guyana power sector policy and investment …...3.4 clean development mechanism 61 3.5 guyana’s...

FINAL REPORT

VERLYN KLASS

ELECTRICAL ENGINEERING CONSULTANT

JUNE 2010

GUYANA POWER SECTOR POLICY AND INVESTMENT

STRATEGY

GUYANA POWER SECTOR POLICY AND INVESTMENT STRATEGY

VERLYN KLASS – CONSULTANT Page ii

TABLE OF CONTENTS

Acknowledgements

Foreword

Abstract

Chapters Page

1.0 INTRODUCTION 15

1.1 Background 15

1.2 Activities and Scope 18

2.0 ENERGY BALANCES AND FORECASTS 22

2.1 Introduction 23

2.2 The GPL Load Forecast 25

2.3 The Sugar Sector 36

2.4 The Mining Sector 38

2.5 Other Sectors 43

2.6 Hinterland Communities 45

2.7 Guyana Medium and Long Term Forecasts 47

2.8 Issues and Options 53

3.0 GENERATION TECHNOLOGY 55

3.1 Introduction 56

3.2 Fuel Oil 57

3.3 Wind 58

3.4 Clean Development Mechanism 61

3.5 Guyana’s Hydroelectric Potential 67

3.6 Biomass 74

3.7 Hinterland Generation Technology 75

3.8 Recommendations 77


4.0 PRIMARY ENERGY 83

4.1 Introduction 84

4.2 Medium Term Demand Forecast 84

4.3 Generation Dispatch Model 85

4.4 GPL Installed and Available Generation Capacity 86

4.5 GPL Load Duration Curve 87

4.6 Medium Term Energy Balances 88

4.7 Other Data for Generation Dispatch Model 89

4.8 Medium Term Generation Dispatch 89

4.9 Long Term Analysis 92

4.10 Long Term Energy Balances (Medium Forecast) 92

4.11 Long Term Demand Forecast 94


VERLYN KLASS – CONSULTANT Page iii

4.12 Long Term Generation Dispatch 97

4.13 Summary of Results of Generation Dispatch Model 103


5.0 NETWORK ISSUES 107

5.1 Introduction 108

5.2 GPL’s Transmission Network 109

5.3 Transmission Network Considerations 115

5.4 Interconnection with Major Industries 117

5.5 Interconnection with Neighbouring Countries 117

5.6 Smart Grid Technology 121

5.7 Unbundling Transmission and Distribution 123


6.0 ENERGY EFFICIENCY 129


6.2 Energy Audits 132

6.3 Efficiency Programmes 135

6.4 Renewable Energy for Domestic and Commercial Applications 141

6.5 Demand Side Management 142

6.6 Incentive Schemes 144

6.7 Recommendations 146


7.0 COMMERCIAL ISSUES 150


7.2 Format for Utility to Negotiate with IPPs 151

7.3 Investment and Activity Priorities for Loss Reduction and Commercial Viability 154

7.4 Long Range Programming for Good System Management 155

7.5 Management of Renewable Projects in Hinterland Communities 155

7.6 Commercial Issues for Power Sector Policy 158

8.0 FINANCIAL ISSUES 160


8.2 Who decides on the Sufficiency of GPL’s Profitability? 161

8.3 Should GPL pay a Dividend if it is a Public Utility? 167

8.4 Should GPL be allowed to Pre-finance its Capital through Tariff Surcharges? 171

9.0 SECTOR ORGAINSATION, MANAGEMENT AND REGULATION 174


9.2 Power Sector Reform 175

9.3 Sector Organisation and Management 184

9.4 Sector Regulation 193



VERLYN KLASS – CONSULTANT Page iv

10.0 SUMMARY OF ISSUES, OPTIONS AND RECOMMENDATIONS 197


10.2 Energy Balances and Forecast 198

10.3 Generation Technology 198

10.4 Primary Energy 200

10.5 Network Issues 200

10.6 Energy Efficiency 201

10.7 Commercial Issues 201

10.8 Financial Issues 202

10.9 Power Sector Organisation, Management and Regulation 203

10.10 Conclusion 204

Appendix I (Energy Balances & Forecasts) 206

Appendix II (Generation Technology) 218

Appendix III 223


VERLYN KLASS – CONSULTANT Page v

LIST OF TABLES

Page

Chapter 2

Table 2.1 Number of Customers per Category 2001-2008 27

Table 2.2 Medium Term Forecast Using Trend Analysis 32

Table 2.3 Comparison of Load Forecast using Different Methods 33

Table 2.4 Long Term Forecasts using several GDP Growth Rates

and Trend Analysis 33

Table 2.5 Long Term Medium Forecast of Generation and Sales 34

Table 2.6 Estimates of Demand and Energy of Self Generators 35

Table 2.7 Guysuco Electrical Power System Data 36

Table 2.8 Guysuco Annual Electricity and Sugar Cane Production 37

Table 2.9 Forecast of Guysuco Annual Electricity and Sugar Cane Production 38

Table 2.10 Grants given out to Individual Gold Miners 2004-2008 39

Table 2.11 Bosai Minerals Group Electricity Demand and Generation and Mineral

Production (2004-2008) 39

Table 2.12 Electricity Demand, Purchases, Sales and Losses for LECI 40

Table 2.13 Total LECI Customers 2004-2008 40

Table 2.14 LECI Electricity Sales 2004 – 2008 41

Table 2.15 Medium Term Load Forecast for the Linden Mining Area 42

Table 2.16 Long Term Load Forecast for the Linden Mining Area 42

Table 2.17 2008 Investment Projects by Region 43

Table 2.18 Details of 2008 Investment Projects 43

Table 2.19 2002 Regional Population Data 45

Table 2.20 Data collected and estimated about energy consumption in

the Hinterland Regions 47

Table 2.21 Medium Term Forecast for the Various Sectors in Guyana 48

Table 2.22 Long Term ‘Low’ Forecast for the Various Sectors in Guyana 49

Table 2.23 Long Term ‘Medium’ Energy Forecast for the Various Sectors in Guyana 50

Table 2.24 Long Term ‘High’ Energy Forecast for the Various Sectors in Guyana 51

Chapter 3

Table 3.1 Installed Capacity of Generating Sets in Guyana 57

Table 3.2 Summary of Wind Speed Measurements at Hope Beach 58

Table 3.3 Data on Proposed Wind Farms 59

Table 3.4 Monthly Average Wind Speeds at Orealla 60

Table 3.5 Annual Frequency of Wind Speeds at Orealla 60

Table 3.6 Small Scale CDM project activity categories 63

Table 3.7 IRR of Various Types of Projects with and without CDM financing 67

Table 3.8 Number of Hydropower Sites in Guyana 70

Table 3.9 Capacity of Hydropower Sites 71

Table 3.10 Sites Deemed Most Promising in the Mazaruni Basin in 1976 Survey 72

Table 3.11 Sites deemed Most Promising in the Cuyuni River Basin in 1976 Survey 72

Table 3.12 Sites Deemed Most Promising in the Potaro Basin in 1976 Survey 73

Table 3.13 Increased Potential of Potaro Basin with Diversion from Chi Chi Dam 73


VERLYN KLASS – CONSULTANT Page vi

Table 3.14 Technical Specifications of Amaila Falls Hydropower Project 74

Table 3.15 Comparison of 11 MW Diesel and Wind Turbine Facilities 77

Table 3.16 Projected Installed Generating Capacity 2015 80

Table 3.17 Projected Installed Generating Capacity 2025 81

Chapter 4

Table 4.1 Historical Load Factors 84

Table 4.2 Guyana Medium Term Demand Forecast 2008 – 2014 85

Table 4.3 Generating Capacities Available to GPL 86

Table 4.4 Generation, Sales and Losses Forecast 2009-2014 88

Table 4.5 Maintenance Costs and Fuel Efficiency Data 89

Table 4.6 Generation Dispatch for the period 2009 – 2014 90

Table 4.7 Medium Term Generation Dispatch with New 15 MW Diesel Sets 91

Table 4.8 Forecast Generation and Sales 2015-2025 92

Table 4.9 Forecast Generation and Sales including Self Generators and Linden 93

Table 4.10 Long Term ‘Low’ Demand Forecast 2015-2025 94

Table 4.11 Long Term ‘Medium’ Demand Forecast 2015-2025 95

Table 4.12 Long Term ‘High’ Demand Forecast 2015-2025 96

Table 4.13 Generation Dispatch for ‘Medium’ Demand’ 2015 – 2020 99

Table 4.14 Generation Dispatch for ‘Medium’ Demand 2021-2025 100

Table 4.15 Generation Dispatch for ‘High’ Forecast 2015 – 2020 101

Table 4.16 Generation Dispatch for ‘High’ Forecast 2021 – 2025 102

Table 4.17 Generation Dispatch for ‘High’ Forecast 2021 – 2025, 50 MW

from Tumatumari in 2021 103

Chapter 5 Table 5.1 GPL’s Existing and Proposed 69 kV Network 110

Table 5.2 Low, Medium and High Load Forecasts for Various Years 111

Table 5.3 Estimates of Loads at various Load Centres up to 2025 112

Table 5.4 Loads considered for the Amaila Falls Power Flow Study 115

Chapter 6

Table 6.1 Energy Intensity Data for Guyana 1994-2008 131

Table 6.2 Typical Calculation of SolarBC Incentives 145

Chapter 7

Table 7.1: 2002 Regional Population Data 156

Chapter 8

Table 8.1 Investment Allocation 168

Table 8.2 Debt Servicing (Etc.) 169

Table 8.3 Interest Charges (G$M) 169

Table 8.4 Loan Repayments (G$M) 169

Table 8.5 Revenue Requirement Summary 172


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APPENDIX I

Appendix I-1: Self Generators List I - GPL Industrial Customers now

Self Generators (Source GPL) 206

Appendix I-2: Self Generators List II (Source OPM 207

Appendix I-3: Self Generators Survey Form 209

Appendix I-4: Self Generators List III (Survey Results) 211

Appendix I-5: GPL’s Monthly Generation and Sales Data – 2000-2003 212



Appendix I-8: IMF GDP 2009 Country Projections – Guyana 215

Appendix I-9: Generation, Sales, GDP, and Population Data 1981 – 2008 216

Appendix I-10: Projected GDP, and Population Data 2009 217

APPENDIX II

Appendix II – 1 First Added Inventory Sites In Order Of Cost per Rated kW (US$) 219

Appendix II-2 Inventory of Sites Developed in Conjunction with

Upstream Storage 221

APPENDIX III

Appendix III-1 Busbar Voltages 2012 Load Forecast 224

Appendix III-2 Line Flows 2012 Load Forecast 225

Appendix III-3 Busbar Voltages 2016 Load Forecast – 50 MW from Amaila Falls 226

Appendix III-4 Line Flows 2016 Load Forecast – 50 MW from Amaila Falls 227

Appendix III-5 Busbar Voltages 2016 Load Forecast 100 MW from Amaila Falls 228


Appendix III-7 Busbar Voltages 2020 Load Forecast – 115 MW from Amaila Falls230


Appendix III-9 Busbar Voltages 2025 Load Forecast 100 MW from Amaila Falls 232

Appendix III-10 Line Flows 2025 Load Forecast 100 MW from Amaila Falls 233


VERLYN KLASS – CONSULTANT Page viii

LIST OF FIGURES

Chapter 2

Figure 2.1 GEC/GPL Annual Generation and Sales 1984-2008 26

Figure 2.2 Actual and Percentage Losses 1984-2008 26

Figure 2.3 Monthly Sales and Losses 2001-2008 27

Figure 2.4 Sectoral Composition of GDP 2004-2008 28

Figure 2.5 Actual and Projected Growth rates 2004-2014 29

Figure 2.6 GDP in Guyana$ and US$ 1981-2008 29

Figure 2.7 Historical and Projected Population 1980-2025 30

Figure 2.8 Sales Forecasts 2014-2025 33

Figure 2.9 Generation Forecast 2014-2025 34

Figure 2.10 Guysuco Monthly Generation and Sugar Production 2004-2008 37

Figure 2.11 Guyana Long Term Energy Forecasts for National Grid 52

Figure 2.12 Total Guyana Long Term Energy Forecasts 52

Chapter 3

Figure 3.1 Map of Guyana showing the Main Rivers 69

Figure 3.2 Installed Generating Capacity - 2015 81

Figure 3.3 Installed Generating Capacity – 2025 81

Chapter 4

Figure 4.1 Generating Capacity and Load 2008-2012 87

Figure 4.2 GPL’s Load Duration Curve 88

Figure 4.3 Generation and Load with Diesel Addition 91

Figure 4.4 Generation Capacity & Load (2015 – 2025)’Low’ Forecast 97

Figure 4.5 Generation Capacity & Load (2015 – 2025)’Medium’ Forecast 97

Figure 4.6 Generation Capacity & Load (2015 – 2025)’High’ Forecast 98

Figure 4.7 Generation Capacity & Load (2015 – 2025)’High’ Forecast,

Additional 50 MW 104

Figure 4.8 Generation by Fuel Type – 2008 104

Figure 4.9 Projected Generation by Fuel Type 2015 105

Figure 4.10 Projected Generation by Fuel Type – 2025 05

Chapter 5

Figure 5.1 Guyana’s Proposed 230 kV Transmission Network 116

Figure 5.2 Venezuela’s Transmission Network 119

Figure 5.3 Brazil’s Transmission Network 120

Figure 5.4 Load Flow Run - 2016 Forecast Projections 127

Figure 5.5 Load Flow Run - 2025 Load Projections 128


VERLYN KLASS – CONSULTANT Page ix

Foreword

The Guyana Power Sector Policy and Investment Strategy is a study that was performed as a

part of the Government of Guyana’s Unserved Areas Electrification Programme (UAEP).

This study sought to advise the Government of Guyana on important policy considerations

that should be addressed in order to sustain the long term goal of ensuring the economic and

financial viability of the power sector.

There are eight areas that were investigated in this study, namely,

Sector Organisation, Management and Regulation

Energy Balances and Forecasts

Generation Technology

Primary Energy

Network Issues

Commercial Issues

Financial Issues, and,

Energy efficiency

Each of the above mentioned areas presented a number of issues that when analysed and

important decisions considered were then used to formulate a plan and a policy for the

sustenance of an efficient and effective power sector that can provide electricity at a

reasonable cost to the other sectors of the economy.

The policy decisions that were made are presented in a separate document called Guyana

Power Sector Policy and Implementation Strategy.


VERLYN KLASS – CONSULTANT Page x

Abstract

The Guyana Power Sector Policy and Investment Strategy analysed eight (8) areas of the Guyana

power sector with a view to formulating policies to ensure the viability of the sector. In each of

these areas the study highlighted issues which if properly addressed could make a significant

impact on the power sector. Where appropriate, different options were investigated and

recommendations made. A summary of the results of the study in these areas is noted as follows:

Sector Organisation, Management and Regulation. This section analysed power sector

reform which is being adopted in many countries in an attempt to bring competition in

the electricity supply industry with its expected concomitant effects of efficiencies and

price reduction. It was noted that a more pragmatic approach is now being recommended

towards power sector reform in developing countries following the failure of such reform

to bring about the projected improvements in the performance of the electricity utilities. It

has been determined that full competition is not practical in many countries that have

weak economies and a limited private sector. It is deemed essential however that the

governments find ways to introduce some measure of reform and thereby improve the

performance of the power sector.

The various options available to the Guyana power sector were discussed. Some of these

included

Issuing of a management contract in the medium term to improve the performance

of the power company and to make it ready for privatization.

Converting GPL to a distribution company with responsibility for the power

systems at 69 kV and below which would include the diesel generating sets

presently connected to these systems.

Forming a Generation and Transmission Authority which would be responsible

for future hydro development and the associated transmission networks.

It was however determined that some of these recommendations may be more feasible in

the longer term.

The roles and functions of the various agencies within the power sector, namely, the

Office of the Prime Minister, the Guyana Power & Light Inc. and the Guyana Energy

Agency, the Government Electrical Inspectors were noted and also the role of the

Environment Protection Agency. Where deemed necessary,certain changes were

recommended.

The issue of planning was highlighted as being very critical to the power sector. The

high capital investments and the length of time before delivery of many power system


VERLYN KLASS – CONSULTANT Page xi

projects make it essential that a medium term plan with a long term perspective be done

on a regular basis.

The importance of an independent regulatory body in promoting transparency and

consumer confidence was also noted.

Energy Balances and Forecasts. The study developed medium term (5 year) and long

term (15 year) forecasts for GPL, the self generators, the sugar and mining industries and

the other sectors of the economy. In certain sectors of the economy, information for

positive forecasting was limited or nonexistent, however, a national forecast was

developed for the medium term and this showed an average of 2.6 % annual growth rate

up until the year 2014.

The study for the long term forecast used the three scenarios of GDP annual growth rates

namely 3.5%, 5% and 7%. Correlating GDP and population estimates with electricity

usage produced forecasts of average annual electricity demand growth rates of 2.8%,

5.5% and 9.2% respectively. These three scenarios were termed the ‘low’, ‘medium’,

and, ‘high’ forecasts for the long term, that is, from 2015 to 2025.

The need for continual updating of the forecast was noted and so was the requirement to

place the responsibility of national forecasting within a specific agency in the power

sector.

Generation Technology. In seeking to reduce the country’s dependence on imported

fossil fuels, this area of study examined hydro, wind and bio-fuels as possible alternatives

to fuel oils. The recommendation is that the Potaro river basin be developed in stages to

meet the requirements of the national grid. The study recognized the medium term

requirement for increased generation before the Amaila Falls hydropower project is

commissioned, and the analysis showed fuel oil to be a better option than wind for the

medium term. Wind energy did not seem appropriate for the long term either as it would

be displaced by the expected hydro facility. The ongoing use and research into bio-fuels

is recommended.

The modalities of the Clean Development Mechanism that was created by the United

Nations Framework Convention on Climate Change (UNFCCC) in 1997 to assist

Developing Countries to address their Sustainable Development needs and also to assist

Industrialised Countries in achieving compliance with their quantified emissions target

and reduction of the six greenhouse gases was investigated. Although this mechanism

seemed more beneficial for large projects it was recommended that its usefulness for

smaller projects be further investigated.


VERLYN KLASS – CONSULTANT Page xii

Primary Energy. This section of the study sought to allocate the available and projected

generating capacities to the growing demand. The need for increased generation capacity

of 15 MW in the medium term was demonstrated. Using the ‘medium’ load forecast and

with the Amaila Falls hydropower station in service by 2015, this station has the

capability to meet the load of the national grid until 2021 when the diesel engines would

again be called into service. This situation would be brought forward by two years if the

‘high’ forecast was encountered. Bearing in mind the length of time necessary to acquire

financing and to construct hydro projects, it is recommended that the feasibility study for

the next suitable hydropower facility commence almost immediately.

Network Issues. The development of a national grid to which all the electricity users in

Guyana could be connected was the focus of the study in this area. As desirable as this

is, there are various constraints, in particular the small sizes of loads in various sections

of the country, and the different system frequency in the case of the sugar estates.

The study highlighted the need for regional forecasts to augment the national load

forecast as it is essential to know where the load growths are expected. Load flow runs

were performed to determine the sufficiency of the 69 kV network to meet load growths

in the long term with Amaila hydropower station being the main power source. It was

demonstrated that the interconnecting 69 kV transmission line between Demerara and

Berbice was a critical link in maintaining system losses at an acceptable level. It was

also necessary to have some level of generation in Berbice to maintain good voltages.

Other issues investigated were the feasibility of transmission line interconnections to

neighbouring countries and the use of digital technological developments in increasing

efficiencies in the Guyana power sector. In the case of the former, such interconnections

were not deemed economical at present and in the case of the latter this required

benefit/cost analyses to determine their practicability.

Energy Efficiency. Energy efficiency/conservation measures are very important in terms

of delaying the dates of future investments in the power sector. In situations where the

electrical energy is produced by fossil fuels then these measures also help to reduce the

carbon footprint. An energy efficiency policy needs to be developed and the funding of

programmes to promote energy efficiency needs to be addressed. Quantifying the

expected benefits and savings as a result of these programmes can only be done through

energy audits of residential, commercial and industrial buildings. The Guyana Energy

Agency has been tasked with this initiative and has drawn up an energy efficiency

programme for approval.

Financial Issues. The report investigated the issues of sustainability, profitability and

payment of dividends by a government owned utility. It was determined that the


VERLYN KLASS – CONSULTANT Page xiii

owner/investor is responsible for making these financial decisions. A proposal was made

for the establishment of a power sector development support fund which will operate as a

revolving fund under the control of the government into which will be placed loan

repayments and dividend payments to the government by the power company. This fund

would be used as investment for the ongoing development of the power company.

It was not recommended that tariffs should be set at such a level so that there are used to

pre-finance capital investments.

Commercial Issues. Tariff proposals being the subject of another study, this study

concentrated on the following commercial issues, namely,

‒ Guidelines for negotiations with Independent Power Producers (IPPs),

‒ Incentives to attract private investment for renewable power projects in the

hinterland regions,

‒ Programme for maintaining good system management, and,

‒ Investment and activity priorities for sustainable loss reduction and commercial

viability

Various practical suggestions were given in each of the above-mentioned areas.

Chapter 1 INTRODUCTION

CHAPTER 1 INTRODUCTION

GUYANA POWER SECTOR POLICY AND INVESTMENT STRATEGY VERLYN KLASS - CONSULTANT

1.0 INTRODUCTION

This chapter is reproduced from the Terms of Reference for the study Guyana Power

Sector Policy and Investment Strategy

1.1 Background

1.1.1 Guyana is a leading producer of bauxite, timber and sugar and is rich in mineral resources

such as gold and diamond. Whilst the country has significant potential for renewable

energy sources, indigenous energy resources are not widely utilised. Biomass, in the

form of rice husk for the operation of a generator in the rice industry and firewood for

cooking, together with small photovoltaic systems are commonly used. Even though the

country is traversed by great rivers, there is yet no major hydro plant in operation and

modern energy needs are largely satisfied by oil products, which are all imported. The

country is highly dependent on oil as evidenced by its energy:GDP intensity ratio.

