies in the sector. The Government would need to create a competitive market mechanism, as well as a new framework and protocols (such as protocols for open access) under which the various 36 Jamaica Public Service Limited - All-Island Electricity Licence, 2001. P.8

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electricity sector companies could operate. This would also involve restructuring costs for JPS. All these transaction costs will need to be recovered from customers.

Furthermore, JPS has entered into various long-term loan agreements (with a total current debt of about US$350 million) with different multilateral financial institutions. Any material change in JPS’s licence would result in a default on all of JPS’s loans. Restructuring the sector would therefore require obtaining consent from the various lenders, which could be difficult and costly.

Increased administration and overhead costs

Under the current structure, administration and overhead costs are minimized because there is only a need for one CEO, and one group of key management and administrative staff. Ideally, if unbundled the electricity sector would comprise at least five or six generator companies and three distribution and retail companies. Each company would need to recruit management staff, specialized and qualified staff, and administrative staff.

In 2009, JPS provided about US$1.4 million in remuneration and compensation to its directors and key management staff.37 With six new generators and three distribution companies, customers in each distribution area would need to be paying for the cost of hiring and remunerating directors, key management and administrative staff in seven companies. Assuming that each distribution company would hire five people to fill director and top management positions, and that each generation company would hire four directors and top managers, and assuming an average salary of US$75,000 for directors and top management positions, electricity prices would need to be sufficiently high to cover a total annual remuneration of about US$2.9 million for directors and key management staff. In addition to that, each company would need to set up a billing and accounting system, and hire administrative staff—these costs would also need to be paid for by customers.

Potential issues with financing generation

The limited ability to finance new generation assets could become an important problem in the electricity sector. To finance new generation assets, companies need an off-taker (that is, someone who can commit to purchase the electricity generated for a defined period), in order to show that there is a secure market for the future output of the facility.

Under a competitive system there would be no single off-taker—potential buyers would include the three distribution companies and large users, so that each of the distribution companies would only be able to commit to buy less than a third of current capacity. Therefore, to finance a large plant, companies would need to sign off-take agreements with two or more distribution companies, as well as a number of large customers for a period of 20 years.

Experience in other markets has shown that this is very difficult in practice. For example, as mentioned in section 7.2.1 the New Zealand electricity market has had difficulty in attracting market-driven investment in generation38, and as a result the Government had to invest in a 155MW oil-fired power plant in 2003, at a cost of more than US$100 million.39 The Philippines has also experienced difficulties with financing generation, resulting in 37 JPS (2010). Growth in the Midst of Adversity-2009 Annual Report. p.82. 38 New Zealand Ministry of Economic Development (June 2003). Discussion Paper: Reserve Generation. 39 TVNZ (June 2004). Whirinaki Power Station Opened.

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insufficient generating capacity to cover peak demand, and consequent risk of power shortages.40 The Dominican Republic has also experienced major difficulties due to distribution companies failing to pay generators for contracted capacity, resulting in frequent and extended rolling blackouts.

Therefore, risks related to off-take agreements would need to be examined very carefully before implementing any sector disaggregation in Jamaica. Securing off-take agreements may be even more difficult if distribution companies have a poor credit rating. In Jamaica, the distribution of electricity is currently characterized by high losses, lack of insurance, and collection problems, therefore unbundling the generation, transmission and distribution would enhance this risk.

In light of the above, financing the new NGCC plant would be very difficult if the system was disaggregated. Therefore, disaggregating the sector would mean foregoing the US$0.10 per kWh benefit that adding this plant would bring to customers.

Risk of increased system losses

A competitive market structure with separate distribution and retailing companies can undermine the incentive to reduce electricity losses and maintain the system. This is because the companies that have the ability to maintain the system and reduce system losses are the distribution companies; however under this type of market structure, the distribution companies would not benefit from any increase revenue as a result of improving the system—the retailing companies would. Therefore, under this type of market structure, the distribution companies have the ability to maintain the system performance to an adequate or desired level but do not have a direct incentive to do so, while the retailing companies have an incentive to maintain the system to increase their revenue, but are not able to do so, as the transmission and distribution assets do not belong to them.