1.1.2 Hydro has not yet been commercially attractive due to natural conditions, relatively small

demand, and/or distances from load centers. However, there are numerous potential sites

for hydroelectric development. In particular, a hydro development in Amaila Falls was

studied in depth by private developers in 2001, shows that such development could be

commercially feasible if concessionary financing were obtained and the entire output

capacity were sold at full price. Other developments include a proposed wind farm

project (Hope Beach, with installed capacity of 12 MW) and bagasse-driven plants from

sugar plantations. A Power Purchase Agreement is being negotiated for the bagasse-

fuelled plant. With oil prices at record levels, a fresh look at the development of non-oil

resources should be given high priority. Hydro developments have been documented in

studies executed in the 70s and 80s by Monenco and Sweco, among others. These studies

are currently available in the archives of the Guyana Energy Agency (GEA).

1.1.3 Guyana Power and Light (GPL), a vertically integrated utility, is the principal public

supplier in Guyana. It operates under a twenty–five year Licence that was granted in

1999. GPL’s operations comprise generation, transmission, and distribution, and the

utility’s licence covers the entire country with the exception of a medium-sized

municipality located in Linden, approximately 100 km from the Coast, and any other area

in which a secondary supplier is licensed to operate. GPL operates several isolated and

connected systems along the coastal area: (i) Demerara Interconnected System (DIS); (ii)

Berbice Interconnected System (BIS); and (iii) isolated systems along the Essequibo

Coast at Anna Regina, Leguan, Wakenaam and Bartica. There is a weak transmission

link between the DIS and BIS. GPL’s current total installed capacity is 131 MW (106.5

MW available) and approximately 555 GWh is produced annually. GPL supplies around

139,000 residential, commercial, and industrial customers.

1.1.4 Other current secondary licensed producers and suppliers are: (a) Lethem Power

Company, Inc, in Rupununi, Region 9 (fully owned by the Government holding company

NICIL) generates and sells electricity to approximately 400 consumers in a hinterland

area under a licence granted in February 2005; (b) Omai Services Inc., which was granted

a licence on March 15, 2005 to generate and sell electricity in bulk; (c) Linden Electricity

Company Inc. which supplies to the Linden community; and (d) Kwakwani Utilities Inc.



1.1.5 GPL’s licence was issued as part of a reform process supported by the Bank aiming to

ensure the economic, financial, environmental, and political viability of the power sector.

In line with these goals, the GOG sought to pursue five major objectives: (i) extending

modern and cleaner energy options to the entire population at affordable terms; (ii)

developing efficient and environmentally sustainable energy production and consumption

patterns; (iii) promoting the development of new markets for energy efficiency and rural

energy by adopting innovative mechanisms and maximizing the potential for self-

sufficiency and replication; (iv) mobilizing local and foreign capital to finance sector

development; and (v) mobilizing foreign expertise to sustain the development process.

1.1.6 This strategy complemented the Government’s vision for the effective management,

operations and investments in GPL by ACP, the private operator that took over these

functions in October 1999. In April 2003, because of unmet expectations and other

differences, ACP withdrew its participation as an investor in GPL and sold its shares to

the Government. The management arrangement also ceased, and GPL is now fully owned

by the Government of Guyana.

1.1.7 GPL has faced severe challenges over the years in curtailing its technical and commercial

losses. During the years of private management total losses increased from 40% in 2000

to 44% in 2003. Since reverting to public ownership management has focused on

reducing losses, particularly commercial ones which account for the major portion of the

total; as at December 2007 losses were reported at 33.4%. The Bank supported Unserved

Areas Electrification Programme (UAEP), includes an element for GPL’s loss reduction

measures. A study to analyze loss reduction options and to prioritize loss reduction

measures/investments was completed in mid-2006 by the consulting firm Power

Planning Associates.

1.1.8 GPL’s finances have reflected its poor operational performance: during 2000-2002 the

company posted pre-tax losses; in 2003 and 2004 it posted pre-tax profits of US$1.6 and

US$1.0 million, respectively. GPL was able to show positive results partly as a result of

cost saving mechanisms and relatively high prices. However GPL's audited financial

statement for 2006 shows a net loss of US $5.3 million largely attributed to rising fuel

prices. The audit for 2007 is still being finalised. Currently, the average price for

electricity is US¢32/kWh, between a high of US¢35/kWh for commercial users and a low

of US¢26/kWh for domestic consumers.

1.1.9 Prices are determined on the basis of GPL’s licence. The Public Utilities Commission

(PUC) has a role in the adjustment of tariffs; it is also in charge, among others, of

approving PPAs in the power sector. The PUC has benefited from a Technical

Cooperation (TC) financed by the IADB to support it in developing the procedures to

solicit IPPs and negotiate PPAs. The TC is also providing support for training of PUC

staff to enhance its regulatory capacity, and acquisition of computing and

communications equipment. A tariff study prepared in 2002 by Mercados Energéticos

recommended the implementation of a tariff rebalancing policy in order to better align

prices with costs through increases in domestic prices and decreases in

commercial/industrial rates.



1.1.10 Tariff increases are politically sensitive and involve several trade-offs:

Maintaining levels at the minimum required to allow GPL to survive financially

under best effort conditions with reduced losses and costs;

Reducing commercial and industrial rates to avoid loss of customers through recourse

to self-generation;

Rebalancing through increases in domestic rates, complemented by measures to

combat fraud and theft.

1.1.11 Government priorities involve expanding supplies within areas currently served by

GPL—along the coastal strip—and in the interior. In this respect, in 2002 the Bank

sought to support power sector development through the $34.4 million Unserved Areas

Electrification Programme (UAEP). This programme was initially conceptualised to

extend service to 40,000 new users and to develop hinterland electrification schemes. It

also comprised a hinterland project preparation component and an institutional

strengthening component. With the withdrawal of the private investor from GPL due,

inter alia, to its inability to address several major weaknesses of the company, the need

became evident to reformulate the programme in order to ensure the sustainability of

GPL in parallel with implementing service extensions.

1.1.12 In 2004 the UAEP was reformulated, to reflect the following: (a) an investment

component comprising a target of 30,000 grid connections, loss reduction, and project

management, (b) a hinterland project preparation component, and (c) an institutional

strengthening and capacity building component. Progress on these fronts can be

summarized as follows: (a) grid extension planned for Phase 1 has been completed to

provide over 15,000 connections. Procurement of materials and works for electrification

of the remaining 6,000 lots under Phase 2 has commenced; (b) legal support for GPL has

been contracted for negotiating power purchase agreements; (c) the loss reduction

prioritization study has been completed by Power Planning Associates and that

consulting firm has been hired to provide technical support for the implementation of the

loss reduction investment programme; (d) over 18,000 meters have been received from

an order for 25,000 for the replacement of defective meters; (e) procurement of customer

information system software and the required hardware has substantially progressed; (f)

plans are afoot to introduce pre-paid meters in 2008 on a pilot basis; (g) a hinterland

electrification study identifying service options was completed in October 2005 by

Projekt Consult; (h) approximately 320 solar home systems have been installed in four

hinterland communities; (i) new distribution networks are being constructed in the

hinterland communities of Orealla and Siparuta with expected commissioning date in

July 2008; (j) design for the upgrade of Port Kaituma electrification system has been

completed; (k) new Electricity Sector (Technical Standards) Regulations have been

published; (l) the Government Electrical Inspectorate has been strengthened; and (m) four

anemometers and data loggers have been procured and will be installed in four hinterland

communities during the 2nd

and 3rd

quarters in 2008 for collection of wind data.

1.1.13 GPL’s generation expansion strategy as detailed in its Development & Expansion

Programme 2008 – 2012 is oriented towards saving fuel costs by replacing high price

diesel oil with lower cost bunker fuel and renewable energy. This includes capacity



additions by GPL through arrangements with Independent Power Producers (IPPs).

Generation capacity will be added in the following manner, including: (a) 20 MW of

Wartsila built medium speed diesel (MSD) units to be financed by GPL, with

Government support, (b) 10 MW of steam power for the Berbice system to be produced

with bagasse, together with around 8MW of MSD, currently being implemented by the

state-owned GUYSUCO sugar company; (c) 100 MW of hydro power from the Amaila

Falls Hydroelectric Project developed by private investors; and (d) 4 MW average of

wind power from Delta Caribbean, a Curaçao-based company.

1.1.14 The sector’s current structure has several difficulties. Public ownership of GPL limits the

possibilities of accessing commercial loans due to IMF conditions. For example, a

European Investment Bank loan for GPL could not be agreed to as it would have required

a significant concessionary component to comply with IMF regulations. The latter would

not apply were GPL to be under private ownership and management. Mobilizing private

sector resources as a potential long-run priority will require addressing questions such as

opportunity and the privatization mode to be adopted, based necessarily on lessons learnt

from the previous failed privatization. Re-privatization is not contemplated by the

Government in the medium term due to the lack of interest of investors for enterprises

with performance problems such as those of GPL, however private participation is

encouraged through power purchase arrangements and outsourcing of grid expansion and

maintenance activities.

1.1.15 Until now, environmental questions have not had a significant impact on power sector

affairs, mainly because developments have not involved high impact investments such as

high voltage transmission lines or hydro. The agency in charge of environmental matters

is the Environmental Protection Agency (EPA), which issues environmental permits with

or without the requirement for the execution of an Environmental Impact Assessment

(EIA) depending on a project’s characteristics.

ne the benefits and costs of a unified power system and recommend a policy approach in the

sector that should provide an updated overall framework for power sector oversight,

investment, regulation, efficiency and hinterland electrification.

1.2 Activities and scope

1.2.1 The project will consist of an assessment of the power sector to: (i) identify all relevant

and critical issues facing the sector, including the effects of high oil prices and measures

to mitigate their impact; (ii) analyze alternative options for addressing these issues, (iii)

single out relevant policy and strategic decisions for implementing solutions; and (iv)

assessing previous studies of hydro sites and identifying updating requirements for

selected projects. The project’s scope includes not only the presentation of issues and

options, but also an active interaction with the relevant Government authorities in order to

assist them in making informed choices that should converge towards an explicit policy

and strategy.

1.2.2 The end product of this policy effort should include the Government’s statement of its

goals, priorities and implementation strategies for the sector as regards the following

matters:



Sector Organization, Management and Regulation - Structure of sector, Role of PUC,

Privatization options

Primary Energy sources - Oil, Renewables

Energy balances and forecast- Current balance, Future projections, suppliers short and

long term plans

Energy efficiency

Generation Technology - Technological priorities

Network Issues - National grid unification, Large self-generator connections, Large

hydro connections, Cross border transmission

Commercial Issues - Pricing options for electricity service, Long range programme

for maintaining good system management,

Financial Issues - Financing of sector

1.2.3 In each of the listed areas, the project activities must address the key issues, questions

and problems. These key activities will be focused on the following elements and issues:

Sector Organization, Management and Regulation

o Is GPL’s current institutional structure adequate to manage the merged

operations of current isolated grid systems with the GPL’s grid?

o Should ―lost‖ large customers be brought back into the GPL system or large

self generators encouraged to feed off the GPL grid, if so, how?

o Is unbundling by segment (generation, transmission, distribution) a feasible

option for GPL?

o How is transparency and regulatory oversight to be maintained in the system

if it undergoes structural change?

o Should GPL continue to own and operate generation assets?

o How could the PUC be strengthened in order for it to perform its functions

effectively?

o What is the role of GEA in formulating electricity policy? Should GEA have

a say in determining the fuel mix of the electricity sector, given its current role

vis-à-vis fuel imports?

Primary Energy

o Assessment of the current primary energy balance of the country with

projections to 2015 and 2020 – detail consumption by end uses and

conversion methods, including self-generation

o How much oil should be used in power generation in the future?

o What is the role of renewables, and separately, where does hydro fit in; large

and small?

o How measures should be implemented for the country to attract CDM (Clean

Development Mechanism) investments in the power sector?



Energy balances and forecast- Current balance, Future projections, suppliers

short and long term plans (5 years and 15 years horizon)

o Current and future energy and electricity sector data and projections in all

traditional sectors including mining, forestry and sugar in quantitative format

most useful to OPM and GPL

o Include discussion of generation technology options, primary fuel options

o GPL forecasts included in output

Energy efficiency

o What programmes should be implemented to promote energy conservation,

energy efficiency, reductions in energy intensity and establish appropriate

measurement and monitoring standards and guidelines;

o Should energy saving measures through introduction of fiscal incentives and

other incentives be promoted?

o Should intensive energy saving and energy efficiency programmes, which

include energy audits of residential and commercial properties be

implemented?

o To what extent should the use and installation of renewable technology in the

construction, refurbishment and upgrade of public, commercial and residential

buildings be encouraged;

o Should electric utilities be obligated to implement Demand Side Management

programmes?

Generation Technology

o Where does the Government see its choice of prime movers going in the

future – better oil burners, more wind, large hydro?

o How should primary energy transitions (e.g., oil to hydro) be accommodated

regarding stranded costs in generation? Who will cover the stranded costs?

o How should system services (ancillary services) provided by generation be

accommodated in the future, and how should they be paid for?

Network Issues

o Should distribution and transmission be unbundled in GPL’s current system or

in the future?

o What are the benefits and costs of national system integration?

o To what extent can high generation costs be offset with better network

infrastructure, including ―smart grid‖ technology?

o What are the benefits and costs of purchasing power from large mining

operations with self-generation, and what are the network investment

implications?

Commercial Issues

o Determine the commercial issues that should be addressed as part of the power

sector policy

o Discuss initiatives that may attract private development of renewable energy

projects in the hinterland communities



o Propose a format that will guide GPL during negotiations with IPPs

o Investigate the licensing of hinterland operators

o Define a long range programme for maintaining good system management

o Determine the investment and activity priorities for sustainable loss reduction and

commercial viability

Financial Issues

o Should GPL pay a dividend if it is a ―public‖ utility?

o Who decides on the sufficiency of GPL’s profitability?

o Should GPL be allowed to pre-finance its capital investments through tariff

surcharges?

o Who decides whether a GPL investment or purchased power agreement (PPA)

is reasonable and proper?

1.2.4 The consultant chosen to undertake this activity will need to formulate a plan to integrate

the current state of knowledge about each of these issues in Guyana with best practices

elsewhere in the Caribbean and the rest of the world, taken in account the Guyana

environment. This plan of action should be oriented toward producing a final policy

paper for the government, as well as interim presentations, memoranda on specific issues

and policy discussions with the Government and with other power sector stakeholders as

appropriate. In addition, the consultant will be responsible for structuring an

implementation strategy, including, among others, a plan of action for mitigating the

impact of high oil prices.

1.2.5 The consultant should focus on the eight (8) key issues highlighted in paragraph 1.2.3

above and should create a list, probably overlapping to some degree, of key local

resources for each issue. In collaboration with the OPM, the consultant should produce

interim reports for each issue along the lines of ―Issues and Options‖ studies.

Chapter 2 ENERGY BALANCES AND FORECASTS

CHAPTER 2 ENERGY BALANCES AND FORECASTS


2.0 ENERGY BALANCES AND FORECASTS

2.1 Introduction

In any society, energy supply is one of its main engines, and economic growth is strongly

conditioned by electricity production because industrial development has become highly

electricity intensive. It is therefore necessary to have a clear knowledge of current and historical

electricity demand determinants so that correct investment decisions can be made with regard to

the generation, transmission and distribution systems. The regulator also needs to have

knowledge of the leading industry indicators and market figures to help in the task of

implementing regulatory framework and tariff design.

The power system in Guyana did not develop under one national grid. For different reasons, the

major industries, bauxite and sugar, did not seek to purchase electricity from the local utility but

developed their own generation and distribution facilities. Beginning in the early 1980s the local

power utility experienced severe generation shortfalls and many businesses purchased

emergency standby diesel generators to augment the utility’s supply. More recently, as the

power company was faced with increasing commercial losses and rising oil prices, many

companies used the standby generators as their main electricity supplier and improved their

generating capacity to ensure higher reliability. This situation does not possess good long term

prospects for the electricity utility and the country and it is essential that, as far as is feasible, the

power system in Guyana is developed under one national grid and that self generators again

become a part of the national power system.

Guyana is in the process of instituting the development of its first hydropower station. This,

together with uncertain fossil fuel oil prices, makes it imperative that a careful analysis be done

of the electrical load projections in the medium term as well as the long term so that there is

enough generation available in the medium term and that there is enough load for the

hydropower development in the long term. This study determines a medium term (5 year) and

long term (15 year) electricity forecast for the whole of Guyana. In a later section the costs and

benefits of connecting the total electrical load to a single national grid will be determined.

This study has developed medium and long term load forecasts in the various areas and sectors

as follows:

The GPL Franchise Area

The EViews forecasting software was used to calculate both the medium term and

long term load forecasts. The medium term load forecast (2009 – 2014) was

calculated using nine years monthly data of generation and sales to perform a

trend dynamic forecast using lagged dependent variables. This generation

forecast was between 6 and 10.5% lower than the GPL 2008 forecast for the years

2009 to 2012. GPL assumes a much higher forecast for 2013 as a result of its

projections that hydropower would be installed in 2012.

Annual data of electricity sales, GDP and population were used to extend the

medium term forecast into the long term (2015 – 2025) using a multiple

regression econometrics forecast method. GDP growth rates of 3.5%, 5% and 7%



were used. The 5% growth rate was chosen for the load forecast as it was

deemed to represent an improved economic climate based on cheaper hydropower

electricity resulting in increasing economic development.

The generation and sales computed by the medium term load forecast showed a

3% loss reduction over the period. GPL has projected a loss reduction of 8% over

the medium term that would result in increased sales. The medium load forecast

developed by the trend analysis was increased to project a loss reduction of 6% in

the medium term. For the long term it is estimated that by 2025 losses would be

reduced to 15%.

There were three sources of data on the companies in the GPL franchise area who

were generating their own electricity. These sources provided different types of

data, however, these were collated and analysed and an estimate made of the

present demand (MW) and energy generation (GWh) of the self generators. An

annual 2% increase was used to extend this figure into the medium and long term.

The Sugar Sector

Five years of monthly data of electricity generation and sugar cane production for each

estate was received from Guysuco. Guysuco is hesitant to release details of its future

plans and projects and data on the increased efficiency of the new Skeldon estate was not

available. Nevertheless certain assumptions were made on the performance of the

Skeldon estate to determine a medium term electricity load forecast for Guysuco. In the

absence of any more information the long term load forecast was kept at the 2014 level.

The Mining Sector

The mining sector was divided into three sections, namely, small, medium and large scale

miners. It was determined that because of the nature and size of their operations, it was

unlikely that small and medium scale gold miners would be a part of the national

electricity grid even in the long term. Three large mining companies were contacted but

only the Bosai Minerals Group responded and it said that its future plans and projections

were not available at present, however, the trend of the last few years was used to provide

a load forecast for the medium and long term.

Efforts would be made to obtain more information from the other mining companies

when the area of Network Issues is being done.

The Linden Electricity Cooperative Inc., the distribution company that purchases power

from the Bosai mining company has been treated separately in the load forecast. It is

projected that because customers will soon be required to pay the real cost of electricity,

demand may fall in the medium term but rise again in the long term as the construction of

the Amaila hydropower project should cause improved economic conditions in the area.

Other Sectors

The Guyana Office for Investment provided a list of over four hundred potential investors

who were interested or had already made an investment in Guyana. An analysis of these

investments determined that many of them could be considered to have been taken into



account in the GPL load forecast. This report does not provide any load forecast for the

other sectors, but, more information may become available when the area of Network

Issues is being analysed.

Hinterland Communities

The various public and private initiatives for electricity generation in the hinterland were

noted and a forecast estimated. It does not seem likely that these areas could become a

part of the national grid in the medium and long term.

2.2 The GPL Load Forecast

The following methodology was used to determine the GPL load forecast.

Annual and monthly data on generation, sales, losses and number of customers were

collected as were available.

Annual historical and projected data were collected on GDP, population, and exchange

rates. Quarterly GDP series data was not available.

An econometrics load forecast was carried out using annual data with generation/sales as

the independent variable and GDP and population as the dependent variables. The

correlation was weak and the load forecast seemed very high.

A trend load forecast was carried out using monthly data of sales by consumer category

and generation. The forecast seemed more acceptable than the econometrics forecast for

the medium term but did not take into account changes that may occur in the long term.

For the long term an econometrics forecast was done using additional data provided by

the trend forecast and considering GDP growth rates of 3.5%, 5% and 7%.

The historical data and the forecasts are outlined in the following sections.

2.2.1 GPL Historical Performances

The Guyana Power & Light Inc. (GPL) is the principal public supplier of electricity in Guyana. It

has two power systems interconnected at 69 kV in Demerara and Berbice, and four isolated

power systems in the Essequibo region. Some important statistical data for the company for 2008

are as follows:

Installed Capacity: 152 MW

Maximum Demand: 90 MW

Generation: 567 GWh

Sales: 356 GWh

Number of Customers: 142,439

The historical data collected from GPL, the 2002 Tariff Study by Mercados Energeticos and the

1992 Long Run Marginal Cost Study by Vladimir Koritarov were as follows:



Annual Generation and Sales 1981 – 2008

Monthly generation, sales and losses for 2000-2008

Annual sales by customer category 2001 – 2008

Number of customers in each category 2001 – 2008

This data is represented in the graphs and tables shown below. Figure 1.1 shows the generation

and sales data for the period 1984 – 2008. The widening gap between generation and sales can

be seen occurring from about 1998.

100

200

300

400

500

600

84 86 88 90 92 94 96 98 00 02 04 06 08

GENERATION SALES

GEC/GPL ANNUAL GENERATION AND SALES 1984-2008

GW

H

Figure 2.1

0

50

100

150

200

250

10

20

30

40

50

84 86 88 90 92 94 96 98 00 02 04 06 08

LOSSES PERCENT

ACTUAL AND PERCENTAGE LOSSES (1984-2008)

GW

h

Figure 2.2

Pe

r Ce

nt



Table 2.1 shows the number of customers per tariff category for the years 2001 to 2008. There

has been an 18% increase in the residential customers over the period, however in the

commercial category customers have decreased then increased again to almost the 2001 figure.

There has been a 56% overall increase in the number of customers in the industrial category

(small and large and street lighting) during the period.

Year Number of Customers

Total Residential Commercial Industrial*

2001 110,366 11,506 386 122,258

2002 114,831 11,247 343 126,421

2003 114,014 10,869 341 125,224

2004 115,611 10,863 384 126,858

2005 116,039 10,628 409 127,076

2006 118,082 11,357 449 129,888

2007 125,805 11,344 572 137,721

2008 130,399 11,439 601 142,439

Table 2.1 - Number of Customers per Category 2001-2008

* Small and Large Industrial and Street Lighting

Annual sales increased from 287 GWh in 2001 to 356 GWh in 2008, an increase of 23.6 percent.

The annual sales per tariff category and the total monthly sales were used to provide the data for

monthly sales per tariff category that is shown in Figure 1.2 above which shows the ‘losses’ to be

the largest category.

0

10

20

30

40

50

00 01 02 03 04 05 06 07 08

ResidentialCommercialSmall IndustrialLarge IndustrialStreet LightingLosses

MONTHLY SALES AND LOSSES 2000-2008

Figure 2.3

MW

h



2.2.2 The Guyana Economy

It was necessary to determine what factors of the Guyana economy had a strong correlation with

electricity generation and sales and therefore all available economic data was collected. The

economic data collected from the Bank of Guyana, the Statistical Bureau and the IMF was as

follows:

Annual GDP at current factor cost from 1960 – 2008

Annual Exchange Rates from 1970 – 2008

Population data from 1980 to 2008 and projections to 2025

Per Capita GDP in US$ from 1980 - 2008

GDP projected growth rates from 2009 to 2014 by the IMF

Details of all the above-mentioned data are in appendix I.

As population data and GPL generation and sales data were available from 1980/1, it was

decided to analyse the performance of the power utility and the economy from the period

commencing 1980 to the present.

The Guyana economy had traditionally been driven by the production of sugar and bauxite. The

period of the 1980s was characterized mostly by negative growth rates of the GDP. This period

was also the time of frequent load shedding, minimal growth in the electricity generation and

sales and a decreasing population. The decade of the 90s showed sustained GDP growth and this

was the time when there began to be more stability in the power system which continued into the

new millennium. The figure below shows the contribution of the various sectors to the GDP

over the last five years. The production and manufacturing sectors continue to decline while the

services sector is rising. It should be noted that for sustained economic growth the production

and manufacturing sectors must again contribute strongly to the economy.

Figure 2.4: Sectoral Composition of GDP 2004-2008



Following its 2009 Article IV Consultation with Guyana on February 27, 2009, the IMF reported

that despite external shocks and social pressures in Guyana that macroeconomic stability had

been preserved. It observed that there should be higher growth in 2009 with a recovery of the

sugar production and lower oil import prices. However, the document opined that Guyana faces

other significant challenges including lower worker remittances and preferential sugar export

prices in the year ahead. In spite of these however, the IMF has predicted that a positive growth

will continue over the next five years peaking at 5.8% in 2011 and then dropping off to 3.8% in

2014. Figure 1.4 shows actual and projected growth rates of GDP for the period 2004 to 2014.

These growth rates were utilized in this study.

Figure 2.5: Actual and Projected Growth rates 2004-2014

(Source: IMF Country Projections)

As there had been a high devaluation of the Guyana dollar during this period it was decided to

use GDP in US$M rather than the Guyana dollar value. The graph below shows an increase by a

factor of 1000 in G$GDP as opposed to a 100% increase in the US$ value during that period.

0

50,000

100,000

150,000

200,000

200

400

600

800

1,000

1985 1990 1995 2000 2005

GDP G$M GDP US$M

GDP in G$ and US$ 1981-2008

G$

00

0U

S$

00

0

Figure 2.6



It was decided to use population as another dependent variable even though the population

figures showed sharp declines in 1991 and 2000. The data on projected population was

presented as low, medium and high scenarios and the high scenario was used. Population

therefore represented the second variable and this improved the correlation factor of the load

forecast. Figure 1.6 shows the historical and projected population data for Guyana.

700

720

740

760

780

800

820

840

85 90 95 00 05 10 15 20 25

HISTORICAL & PROJECTED POPULATION 1980-2025

Figure 2.7

000s

In order to determine the long term forecast it was necessary to assess what factors could

influence the economy and thereby influence the electricity forecasts.

The first consideration would be the installation of the Amaila Falls hydropower station.

This, together with GPL’s plans to invest in its transmission and distribution

infrastructure should provide a cheaper and more stable power supply with high

reliability and power quality. This would therefore encourage more investment in the

country.

The second consideration would be the President’s Low Carbon Development Strategy

which has as its objective the ‘Transforming of Guyana’s Economy while Combating

Climate Change.’ This initiative recognizes that Guyana’s most valuable asset, its 15

million hectares of timber forest which is suitable for timber extraction and also post

harvest agriculture as well as having significant amounts of mineral deposits below the

surface, has an economical value to the nation estimated to be the equivalent of annuity

payments of US$580 million. However, if it is developed in the traditional manner, this

deforestation would have significant negative consequences to the world as it would

reduce the critical environmental services that Guyana provides to the world in the form

of bio-diversity, water regulation and carbon sequestration. It is projected that the success

of this initiative could bring Guyana’s GDP growth rates in line with many of the other

more successful Latin American nations.



The Guyana Geology and Mines Commission has indicated that there will be a few

companies continuing their investigations for oil in Guyana in commercial quantities.

This could be another landmark change for the Guyana economy.

With these projects in mind, the long term forecast study has considered GDP growth rates of

3.5%, 5% and 7 %.

2.2.2 GPL Forecast Results

The first forecast model used was the econometrics model using the multiple regression analysis

with generation/sales as the independent variable and GDP in US dollars and population as the

dependent variables. The formula for this model is

yt = xtxtt

where y = sales or generation

xGDP in US$M

x = population

t = time intervals in months or years

and and are the constants of the regression equation and is the error of the regression

equation.

The series from 1981 to 2008 represented only 28 points. The GDP data that was utilized in the

forecast were the IMF projected GDP growth rates up to 2014 and then an annual GDP growth

rate of 3.5 %. The exchange rate was deemed constant at the present value. It became evident

that sales rather than generation had a higher correlation factor however probably because of

insufficient data series the sales forecast was deemed to be too high.

It was then decided to use a trend analysis because nine years of monthly sales data (108 points)

per tariff category was available but there was no corresponding monthly or quarterly economic

data. A dynamic forecast method was utilized using forecast values of lagged dependent

variables rather than the actual values of the lagged dependent variables. The model utilized is

the simple regression equation

yt = xtt

and for the lagged forecast model

yt = xt (for t=1), and,

yt (t) = xt - xt-1 + yt-1 (for t>1) where y = sales

x = time intervals

and are the constants of the regression equation and is the error calculated by the

software.



This model was used to forecast on a monthly basis each tariff category individually and also

total sales and generation. The monthly forecasts were then added to give the annual load

forecast.

The results of the medium term forecast using the trend analysis is shown in the Table 2.2 below.

Forecast Generation and Sales (GWh) Growth

Rates

Tariff Category 2008 2009 2010 2011 2012 2013 2014 %

Residential 160.36 160.98 164.22 168.15 172.07 176.00 179.93 12.1

Commercial 64.50 68.26 70.33 72.30 74.28 76.26 78.23 21.8

Small Industrial 31.33 31.19 31.24 31.59 31.95 32.31 32.67 4.2

Large Industrial 93.19 93.28 93.08 95.66 98.64 101.68 104.73 12.4

Street Lighting 6.27 7.17 8.01 8.87 9.75 10.64 11.53 83.7

Total Sales 355.55 360.89 366.87 376.57 386.69 396.88 407.09 14.4

Losses 185.03 178.73 179.79 178.75 177.32 175.82 174.31

Losses % 34.20 33.12 32.89 32.19 31.44 30.70 29.98

Station Use 25.06 28.40 28.77 29.23 29.68 30.14 30.60

Generation 565.98 568.03 575.43 584.55 593.70 602.85 612.00 7.9

Table 2.2: Medium Term Forecast Using Trend Analysis

The forecast developed by the Trend forecast method assumes that in the medium term there will

be no significant change in trend that has been observed over the past few years. This is

acceptable because although a three year timeline is being quoted, it is not expected that the

Amaila hydropower project would become fully operational in the medium term.

GPL has indicated that there are two major activities that will assist in its loss reduction

measures. These are

Installation of 2400 Itron meters for its maximum demand customers which will

eliminate any tampering

The use of twelve ‘Bird Dog’ mobile meter testers that will be able to accurately

determine any defective meters. Emphasis will be placed on the consumers’ meters that

are showing consumption at or below 49 kWh.

These two initiatives should result in increased sales as a result of loss reduction measures and

therefore the sales forecast using the trend method has been increased annually by a further 1%

decrease in losses. The table below compares the results of the medium term sales forecast for

the various methods including the GPL forecast. The sales forecast that is being recommended

for the medium term is the trend forecast adjusted to cater for loss reduction measures resulting

in increased sales. It is to be noted that the generation forecast produced by the model will

remain the same.



Forecast Method Sales Forecast (GWh)

2008 2009 2010 2011 2012 2013 2014

GPL Forecast 355.58 389.56 426.45 447.72 515.26 659.93 N.A.

Econometrics 390.66 397.29 407.27 428.18 445.46 463.03 478.61

Trend 355.88 360.89 366.87 376.57 386.69 396.88 407.09

Trend (Adjusted for L.R) 355.88 366.95 377.19 388.72 400.44 412.35 424.24

Table 2.3: Comparison of Load Forecast using Different Methods

The long term forecast used the results of the original medium term forecast for sales developed

by the trend analysis as additional historical data. This model showed an increased correlation

between sales, GDP and population. Additionally, GDP growth rates from 2014 were

determined at 3.5%, 5% and 7%.

The results of the various long term forecasts are shown in Table 2.4 and Figure 2.8 below.

Forecast Sales Forecast (GWh)

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Trend 407.1 417.3 427.5 437.7 447.9 458.2 468.4 478.6 488.8 499.0 509.2 519.4

Econometrics (3.5%) 426.5 437.3 448.8 460.6 472.8 485.4 498.3 512.5 527.1 542.1 557.7 573.7

Econometrics (5%) 424.7 442.0 460.9 480.8 501.9 524.2 547.7 573.8 601.3 630.3 660.8 692.9

Econometrics (7%) 424.7 450.4 478.6 509.0 541.8 577.0 614.9 656.9 702.0 750.4 802.3 857.9

Table 2.4: Long Term Forecasts Using several GDP Growth Rates and Trend Analysis

400

500

600

700

800

900

14 15 16 17 18 19 20 21 22 23 24 25

Trend Econometrics-3.5%

Econometrics-5% Econometrics-7%

SALES FORECASTS 2014 - 2025

GW

h

Figure 2.8

The sales forecast determined by 5% annual GDP growth rate in the long term is being

designated the Medium Forecast. The other two forecasts are the Low Forecast (3.5% annual

GDP growth rate) and the High Forecast (7% annual GDP growth rate). The Long Term

Medium Generation and Sales forecast is shown in Table 2.5 below.



Energy Balance Long Term Medium Generation and Sales Forecast (GWh)

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Sales 424.2 442.0 460.9 480.8 501.9 524.2 547.7 573.8 601.3 630.3 660.8 692.9

Losses 157.2 155.3 153.6 151.8 149.9 147.8 145.6 143.5 141.1 129.1 125.9 122.3

Losses % 27.0 26.0 25.0 24.0 23.0 22.0 21.0 20.0 19.0 17.0 16.0 15.0

Net Generation 581.4 597.3 614.5 632.7 651.8 672.0 693.3 717.3 742.4 759.4 786.7 815.2

Station Use 30.6 15.3 15.8 16.2 16.7 17.2 17.8 18.4 19.0 19.5 20.2 20.9

Gross Generation 612.0 612.6 630.3 648.9 668.5 689.3 711.1 735.7 761.4 778.9 806.8 836.1

Table 2.5: Long Term Medium Forecast of Generation and Sales

Figure 2.9 shows GPL generation forecasts for all three scenarios.

2.2.4 Self Generators

Data on self generators was received from the following three sources:

A list from GPL indicating the date of disconnection, and the demand and energy

consumption over the last 12 months of utilization of the GPL supply – Self Generators I.

A list of current persons/companies indicating their installed generating capacity,

monthly energy generation and an indication that these generators were their main source

of electrical power – Self Generators II. This information has been supplied in response

to an advertisement placed in the national newspapers by the Office of the Prime

Minister.

Initial results of a survey of self generators being carried out for this study – Self

Generators III.

It is to be noted that each list is exclusive and that each person or company only appears on one

list.



Self Generators - List I

A list of 35 persons/companies who had terminated their services with the company during the

period 2002 to 2008 and were known to be still in business was provided by GPL. The GPL List

(See Appendix I-1) shows that the company had lost a demand of nearly 5.6 MW and energy

sales of 14.4 GWh.

Self Generators - List II

This second list comprises of persons/companies who had responded to the OPM request for data

on installed generating capacity and utilization. Of the nearly 500 responses, 57 had indicated

that they used their generators as their main electricity supplier. Of these 57 responses, 41 had

an installed generating capacity over 10 kVA. The estimated maximum demand and energy of

this group has been calculated at 40% of installed capacity and a load factor of 0.24 respectively.

This gives a maximum demand of 8.3 MW and energy consumption of 17.8 GWh. Appendix I-2

gives this list of self generators by their type of business, installed capacity, and estimated

maximum demand and energy consumption.

Self Generators III

A survey form (See Appendix I-3) has been designed to determine not only the demand and

electrical energy generation of the self generators but the conditions under which they would re-

apply for electricity from GPL. There have only been a few respondents to date, however, these

have been from some of the major self generators. This data shows five companies with an

installed capacity of nearly 20 MW, maximum demand of 8.75 MW, and annual energy

consumption in excess of 32 GWh. More companies have been targeted for the survey which

would be ongoing over the next three months. The present data from this survey is shown in

Appendix I-4.

Table 2.6 shows the summary of these lists and estimates of the 2008 demand and energy

consumption of self generators.

Self

Generators

Installed

Capacity

(kW)

Maximum

Demand

(kW)

Annual

Consumption

(kWh)

List 1 14,038 5,615 14,444,894

List 2 20,838 8,335 17,815,616

List 3 19,893 8,750 34,051,688

Total 54,769 22,700 66,312,198

Table 2.6: Estimates of Demand and Energy of Self Generators

Although the 93 companies in the above mentioned table do not represent the total number of

self generators, due to the fact that the major industries have been captured, the above estimate of

66.3 GWh of energy consumption would be used as the estimate of self generation for 2008.

Because of the present global economic climate, a nominal annual increase of 2% would be used

for the medium term load forecast and continued through the long term.



2.3 The Sugar Sector

The sugar industry has been one of the pillars of the Guyana economy over the years but in

recent times has been facing difficult circumstances. Although Government-owned, the Guyana

Sugar Corporation (Guysuco), operates as an independent commercial organization whose policy

is determined by the Board of Directors appointed by the Minister of Agriculture. The

corporation operates five sugar estates and eight factories all sited along the coast, four in the

Demerara region and four in the east of the country on the banks of the of the Berbice and

Corentyne Rivers.

The eight factories are situated on the narrow, fertile coastal strip which lies between the Atlantic

Ocean and the rain forest and the savannah of the interior. The area is low-lying and is protected

from the ocean by a sea wall. Drainage is by a complex system of canals, sluices and pumps,

which is essential to ensure effective cultivation. Guyana is unique in having most of its sugar

cane transported on water ways rather than by road or rail.

In 2004 an Agriculture Improvement Plan (AIP) was introduced to boost the sugar cane

production. In addition, the decision taken in 2001 to embark on the Skeldon Sugar

Modernization Project was aimed at reducing the production costs. The reduction in production

costs should be achieved with the introduction of state of the art processing technology, and

increases in production and mechanization of the field operations. The project also included the

provision of the facilities to supply power to the national grid.

2.3.1 Historical Data

The generating capacity, installed capacity, monthly electricity demand and production, and

sugar cane production data have been provided by Guysuco for each of the estates for the period

January 2004 and to June 2009. The new Skeldon estate should have been operational in 2008

but experienced commissioning delays. This estate has a generating facility consisting of 30

MW and 10 MW of steam and diesel generators respectively. This has increased the installed

capacity of Guysuco to 55.5 MW of steam and 20.5 MW of diesel generation. Generating

capacity at the eight estates vary from 3 MW to 8.5 MW. Excluding Skeldon II, the estates have

a total maximum demand of around 16 MW and off grinding demand of 5.7 MW. Table 1.7

gives the details of the installed capacity and demands of the Guysuco estates.

Estate

Installed Capacity

(MW) Demand (MW)

Steam Diesel Max. Min.

Albion 5.72 2.75 3.5 2.0

Blairmont 2.0 0.96 1.8 0.55

Enmore 3.5 1.51 2.0 0.8

LBI 3.5 0.85 2.0 0.5

Rose Hall 3.05 1.26 1.8 0.4

Skeldon I 1.72 1.3 1.5* 0.8*

Skeldon II 30.0 10.0 N.A. N.A

Uitvlugt 3.5 0.95 1.65 0.35

Wales 2.5 0.95 1.6 0.3

Total 55.49 20.53 15.85 5.7

Table 2.7 Guysuco Electrical Power System Data (*) – estimated



Table 2.8 outlines the data for sugar cane production and electricity generation for the period

2004 – 2008.

Year

Electricity

Production

(MWh)

Sugar Cane

Production

(tons)

2004 68005 1,356,470

2005 54188 1,131,461

2006 61984 1,113,225

2007 64541 1,126,907

2008 58360 1,035,775

Table 2.8 Guysuco Annual Electricity and Sugar Cane Production

The monthly variation of sugar production and electricity generation is shown in Figure 2.10

below.

0

50,000

100,000

150,000

200,000

250,000

0

2,000

4,000

6,000

8,000

10,000

2004 2005 2006 2007 2008

GENERATION PRODUCTION

GUYSUCO MONTHLY GENERATION AND PRODUCTION

JAN 2004 - MAY 2009

TO

NS

MW

H

Figure 2.10

An analysis of the data shows the following

Sugar cane production at Guysuco has declined by nearly 24% since 2004.

Electricity generation declined by nearly 19% during the same period

In 2004 70.8% of the electricity was produced by the steam generators using bagasse but

this had declined to 61.5% in 2008.

The number of tons of sugar cane processed per kWh of electricity generated had also

declined by 11%.

2.3.2 Guysuco Load Forecasts

Guysuco was reluctant to give production forecasts however based on the information researched

about the new Skeldon estate the following assumptions were made for the medium and long

term Guysuco load forecast:



The old estate, Skeldon I, will no longer be in operation.

The new estate, Skeldon II, will be processing 400,000 tons of sugar cane in 2009 and

increasing by the 200,000 tons each year until it reaches its maximum capability of

1,200,000 tons in 2013.

The energy generated to process each ton of sugar by the new estate is 20% less than the

average for the other estates combined.

The other estates will improve their 2008 performance and will reach the 2004 levels in

2014.

The long term forecast will be kept constant at the 2014 levels

The above assumptions were used to produce the medium term forecast shown in Table 2.9

below.

Year

Electricity

Production

(MWh)

Sugar Cane

Production

(tons)

2009 68740 1,300,000

2010 77775 1,500,000

2011 92404 1,800,000

2012 101420 2,000,000

2013 110434 2,200,000

2014 121723 2,400,000

Table 2.9: Forecast of Guysuco Annual Electricity and Sugar Cane Production

The success of the Skeldon II estate is based on the ability of Guysuco to access the necessary

quantities of sugar cane. Therefore the above forecast can be adjusted in the future based on the

success made in this area. Also the actual efficiency of estate in terms of the processed tons of

sugar cane per kWh of electricity generated (minus sales to GPL) can be determined when the

estate achieves normal operation. These two sets of information will lead to a more accurate

forecast being produced.

2.4 The Mining Sector

The mining industry, like the sugar industry had been the other pillar of the Guyana economy,

and like the sugar industry has had a decreasing contribution to the GDP in recent years. Mining

in Guyana has consisted mainly of bauxite, alumina, gold and diamond products. This analysis

deals with mining in three groups, namely,

Small gold miners whose individual energy requirement is less than1 kW

Medium sized gold and diamond companies whose individual energy requirement is in

the kW range

Large bauxite and gold companies utilizing energy in the MW range



Information received from the Guyana Geology and Mines Commission stated that mining takes

place in four regions of Guyana, namely, Regions 1, 6, 7 and 8 and in six mining districts, that is,

Berbice, Potaro, Mazaruni, Cuyuni, Rupununi and the North West Districts.

2.4.1 Small Scale Gold Miners

The Geology and Mines Commission has given the following data on the number of grants that

have been given to small gold miners over the last five years.

Year 2004 2005 2006 2007 2008

Number of Grants 9,152 10,260 9,408 10,563 12,582

Table 2.10: Grants given out to Individual Gold Miners 2004-2008

These small miners, though sizable in number, are widely dispersed throughout the country in

somewhat rough terrain and it is unlikely that they can be considered as prospective users of a

national electricity power grid even in the long term.

2.4.2 Medium Sized Mining Companies

The number of grants issued to medium sized mining companies decreased from 1077 to 856

during the five year period 2004 to 2008. The information received is insufficient to allocate any

electricity demand to this group of miners. It is also unlikely that it would be economical to

connect this group to a national power grid.