The electricity sector in the Dominican Republic provides a real example of how system losses can increase under a competitive market structure, and contribute to a power crisis that affects all stakeholders in the country, as outlined in Box 7.2 below.

40 Rubrico J. G. (April 2010). Philippines’ Power at Crisis Point.

http://www.atimes.com/atimes/Southeast_Asia/LD10Ae01.html

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Box 7.2: Electricity Sector Disaggregation in Dominican Republic

In the Dominican Republic, the disaggregation of the sector has resulted in a long sector crisis involving a combination of high prices, poor sector performance and costly subsidies. The vertically integrated electricity utility was unbundled in 1997, and in 2000 the Government established an open generation market under which distributors and generators could trade electricity. By 2008 there were more than a dozen generators, a transmission company and three regional distribution companies operating in the sector. A range of national and international market shocks starting in 2001 led to an economic crisis throughout the country, as well as increases in energy prices. In 2003 the Government introduced a new tariff regime under which distribution companies were not allowed to recover increases in energy prices. The three distribution companies have been suffering from financial instability since (also due to high levels of non-technical losses), and have been unable to recover sufficient cash from their customers. In 2003, the Government renationalized two of the three distribution companies by repurchasing 50 percent of the shares held in them. In 2008 the distribution companies had a cash recovery index of about 60 percent (whereas a CRI of 70-75 percent was estimated for ensuring operational breakeven), and were expected to require a cash infusion of over US$800 million just to meet their 2008 deficit. System losses were around 32 percent in 2008. Despite the reasonable availability of generation capacity, distribution companies have been unable to purchase sufficient electricity to meet demand. This has resulted in frequent and extended rolling blackouts, and temporary shutdown of power generation units. In September 2010, the System Average Interruption Duration Index for the distribution company in the North was still as high as 23.63 hours—meaning that during that month, the average outage duration for each customer served was almost 24 hours. The electricity crisis in Dominican Republic has had significant and extensive social consequences. The unreliability of the service has affected the poorest areas more than other areas. In September 2002, as blackouts of up to 20 hours a day were affecting many neighborhoods and particularly the poorest areas, the population expressed dissatisfaction through riots that turned violent and led to the loss of 15 lives. Due to a shortage of funds, the distribution companies have been unable to invest in maintaining and improving their assets—this resulted in deteriorating networks. Between 2005 and 2006, the Government provided more than US$100 million to the companies for investment. However, much of this went into working capital that was essential for continuing operations. The Government provided another US$53 million for investments in 2007, US$75 million in 2008, and agreed to US$80-100 million in both 2009 and 2010. The Government has had to provide large subsidies to the distribution companies (for example, the Government provided more than US$1.3 billion subsidies to these companies between 2005 and 2007 alone), and implement a long Blackout Reduction programme to provide about 20 hours of electricity per day in the poorest neighborhoods. This programme was extended from 2001 until 2009. Sources: DeNorte (30 September 2010). Operatividad Técnica-Distribución; The World Bank (August

2008). Project Appraisal Document on a Proposed Loan to the Dominican Republic for an Electricity Distribution Rehabilitation Project; BCP Securities, LLC (September 2010). The Dominican Republic’s Electricity Industry: A Sector that Generates Attractive Yields.

Using the current pricing formula for electricity tariffs in Jamaica, we can estimate the impact of increased system losses on electricity costs to customers, as shown in section 5.3: ℎ ℎ = × × (1 + )(1)

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Where the fuel cost is the actual fuel cost in US$ per MMBtu, the heat rate is the average heat rate of all plants operating on the system in MMBtu per kWh, and system losses are expressed in percentage of net generation, and where: = − + ℎ ℎ(2) Assuming an increase in electricity losses to 26 percent (that is about half way between the current level of system losses in Jamaica and Dominican Republic), and that the target for system losses was accordingly adjusted to 26 percent, we estimate that the electricity prices to customers would increase by US$0.02 per kWh for residential and commercial customers.