2.4.3 Large Mining Companies

GGMC provided a list of thirty two companies that it considered as ‘large’ mining companies.

Information was sought from the three bauxite mining companies, namely, Bosai, Rusal and

Kwakwani. However, only Bosai responded and the information given was very limited. The

Bosai Minerals Group now operates the bauxite company at Linden. In response to a

questionnaire, it indicated that it had an installed capacity of 22.5 MW. Other information

provided by the company is shown below.

Year Maximum

Demand (MW)

Electricity

Generation

(MWh)

Total Bauxite

Production – All

Products

(tonnes)

Sales to Linden

Elect. Co. (MWh)

2004 N/A N/A N/A N/A

2005 Start up

May 2005 12 40,500 249,000 N/A

2006 10 67,500 196,000 N/A

2007 11 71,500 354,000 N/A

2008 11 73,000 466,000 N/A

Table 2.11: Bosai Minerals Group Electricity Demand and Generation and Mineral Production



Mineral production has been increasing over the years and utilizing the information provided by

the Linden Electricity Coop Inc. which purchases power from the Bosai minerals Group, it can

be estimated that the 2008 demand and energy requirements of the company is in the region of 4

MW and 30,000 MWh. Bosai was also asked directly whether its future plans were connected to

the Amaila Falls hydropower project and its response was that they were not at the present

moment. In the absence of any definitive information on which to base a load forecast an

assumption of a continuing 5% growth over the study period would be used.

There is no other information available from the mining sector, however, continued efforts

would be made to obtain information from these bauxite and other large gold mining companies

to obtain more data for the forecast and to determine if any of them represent a sizable load that

can be economically connected to the national grid.

2.4.4 Linden Electricity Coop Inc. (LECI)

The Linden Electricity Coop Inc. is one of four companies that have been granted license to

supply electricity to consumers. LECI buys bulk power from Bosai and sells to consumers in

Mackenzie and also sells bulk power to Linden Utility Services Co-op Society Limited

(LUSCSL) which sells power to consumers in Wismar. It is therefore appropriate to develop a

load forecast for this area in this section. Tables 2.12 to 2.14 gives historical information on

electricity demand, energy purchase and sales, and number of consumers for the period 2004 to

2008 as supplied by LECI.

Year Demand

(MW)

Energy

Purchases

(MWh)

Energy Sales

(MWh)

Losses

(%) Comments

2004 N/A 35,620 25,618 39

2005 7.95 37,071 28,269 31

2006 7.38 43,163 30,179 43 Energy savings bulbs

installed in 2006

2007 7.02 42,746 29,818 43

2008 6.81 42,393 34,619 24

Table 2.12: Electricity Demand, Purchases, Sales and Losses for LECI

Customer

Category

Number of Customers Growth

Rates

(%) 2004 2005 2006 2007 2008

Residential 1966 2085 2187 2394 2588 31.6

Commercial 518 556 590 612 665 28.4

LINMINE

Pensioners 406 365 359 356 338 -17.2

Total 2890 3006 3136 3362 3591 24.2

Table 2.13: Total LECI Customers 2004-2008



Customer

Category

Sales (kWh) Growth

Rates (%) 2004 2005 2006 2007 2008

Residential 6,082,537 6,833,565 6,960,478 6,915,851 7,852,134 29

Commercial 4,022,316 4,498,163 6,108,697 5,268,258 8,267,288 105

LINMINE

Pensioners 1,157,210 1,216,453 1,151,794 1,193,585 1,186,952 3

LUSCSL 14,356,131 15,721,008 15,957,848 16,440,716 16,862,477 17

TOTAL 25,618,194 28,269,189 30,178,817 29,818,410 34,168,851 33

Table 2.14: LECI Electricity Sales 2004 - 2008

An analysis of the data shows the following:

Loss reduction from a high of 43% in 2006/7 to 24% in 2008

Increase number of consumers in all categories except the pensioners

Increase sales in all consumer categories, although there is just a slight increase in the

usage by the pensioners.

A discussion with the officials of the company revealed that much of the increases in number of

customers and sales could be attributed to improved accounting procedures in the company

rather than actual load growth in the area. This and other loss reduction measures would account

for the reduction in losses.

It was also opined that if the consumers were charged the true financial costs of the electricity

then sales would drop appreciably rather than increase. Residential and commercial consumers

are presently paying $5 and $12 respectively for each kWh of electricity used whereas the

financial costs should be in the region of $40 and $70 respectively. In the past the bauxite

company provided electricity to the community at subsidized rates but presently these subsidies

are being provided by the government. It was noted that many consumers use electricity for

cooking but this would change should these costs prove higher than cooking by other means.

Analysis showed that residential customers in Linden have average kWh usage of two and a half

times the average use of the residential customer supplied by GPL.

The assumptions for the load forecast is that in the medium term there will be a reduction in the

load requirements but that when the Amaila hydropower project comes on stream then the

economy of the area would improve resulting in increased power consumption in the community.

The medium and long term forecast for both Bosai and LECI are given in Tables 2.15 and 2.16

shown below.



Table 2.15: Medium Term Load Forecast for the Linden Mining Area

Linden Mining Area Long Term Forecast (MWh)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

BOSAI 42,213 44,324 46,540 48,867 51,310 53,876 56,569 59,398 62,368 65,486 68,761

LECI

Sales 26,372 27,691 29,076 30,529 32,056 33,659 35,342 37,109 38,964 40,912 42,958

Losses 9,355 9,449 9,543 9,638 9,735 9,832 9,931 10,030 10,130 10,231 10,334

Sub-total 35,727 37,140 38,619 40,168 41,791 43,491 45,272 47,138 49,094 51,144 53,292

TOTAL 77,940 81,463 85,158 89,035 93,101 97,367 101,842 106,536 111,462 116,630 122,052

Table 2.16: Long Term Load Forecast for the Linden Mining Area

Linden Mining Area Medium Term Load Forecast (MWh)

2008 2009 2010 2011 2012 2013 2014

BOSAI 30,000 31,500 33,075 34,729 36,465 38,288 40,203

LECI

Sales 34,168 32,460 30,837 29,295 27,830 26,439 25,117

Losses 8,225 8,389 8,557 8,728 8,903 9,081 9,262

Sub-total 42,393 40,849 39,394 38,023 36,733 35,519 34,379

TOTAL 72,393 72,349 72,469 72,752 73,198 73,808 74,582



2.5 Other Sectors

The Guyana Office for Investment (Goinvest) provided their 2007 and 2008 lists of investment

projects in the various sectors of the economy. As both lists showed a similar pattern the

analysis was carried out on the 2008 data. The summary list for 2008 subdivided into the ten

administrative regions and including the total value of the projects is shown in Table 2.17 below.

SUMMARY 2008 INVESTMENT PROJECTS

Sector No of

Projects

Value

G$

'000,000

Regional Distribution of Economic Activities

1 2 3 4 5 6 7 8 9 10

SUMMARY OF PROJECTS 2008

Agro-Processing 70 8,884 5 5 8 33 7 11 1 1 2 7

ICT 15 10,938 2 3 2 12 2 4 2 2 2 3

Light

Manufacturing 23 3,002 - - - 20 - 1 - - - 2

Energy 8 252 1 - - - - 3 - 2 - 2

Mining 10 4,404 3 - - 2 - - 2 - - 2

Services 30 10,116 1 2 5 26 1 4 2 1 3 7

Tourism 26 5,234 - - 4 17 - 3 1 - 1 -

Wood Products 50 10,052 3 1 7 18 1 5 2 - 1 15

Total 232 52,880 15 11 26 128 11 31 10 6 9 38

Percent

5 4 9 45 4 11 4 2 3 13

Table 2.17: 2008 Investment Projects by Region

Table 2.18 below outlines this information in more detail and the following key explains the

various abbreviations

Sector No of

Projects

RO

Source of Investment Status Size of Projects

FDI

JV

OG Local O PL

CL/

NO MI S M L

Agro-Processing

70

29

23

4

12

42

39

30 -

1

43

18

7

ICT

15

10

8

1

5

6

12

2

1 -

10

1

4

Light

Manufacturing

23

8

7

6

8

10

12

11 - -

18

4

1

Energy

8

1

7 -

1

1

1

7 - -

3

2

3

Mining

10

5

4

2

1

2

6

2 - -

5 -

1

Services

30

10

11

1

6

21

25

8 - -

17

9

7

Tourism

26

10

8 -

6

18

15

11 - -

18

6

2

Wood Products

50

18

21

4

7

25

36

14 - -

31

13

6

Total 232

91

89

18

46

125

146

85

1

1

145

53

31

Percent

39

38

8

20

54

63

37 0.4

0.4

63

23

13

Table 2.18: Details of 2008 Investment Projects (See Key below for explanation of the acronyms)



Acronym Meaning

RO Projects rolled over from the previous year

FDI Foreign Direct Investments

JV Joint Venture Investment with local Guyanese

OG Investments by Overseas Guyanese included in

the FDI total

O Operating projects

PL Pipeline projects

CL/NO Projects that are closed or not operating

Key: Explanation of the Acronyms

The three main areas of analysis of these projects were as follows:

the size of the investment, and by extension the possible size of the electrical demand

whether the project is new, the extension of an existing investment or an acquisition

the location of the project and whether it can be deemed to have been covered in the GPL

load forecast or needs to be considered separately

2.5.1 Agro-processing

The investment in agro-processing is mainly in the area of light manufacturing or farming. Of

the 70 projects listed in this sector about 60% are designated ‘small’ and the same percentage is

deemed as ‘new’ investments. None of the seven large projects are new investments but are

either extensions or acquisitions. The majority of the projects are in Demerara with nine projects

being in the hinterland region. These projects may not have been covered in the medium term

forecasts however their electricity usage would also be small. The long term forecast which

foresees a 5% GDP growth rate would cover such projects.

2.5.2 Information and Communications Technology

There are 15 projects in this sector and the largest investments are by the recognized leaders in

the communications industry in Guyana. This sector does not require a separate load forecast for

the medium or long term.

2.5.3 Light Manufacturing

Twenty of the twenty three projects in this sector are in Region 4, two are in Region 10 and one

in Region 6. These light manufacturing projects would have been considered in both load

forecasts.

2.5.4 Energy

The Amaila hydropower project is one of the eight projects listed in the energy sector of which

seven of the projects are new. The value of the investment of many of the projects in this sector

has not been stated pointing to the fact that these are probably now in the pre-feasibility stage. It

is difficult to allocate an electrical energy value to this sector.

2.5.5 Mining

The mining sector has already been investigated in this load forecast and this list, which includes

Bosai’s acquisition of the mining company at Linden, does not give any new information for this

sector.



2.5.6 Services

Twenty six of the thirty projects are in Region 4 and nineteen of these projects are extensions of

existing investments. These investment projects can be considered to have been covered already

covered in both load forecasts.

2.5.7 Tourism

The tourism projects consist of hotels and resorts, seventeen of the twenty six being in Region 4.

There are two large projects, both of which are in Region 4, one being a new project and the

other an acquisition. From the information available, the tourism sector does not provide any

additional input to the load forecast.

2.5.8 Wood Products

This sector has the second largest number of projects (50) and the highest percentage of foreign

direct investments. Fifteen of these projects are in Region 10 and six are considered large

investments. There is not enough information to determine the electricity requirements for these

projects however more information would be sought when the area of Network Issues is being

addressed.

2.6 Hinterland Communities

Although the majority of Guyana’s population lives along the coastland, it is also essential that

the electricity needs of the hinterland regions be assessed as in most cases provision of electricity

leads to improved economic development.

The most recent data collected on the regional population of Guyana was done during the 2002

population survey, the details of which are shown below in Table 2.19.

Region Geographical Area Economic Activity Population

(2002

Census)

1 Barima-Waini Logging, small scale mining 24,275

2 Pomeroon – Supenaam Agriculture 49,253

3 Essequibo Islands, West Demerara Agriculture 103,061

4 Demerara – Mahaica Agriculture and commerce 310,320

5 Mahaica – Berbice Agriculture 52,428

6 East Berbice – Corentyne Agriculture 123,695

7 Cuyuni – Mazaruni Gold mining 17,597

8 Potaro – Siparuni Mining and forestry 10,095

9 Upper Takatu – Upper Essequibo Agriculture, small scale mining 19,387

10 Upper Demerara – Upper Berbice Bauxite mining 41,112

Total 751,223

Table 2.19: 2002 Regional Population Data

Regions 1, 7, 8 and 9 can be considered as the hinterland regions of Guyana, however there are

areas in all of the other regions that can also be considered hinterland. As can be seen in the

above table, the economic activity in the hinterland areas is mainly small scale mining and

forestry. Neither of these activities are energy intensive and so there has been no development of

an electricity supply system. In an attempt to determine a medium and long term forecast for the



hinterland regions an analysis was done of the areas which had some form of electricity supply

and the effects of this on the economy of the region. The pilot projects that have been

established to supply power to other areas in the hinterland were also analysed. The results are

being presented in terms of the type of electricity supply used in the different areas.

2.6.1 Diesel Generators

This still represents the most common form of electricity supply in the hinterland regions.

Service is provided normally in the evenings for six to twelve hours as during the day there is

hardly any load. However, because of this, there has been little economic development in these

areas resulting from the availability of electricity. In most cases the consumers pay a flat rate

and there are no energy meters. There are a few areas where the electricity supply system is self

sustained however, in many instances the cost is being subsidized.

2.6.2 Hydropower

The 500 kW Moco Moco hydropower station in the Lethem area is one of two hydropower

stations that was established in Guyana, the other being at Tumatumari. The Moco Moco station

was commissioned in 1999 but ceased operation in 2003 after the penstock was fractured. This

was one of the more developed power systems in the hinterland as there is a secondary

distribution system to supply the community. The system also provided 24 hour service. Efforts

are being made to have the power station re-commissioned. However at present the area is being

supplied on a part time basis using diesel generators and there is also a plan to utilize an existing

GPL generator to provide 24 hour service.

A pilot study has been carried out and the recommendation has been made for the installation of

a 570 kW mini hydropower station on the Chiung River near Kato in Region 8. It was calculated

that a single turbine operating at a flow rate of 2 m/s would produce an annual output of 3.5

GWh annually. For an estimated construction cost of US$2.5 million it was determined that a

selling price of $G30/kWh would make this project viable. A decision is still to be made on its

implementation.

2.6.3 Individual Solar Units

A pilot project is being carried out in four hinterland communities where individual 125W solar

units have been installed on 336 homes at a cost of G$300,000 each. Home owners have been

asked to pay G$500 a month into a fund for the cost of maintenance and it is estimated that 80%

of the homeowners have been doing so. This amount would be increased by G$100 every two

years. On average each householder has 2, 15W compact fluorescent bulbs, a radio and a CD

player. Although there has not been any formal study of the success of the project, informal

reports are that although the provision of electricity is helpful for evening activities such as

studying, etc., there has not been any substantial economic development as a result of the

provision of electricity.

2.6.4 Wind

Wind data has been collected in four hinterland areas however initial analysis shows that wind

energy may not be an alternative source in these regions as the average wind speeds appear to be

below the normal cut-in speed of wind turbines.



2.6.5 Hinterland Communities Forecast

The list below, though not exhaustive, shows the main communities that are now being supplied

with electricity by diesel or solar power. Estimates have been made of the annual energy

generation where sufficient data is available to make such estimates.

Table 2.20: Data collected and estimated about energy consumption in the Hinterland Regions

The generation technology that would be most economical to develop the hinterland regions of

Guyana has not been determined. However, every effort is being made to supply electricity to

these communities. Growth rates would be slow unless there is some form of major economic

activity in these communities. Using the estimated energy consumption determined above a 5%

growth rate has been used to determine the medium and long term load forecasts for the

hinterland communities. This is shown in the total Guyana load forecasts in the following

section.

No. Location Region

Installed

Capacity

(kW)

Type of

Generation

Annual

Energy

Generation

(kWh)

Comments

1 Ituni 10 576 Diesel 600,480 Power supplied only in evenings

2 Muritario 10 - Solar 8,147 Individual 125 W solar panels

3 Capoey 2 - Solar 8,804 Individual 125 W solar panels

4 Kurukubaru 8 - Solar 13,403 Individual 125 W solar panels

5 Yarrakita 1 - Solar 13,797 Individual 125 W solar panels

6 Orealla 6 75 Diesel 131,400 Wind data being collected

7 Jawalla 7 -

- Wind data being collected

8 Yupukari 9 -


9 Campbellton 8 -


10 Mabaruma 1 625 Diesel -

11 Port Kaituma 7 N.A. Diesel N.A.

12 Lethem 9 625 Diesel/hydropower 1,095,000

13 Siparita 6 35 Diesel 76,650

14 St. Cuthbert's 5 90 Diesel 197,100

15 Muraikobai 50 Diesel 109,500

16 Mahdia 8 N.A. Diesel N.A.

17 Kato 8

Mini hydro

Feasibility stage

Total 2,254,280



2.7 Guyana Medium and Long Term Energy Forecast

2.7.1 Medium Term Forecasts for all Sectors

The medium term electricity forecast shown in Table 2.21 below shows the results of the forecast

for the various sectors for which information has been made available for such forecast to be

made. The sub-total represents load that would be connected to the Amaila hydropower plant.

SECTOR

GUYANA MEDIUM TERM ENERGY FORECAST

GWH

2008 2009 2010 2011 2012 2013 2014

GPL 567 568 575 585 594 603 612

SELF GENERATORS 67 68 69 70 72 73 75

BOSAI MINING 30 32 33 35 36 38 40

LECI* 42 41 39 38 37 36 34

SUB-TOTAL 706 709 716 728 739 750 761

GUYSUCO 58 69 78 92 101 110 121

OTHER MINING N.A. N.A. N.A. N.A. N.A. N.A. N.A.

OTHER SECTORS - - - - - - -

HINTERLAND 3 3 3 3 4 4 4

TOTAL 767 781 797 823 844 864 886

Table 2.21: Medium Term Forecast for the Various Sectors in Guyana

* Linden Electricity Coop Inc.

The average annual growth rate for the medium term forecast is 2.6%.



2.7.2 Long Term Energy Forecast for all Sectors

The long term low, medium and high forecasts are shown in Tables 2.22, 2.23 and 2.24 below.

This forecast should be updated as more information is received.

TOTAL GUYANA LONG TERM LOW ENERGY FORECAST

SECTOR

GWH

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 606 614 622 630 638 647 657 667 670 681 692

SELF

GENERATORS 76 78 79 81 82 84 86 87 89 91 93

BOSAI MINING 42 44 47 49 51 54 57 59 62 65 69

LECI* 36 37 39 40 42 43 45 47 49 51 53

SUB-TOTAL 760 773 786 800 814 828 845 861 871 889 907

GUYSUCO 121 121 121 121 121 121 121 121 121 121 121

OTHER MINING N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A.

OTHER SECTORS

HINTERLAND 4 4 5 5 5 5 6 6 6 7 7

TOTAL 885 898 912 926 940 955 971 988 998 1016 1035

Table 2.22: Long Term ‘Low’ Forecast for the Various Sectors in Guyana


The average annual growth rate for the long term ‘Low’ forecast is 2.8%.



SECTOR

GUYANA LONG TERM MEDIUM ENERGY FORECAST

(GWH)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 613 630 649 669 689 711 736 761 779 807 836

SELF GENERATORS 76 78 79 81 82 84 86 87 89 91 93

BOSAI MINING 42 44 47 49 51 54 57 59 62 65 69

LECI* 36 37 39 40 42 43 45 47 49 51 53

SUB-TOTAL 767 789 814 839 864 892 924 954 979 1014 1051

GUYSUCO 121 121 121 121 121 121 121 121 121 121 121


OTHER SECTORS - - - - - - - - - - -

HINTERLAND 4 4 5 5 5 5 6 6 6 7 7

TOTAL 892 915 940 965 990 1018 1051 1081 1106 1142 1179

Table 2.23: Long Term ‘Medium’ Energy Forecast for the Various Sectors in Guyana


The average annual growth rate for the long term ‘Medium’ forecast is 5.5%.



TOTAL GUYANA LONG TERM ‘HIGH’ ENERGY FORECAST

SECTOR

GWH

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 624 655 687 722 759 798 842 889 927 980 1035

SELF

GENERATORS 76 78 79 81 82 84 86 87 89 91 93

BOSAI MINING 42 44 47 49 51 54 57 59 62 65 69

LECI* 36 37 39 40 42 43 45 47 49 51 53

SUB-TOTAL 778 814 851 891 934 980 1030 1083 1128 1187 1250

GUYSUCO 121 121 121 121 121 121 121 121 121 121 121


OTHER SECTORS

HINTERLAND 4 4 5 5 5 5 6 6 6 7 7

TOTAL 904 939 977 1017 1060 1106 1156 1210 1255 1315 1378

Table 2.24: Long Term ‘High’ Energy Forecast for the Various Sectors in Guyana


The average annual growth rate for the long term ‘High’ forecast is 9.25%.



Figures 2.11 and 2.12 show the three types of long term forecasts for National Grid (GPL and

Linden) and the entire Guyana respectively.



2.8 Issues and Options

Load forecasting is important to power companies because it is the basis for the planning of

generation, transmission and distribution systems. The load forecast method that is utilized is

also important because the results of the forecast need to represent as closely as possible what

will pertain in the future. It is therefore essential that all the data that could assist in the

forecasting be collected and that the forecast be regularly updated as more accurate information

becomes available.

The following issues are pertinent to this area of the study

The agency that would be responsible for the development of national load forecasts for

Guyana.

The agency(s) that would be responsible for provision of the necessary data.

There are several options available for national load forecasting. One agency can be responsible

for its development, or, each sector can develop its own load forecast and an agency can be

responsible for reviewing them and bringing these load forecasts together into a national load

forecast. Ideally, the expertise for load forecasting should be with the power utility, but GPL

may not be willing to be tasked with responsibility for doing the national load forecast.

Therefore another option would be for GPL to do the forecast for its own area and another

agency can be responsible for doing the forecast for the other sectors and bringing all the

forecasts together. Yet another option for the future is that in the event that a national grid is

developed, a new agency could be formed with the responsibility for the operation of the

transmission systems, then, that agency could be charged with the responsibility for the

development of the national load forecast.

The option that would be recommended for the present is that GPL would be tasked with

formulating its own forecast and that another agency, perhaps the Guyana Energy Agency can be

responsible for the forecasts for the other sectors and bringing them together with the GPL

forecast for a national load forecast. Therefore the forecasting expertise would lie with both

GPL and GEA and there can be collaboration in the load forecasting.

It would be necessary for there to be training of personnel in the various load forecasting theories

and methods and in the decision making process for the right methods to be adopted. It is

essential that proper load forecasting methods be adopted and the load forecasts do not just

represent estimates based on recent trends.

The agencies that should be providing the data for the load forecast are GPL, the Statistical

Bureau, the Bank of Guyana, Goinvest and the various sectors in the country. These agencies

must be clear on what data needs to be provided, the format in which it should be presented and

what systems should be put in place for them to be able to provide the required data. It would

also be necessary for investment projects to include data on their electricity energy requirements,

and since most projects are presently requesting a diesel generator either as standby or as their

main supply, then the electricity requirements for most projects are known.



It is also essential that the data provided by the load forecast be considered in decision making

for investment. If the load forecasts are not deemed as important then the effort would not be

made to develop good forecasts for the country.

Chapter 3 GENERATION TECHNOLOGY

CHAPTER 3 GENERATION TECHNOLOGY


3.0 GENERATION TECHNOLOGY

3.1 Introduction

This section on generation technology seeks to determine the types of energy sources that

should be utilized in Guyana in the medium and long term for the production of

electricity.

For the medium term, fuel oil and wind technologies appear to be the natural choice for

additional generation because this is required almost immediately. Both have short lead

times and are relatively inexpensive. An analysis of the two technologies is made and a

recommendation given. The role of wind technology in Guyana’s long term development

is also discussed.

The extensive hydropower potential in Guyana makes it important that this resource be

harnessed and developed. The results of the 1976 Hydroelectric Power Survey of

Guyana by Monenco Engineering Company Limited are used to make recommendations

for Guyana’s future hydroelectric power development.

Biomass is a renewable energy source which Guyana is seeking to include in its energy

supply chain. Bagasse has already begun to make a contribution to the generation mix

with the commission of the Skeldon cogeneration project. Similar projects and other use

of biomass energy particular for the hinterland communities is being recommended.

The principles and modalities of the Clean Development Mechanism, one of three

flexible mechanisms under the Kyoto Protocol that was created by the United Nations

Framework Convention on Climate Change, are investigated to determine the potential

benefits to Guyana for both small and large energy projects.

Finally, it is recommended that, because of the abundance of both mini and micro

hydroelectric resources in Guyana’s hinterland, efforts should be made to develop these

facilities to enhance economic development for the hinterland communities.



3.2 Fuel Oil

Guyana is almost totally dependent on its imports of fuel oil for electricity generation as

shown by Table 3.1 which gives the type of installed generating capacity of the various

sectors.

Sector Installed Capacity (MW)

Diesel Bagasse Hydro

GPL 151.5

Mining Industry

63.0

Sugar Industry 20.5 55.5

Self Generators1 55.0

Standby Generators 35.0

Hinterland 3.0 0.5

Total 328.0 55.5 0.5

Table 3.1: Installed Capacity of Generating Sets in Guyana

1 Estimated

With the addition of the 30 MW bagasse-fired steam sets at Guysuco’s Skeldon estate in

2009, bagasse now represents 14.5 % of the installed capacity of Guyana. However, only

5% of the total energy generation in 2008 was produced by bagasse.

Guyana cannot immediately reduce its dependence on imported fossil fuels, however,

there needs to be a plan to gradually reduce this dependency. As Chapter 4 on Primary

Energy shows, although the existing generation can meet the energy needs of GPL’s

system, the firm capacity, that is, the available capacity minus the two largest sets, will

not provide the required reliability demanded by its licence and especially at a time when

GPL is trying to win back customers that are generating their own electricity. An

addition of 10 to 15 MW of generating capacity will provide that security. The merits

and demerits of diesel engines and wind technologies to meet this immediate need would

be considered in Section 3.8.1.

If diesel generation from fuel oil rather than wind energy is chosen, then the size of diesel

sets that would provide the best efficiency should be purchased. A previous study had

indicated that 13 MW sets provided the least cost generation alternative for the GPL

system, however, in view of the fact that 6.9 MW sets have recently been purchased then

GPL will probably find it economical to purchase two sets of the similar size to those at

the new Kingston power station as this would standardise stock items for maintenance.

The role of fuel oil in the longer term will depend on when the first hydropower facility is

brought on stream and whether its development is sustained by timely investments in

future hydropower projects. The feasibility of the conversion of the existing diesel sets to

operate on compressed gas is also being investigated

Guyana is also pursuing its search for oil both on land and offshore and the results of

these searches could determine any future role of fuel oil in the electricity generating

industry.



3.3 Wind

3.3.1 Coastal Wind Development

A wind power feasibility study, sponsored by the Dutch Government with Delta

Caribbean, NEG-Micon and Rheden Steel as co-sponsors, was carried out during 2002/03

for the Guyana government. The major objective of the study was to investigate the

feasibility of installing approximately 10 MW of generating capacity from wind

resources. The other objectives were as follows:

Primary Objectives:

o Implementation of government policy regarding renewable energy resources

o Implementation of new generation capacity to address power outages

o Exploitation of relative cheap energy resources

o Diversification of Guyana’s energy mix

o Utilisation of indigenous (sustainable) energy resources, especially the abundance

of wind along the coast.

Secondary Objectives

o Import reductions (petroleum based) in view of the Balance of Trade and

dependence on fossil fuels.

o (High) technology transfer to Guyana resulting in eventual local expertise and

experience in a large scale wind energy project.

o Greenhouse gas emission reductions

Tertiary Objectives

o Tangible and affirmative action from Guyana as a signatory of the UNFCCC

regarding the reduction of greenhouse gases and a ratification of the Kyoto

Protocol

o Education and research spin-off for the University of Guyana and other

institutions in the country and in the Caribbean.

o Prestigious project for the region and a landmark project for Guyana

o Attractive investment opportunity for Guyanese investors.

Wind speed and other data were collected for the period April 2002 to April 2003. The

summary of the wind speed data measurements are shown in Table 3.2 below.

Wind

Speed

(m/s)

No. of

hours per

year

Wind Speed

(m/s)

No. of hours

per year

1 45 9 1751

2 58 10 973

3 123 11 422

4 181 12 73

5 469 13 8

6 915 14 0

7 1663 15 2

8 2076

Table 3.2 Summary of Wind Speed Measurements at Hope Beach



The analysis of this data gave the following results

o Hourly average wind speeds were between 6.5 and 8.5 m/s

o Wind speeds showed little variation during the day and were the highest in the

evenings

o Wind turbines would only be inoperable for a maximum of 100 hours during the

year due to lack of wind

o Shape factor k = 5.2

o Scale factor c = 8.45

o Wind turbulence was estimated at about 8%

Based on the above, the following project details were developed for a wind turbine at

Hope Beach and a proposed project for the Georgetown Foreshore. As a result of the

project now being undertaken to build a 69 kV line between Sophia and Onverwagt a

short 3km line would now be required to connect the Hope Beach wind turbines to the

national grid. Although no wind speed data had been taken at the Foreshore at that time,

it was felt that the wind speed data would be similar to that of Hope Beach and that the

Foreshore site offered several advantages over the Hope beach site. These were:

o No need for an long transmission line to the load centre (no longer an advantage)

o The site could become a tourist attraction

The other calculated details of the project for the two sites are shown in Table 3.3.

Location Hope Beach Foreshore

Lay Out Straight Line Straight Line

Wind Speed (at hub height) 7.74 m/s 7.74 m/s

Turbine Choice NM54/950 NM82/1650

Generator Size 950 kW 1650 kW

Number of Turbines 12 8

Tower Height 70 m 78 m

Total Size of Wind Farm 11.4 MW 8.25 MW

Estimated Yearly Production 29.2 GWh 26.2 GWh

CO2 Reductions 28.2 tons/annum 25.3 tons/annum

NOx Reductions 134 tons/annum 121 tons/annum

SO2 Reductions 408 tons/annum 367 tons/annum

Avoided Fuel 1.8 million imp. gals 1.6 million imp gals

Total Investment Costs US$13.7 million US$ 12.3 million

Table 3.3: Data on Proposed Wind Farms

GPL signed a Memorandum of Understanding with Delta Caribbean in March 2007 for

the development of this project and negotiations have been ongoing for agreement on the

cost per kWh, however, since this proposal was submitted wind turbine costs have

increased due to increased commodity prices and high demand. Additionally, stability

studies, related to the integration of the wind farm with GPL’s power system, are also

being carried out. The agreement for the construction of the wind turbine project has not

yet been reached. This project should be able to be registered as a Clean Development

Mechanism project whose modalities are discussed later in this chapter.



3.3.2 Hinterland Wind Development

Anemometers were installed at four hinterland locations, namely, Orealla, Jawalla,

Campbellton and Yupukari regions 6, 7, 8 and 9 respectively during the period June 2008

to May 2009. A final year student in the department of electrical engineering at the

University of Guyana analysed the results of the data collected at Orealla for his final

year project.1

The analysis of the wind speed data is shown in the following tables.

Month

Average

wind speed

(m/s)

June 1.7

July 1.7

August 1.9

September 2.3

October 2.2

November 2.4

December 1.8

January 2.3

February 2.9

March 2.7

April 2.7

May 2.7

Average 2.3

Table 3.4: Monthly Average Wind Speeds at Orealla

Wind

Speed

(m/s)

No. of

hours per

year

Wind

Speed

(m/s)

No. of

hours per

year 0.0-0.49 678 3.5-3.99 566

0.5-0.99 939 4.0-4.49 313

1.0-1.49 995 4.5-4.99 244

1.5-1.99 1112 5.0-5.49 97

2.0-2.49 1355 5.5-5.99 69

2.5-2.99 1262 6.0-6.49 21

3.0-3.49 1092 6.5-6.99 17

Table 3.5: Annual Frequency of Wind Speeds at Orealla

The reasons for these low wind speeds are Guyana’s closeness to the equator. These

wind speeds are too low for the larger wind turbines that are being constructed. The use

of micro wind for individual homes may need to be investigated. This however would

necessitate an additional power source.

1 Development of a Wind Power System for Orealla, Rameez Ishmael, 2008/09 Final Year Project, Department of Electrical

Engineering, University of Guyana



3.4 Clean Development Mechanism

3.4.1 Background

The Clean Development Mechanism (CDM) is one of three flexible mechanisms under

the Kyoto Protocol that was created by the United Nations Framework Convention on

Climate Change (UNFCCC) in 1997. The two main CDM objectives are as follows:

To assist Developing Countries to address their Sustainable Development needs in

terms of achieving economic growth, poverty reduction, technology transfer,

environmental protection/improvement and capacity building.

To assist Industrialised Countries in achieving compliance with their quantified

emissions target and reduction of the six greenhouse gases, namely,

o Carbon Dioxide (CO2)

o Methane (CH4)

o Nitrous Oxide (N2O)

o Hydrofluorocarbons (HFCs)

o Perfluorocarbons (PFCs)

o Sulphur Hexafluorides (SF6)

The Kyoto Protocol defines legally binding commitments for developed countries in

Annex I to reduce their greenhouse gas emissions by at least 5% compared to 1990 levels

by the period 2008-2012 (the first commitment period). Developing countries have no

legal binding commitments to reduce GHG emissions due to comparatively low levels of

industrialization.

Sustainable development projects have been defined by three criteria as follows:

Social criteria. The project improves the quality of life, alleviates poverty, and

improves equity.

Economic criteria. The project provides financial returns to local entities, results

in positive impact on balance of payments, and transfers new technology.

Environmental criteria. The project reduces greenhouse gas emissions and the use

of fossil fuels, provides health and other environmental benefits , conserves local

resources, reduces pressure on the local environments and meets energy and

environmental policies.

The basic principle of the CDM is simply that developed countries can invest in low cost

abatement opportunities in developing countries and receive credit for the resulting

emissions reductions, thus reducing the cutbacks needed within their borders.

From the perspective of the developing country, the CDM can

o Attract capital for projects that assist in the shift to a more prosperous and less

carbon intensive economy.

o Encourage and promote the active participation of both private and public sector.



o Provide a tool for technology transfer, if investment is channeled into projects that

replace old and inefficient fossil technology, or create new industries in

environmentally sustainable technologies.

o Help define investment priorities in projects that meet sustainable development

goals.

Specifically, the CDM can contribute to a developing country’s sustainable development

objectives through:

o Transfer of technology and financial resources

o Sustainable ways of energy production

o Increasing energy efficiency and conservation

o Poverty alleviation through income and employment generation

o Local environmental side benefit

There is a special Small-Scale CDM project category into which small renewable energy

projects can fall. Three types of small scale CDM projects are possible. For the first two

there is a maximum size of the activity that reduces emissions, but for the third type,

there is a maximum total emission from the project at the end of the project activity. The

three types of small scale CDM projects are:

I. Renewable energy project activities with a maximum output capacity equivalent

of up to 15 MW (or an appropriate equivalent)

II. Energy efficiency improvement project activities which reduce energy

consumption, on the supply or demand side, by up to the equivalent of 15 GWh

per year.

III. Other project activities that both reduce anthropogenic activities by sources and

directly emit less than 15 thousand tones (kt) of carbon dioxide equivalent

annually.

Guyana already has one registered CDM project, the Skeldon Bagasse Cogeneration

Project which was registered as a CDM project in September 2008, however it can seek

to benefit from projects in the any of the following project activity categories.



Project Types Small scale CDM project activity categories

Type I:

Renewable

energy projects

A. Electricity generation by the user

B. Mechanical energy for the user

C. Thermal energy for the user

D. Renewable energy generation for a grid

Type II:

Energy

efficiency

improvement

projects

A. Supply side energy efficiency improvements –

transmission and distribution

B. Supply side energy efficiency improvements – generation

C. Demand side energy efficiency programmes for specific

technologies

D. Energy efficient and fuel switching measures for

industrial facilities

E. Energy efficient and fuel switching measures for

buildings

Type III;

Other project

activities

A. Agriculture

B. Switching fossil fuels

C. Emission reductions by low greenhouse gas emission

vehicles

D. Methane recovery

E. Methane avoidance

Types I-III Other small scale projects

Table 3.6: Small Scale CDM project activity categories2

3.4.2 Designated National Authority

In order for a host country to benefit from the CDM it must establish a Designated

National Authority. Guyana had designated the Hydrometeorological Service as the

Designated National Authority for Clean Development Mechanism projects in Guyana.

However, this responsibility now rests with the Office of Climate Change in the Office of

the President. The responsibilities of the Designated National Authority are as follows:

Development of a national criteria and respective information requirements to

ensure a coherent, justifiable and transparent assessment of CDM projects in

accordance with the CDM Executive Board’s decisions.

Ensuring the compliance of CDM projects with relevant national policy and

regulatory regimes.

Elaboration of guidelines and procedures for project approval.

Five approaches to developing the DNA have been suggested

A. Single government department model

In this case the DNA is located within the climate change unit, however, since

CDM projects may involve different sectors and validation requires specific

technical expertise, the department may invite experts from other government

agencies upon demand. This effectively means that the DNA acts as a secretariat

and will ultimately be responsible for the approval of the CDM projects.

2 http://cdm.unfccc.int/methodologies



B. A two unit model

In this case the activities of the DNA can be split into two parts, one part located

in the climate change unit and the other part being an independent unit to avoid

conflicts of interest in the process of the formulation and approval of the project.

C. The Inter-Department Government Model

In this structure all relevant government departments are integrated into the DNA

as permanent members with the Environmental Protection Agency acting as the

coordinator but all member departments undertake the approval of projects.

D. Foreign Investment Model

In this instant an agency such as the Guyana Office for Investment (GoInvest)

provides the promotion office. It would receive projects from foreign investors

and evaluate and approve projects using pre-structured criteria which largely

reflect the national development priorities and interests. However, because of the

special nature of the CDM projects, relevant technical experts could be sourced

by the investment office when a CDM project is submitted so that the GHG

emission reductions can be properly validated.

E. Outsourcing Model

The services of the DNA can be outsourced to a private agency which evaluates

and validates the projects. The agency would then report to the government

agency that has been designated as the DNA.

3.4.3 Designated Operational Entity (DOE)

A designated operational entity (DOE) chosen by the project participants will then review

the project design document, invite feedback from NGO’s and local communities, and

decide whether or not it should be validated. The DOE could be auditing and accounting

firms, consulting companies and law firms capable of conducting credible and

independent assessments of emission reductions. If validated, the DOE will forward the

project to the Executive Board of the CDM for formal registration.

Chart 3 below shows the cycle of a CDM project.



3.4.4 Certified Emissions Reductions (CERs)

CDM projects produce both conventional project outputs and carbon benefits (CERs).

The value of carbon benefits and its impact on project viability are influenced by several

factors such as the amount of CERs generated by the project, the price of CER and the

transactions involved in securing the CERs.

The amount of CERs generated by the project depends on the greenhouse gases displaced

by the project and the crediting period selected. Grid-based or off-grid projects that

displace more carbon intensive coal and diesel fuels generate more CERs than those that

displace natural gas. Projects that capture methane and greenhouse gases other than CO2

produce more CERs since the global warming potential (GWP) of methane and other

gases are several times higher than that of carbon dioxide.



The price of CERs is highly speculative and is determined in the carbon market. At

present there is no single CER price but it is differentiated according to risks. The

forecasted price for the period 2008-2012 is US$5-11 per ton of CO2.

3.4.5 Transaction Costs

The transaction costs are those that arise from initiating and completing transactions to

secure CERs. The activities involved in the pre-operational and operational phases are:

Pre-operational Phase Design

Preparation and Review

Baseline Study

Monitoring Plan

Environmental Assessment

Stakeholder Consultation

Approval

Validation

Consultation and Project Appraisal

Legal and Contractual Arrangements

Operational Phase Costs

Sale of CERs

Adaptation Levy

Risk Mitigation

Verification

Executive Board Administration

Transaction costs for large projects can be as much as US$300,000. These high costs are

primarily because developing countries do not have the expertise to carry out many of the

activities required for CDM projects. Studies have shown that transaction costs per ton

of CO2 can be very small or even negligible for large projects but can be very significant

for small projects.

3.4.6 Impact of CERs on Project Viability

The net financial gain derived from the sale of CERs is the difference between the project

CER value and the transaction costs. The following tables show the impact of CER in

the IRR of the CDM approved projects.



Country Project IRR without

carbon finance

%

IRR with

carbon finance

%

Change in IRR

%

Costa Rica wind power 9.7 10.6 0.9

Jamaica wind power 17.0 18.0 1.0

Morocco wind power 12.7 14.0 1.3

Chile Hydro 9.2 10.4 1.2

Costa Rica Hydro 7.1 9.7 2.6

Guyana Bagasse 7.2 7.7 0.5

Brazil Biomass 8.3 13.5 5.2

India Solid waste 13.8 18.7 5.0

Table 3.7: IRR of Various Types of Projects with and without CDM financing

As expected, the biomass and solid waste projects produced much better results than the

power projects as the reduced emissions from these projects are more. It would have

been useful to assess the performance of the Guysuco’s Skeldon Cogeneration project to

date but the relevant information was not available. It is known that the monitoring

committee did visit Guysuco in 2009 to assess the reduced emissions.

3.5 Guyana’s Hydroelectricity Potential3

3.5.1 Introduction

In 1976 the Montreal Engineering Company Limited carried out an inventory to

determine the power potential of the numerous rivers in Guyana. The regions and rivers

that were selected for this inventory were as follows:

Northwest Coastal Region. This region contains a number of small rivers

draining into the Atlantic Ocean. It is bounded on the west by Venezuela, on the

east by the Essequibo river estuary and on the south by the Cuyuni river basin.

The major activity in this region is agriculture along the coast with some minor

inland forest harvesting. Mining of manganese at Matthew’s ridge ceased in

1968.

Cuyuni River Basin. The Cuyuni river rises in Venezuela and comprises a total

estimated drainage area of 20,600, of which 5,600 square miles is contained in

Guyana. The river flows from west to east, containing a relatively narrow

drainage in Guyana. The northern limit of the basin is formed by the northwest

coastal region. The southern limit is formed by the Mazaruni river basin and the

western limit in Guyana is formed by the Venezuela border. Economic activities

in the basin are limited to some forest harvesting near the mouth and mining for

gold.

3 Hydroelectric Power Survey of Guyana, Final Report, Volume 1, 9, 10, April 1976, Montreal Engineering

Company Limited



Mazaruni River Basin. The Mazaruni Basin, which has the highest potential for

hydropower development in Guyana, is almost entirely contained in Guyana. It

rises in the Pakaraima mountains at an elevation in excess of 6,000 feet and

follows a clockwise course until it finally flows northwards at Tiboku to join the

Essequibo estuary at Bartica. The estimated catchment area at Bartica is 12,200

square miles. The basin is bounded in the north by the Cuyuni basin, on the west

by Venezuela, on the south by Brazil and the Potaro basin, and on the east by the

Essequibo basin. Mining for alluvial gold and diamonds along the main stem and

tributaries is a major activity in the basin. Subsistence agriculture is practiced by

the Amerindians.