Risk eliminating ability to cross-subsidize tariffs between different areas

Unbundling the distribution of electricity into three different companies serving three main regions would likely require the OUR to determine separate tariffs for different regions. This could impede on the ability for firms to cross-subsidize tariffs from richer areas to poor and rural areas—particularly if one of the distribution companies serves most of the richer customers, while the other companies serve mostly poorer and rural areas. In addition, service quality and standards may differ from one distribution company to another, thereby affecting customers differently, depending on their geographical location.

7.3 Summary In this section we have shown that disaggregating the electricity sector in Jamaica would not lead to any reduction in the cost of electricity transmission and distribution (as this is a natural monopoly). We have also demonstrated that disaggregating the sector would lead to an increase in electricity generation costs, with an increase in electricity costs to customers of US$0.11 per kWh if competition was introduced given the current generation capacity, and increase by US$0.12 per kWh if competition was introduced after the NGCC is commissioned and the CC plant is converted to LNG. In other words, if LNG was used as the main fuel for electricity generation and the market structure was changed to a competitive structure, electricity generators would absorb all of the benefits from the reduction in electricity generation costs.

We anticipate that the cost of electricity would likely increase disproportionately for different types of customers, with a disadvantage for small customer classes such as residential and commercial customers.

These estimates represent the minimum possible increase in retail electricity prices. We expect that retail electricity prices would increase further as a result of the transaction and restructuring costs listed in section 7.2.3. Furthermore, disaggregating the sector may lead to difficulties in financing generation assets, thereby potentially preventing the financing of the NGCC plant and conversion of the CC plant to LNG, and forfeiting the potential saving of US$0.10 per kWh. In addition, we have seen that disaggregating the sector may increase the risk of blackouts throughout the country.

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8 Option 6: Enabling Competition in Generation and Supply to Large Users

In this section we examine the option of enabling competition in electricity generation and retailing for large customers—this is known as ‘retail wheeling’.

Below we provide a description of the reform and explain how it would change the sector (8.1), examine the potential costs and benefits of this reform (8.2), and the potential impact on electricity costs to customers (8.3). We find that enabling retail wheeling in Jamaica would unlikely be economically viable, and therefore would be unlikely to bring any benefits to large customers. If large customers were able to buy power from generators other than JPS at a lower cost, however, the result would be an increase in electricity tariffs to smaller customers.

8.1 Description of the Reform Some stakeholders in Jamaica have suggested that the electricity sector be reformed so as to enable competition in electricity generation and supply to large users (‘retail wheeling’). Possible benefits of retail wheeling include lower prices, more consumer choice, and greater efficiencies in the generation of electricity. These benefits could, in turn, lower electricity-related costs for industrial producers and other businesses, thereby potentially affecting their national and international competitiveness.

Retail wheeling would enable large commercial and industrial electricity customers to buy electricity from suppliers other than JPS, and pay JPS a wheeling charge for the power transmitted and distributed. Implementing this reform would therefore require modifying the current regulatory arrangements so as to:

Enable third party generators to generate and sell electricity to customers in Jamaica—JPS currently has “the exclusive right to provide service within the framework of an All-Island Electric Licence and the All-Island Electrical System […] the exclusive right to transmit, distribute and supply electricity throughout Jamaica for a period of 20 years”41; therefore the licence would need to be renegotiated

Enable third party generators to wheel their electricity over the transmission and distribution lines owned by JPS—this would require the OUR to set a wheeling tariff which JPS would charge to third party generators.

8.2 Evidence of Benefits and Costs The potential benefit of enabling retail wheeling in Jamaica would be a reduction in the cost of generation through an increase in competition. However, in theory this option would be unlikely to result in a reduction in electricity costs, because the OUR already commissions all new capacity under competitive tenders—therefore all capacity recently commissioned should represent low cost solutions.

In addition, under the current market structure and legislation, all customers have the right to self-generate. Therefore, if JPS charged tariffs that were higher than self-generation costs, the company could lose its largest customers.

41 Jamaica Public Service Limited - All-Island Electricity Licence, 2001. P.8

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Furthermore, as seen in section 1, the implementation of a NGCC plant such as that planned for 2014 and conversion of existing CC plant to LNG could achieve a significant reduction in electricity costs—thereby providing little scope for other, smaller plants to generate electricity at a cost lower than the resulting tariffs.

Below we examine the cost of generating electricity for two large users in Jamaica, to determine whether retail wheeling would be beneficial to such customers.

To determine whether retail wheeling would be beneficial to large electricity users, we estimate the cost of electricity generation using a generator that would be large enough to supply two of the biggest industrial customers in Jamaica. We assume that the combined peak demand of these two users is 2.5MW. Table 8.1 below shows the Long-Run Marginal Cost of a 2.7MW diesel generator, using cost figures from a small generator used in Nevis.

Table 8.1: Estimation of Unit Cost of Electricity Generation using a Small Diesel Generator

Average price of diesel for the period 2010-2029* (a) US$/MMBtu 21.33

Plant heat rate (b) MMbtu/kWh 0.012994

Installed capacity (c) kW 2,700

Unit capital cost** (d) US$/kW 1,500




Capacity factor (h) % 97

Availability (i) % 99

Typical output per year*** (j = c*h*i) kWh/kW/year 8,403.6

Total system cost (k = c*d) US$ 4,050,000

Annualized capital cost (l ) US$/year 514,584

Annual fixed O&M cost (m = e*c*12) US$/year 74,520

Typical annual output (n = c*j) kWh/year 22,689,600

Capital cost recovery factor (o = l/n) US$/kWh 0.023

O&M cost per kWh (p) US$/kWh 0.003

Fuel cost (q) US$/kWh 0.277


*Calculated from projected ADO prices over the period 2010-2029 (from the Generation Expansion Plan), and adding freight and transport charges (derived from Petrojam’s pricing formulas); **Includes interest during construction

Note: Costs derived using a discount rate of 11.95%

Source: Capital cost, efficiency and availability figures from NEVLEC (2003). O&M Cost figures from: The World Bank (1985) Diesel Plant Performance Study. Energy Department Paper No. 21

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The table above shows that the LRMC of a small diesel generator (the type of plant that would be used to supply electricity to a couple of large users in Jamaica), is around US$0.30 per kWh. This is very close to the current tariff charged to industrial customers (US$0.31 for R50 customers, and US$0.33 for R40 customers).

The independent generator running this system would therefore charge a minimum of US$0.30 per kWh to the customers. In addition to that, all retail wheeling customers would be required to pay a wheeling charge to JPS for transmitting the electricity to their premises. If the wheeling charge was below US$0.02 per kWh, it would cost the same for the large customers to buy power exclusively from JPS, or from the small generator. However, if the wheeling charge was more than US$0.02 per kWh, it would not be economically viable for large users to buy power from generators other than JPS. Importantly, customers may still want to have a separate contract with JPS for standby power, to ensure continuity of supply even when the independent generator is unable to supply power. Adding this cost to the generation cost and wheeling charge would make retail wheeling non-viable.

In section 3.2.2 we found that with the commissioning of the NGCC plant on the system and conversion of existing CC plant to LNG, electricity tariffs would decrease by US$0.10 per kWh. In this context, it would therefore not make sense for the large customers to buy their power from the small generator, as they would be able to buy power from JPS at a much lower rate.

Bagasse cogeneration, wind power and landfill gas to energy would also generate power at a lower cost than a small diesel plant (as shown in section 4.2.3). The best solution would be for all customers to benefit from cheaper power from these sources, as demonstrated in section 4.2.

If an independent generator was able to sell power to large users at a cheaper cost than JPS, it is likely that the generator would in fact be taking advantage of a distortion in electricity prices (such as a cross-subsidy from large customers to smaller customers). Furthermore, if several of JPS’s large customers were to buy their power directly from other generators, JPS would be forced to increase its tariffs to the residential and commercial customers, in order to recover its actual cost of operations. The burden of maintaining the system capacity would therefore be shifted to smaller users.

Jamaica has already seen some adverse effects of introducing competition in the market for water and “cherry picking”. By “cherry picking”, we mean when operators target specific market segments within a given service area, and exclude less desirable customers. For example, in Ocho Rios, there is a water company is supplying to large hotels, but not to residential and small users (as doing so is not considered profitable). This cherry picking removes NWC’s ability to cross-subsidize small users with profits from the hotels, and may ultimately push up charges for small users.