Potaro River Basin. The Potaro river and its principal tributary the Kuribrong

rise in the Ayanganna mountains (part of the Pakaraima mountain range) at an

elevation of 6,700 feet and drop rapidly to the east where the Potaro joins the

Essequibo river at an elevation of 72 feet. On the north and northwest the basin

borders on the Mazaruni watershed. To the southwest the Potaro basin borders

the Ireng watershed, and to the south it borders on tributaries of the Essequibo

river. The basin is sparsely populated however transitory miners normally search

for gold and diamonds. Most of the basin is heavily forested. The outstanding

feature of this basin is the magnificent Kaieteur Falls where the waters of the

Potaro River fall some 740 feet.

Northeast Coastal Region. The northeast coastal region includes the rivers

flowing into the Atlantic river east of the Essequibo watershed. The main rivers

are the Berbice, Demerara and Canje. The region is bounded by the Corentyne

River on the east, the Atlantic Ocean on the north and by the Essequibo river

basin on the south and west. This area contains the capital, Georgetown, and is

the centre of economic activity within the country.

Essequibo River Basin. The Essequibo River rises in the south at about elevation

1,100 feet on the border with Brazil, and flows northward to the Atlantc ocean.

At Bartica, the basin contains over 26,500 square miles of drainage area, or about

one third of the entire area of Guyana. This area is bounded on the west by the

Mazaruni, Potaro, Ireng and Takutu rivers. This area has comparatively little

economic activity. There is some agriculture along the coastal strip and cattle

raising in the Rupuni savannahs. The town of Bartica is the service centre for

inland mining and forestry operations.

New River Basin. The New River is a major tributary of the Corentyne River

whose west bank represents the border between Guyana and Surinam. The river

adjoins the Essequibo River to the west and Brazil to the south. Limited

livelihood farming is practiced in the area.

Ireng and Takutu River Basins. The Takutu river and its tributary the Ireng river

flow in opposite directions to meet near Lethem, where the Takutu turns west to

flow into Brazil. The main stems of both rivers form the international boundary



with Brazil. The Ireng rivers rises in the Pakaraima mountains and flows in a

winding gorge with many falls and rapids, until it reaches the savannah plain at

Good Hope at an elevation of 300 feet. The Takutu flows from south and follows

a meandering path for most of its length through a flat savannah type terrain.

Economic activity in the region is centred around the cattle industry.

Figure 3.1 Map of Guyana showing the Main Rivers



3.5.2 Hydropower Assessment

The study of the hydro power sites were carried out at four levels of detail as outlined

below:

o Level A – Pre-Inventory. All rivers were examined for power sites with an

average potential of 6 MW or greater.

o Level B – Inventory. Preliminary order of magnitude costs were prepared for all

sites with a power potential equal to or greater than 15 MW average potential.

o Level C – Most Promising Sites. From the inventory studies fifteen of the most

promising sites were selected.

o Level D – Pre-Feasibility. Three sites were selected from the list of promising

sites and investigated to pre-feasibility level based on one each of the following

criteria:

To supply basic load that is normal domestic, commercial and industrial

loads

To supply basic load plus a 60,000 ton per year aluminum smelter

To supply basic load plus a 200,000 ton per year aluminum smelter

Table 3.6 below summarises the number of sites that were designated at the various

levels in the areas of Guyana.

Area Number of Hydropower Sites

Level A Level B Level C Level D

Northwest Coastal Region 1 0 0 0

Cuyuni 5 5 2 0

Mazaruni 18 12 9 1

Potaro 8 8 3 2

Northeast Coastal Region 2 1 0 0

Essequibo 6 4 1 0

New River 3 3 0 0

Ireng and Takutu 0 0 0 0

Total 43 33 15 3

Table 3.8: Number of Hydropower Sites in Guyana



3.5.3 Hydropower Potential

The hydropower potential of the various river basins and regions was determined as

follows:

River Basin or Region

Capacity at 60% Annual Capacity

Factor

Sites 6 MW

average

regardless of

Cost

Sites 15 MW

average or Greater

at costs less than

US$1500/kW1

MW MW

Northwest Coastal Region 11 0

Cuyuni 726 671

Mazaruni 3,869 3,641

Potaro 1,088 1,066

Northeast Coastal Region 35 0

Essequibo 1,633 1,610

New River 292 178

Ireng and Takutu 0 0

Total 7,660 7,166

Table 3.9: Capacity of Hydropower Sites

1 Average cost/kW of thermal sets in 1976

Appendix II give the following inventory of hydropower sites

First Added Inventory of Sites in order of Increasing Cost/kW of Rated Capacity

Inventory of Sites Developed in Conjunction with Upstream Storage in order of

Increasing Cost per kW of Rated Capacity

These costs are all based on mid 1974 prices. Developing the sites in conjunction with

upstream storage reduces the average cost/installed kW by 44% and increases the rated

and average capacity by nearly 5000 and 3000 MW respectively.

3.5.4 Most Promising Sites

The fifteen sites that were designated most promising were:

Mazaruni River Basin : Upper Mazaruni, Sand Landing, Chi Chi, Turtruba,

Aruwai, Peaima, Tiboku, Apaikwa, Chitigokeng,

Potaro River Basin: Kaieteur, Tumatumari, Amaila

Essequibo River Basin: Arisaru

Cuyuni River Basin: Oko-Blue, Kamaria

3.5.4.1 The Mazaruni Basin

There were 9 sites in the Mazaruni River basin that were deemed most promising, three

of which could be developed in two stages, and some which became promising only after

upstream development. The sites, the rated and average power, and other details are

given in Table 3.8 below.



Sites

Power (MW) Remarks

Rated Average

1 Upper Mazaruni 2,800 1,678 Ultimate 3 power houses

2 Sand Landing 1,200 720 Canal scheme, ultimate

3 Chi-Chi 156 91 Only economical after Upper Mazaruni

4 Turtruba 533 320

5 Tiboku 222 133

6 Aruwai 454 230 Requires upstream development

7 Peaima 105 63 As above

8 Apaikwa 123 74 As above

9 Chitigokeng 440 264 As above

Total 6,033 3,641

Table 3.10: Sites Deemed Most Promising in the Mazaruni Basin in 1976 Survey

The sites in the Mazaruni River Basin have high capacity and/or need upstream

development to be profitable. The Turtruba site was studied up to pre-feasibility level to

meet the requirement of an aluminum plant of 200,000 tons per year plus the country’s

basic load. These sites need to be developed in conjunction with known industrial

development. It is not recommended that these sites be considered for normal load

forecasts.

3.5.4.2 The Cuyuni River Basin

There were two promising sites in the Cuyuni River basin, Oko Blue and Kamaria. Oko

Blue can be developed in two phases. Kamaria requires upstream storage to be

economical.

Sites Power (MW)

Remarks Rated Average

1 Oko-Blue 313 188 Phase 2

2 Kamaria 172 103 Requires upstream storage sites

Total 485 291

Table 3.11: Sites deemed Most Promising in the Cuyuni River Basin in 1976 Survey

3.5.4.3 The Essequibo River Basin

The Essequibo River basin had an estimated hydropower potential of 1633 MW however

only one site was deemed as most promising and this was the Arisaru site located 56

miles up the Essequibo river with a rated capacity of 200 MW and an average capacity of

120 MW. Because this site means the harnessing of Guyana’s largest river, the costs of

this would be quite expensive.

3.5.4.4 The Potaro River Basin

The development of the Potaro basin was thought to be the most feasible development

and several alternatives were investigated. It was determined that this river basin could

yield over 1000 MW average power if developed systematically. This basin had three

most promising sites, that is, Kaieteur, Amaila and Tumatumari, and two of these,

Kaieteur and Amaila were studied to pre-feasibility level.



Several recommendations were made for the development of this river basin and although

it seems that it may not be desirable to interfere with the Kaieteur Falls, this basin can

still be developed to meet Guyana’s long term future energy needs. The potential of

these three individual sites are as follows:

Sites

Power (MW) Remarks

Rated Average

1 Kaieteur 579 347 Full development

2 Amaila 103 172 Ultimate 3 power houses

3 Tumatumari 75 45 No upstream storage

Total 757 564

Table 3.12: Sites Deemed Most Promising in the Potaro Basin in 1976 Survey

It was suggested that the potential of the Potaro river basin could be increased if the Chi-

Chi dam on the Upper Mazaruni river was raised to divert water to the Potaro water shed

and would result in the following:

Amaila power output would be increased by an average of 215 MW

Tumatumari output would be increased by an average of 17 MW

Two sites on the Potaro river upstream of Kaieteur, Akobeng and Iatuk, with

heads of 156 and 500 feet respectively can have an increased output of 102 MW

average.

The available power output of the Potaro basin without that of Kaieteur would be as

follows:

Sites Power (MW)

Remarks Rated Average

1 Amaila 387 318

2 Tumatumari 92 62

3 Akobenang 46 37

4 Iatuk 205 155

Total 730 572

Table 3.13: Increased Potential of Potaro Basin with Diversion from Chi Chi Dam

3.5.5 The Amaila Falls Hydropower project4

The Amaila Falls hydropower project on the Kurubrong river has already been earmarked

as Guyana’s first hydropower project. The Amaila Falls hydropower project is located on

the Kuribrong River in west central Guyana, about 250 kilometers south west of

Georgetown. The dam site is at the confluence of the Amaila and Kuribrong rivers. The

project includes a small storage reservoir constructed at the top of Amaila Falls. It will

also include 296 kilometers of 230 kV, double circuit transmission line. The following

are the technical details of the power station and transmission system.

4 Amaila Falls Hydroelctric Project, Guyana, prepared by Montgommery Watson Harza fo r Synergy Hodings Inc. and

Harza International Development Company LLC



Powerhouse

Type Surface

Number of units 4

Type Francis

Nominal power output/unit 38 MW

Nominal discharge/unit 8.38 m3/s

Gross head (max) 365 m

Turbine

Rated head 347.56 m

Rated output 25.64 MW

Generator

Rating 40 MVA

Speed 720 rpm

Average Energy Output 1000 GWh

Main Transformers

Number 2

Rating 48/64/80 MVA OA/FA/FA

Transmission Line

Length 278 km

. Type 230 kV, double circuit, single tower

Termination Sophia

Table 3.14: Technical Specifications of Amaila Falls Hydropower Project

3.6 Biomass

Guyana will soon benefit from a technical cooperation agreement to define a critical path

in order to promote development in the agro-energy sector. The objectives of this

agreement are:

To improve capacity to identify and evaluate viable investment opportunities in

the bio-energy production chain.

To develop a financial vehicle to promote investment opportunities and develop a

strategy to harness Guyana’s potential for bio-energy production.

To increase capacity building and the transfer of technology so as to build a

critical mass of bio-energy technicians, operators, and demonstration projects,

and,

To provide institutional strengthening to support an Agro-energy Policy for

Guyana and support small bio-energy demonstration projects and dissemination

of results.

3.6.1 Bagasse

Bagasse is known to have the highest bioconversion efficiency of capture of sunlight

through photosynthesis compared to other crops. In the process of the recovery of the

sugar the fibrous fraction of the cane stalk in the form of bagasse composed of 50% fibre,

48% moisture and 2% sugar is normally burnt to generate steam and electricity to meet

the requirements of the sugar industry. Over the years sugar factories in a number of

countries have adopted energy conservation and efficiency measures with a view to either



generating surplus bagasse for use as raw material for pulp and paper and particulate

board or surplus energy for sale to the grid.

An example of a country which has successfully utilized bagasse for production of

electricity to the grid is Mauritius where in 2005, 44% or 750 GWh of its electrical

energy came from the sugar industry and 300 GWh of this total came from bagasse. (In

the off crop season coal is used in the boilers.)

Guyana has commissioned one cogeneration project using bagasse fired steam

generation. Bagasse would contribute between 5 and 7% of the electricity requirements

of the grid in the medium term and about 70% of Guysuco’s electricity requirements.

Guyana should seek to develop other such projects as a means of contributing renewable

energy to the electricity supply chain.

3.6.2 Other Biofuels

The other opportunities that Guyana has to use biofuels for electricity production are rice

and wood waste, biodiesel production from oil palm and coconut oil and used vegetable

and animal fats.

3.7 Hinterland Generation Technology

The development of electrical energy sources for the hinterland depends on the

emergence of economic activity to support this development. The success of individual

solar units for four hinterland communities needs to be assessed and the results of the

wind speed measurement suggest that only individual wind turbines may be feasible.

There are many mini and micro hydropower sites in the hinterland but the development

of these would not be feasible especially without any major economic activity.

3.7.1 Diesel Generators

This still represents the most common form of electricity supply in the hinterland regions.

Service is provided normally in the evenings for six to twelve hours as during the day

there is hardly any load. However, because of this, there has been little economic

development in these areas resulting from the availability of electricity. In most cases the

consumers pay a flat rate and there are no energy meters. There are a few areas where

the electricity supply system is self sustained however, in many instances the cost is

being subsidized. Recent announcements stated that small Caterpillar sets utilized by

GPL would be taken to a few of the larger hinterland communities.

3.7.2 Hydropower

The 0.5 MW Moco Moco hydropower station in the Lethem area is one of two

hydropower stations that was established in Guyana, the other being at Tumatumari. The

station was commissioned in 1999 but ceased operation in 2003 after the penstock was

displaced. This was one of the more developed power systems in the hinterland as there

is a secondary distribution system to supply the community. The system also provided



24 hour service. Efforts are being made to have the power station re-commissioned.

However at present the area is being supplied on a part time basis using diesel generators

and there is also a plan to utilize an existing GPL generator to provide 24 hour service.

The 1976 hydropower survey of potential sites in Guyana only considered sites larger

than 6 MW, however there are many sites that could be economical for mini/micro hydro

schemes. At present two such sites are being investigated.

Cato, in Region for which a feasibility study has been completed for a run of the

river scheme with an output of 570 kW, and,

Eclipse Falls in Region1 which is expected to produce an average of 4 MW to

supply Matthews Ridge, Port Kaituma and the Amerindian village of Arakaka, a

community of person.

3.7.3 Individual Solar Units

A pilot project is being carried out in four hinterland communities where individual

125W solar units have been installed on 336 homes at a cost of G$300,000 each. This

sum included the electrical wiring installation of the homes, which included the provision

fo 2, 15 watt compact fluorescent bulbs and a power outlet. Home owners have been

asked to pay G$500 a month into a fund for the cost of maintenance and it is estimated

that 80% of the homeowners have been doing so. This amount would be increased by

G$100 every two years. Although there has not been any formal study of the success of

the project, informal reports are that although the provision of electricity is helpful for

evening activities such as studying, etc., there has not been any substantial economic

development as a result of the provision of electricity.

Individual units that would provide power for small economic activity would be more

costly, however incentives can be given for private companies to become involved in the

supply of solar units for hinterland communities.

3.7.4 Wind

As mentioned previously the wind speed data collected for the Orealla community has

been analysed and the wind regime does not seem to support large scale wind farms.

Wind speed data has also been collected for two other communities, Jawalla and

Yapakari. These data also show that hinterland wind speeds cannot run large wind farms.

The use of individual micro wind turbines needs to be further investigated.



3.8 Recommendations

3.8.1 Comparison of Fuel Oil versus Wind for the Medium Term

Section 4.7 of Primary Energy shows that GPL has enough available generation capacity

to meet the forecasted energy requirements for the medium term however the ‘firm’

capacity is not enough to meet the maximum demands throughout the period. GPL is

therefore in need of additional 10 to 15 MW of generation capacity before the proposed

hydropower station comes on stream. The merits and demerits of wind and diesel

engines are now highlighted in an attempt to make a recommendation.

Table 3.15 shows the comparison between the 11.4 MW wind turbine farm proposed for

Hope Beach and an 11 MW HFO diesel generator in terms of available and firm capacity,

costs and emissions. Fuel Oil Wind

1

Installed Capacity (MW) 11.3 11.4

Firm/Average Capacity (MW) 11.3 4.0

Annual Generation (GWh) 942

29.2

CO2 Reductions/Emissions 59,600 tons/annum 29,200 tons/annum

NOx Reductions/Emissions 376 tons/annum 116 tons/annum

SO2 Reductions/Emissions 1316 tons/annum 408 tons/annum

Capital Cost (US$) 18.0 13.7

Maintenance Costs (US cents/kWh) 1.5 1.0

Energy Cost/kWh (US cents) 12.83

9.0

Lead time (years) 2 2

Table 3.15: Comparison of 11 MW Diesel and Wind Turbine Facilities

1

Wind information from 2002 study and recent negotiations

2

95% availability

3

Includes investment costs; HFO costs $2.07/gal

The following points can be noted about the comparison:

The wind farm has an average capacity of 4 MW whereas the full capacity can be

obtained from the diesel change which can also supply over three times the annual

generation.

The investment costs for the wind farm from the 2003 report are quoted here

however the most recent negotiated price per kWh of 9 cents as opposed to the

original price of 7 cents reflects the increased wind turbine costs. .

The cost per kWh for the diesel set reflects today’s fuel prices which are quite

uncertain in the future.

The emission levels are based on 95% operation at rated load.

As GPL’s requirement is for increased capacity (MW) to improve its reliability more than

a deficit of electrical energy (MWh) then the diesel sets may be preferable. This however

could all change if fuel prices begin a dramatic rise again.

Unfortunately, although there is a high level of emissions from the diesel set, it seems to

be better able to meet the requirements of GPL for the medium term. As GPL has



recently installed 6.9 MW sets, the purchase of two more of these sets should prove more

economical in terms of stock of maintenance spares than the larger set.

3.8.2 Wind Energy in the Long Term

The role of wind energy in the long term needs to be addressed. It is expected that

hydropower facilities would be developed for Guyana and would provide most of its long

term needs. The scenarios for which hydropower may not be available or sufficient are:

Long dry spells

Transmission line failures

It would however seem for feasible for diesel engines to provide the necessary backup

facilities rather than wind energy because of the unpredictable nature of the wind.

3.8.3 Fuel Oil

The predominant use of fuel oil for generation purposes will continue until the Amaila

Falls hydropower station is commissioned probably in 2013 or 2014. It is expected that

the new Amaila hydropower station would displace the use of fuel oil in the long term

although operationally some diesel sets may still be required. See Table 4.11. If it is

intended to continue to limit the use of fuel oil then studies should start immediately on

the next hydropower facility as the Amaila Falls hydropower station reach its projected

annual energy output of 1000 GWh in 2019 and this necessitates the use of the diesel

sets.

3.8.4 Hydropower

Guyana has a wealth of hydropower potential and it is expected that construction work

should begin on the Amaila falls hydropower project by mid 2010. Although the

Kaieteur site was recommended as the most economic of all the hydropower sites, it is

not expected that Guyana would want to interfere with the majestic Kaieteur Falls. The

location of the next hydropower investment would depend on the growth in electrical

demand over the next few years.

The development of the Mazaruni river basin would not be recommended as most of the

sites in this basin have high hydropower potential and should be developed in

conjunction with large industrial projects. There was only one ‘most promising’ site

recommended for the Essequibo river basin so the development of this basin is also not

recommended. The Potaro and Cuyuni river basins seem to be the areas that should be

further investigated for future hydropower development. The following are the potential

hydropower capacities of the various sites in these basins.

Tumatumari. With the first development of the Amaila Falls site, the potential of

Tumatumari is expected to rise to an average output of 50 MW.

Diversion of Chi Chi dam on the Mazaruni river is expected to increase the

potential of the Potaro river basin as follows:



Amaila Falls increase by 215 MW average output

Tumatumari to increase to 67 MW average output

Akobenang to 37 MW average output

Iatuk to 155 MW average output

In the Cuyuni river basin

Oko Blue – 188 MW average output, and,

Kamaria – 103 MW average output

The medium load forecast (minus Guysuco and hinterland communities) shows the

following demands.

2015 126 MW

2020 146 MW

2025 171 MW

This could change depending on the economic conditions in the country. However, the

development of Tumatumari downstream of Amaila seems a natural second stage as both

of these sites can be further increased.

The next decision would be whether to continue the development of the Potaro river

basin or move to the Cuyuni river basin. The latter could give a maximum of about 300

MW whereas the Potaro river basin (without Kaieteur) has a potential in excess of 500

MW. It would therefore seem a better prospect to continue the development of the Potaro

river basin with the extension of the Amaila Falls site, the extension of the Tumatumari

site, followed by Akobenang and Iatuk as deemed appropriate.

3.8.5 Biomass

The development of other bagasse cogeneration projects should be pursued as well as the

production of biodiesel for electricity generation.

3.8.6 Clean Development Mechanism

The principles and modalities of the Clean Development Mechanism were explained in

Section 3.4 and although efforts are being made to encourage smaller projects there

seems to be greater benefits from the larger projects. The Amaila Falls hydropower

project with its expected annual output of 1000 GWh, reducing CO2 emissions by over

700,000 tons per year should rank as a good CDM project. Guyana would therefore need

to examine the following.

Determine whether it would only consider large CDM projects or whether it

would seek all avenues for such projects and therefore structure the office of the

Designated National Authority (DNA) to determine and promote CDM projects

for the country.

If the decision is the latter, then five models of DNA have been suggested and

although a decision has been made that the Office of Climate Change in the

Office of the President will be the DNA for Guyana no DNA unit has been set up.



A decision must therefore be made on the type of unit that would be set up and

the functioning of such a unit.

Preparation and review of projects, establishing of baseline data and monitoring

plans are some of the expertise that is required for the registration of CDM

projects. The acquisition of such expertise and the associated costs need to be

established.

Small projects can include energy efficiency and conservation and as GPL is

embarking on reduction of technical losses this project can be considered as a

CDM project, however, baseline data would need to be established before the

project has started.

3.8.7 Hinterland Communities

As wind and solar options seem to only provide power for individual homes and may not

be economical, and as diesel power will continue to be expensive for hinterland

communities and therefore will not attract economic development, there needs to be a

consorted effort to investigate the setting up of industries together with mini or micro

hydropower schemes for the hinterland.

3.8.8 General

Table 3.16 and 3.17 below gives a projection of the proposed generation mix in the

country for 2015 and 2025 respectively. The information on the mining sector is not

available and it is projected that self generators and standby sets would still be available

although it is projected that GPL would be the main supplier of power.