8.3 Impact on the Cost of Electricity As shown in section 8.2, enabling retail wheeling in the sector would be unlikely to bring a reduction in the cost of electricity to large customers. At best, it would cost the same amount for large customers to buy power from JPS or a small independent generator. Therefore, even if it was available, the retail wheeling option would unlikely be sought after, as large customers would not benefit from buying power from small generators.

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Nevertheless, even if large customers benefited from this option if this reform was implemented, there would likely be tariff rebalancing and social consequences. Electricity tariffs would increase for residential and small commercial users—in other words, any benefits that may be brought by retail wheeling (if any) would not be shared across customers, the costs would simply be shifted from large users to small customers.

Therefore, we would not recommend implementing retail wheeling, because despite involving transaction and regulatory costs, it would be unlikely to benefit large customers, and could harm small customers. The best option would be for people to propose projects or technologies that could really reduce system costs (if these options are not already being used or considered), and for the OUR to ensure that power is purchased from least-cost suppliers for the benefit of all customers.

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9 Option 7: Creating an Independent System Operator

Economic dispatch is the method of determining the most efficient, low-cost and reliable operation of a power system by dispatching the available electricity generation resources to supply the load on the system. The primary objective of economic dispatch is to minimize the total cost of generation while honoring the operational constraints of the available generation resources and the transmission system.

In this section we examine the option of setting up independent dispatching, amid claims that JPS is manipulating the dispatching in order to increase profits. In this section we provide a description of the reform and explain how it would change the market structure (9.1), examine the potential costs and benefits of this reform (9.2), and evaluate the potential impact on electricity costs to customers (9.3). We find that setting up an independent system operator would have no impact on the cost of electricity to customers, or increase the cost slightly across all customers.

9.1 Description of the Reform As a vertically-integrated utility responsible for electricity generation, transmission and distribution on the island, JPS is currently responsible for dispatching the generation required to meet the load. Figure 9.1 below illustrates the current arrangement for dispatching electricity.

Figure 9.1: Current Arrangement for System Dispatch in Jamaica

JPS Generation

JEP Old HarbourIPP

JPPC RockfortIPP

Wigton WindFarm

ResidentialConsumers

Large CommercialConsumers

Large IndustrialConsumers

Other IPPsStreet Lights

Small CommercialConsumers

Small IndustrialConsumers

Generators ConsumersSystem Dispatch and Transmission and Distribution

JPS System Dispatcher andTransmission & Distribution System

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The current requirements and rules for system dispatch in Jamaica are established under JPS’s electricity licence, as follows:

“1. The Licensee shall establish and operate as part of the Generation Code a merit order system, for generation sets that are subject to central dispatch.

2. The Licensee shall schedule and issue direct instructions for the dispatch in accordance with a merit order system of all available generation sets of each authorised electricity operator which are required or are agreed to be subject to such scheduling and instructions.

3. Subject to the factors in paragraph 4, the Licensee shall schedule and issue direct instructions for the dispatch of such generation sets as are at such times available to generate or transfer electricity:

(a) in ascending order of the marginal cost in respect of any hour for the generation and delivery or transfer of electricity into the System, to the extent allowed by Transmission System operating constraints based on "Equal Incremental Cost-System" principles; and

(b) as will in aggregate and after taking into account electricity delivered into or out of the System from or to other sources be sufficient to match at all times (so far as possible in view of the availability of generation sets) demand forecast taking account of information provided by authorised electricity operators, together with an appropriate margin of reserve for security operation.

4. The factors referred to in paragraph 3 above include:

(a) forecast demand (including transmission losses and distribution losses);

(b) economic and technical constraints from time to time imposed on the System or any part or parts thereof;

(c) the dynamic operating characteristics of available generation sets; and

(d) other matters provided for in the Generation Code.

5. The Licensee shall provide to the Office such information as the Office shall request concerning the merit order system or any aspect of its operation.”42

To ensure that the system dispatcher uses up-to-date information on plant costs and efficiencies for determining dispatch, the OUR requires that JPS tests the efficiency of all plants regularly.

Recently, some stakeholders in Jamaica have suggested that JPS has not been operating faithfully in accordance with the principles established in its licence (as explained in Box 8.1 below), and that an effective way of addressing this problem would be to create an independent entity that would be responsible for the dispatch of the various generators on the system.

42 Jamaica Public Service Company Limited All-Island Electricity Licence, 2001. Condition 23, page 33.

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Box 9.1: Is JPS manipulating dispatch out of merit-order?

Some stakeholders in the sector have suggested that JPS has not been operating faithfully in accordance with the principles established in its licence, and that the company has been using the excuse of transmission system constraints to dispatch its own plant at the expense of the IPPs. Others believe that JPS has been dispatching plant to achieve reductions in heat rate figures, in order to achieve heat rates that are less than the target maximum rates specified in the fuel recovery clause of the tariff—whereas according to JPS’s licence, the dispatch should be arranged to minimize costs rather than overall heat rates. However, to date there is no firm evidence that this is the case, and the above claims are impossible to verify one way or another in this study. JPS states that, to the extent allowed by transmission system operating constraints, its dispatch is in accordance with the cost minimization function specified in the licence, and that it reports on its dispatch to the OUR on a monthly basis (in addition to sending two Gross Plant Capacity Reports to the OUR every day). JPS further states that because of the transparency involved in this reporting, it should be easy for the OUR to verify that the dispatch is undertaken in accordance with the requirements set out in the licence. The OUR has recently audited the dispatch function, but the results have not yet been published. Source: JPS

The proposed reform would involve setting up an independent system operator who would be responsible for dispatching the power produced by both the IPPs and JPS unto the JPS-owned transmission and distribution system for distribution to customers. It is not intended that the independent system operator would be a wholesaler of power or take any title to the power sold to the JPS transmission system. Figure 9.2 below illustrates how the system would be dispatched with an independent system operator.

Figure 9.2: Dispatch of Electricity with a New, Independent System Operator

IndependentSystem

Dispatcher

JPS Generation

JEP Old HarbourIPP

JPPC RockfortIPP

Wigton WindFarm

ResidentialConsumers

Large CommercialConsumers

Large IndustrialConsumers

Other IPPsStreet Lights

Small CommercialConsumers

Small IndustrialConsumers

Generators ConsumersSystem Dispatch and Transmission and Distribution

JPSTransmission

and DistributionSystem

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9.2 Benefits and Costs of the Proposed Reform Creating an independent system operator would ensure that the dispatching of plant is always undertaken according to the principles established under JPS’s current licence, and therefore improve perceptions about the fairness of dispatch. These outcomes should be achieved at all times. However, we think that setting up an independent system operator would not be the most efficient way of achieving these outcomes because:

Setting up an independent system operator would involve transaction costs, which would be borne by customers: these transaction costs will be related to renegotiating JPS’s licence, setting up the new operator, and a new regulatory framework for dispatching

Setting up an independent system operator would entail increased overhead costs which would be borne by customers: even though it may be argued that the size of the new system operating team may be the same size as the current team at JPS, the team will require executive and management support staff, and administrative and clerical staff, therefore leading to an increase in the operating costs of the dispatching. These increased costs will have to be passed on to customers in the form of higher rates, and such increases will have to be offset by any gains in the efficiency of dispatch which would result in lower unit costs

The OUR is already monitoring the dispatching on a monthly basis: if the OUR is monitoring the dispatch effectively and not reporting any problems, then this means that the system dispatch is already undertaken in an efficient manner, and following the principles established in JPS’s licence. On this basis, establishing an independent system operator would entail additional costs to customers, with no benefits compared to the current system.

In light of the above, the most cost-effective solution would be to improve the monitoring of dispatching. One way to ensure effective monitoring would be to require that JPS provides, in addition to the data already being provided:

An ex-ante monthly maintenance plan: JPS would file a report outlining its maintenance plan for each month ahead, describing which lines and/or units it is planning to take out of service, and at what time. The OUR would be able to vet this report before approving the maintenance plan, or suggest an alternative plan. JPS would then be required to follow the maintenance plan approved by the OUR

Evidence of emergency: in cases where the actual maintenance plan followed by JPS was different to the maintenance plan approved by the OUR, JPS would be required to provide compelling evidence that this was due to an emergency. JPS would be required to report on how it dispatched all plant, explaining and justifying any dispatching out of merit order. In such cases, the OUR would have the right to audit JPS. In the event that the OUR does not find an allowable reason for JPS to diverge from the approved maintenance plan, JPS would be liable for a penalty.