Diesel Biomass Hydro Solar Wind GPL 110.0

IPP 154.0 Mining Industry

1 50.0 Sugar Industry 25.0 55.5 Self Generators

1 55.0

Standby Generators 35.0 Hinterland 3.0 0.5 Total 278.0 55.5 154.5

Table 3.16: Projected Installed Generating Capacity 2015

1 Estimated




Diesel Biomass Hydro Solar Wind GPL 50.0

IPP 190.0

Mining Industry1

75.0

Sugar Industry 25.0 75.01

Self Generators1 5.0

Standby Generators 85.0

Hinterland 5.0 10.01

Total 245.0 75.0 200.0

Table 3.17: Projected Installed Generating Capacity 2025

1

Estimated




The various issues have all been outlined in the above Section 3.8 on Recommendations.

These can be summarized as follows:

The need to ensure that there is not a return to fuel oil technology once the

hydropower development programme has started. However the role of oil in the

event of the discovery of oil in Guyana needs to be addressed.

Wind does not seem to still have a place in the generation technology mix with

consideration only given to small wind farms on the coast. The hinterland sites

have not proved to be good for wind regimes, and it is expected that hydropower

generation will take over most of the energy now being generated by fuel oil in

the long term.

There is the need to immediately carry out pre-feasibility studies of small to

medium sized (50 to 200 MW) hydropower sites so that based on the load growth

over the next few years the required size of site can be developed.

The decision on the use of the Clean Development Mechanism for small projects

needs to be made.

Chapter 4 PRIMARY ENERGY

CHAPTER 4 PRIMARY ENERGY


4.0 PRIMARY ENERGY

4.1 Introduction

In this section on Primary Energy a spreadsheet generation dispatch model is used to

allocate the generation to the various stations based on the recommendations of Section 3

on Generation Technology. The medium term and long term forecasts are treated

separately. The methodology that is used for dealing with the medium term generation

forecast is as follows:

As generation needs to not only meet the required energy but also the maximum

demand, the energy forecast was developed into a demand forecast by utilizing

historical data on load factors.

It was decided that the provision of cheaper electricity from the hydropower

station may not be available until the end of the medium term and it was therefore

unlikely that many self generators may be won back to the GPL system during the

medium term. The analysis of primary energy in the medium term therefore

focuses on the GPL system.

4.2 Medium Term Demand Forecast

The Guyana medium term energy forecast was developed into a demand forecast using

the following historical load factors. The load factor is a measure of the ratio of the

actual energy generation and the generation that would have been achieved if the load

was at its maximum for the entire period. Table 4.1 shows the various load factors that

were utilised.

Company Load Factor

GPL 0.7

Self Generators 0.4

Bosai Mining 0.86

LECI 0.7

Guysuco 0.42

Hinterland 0.85

Table 4.1 Historical Load Factors



The medium term demand forecast developed from the load factors and the forecasted

energy generation is shown in Table 4.2 below.

GUYANA MEDIUM TERM DEMAND FORECAST

(MW)

2008 2009 2010 2011 2012 2013 2014

GPL 91 91 93 94 95 97 98

SELF GENERATORS 15 15 16 16 16 16 16

BOSAI MINING 4 4 4 5 5 5 5

LECI 7 7 6 6 6 5 5

SUB-TOTAL 117 118 119 120 122 124 125

GUYSUCO 16 20 20 20 20 20 20

OTHER MINING N.A. N.A. N.A. N.A. N.A. N.A. N.A.

OTHER SECTORS - - - - - - -

HINTERLAND 1 1 1 1 1 1 1

TOTAL 134 139 140 142 143 145 146

Table 4.2: Guyana Medium Term Demand Forecast 2008 - 2014

4.3 Generation Dispatch Model

A spreadsheet generation dispatch model was used to allocate generation from the

various existing generating stations to meet the forecasted energy and demand. The

following information was used in the model:

GPL installed and available generating capacity

Guysuco’s Skeldon capacity available to GPL

GPL load duration curve. The area under this curve represents the annual

generation requirement and the different stations are dispatched to supply the

demand and energy required.

Forecast energy sales and losses for each customer category

Station use and technical losses

Current and projected HFO and LFO prices

For each generating station

Year of installation (if necessary) and year of retirement

Type of fuel utilized (light or heavy fuel oil or no fuel)

Fuel Costs

Heat rates (Btu/kWh)



Lubricating oil usage

Top and major overhaul maintenance costs

Other fixed costs

Some of the data utilized is shown in the various tables and graphs below.

4.4 GPL Installed and Available Capacity

The present installed and available generating capacity to meet the GPL forecast is shown

in Table 3.3 below.

First

Year

of Full

Operation

Projected

Final Year

of Operation

(Year)

Nameplate

Capacity

MW

Available

Capacity

MW Generating Station

Garden of Eden Crossley (5.3 MW) (2)

2008 10.6 -

GoE Nigaata (5.3 MW) (2)

2017 10.6 8.0

GoE/Versailles/Sophia/ Cat (2.0/1.6 MW) (18)

2011 32.6 19.8

GoE Wartsila (5.5 MW) (4)

2022 22.0 22.0

Kingston Wartsila I (5.5 MW) (4)

2022 22.0 22.0

Kingston Wartsila II (6.9 MW) (3) 2010 2030 20.7 20.7

Versailles Nigaata (2 MW) (2)

2012 4.0 3.8

Canefield Mirlees (5.3 MW) (2)

2025 10.6 8.0

Onverwagt GM (2.5 MW) (2)

2014 5.0 4.3

Canefield/Onerwagt Cat (1.4 MW) (4)

2009 5.6 3.2

Skeldon Bagasse (15 MW) (2) 2009 2030

8.0

Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 2009 2030

8.0

Anna Regina Wartsila (2 MW) (2)

2020 4.0 4.0

Leguaun/Wakenaam Cat (.325 MW) (3)

2025 1.0 1.0

Bartica Cat (1.1 MW) (2)

2025 2.8 2.4

Total

151.5 135.0

Table 4.3: Generating Capacities Available to GPL

The stations at Garden of Eden (GoE), Kingston and Versailles represent the Demerara

system which is presently interconnected. The stations at Onverwagt, Canefield and

Skeldon are interconnected to form the Berbice system. The model assumes the

interconnection of these two systems which has been scheduled for 2011. The stations at

Anna Regina, Leguan, Wakenaam and Bartica are small isolated systems in Essequibo

and are not expected to be a part of the national grid in the medium or long term.

The above table shows that the present installed capacity of GPL is 151.5 MW and the

available capacity is 135 MW which includes 8 MW each of steam and diesel generating

capacity respectively from Guysuco’s Skeldon power station. It is to be noted that the

full 16 MW is only available during the grinding season (26 weeks) and the 8 MW of

diesel power during the entire of the year.



There are presently 23 MW of Caterpillar sets rated between 2 and 1.4 MW connected to

the GPL’s network. This represents an inefficient way of generating electricity for the

power system. GPL has plans to de-commission these sets as early as possible especially

as they utilize the more expensive light fuel oil (LFO). This will reduce the system to an

available capacity of 104 MW. For system reliability firm capacity is normally defined

as the available capacity minus the two largest sets. It assumes the possibility of one of

the largest sets being on planned maintenance and the other experiencing an unscheduled

outage. It can be seen that the GPL’s firm capacity is only 91 MW which is equal to its

present maximum demand. A graph of the forecast maximum demand and the present

generation capacity is shown in Figure 4.1.

Figure 4.1: Generating Capacity and Load 2008-2012

In the above graph the following is assumed.

Import from Skeldon and new Kingston sets in 2009/10

Inefficient Caterpillar sets removed from system by 2011

It can be seen that the GPL system is already in need of additional more efficient

generating capacity.

4.5 Load Duration Curve

The load duration curve indicates the maximum demand, the base load and the periods

that the various loads are demanded for the system. The available data for the Demerara

system was extrapolated for the entire GPL system and the graph is shown below. This

data is used by the generation dispatch model to allocate generation to meet the load.

The same shape of the curve is used as the load forecast increases.



0

20

40

60

80

100

1000 2000 3000 4000 5000 6000 7000 8000

GPL'S LOAD DURATION CURVE 2008

FIGURE 4.2

MW

HRS

4.6 Medium Term Energy Balances

The generation and sales forecast that was produced using the trend analysis was adjusted

to indicate an increase in sales as a result of a reduction in losses due to the various loss

reduction programmes being run by GPL. These adjusted figures are shown in Table 4.4.

Tariff Category GENERATION, SALES AND LOSSES (GWh)

2008 2009 2010 2011 2012 2013 2014

Residential 160.5 163.7 168.8 173.6 178.2 182.9 187.6

Commercial 64.6 69.4 72.3 74.6 76.9 79.2 81.6

Small Industrial 31.4 31.7 32.1 32.6 33.1 33.6 34.1

Large Industrial 93.2 94.8 95.7 98.7 102.1 105.6 109.2

Street Lighting 6.3 7.3 8.2 9.2 10.1 11.0 12.0

Total Sales 355.9 366.9 377.2 388.7 400.4 412.3 424.4

Losses 183.0 172.7 169.5 166.6 163.6 160.4 157.0

Losses % 34.0 32.0 31.0 30.0 29.0 28.0 27.0

Station Use 28.4 28.4 28.8 29.2 29.7 30.1 30.6

Generation 567.3 568.0 575.4 584.5 593.7 602.8 612.0

Table 4.4: Generation, Sales and Losses Forecast 2009-2014



4.7 Other Data for Generation Dispatch Model

Some of the other data that was used in the generation dispatch model are shown in the

Table 4.5 below.

Top Overhaul

(US$1000)

Major

Overhaul

(US$1000)

Heat Rate

Btu/kWh Generating Station

Garden of Eden Crossley (5.3 MW) (2) 120 400 9,137

GoE Nigaata (5.3 MW) (2) 225 375 9,137

GoE/Versailles/Sophia Cat (2.0/1.6 MW) (18) 125 300 9,976

GoE Wartsila (5.5 MW) (4) 300 300 9,000

Kingston Wartsila I (5.5 MW) (4) 300 300 8,500

Kingston Wartsila II (6.9 MW) (3) 300 300 7,425

Versailles Nigaata (2 MW) (2) 85 142 9,337

Canefield Mirlees (5.3 MW) (2) 60 130 9,337

Onverwagt GM (2.5 MW) (2) 40 110 8,810

Anna Regina Wartsila (2 MW) (2) 200 200 9,976

Canefield/Onverwagt Cat (1.4 MW) (4) 125 300 9,976

Leguan/Wakenaam Cat (.325 MW) (3) 40 40 12,494

Bartica Cat (1.1 MW) (2) 125 300 9,379

Bartica Mirlees (.392 MW) (2) 12 36 9,140

Skeldon Bagasse (15 MW) (2) 0 0

Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 9,500

Table 4.5: Maintenance Costs and Fuel Efficiency Data

The following data on prices and costs were also used:

HFO price of US$74.76 per barrel increasing annually by 5%

LFO prices of US$69 per barrel also increasing annual by 5%

Bagasse generation at 10.5 US cents/kWh

Generation station fixed costs as calculated by GPL for 2008

4.8 Medium Term Generation Dispatch

The generation dispatch model used the financial and efficiency data above to determine

a merit order for the sets. The sets at Essequibo were put to ‘must run’ as being more

costly they would be very low in the merit order. The results of the generation dispatch

model are shown in Table 4.6 below.



Electricity Generation by unit, MWh

Generating Stations 2009 2010 2011 2012 2013 2014

Garden of Eden Crossley (5.3 MW) (2) 0 0 0 0 0 0

GoE Nigaata (5.3 MW) (2) 0 0 0 0 1,034 1,705

GoE/Versailles/Sophia Cat (2.0/1.6 MW)

(18) 109,905 19,518 0 0 0 0

GoE Wartsila (5.5 MW) (4) 180,765 126,736 129,977 133,944 138,311 142,762

Kingston Wartsila I (5.5 MW) (4) 192,720 187,473 189,374 190,621 191,417 192,227

Kingston Wartsila II (6.9 MW) (3) 0 175,200 175,200 175,200 175,200 175,200

Versailles Nigaata (2 MW) (2) 0 0 0 375 0 0

Canefield Mirlees (5.3 MW) (2) 3,747 0 5,845 6,751 7,361 7,982

Onverwagt GM (2.5 MW) (2) 7,436 483 9,369 10,917 12,449 13,656

Anna Regina Wartsila (2 MW) (2) 21,900 21,900 21,900 21,900 21,900 21,900

Canefield/Onverwagt Cat (1.4 MW) (4) 0 0 0 0 0 0

Leguaun/Wakenaam Cat (.325 MW) (3) 2,278 2,278 2,278 2,278 2,278 2,278

Bartica Cat (1.1 MW) (2) 7,008 7,008 7,008 7,008 7,008 7,008

Bartica Mirlees (.392 MW) (2) 0 0 0 0 0 0

Cat (1.6 MW) (3) 0 0 0 0 0 0

Skeldon Bagasse (15 MW) (2) 35,040 35,040 35,040 35,040 35,040 35,040

Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 7,259 0 8,658 9,756 10,843 12,304

Total Generation 568,057 575,636 584,648 593,790 602,840 612,061

Table 4.6: Generation Dispatch for the period 2009 - 2014

The analysis of the results of the generation dispatch model is as follows:

The model assumes a combined Demerara/Berbice system which may not be

operational until 2011

The installed generation capacity can meet the energy requirement which does not

include the self generators.

The Wartsila sets are carrying 85% of the generation and bagasse generation

about 6%.

It can be seen that there is available capacity is able to meet the energy requirement in the

medium term but as has been discussed before this available capacity is too close to the

maximum demand to offer a high reliability and therefore additional generation needs to

be considered for the medium term.

In Chapter 3 on Generation Technology it was determined that two 6.7 MW sets similar

to those now installed at the new Kingston station will be the most appropriate additional

generation technology for the medium term. The results of installing these new sets in

2012 are shown in Table 4.7.



Electricity generation by unit, MWh

Primary Generation 2009 2010 2011 2012 2013 2014


GoE Nigaata (5.3 MW) (2) 4,537 0 0 0 0 0


(18) 2,449 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 180,765 126,736 129,977 84,778 91,526 98,407

Kingston Wartsila I (5.5 MW) (4) 192,720 187,473 189,374 170,774 171,807 172,855

Kingston Wartsila II (6.9 MW) (3) 0 175,200 175,200 175,200 175,200 175,200

Versailles Nigaata (2 MW) (2) 3,489 0 0 0 0 0

Canefield Mirlees (5.3 MW) (2) 34,542 4,582 5,845 647 1,306 1,978

Onverwagt GM (2.5 MW) (2) 26,255 3,902 3,902 1,951 1,951 2,537


Canefield/Onverwagt Cat (1.4 MW) (4) 2,251 0 0 0 0 0


Bartica Cat (1.1 MW) (2) 7,008 7,008 7,008 7,008 7,008 7,008


Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 54,823 11,517 14,125 6,615 7,224 7,259

New Diesel (13.4MW) 0 0 0 87,600 87,600 87,600


Table 4.7: Medium Term Generation Dispatch with New 15 MW Diesel Sets

The diesel sets was chosen in preference to a similarly sized wind farm because the need

was for a higher level of reliability (demand) rather than energy supply and it was felt

that the wind farm is more useful for the supply of energy supply than being able to

provide a firm demand. Figure 4.3 shows the results with the added diesel sets.



4.9 Long Term Analysis

The long term forecast covers the period 2015 – 2025. For the GPL forecast an

econometrics method was used with sales as the independent variable and GDP and

population as dependent variables. GDP annual growth rates of 3.5%, 5% and 7% were

analysed and these were designated Low, Medium and High forecasts with more detailed

analysis done for the Medium forecast. The long term forecast is based on the premise

that hydropower development, in particular, the Amaila hydropower project would come

on stream towards the end of the medium term.

An estimate of the self generation was determined and a growth rate of 2% assumed

throughout the medium and long term forecast period. This load will be gradually

included with the GPL forecast over a three year span. It is anticipated that GPL would

be able to improve its reliability and power quality in the medium term and will also be

purchasing power from the Amaila Falls hydropower station towards the end of the

medium term.

The energy forecast for Linden is also included in the long term analysis as the

development of a national grid is projected with the development of the Amaila Falls

hydropower project.

4.10 Long Term Energy Balances (Medium Forecast)

Table 4.8 shows the long term energy generation and sales forecast with the self

generators gradually included over a three year period.

Tariff

Category

FORECAST GENERATION AND SALES (GWh)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Residential 195 204 213 222 232 242 254 266 279 292 306

Commercial 85 89 92 96 101 105 110 116 121 127 133

Small

Industrial 35 37 39 40 42 44 46 48 51 53 56

Large

Industrial 139 170 195 201 209 215 223 232 239 249 259

Street Lighting 13 13 14 14 15 16 16 17 18 19 20

Total Sales 467 512 552 573 598 622 649 678 707 740 774

Losses 125 132 136 136 135 134 134 132 124 122 119

Losses % 26 25 24 23 22 21 20 19 17 16 15

Station Use 15 16 16 17 17 18 18 19 19 20 21

Generation 634 685 729 749 773 795 821 849 867 898 929

Table 4.8 Forecast Generation and Sales 2015-2025



Table 4.9 includes Linden as ‘Bulk Sales’ customer from the beginning of 2015.

Tariff

Category

GENERATION AND SALES (GWh)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Residential 195 204 213 222 232 242 254 266 279 292 306

Commercial 85 89 92 96 101 105 110 116 121 127 133

Small

Industrial 35 37 39 40 42 44 46 48 51 53 56

Large

Industrial 139 170 195 201 209 215 223 232 239 249 259

Street Lighting 13 13 14 14 15 16 16 17 18 19 20

GPL Sales 467 512 552 573 598 622 649 678 707 740 774

Bulk Sales 78 81 85 89 93 97 102 107 111 117 122

Total Sales 545 593 637 662 691 719 751 785 819 857 896

Losses 206 180 160 159 156 156 154 152 141 137 134

Losses % 27 23 20 19 18 18 17 16 15 14 13

Station Use 15 16 16 17 17 18 18 19 19 20 21

Total

Generation 767 789 813 838 865 893 923 955 980 1014 1051

Table 4.9: Forecast Generation and Sales including Self Generators and Linden



4.11 Long Term Demand Forecast

The energy forecast is converted into a demand forecast for the Low, Medium and High

scenarios as shown in Table 4.10, 4.11 and 4.12.

TOTAL GUYANA LONG TERM LOW DEMAND FORECAST

SECTOR

MW

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 97 99 100 101 103 104 106 107 108 109 111

SELF GENERATORS 16 17 17 17 17 17 17 18 18 18 18

BOSAI MINING 6 6 6 7 7 7 8 8 8 9 9

LECI 5 6 6 6 7 7 7 8 8 8 9

SUB-TOTAL 125 127 129 131 133 135 138 140 142 145 147

GUYSUCO 20 20 20 20 20 20 20 20 20 20 20


OTHER SECTORS - - - - - - - - - - -

HINTERLAND 1 1 2 2 2 2 2 2 2 2 2

TOTAL 146 148 150 153 155 157 160 162 164 167 170

Table 4.10: Long Term ‘Low’ Demand Forecast 2015-2025



TOTAL GUYANA LONG TERM MEDIUM DEMAND FORECAST

MW

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 99 101 104 107 111 114 118 122 125 130 134

SELF

GENERATORS 16 17 17 17 17 17 17 18 18 18 18

BOSAI MINING 6 6 6 7 7 7 8 8 8 9 9

LECI 5 6 6 6 7 7 7 8 8 8 9

SUB-TOTAL 126 129 133 137 141 146 150 156 159 165 171

GUYSUCO 20 20 20 20 20 20 20 20 20 20 20


OTHER SECTORS - - - - - - - - - - -

HINTERLAND 1 1 2 2 2 2 2 2 2 2 2

TOTAL 147 151 155 159 163 167 172 177 181 187 193

Table 4.11: Long Term ‘Medium’ Demand Forecast 2015-2025



TOTAL GUYANA LONG TERM HIGH DEMAND FORECAST

SECTOR

MW

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

GPL 100 105 110 116 122 128 135 143 149 158 166

SELF GENERATORS 16 17 17 17 17 17 17 18 18 18 18

BOSAI MINING 6 6 6 7 7 7 8 8 8 9 9

LECI 5 6 6 6 7 7 7 8 8 8 9

SUB-TOTAL 128 133 139 146 152 160 168 176 183 193 203

GUYSUCO 20 20 20 20 20 20 20 20 20 20 20


OTHER SECTORS - - - - - - - - - - -

HINTERLAND 1 1 2 2 2 2 2 2 2 2 2

TOTAL 149 155 161 167 174 181 189 198 205 215 225

Table 4.12: Long Term ‘High’ Demand Forecast 2015-2025



4.12 Long Term Generation Dispatch

Figures 4.4 through 4.6 show the generation and load for the three forecast scenarios with

the 140 MW Amaila hydropower station in service.



The following are the generation and sales details associated with the above graphs:

2014 – 140 MW Amaila hydropower station

2015 – Linden load added to the system

2015-2018 – Self generators added to the system

Old Wartsila sets (44 MW) retired in 2022

An analysis of the three forecasts shows the following:

The addition of the Amaila Falls 140 MW hydropower station in 2014 would be

adequate to cover ‘Low’ demand for the entire long term period.

The ‘Medium’ forecast demand lags the ‘High’ forecast demand by two years.

Whereas additional generation would be required in the latter case around 2021,

in the former scenario additional generation could wait until 2023.

Generation dispatch results for both the ‘Medium’ and ‘High’ forecast demands and are

shown in Tables 4.12 thru 4.14.

Table 4.12 below shows the generation dispatch for the Long Term ‘Medium’ forecast

for the period 2015 - 2020. Apart from the four isolated stations in Essequibo, only

Amaila Falls hydropower and Skeldon cogeneration stations are required to meet the

forecast.