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9.3 Impact on the Cost of Electricity At best, setting up an independent system operator would not affect the cost of electricity to customers. The cost of electricity might slightly increase (for all customer categories) if a system operator fee was imposed on customers.

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10 Conclusion and Recommendations If the priority for all stakeholders in the electricity sector in Jamaica is to reduce prices, any efforts to reform the sector should not focus on options that will increase prices or have no discernable effects. Accordingly, the analysis shown in this report demonstrates that the options of disaggregating the electricity sector, setting up an independent system operator, and enabling retail wheeling should not be a focus.

Fortunately, our analysis also shows that there are four options which would bring down electricity prices in Jamaica—these are:

Changing the main fuel used for generating electricity to LNG or coal,

Reducing losses in the electricity system,

Implementing viable renewable energy technologies, and

Increasing the use of energy efficient technologies amongst end-users.

These options should be prioritized.

The Government and JPS are already working on these options. Nevertheless, there may be scope for more rapid and effective progress. This report has identified a number of specific actions that JPS and the Government could take to ensure that the reform options listed above are implemented rapidly and effectively—we summarize these in Table 10.1 below.

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Table 10.1: Reducing Electricity Costs in Jamaica—Current Efforts and Recommendations

Reform option

Current efforts to implement reform Recommendations

Changing the main fuel

The OUR recently completed a tender for a large new plant, with preference for the use of LNG as a fuel. JPS submitted a bid to build a NGCC plant

Secure an off-take agreement for the NGCC plant and non-generation gas customers, so that an LNG terminal can be financed

Secure supply of natural gas

Reducing losses in the electricity system

JPS is working on installing new systems, aiming to reduce system losses to 15 percent

JPS to keep working on reducing non-technical losses, but also focus on reducing technical losses (for example by adding voltage regulators for feeders, upgrading high voltage distribution lines from 12kV to 24kV, and possibly by interconnecting different feeders)

Government could also reduce non-technical losses by: – Increasing legislative penalties for theft of electricity – Formalizing procedures allowing JPS to back-bill for stolen

electricity – Implementing a “name and shame” programme to

publicize the names of individuals and companies found to be stealing electricity (similar to that proposed for tax evasion)

– Educating the public about electricity theft and its consequences.

Confidential

86

Reform option

Current efforts to implement reform Recommendations

Implementing viable renewable energy technologies

Government has released its first National Energy Policy to facilitate the deployment of renewable energy technologies

The OUR has released indicative generation avoided costs, to be used as a basis for pricing distributed renewable energy generation

JPS and the OUR have drafted a standard contract for distributed generation technologies

Integrate viable renewable energy options (bagasse cogeneration, wind power and landfill gas-to-energy) into the system expansion plan

Extend the duration of the standard offer contract to 20 years—to provide more certainty, and minimize transaction and processing costs

Offer two options for pricing distributed renewable energy generation: – Providing the long-run avoided cost and 15 percent

premium, fixed for a period of 20 years – Providing the current short-run avoided cost for a period

of 3 years, with the OUR resetting the avoided cost to actual short-run avoided cost on an annual basis

Increasing the use of energy efficient technologies amongst end-users

Government issued a National Energy Conservation and Efficiency Policy for 2010-2030, and proposed a flagship project for supporting increased energy efficiency in Jamaica

Government invested in a Testing, Labeling and Energy Efficiency Information Programme

Government could: Increase uptake of efficient technologies other than lighting Procure an ESCO for retrofitting public buildings, and for

marketing to large consumers Negotiate an arrangement for retrofitting street lights. Implement a standard and labeling programme for appliances Restrict the import of non-efficient equipment, or provide a

preferential customs regime for energy efficient equipment Review the building code to mandate energy efficiency

measures and solar water heaters, and efficient design in new buildings.

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