GoE Nigaata (5.3 MW) (2) 0 0 0 0 0 0


(18) 0 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 0 0 0 0 0 0

Kingston Wartsila I (5.5 MW) (4) 0 0 0 0 0 0

Kingston Wartsila II (6.9 MW) (3) 0 0 0 0 0 0


Canefield Mirlees (5.3 MW) (2) 0 0 0 0 0 0

Onverwagt GM (2.5 MW) (2) 0 0 0 0 0 0




Bartica Cat (1.1 MW) (2) 3,882 4,159 4,411 4,551 4,696 4,841


Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 0 0 0 0

Amaila Falls Hydro (38 MW), (4) 679,372 727,838 771,843 796,400 821,806 847,145

Hope Beach Wind (4 MW) 0 0 0 0 0 0

New Diesel (7.8 MW), (2) 0 0 0 0 0 0

Tumatumari (50 MW) 0 0 0 0 0 0


Table 4.13: Generation Dispatch for ‘Medium’ Demand’ 2015 - 2020



The generation dispatch for the ‘Medium’ forecast for the period 2021 to 2025 is shown

in Table 4.14 below. Amaila Falls is reaching an output of 1000 GWh and the diesel sets

are gradually being brought back in service.


Primary Generation 2021 2022 2023 2024 2025

Garden of Eden Crossley (5.3 MW) (2) 0 0 0 0 0

GoE Nigaata (5.3 MW) (2) 0 0 0 0 0


(18) 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 0 0 0 0 0

Kingston Wartsila I (5.5 MW) (4) 0 0 0 0 0

Kingston Wartsila II (6.9 MW) (3) 235 2,730 4,339 8,391 12,939

Versailles Nigaata (2 MW) (2) 0 0 0 0 0

Canefield Mirlees (5.3 MW) (2) 0 0 0 0 0

Onverwagt GM (2.5 MW) (2) 0 0 0 0 0

Anna Regina Wartsila (2 MW) (2) 15,630 16,168 16,515 17,058 17,586

Canefield/Onverwagt Cat (1.4 MW) (4) 0 0 0 0 0

Leguaun/Wakenaam Cat (.325 MW) (3) 1,625 1,681 1,718 1,774 1,829

Bartica Cat (1.1 MW) (2) 5,001 5,174 5,285 5,459 5,628

Skeldon Bagasse (15 MW) (2) 25,007 25,869 26,424 27,293 28,138

Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 0 0 0

Amaila Falls Hydro (38 MW),(4) 875,262 905,413 924,851 955,259 984,828

Hope Beach Wind (4 MW) 0 0 0 0 0

New Diesel (7.8 MW), (2) 0 0 0 0 532

Tumatumari (50 MW) 0 0 0 0 0

Total Generation 922,761 957,035 979,132 1,015,234 1,051,480

Table 4.14: Generation Dispatch for ‘Medium’ Demand 2021-2025



Tables 4.15 and 4.16 show generation dispatch results for the ‘High’ forecast.




GoE Nigaata (5.3 MW) (2) 0 0 0 0 0 0


(18) 0 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 0 0 0 0 0 0

Kingston Wartsila I (5.5 MW) (4) 0 0 0 0 0 0

Kingston Wartsila II (6.9 MW) (3) 0 0 0 0 1,120 4,425


Canefield Mirlees (5.3 MW) (2) 0 0 0 0 0 0

Onverwagt GM (2.5 MW) (2) 0 0 0 0 0 0




Bartica Cat (1.1 MW) (2) 4,221 4,415 4,615 4,829 5,063 5,291


Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 0 0 0 0

Amaila Falls Hydro (140 MW) 738,760 772,682 807,589 845,043 885,956 925,895

Hope Beach Wind (4 MW) 0 0 0 0 0 0

New Diesel (15 MW) 0 0 0 0 0 0

Tumatumari (50 MW) 0 0 0 0 0 0


Table 4.15: Generation Dispatch for ‘High’ Forecast 2015 - 2020






GoE Nigaata (5.3 MW) (2) 0 0 0 0 0


(18) 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 0 0 0 0 0


Kingston Wartsila II (6.9 MW) (3) 10,533 15,076 20,054 26,990 45,209



Onverwagt GM (2.5 MW) (2) 0 0 0 0 0




Bartica Cat (1.1 MW) (2) 5,530 5,776 5,985 6,212 6,407


Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 0 3,608 4,995

Amaila Falls Hydro (140 MW) 967,729 1,010,717 1,047,449 1,087,160 1,121,232


New Diesel (15 MW) 0 2,843 6,392 10,736 13,611

Tumatumari (50 MW) 0 0 0 0 0

Total Generation 1,030,519 1,083,214 1,130,457 1,187,202 1,245,593







GoE Nigaata (5.3 MW) (2) 0 0 0 0 0


(18) 0 0 0 0 0

GoE Wartsila (5.5 MW) (4) 0 0 0 0 0


Kingston Wartsila II (6.9 MW) (3) 0 0 0 0 1,386



Onverwagt GM (2.5 MW) (2) 0 0 0 0 0




Bartica Cat (1.1 MW) (2) 4,173 4,386 4,578 4,807 5,057


Skeldon Diesel (5 MW)(1), (2.5 MW) (2) 0 0 0 0 0

Amaila Falls Hydro (140 MW) 730,273 767,615 801,093 841,305 884,934


New Diesel (15 MW) 0 0 0 0 0

Tumatumari (50 MW) 260,812 274,148 286,105 300,466 316,048

Total Generation 1,030,519 1,083,214 1,130,457 1,187,202 1,250,155


Additional 50 MW from Tumatumari in 2021



Figures 4.8 thru 4.10 show the actual and projected generation by fuel type for the years

2008, 2015 and 2025 respectively using the ‘Medium’ Long Term energy forecast. There

are limitations in the generation dispatch model used as it did not cater for the hydrology

data of the hydropower station not for operational requirements to operate diesel sets to

maintain stability and voltage requirements.



4.13 Summary of Results of Generation Dispatch Model

4.13.1 Medium Term

Additional generating capacity is required and the installation of two 7.8

MW sets similar to those newly installed at Kingston is recommended.

Available generation can meet the GPL generation forecast without the

Self Generators

The Amaila Falls hydropower project should begin construction at the

earliest period because the winning back of self generators would only be

possible if this station is on stream.

4.13.2 Long Term

Three load forecasts are considered for the long term, ‘Low’, ‘Medium’ and

‘High’.



With the Amaila Falls hydropower station assumed installed in 2013/14 with an

available capacity of 140 MW, the available generation can meet the forecasted

demand and energy requirement for the ‘Low’ forecast. This forecast includes

Linden and the self generators.

For the ‘Medium’ forecast, the situation is almost similar except that towards the

end of the period, diesel sets are beginning to be dispatched to meet the energy

requirement. It is to be noted that for most of the period, only the Skeldon

cogeneration station and the Amaila Falls hydropower station are contributing to

the dispatch.

For the ‘High’ forecast Amaila Falls hydropower station is being dispatched for

more than 1000 GWh in 2022 and the newer diesel stations are also being

dispatched.

Additional available generating capacity of 50 MW (possibly from Tumatumari)

relieves this situation. (Tables 4.15 and Figure 4.6). Figure 4.6 also shows that if

the growth rate were to continue then increased generating capacity would soon

be required.

Because of the limitations of the dispatch model, the Guyana Power Sector Policy

document shows the generation by fuel type as hydro – 80%, diesel – 10%,

bagasse 10%.


The issues and options of Primary Energy have been effectively dealt with in Generation

Technology and no new issues have arisen. The type of generation technology to be

employed in the medium and long term, the timing of additional generation and the use of

the Clean Development Mechanism to reduce the costs of renewable energy projects have

already been discussed in Chapter 3.

Chapter 5 NETWORK ISSUES

CHAPTER 5 NETWORK ISSUES


5.0 NETWORK ISSUES

5.1 Introduction

Traditionally, electricity is generated at medium voltages (11 – 25 kV) and transmitted in bulk at

high (HV) or extra high (EHV) voltages to the main load centres. It is then distributed at lower

voltages to consumers. As the size of the transfer of power and the distances increase, then the

required voltages for transmission become higher. In the 1970’s, a major electricity

developmental project in Guyana sought to provide an interconnected system at 69 kV

connecting the power stations in Berbice and Demerara. This voltage level has been adequate

for the levels of transfer of power and the distances of the transfer. Presently, however, a project

is being developed for a hydropower station at Amaila Falls which will necessitate a 278 km

transmission line to Sophia in Georgetown. A 230 kV transmission system has been proposed.

As has been mentioned before, the development of electricity in Guyana has not been centralized

with all users connected to the same national grid, but has been fragmented with the main

industries, sugar and bauxite, developing their own power systems and the main power company

supplying power to the rest of the mainly coastal community. This situation has not been helped

by certain parts of the country being developed with a 50 Hz system and other parts being

developed at 60 Hz. The main purpose of this section on Network Issues therefore is to

determine the feasibility of all electricity users in Guyana being connected to one national grid

and thus the users benefitting from the economies of scale that such a national network can

bring. In consideration of all the issues surrounding the development of a national grid for

Guyana, it is therefore necessary to examine the following:

The present and future loads of GPL’s system and the ability of the present and proposed

69 kV transmission systems to meet the future demands.

The proposed 230 kV transmission line from the Amaila Falls hydropower station to

Sophia and the possibility of it being connected to other major loads.

Feasibility of further interconnections with the sugar and other mining industries.

The feasibility of importation of cheap electricity from neighbouring countries.

The use of ‘smart grid’ technology to offset high generation costs.

Unbundling of the transmission and distribution systems in an attempt to better manage

the power system.



5.2 GPL’s Transmission Network

The Guyana Power and Light Inc. (GPL) operates the following power systems:

The Demerara Interconnected System, (DIS) which had a peak of 70 MW in 2008 is

interconnected at 69, 13.8 and 11 kV. The 69 kV sub-transmission line connects the

power stations at Garden of Eden, Sophia and Kingston. Versailles power station is

interconnected at 13.8 kV to the Garden of Eden power station. The afore-mentioned

systems all operate at 60 Hz. Additionally there is a 50 Hz system where Sophia is also

linked to the Kingston 50 Hz generation by 11 kV distribution lines. There is a plan to

complete conversion of all 50 Hz areas to 60 Hz by 2012. The 69 kV network in

Demerara consists of 43 km of lines using partridge conductors. The location and sizes

of the 69/13.8 kV substations are as follows:

Kingston: 1 x 35 MVA, 69/13.8 kV

Sophia: 3 x 16.7 MVA, 69/13.8 kV

Garden of Eden: 3 x 16.7 MVA, 69/13.8 kV

The Berbice Interconnected System, (BIS) had a peak of 16 MW in 2008 and is

interconnected at 69 and 13.8 kV. 69 kV sub-transmission lines link the Canefield and

Onverwagt power stations. The 69 kV transmission line from Canefield extends east

along the Corentyne Coast to the #53 Village substation. Presently a 13.8 kV distribution

line links the #53 Village substation to the new cogenerating facility at the Guysuco’s

Skeldon location. A 69 kV line which will replace this 13.8 kV line is now under

construction. Berbice has 107 km of 69 kV network also using partridge conductors.

The 69/13.8 kV substations in Berbice are as follows:

Onverwagt: 1 x 16.7 MVA

Canefield: 1 x 16.7 MVA

# 53 Village : 1 x 16.7 MVA

Skeldon: 1 x 16 MVA

A 13.8 kV distribution line is sometimes operated to link the Demerara and Berbice

systems.

Four isolated systems are operated in the Essequibo region at Anna Regine, Bartica,

Wakenam and Leguan. The size of the power stations in Essequibo range from 4 to 0.4

MW. These systems had a combined systems peak of 5.0 MW in 2008.

GPL is in the process of commencing works to extend the present 69 kV network (using a

larger sized Canton conductor) as follows:

o Kingston to Edinburgh via Versailles with a 69 kV submarine cable across the

Demerara river and 69 kV transmission line to Edinburgh

o Sophia substation to Onverwagt substation (both upgraded)

o Sophia substation to South Georgetown (Durban Backlands) substation

o 69/13.8 kV substations at Mahaica, Good Hope and Diamond.



The new 6913.8 kV substations to be constructed are as follows:

o Mahaica and Good Hope: 1 x 16.7 MVA each

o Edinburgh: 1 x 10 MVA

o Versailles: 1 x 20 MVA

o Durban Backlands: 2 x 16.7 MVA.

o Diamond: 2 x 10 MVA

o Sophia (upgraded): 4 x 16.7 MVA

o Onverwagt (upgraded) 1 x 16.7 MVA

The single line diagram of the proposed 69 kV transmission system is shown in the load flow

diagram presented in Appendix III. The proposed 69 kV network in Guyana is shown in Figure

5.1.

A summary of the present and proposed interconnecting lines are shown in Table 5.1

From To Voltage

(kV)

Length

(km) Remarks

Garden of Eden Versailles 13.8 17 Existing

Garden of Eden Sophia 69 2 x 19 Existing

Sophia Kingston 69 5 Existing

Sophia Kingston 11 3 x 5 Existing

Sophia Durban

Backlands 69 5 Proposed

Kingston Edinburgh 69 22 Proposed

Sophia Onverwagt 69 80 Proposed

Onverwagt Canefield 69 32 Existing

Canefield # 53 Village 69 75 Existing

#53 Village Skeldon 13.8 19 Existing

#53 Village Skeldon 69 19 Under

construction

Table 5.1: GPL’s Existing and Proposed 69 kV Network



5.2.1 Load Centres

In order for transmission network development to be planned it is necessary to develop regional

load forecasts so that growth at the various load centres can be established. In Section 2 of this

Report a national load forecast was developed for the medium (2009 – 2014) and the long term

(2015 – 2025). Three scenarios were considered for the long term forecast as follows:

GDP annual growth rate of 3.5% (Low forecast)

GDP annual growth rate of 5% (Medium forecast)

GDP annual growth rate of 7% (High forecast)

The loads for various years for the three forecasts are shown below:

Year

Load Forecast (MW)

Low Medium High

2008 91 91 91

2012 95 95 95

2016 116 118 122

2018 118 124 133

2020 121 131 145

2022 125 140 161

2025 129 152 184

Table 5.2: Low, Medium and High Load Forecasts for Various Years

In order to determine the capability of the 69 kV transmission system, the load needs to be

apportioned to the various load centres. Ideally, a combination of a regional and a national

forecast would best suit this task, however, using the various growth rates and transferring some

of the existing loads to the new proposed substations a projection for loads at the various load

centres up to 2025 has been developed for the ‘Medium’ forecast and is shown Table 5.3.

The assignment of the loads to the various centres was done as follows:

The Georgetown busbars at Sophia and Kingston now supply 80% of the Demerara

system load. It is anticipated that the new substation at Durban Backlands will offload

Sophia and will also pick up some of the self generators load by 2016. Good Hope will

also relieve Sophia and will cater for load growth along the East Coast Demerara.

The East Bank Demerara busbars at Garden of Eden and Diamond will receive most of

the loads acquired from the self generators. It is anticipated that in the future the East

Bank Demerara will develop into a major load centre.



Nominal load growths are projected for West Demerara (Versailles and Edinburgh), West

Berbice (Onverwagt and Mahaica), and East Berbice (Canefield and #53 Village).

Load Centre

Load Projections (MW)

Medium Forecast

2008 2012 2016 2020 2025

Sophia 33 18.5 20 22 23

Kingston 23 24 25 26 27

Durban Backlands 0 10 14 16 20

Good Hope 0 5 7 8 10

Sub-total 56 57.5 66 74 80

Garden of Eden 7 4 5.5 6 8.5

Diamond 0 3.5 9.0 12 16

Sub-total 7 7.5 14.5 18 24.5

Versailles 7 4 4 5.5 6.5

Edinburgh 0 3.5 5 4.5 5.5

Sub-total 7 7.5 9 10 12

Mahaica 0 2.5 2.5 3 3.5

Onverwagt 4.8 2.5 3.5 4 4.5

Sub-total 4.8 5.0 6 7 8

Canefield 6.7 7.5 9.0 9.5 11

# 53 Village 4.5 5.0 7.5 8 9

Sub-total 11.2 12.5 16.5 17.5 20

Demerara/Berbice 86 89.5 112.0 124.5 144.5

Essequibo 5 5.5 6 6.5 7.5

TOTAL 91 95 118 131 152

Table 5.3: Estimates of Loads at various Load Centres up to 2025



5.2.2 Load Flows

Load flow runs were carried out for each of the above-mentioned years with the various loads as

determined in Table 5.3. Details of busbar voltages and line and transformer flows are given in

the Appendix. A single line diagram of the network is also shown in the Appendix.

2012

In 2012 it was considered that the Demerara and Berbice systems were interconnected at

69 kV and all the proposed substations had been built and were in service. Frequency

conversion to 60 Hz was also completed including the conversion of the 50 Hz power

station at Kingston. Power factor of the loads were determined to be 0.91 for Berbice and

0.87 for Demerara.

o For minimum losses it was necessary to have some generation in Berbice and 10

MW of generation at Skeldon was chosen

o Generation was utilized at Kingston, Garden of Eden and Skeldon with Garden of

Eden chosen as the slack bus, that is, the bus to take up any extra load and losses.

This configuration gave total system losses of 1.02 MW (1.1%).

o All transformer tap positions needed to be set at between 97.5 and 95 % for

acceptable voltage levels. As the load flows represented conditions of system

peaks the use of on-load tap changers on the transformers is recommended.

o No additional capacitors were utilized on the network.

2016 In 2016, Amaila Falls hydropower station was considered in service and represented as a

generator at Sophia 69 kV busbars. (A load flow study for the Amaila Falls/Sophia

interconnection has already been completed.) Two scenarios were considered,

importation of 100 MW and 50 MW (Case 1 and 2 respectively) from Amaila Falls.

Kingston and Skeldon power stations were considered in service for Case 1 and Garden

of Eden power station was also included for Case 2.

o Total system losses were 1.9 MW (1.7%) for Case 1 but decreased to 1.75 MW

(1.5%) for Case 2.

o For Case 1 shunt capacitors were necessary at all the Berbice 13.8 kV distribution

busbars and also at the Garden of Eden busbars. Kingston power station supplied

a large amount of inductive MVars.

o For Case 2 shunt capacitors were only necessary for the Berbice 13.8 kV

distribution busbars.

2020 In 2020 the Demerara/Berbice system peak was projected at 124.5 MW. System losses

increased to 2.43 MW (1.9%) if the majority of this load was taken from the Amaila Falls

(115 MW). This loss was reduced to just over 2.0 MW (1.6%) if only 100 MW was

imported from Amaila Falls and Kingston was placed in service. Additional capacitance

was required for all the 13.8 kV busbars in Berbice.



2025 With a maximum load of about 145 MW and 130 MW being imported from the Amaila

Falls hydropower station, the 69 kV system losses were 3 MW (2.1%). Even more

capacitors were required for the Berbice busbars.

For the ‘Medium’ load forecast the 69 kV transmission system seems adequate for Demerara

until 2025 however by 2020 the Berbice voltage levels required increasing reactive

compensation to bring them up to acceptable levels.

The following needs to be noted:

o The loads depicted at the load centres are crude estimates and may not be very accurate.

o Operationally it would be necessary to keep some amount of generation in Demerara and

this would reduce the 69 kV system losses.

o It is assumed that there is just nominal load growth in Berbice and there is no major

development there. The Sophia/Onverwagt transmission line is accountable for between

40 and 55% of the transmission losses and should the Berbice load be more than

projected, then losses would definitely increase.

o All load flows envisage 10 MW of generation at Skeldon. If this is not available then the

losses increased as much as 250% and by 2020 the voltage levels in East Berbice cannot

be sustained. (Assuming also no generation at Onverwagt and Canefield)

o It will therefore be critical to determine the timing of the upgrade of the

Sophia/Onverwagt line and the voltage upgrade. For major development in Berbice, then

the 230 kV line can be extended. However it seems more likely that an upgrade to 138

kV may be more realistic. This would however necessitate the Sophia substation to

become a 230/138/69 kV substation. The more economic alternative would definitely

depend on the system loads.

o The analysis was done for the ‘Medium’ forecast. For the ‘Low’ forecast scenario, the 69

kV transmission system would be adequate throughout the study period. For the ‘High’

forecast scenario the transmission system upgrade would be required by 2016.

It is very important that load forecasts be adjusted annually and long term forecasts be done

every five years so that changes can be made to the development plans and any necessary

decisions can be made in good time.



5.3 Transmission Network Considerations

The Amaila Falls hydropower project is expected to become operational in 2013/14. This

project entails the construction of a hydropower facility consisting of 4, 40 MVA, 13.8 kV

generators linked to a 13.8/230 kV switchyard consisting of 2, 48/64/80 MVA, 13.8/235.75 kV

transformers. A double circuit 230 kV transmission line will connect this switchyard to a new

GPL’s Sophia 230/69 kV substation which will consist of 2, 60/80/100 MVA transformers. The

transmission line will also supply a 50 MVA, 230/13.8 kV substation at Linden. Figure 5.1

shows the anticipated transmission line route.

Load flow studies1 have been performed on the Amaila Falls/Linden/Sophia Interconnection

with the following projected peak loads.

Year

Projected

Peak Load

(MW)

2008 99

2012 115

2013 119

2014 123

2015 127

2016 131

2017 135

Table 5.4: Loads considered for the Amaila Falls Power Flow Study

The load flow study deemed the system capable of supplying the projected maximum

load in 2017 and noted the technical considerations that were necessary for line

energisation, operation with only one 230 kV transmission line in service, and general

system operations.

It was indicated that the transmission voltage of 230 kV was chosen because at 138 kV

there would not have been enough voltage regulation with one line in service and also the

fact that 230 kV is utilised in both Brazil and Venezuela.

The load at Linden was expected to have a peak of 11 MW in 2017 and Sophia would

receive the remaining power required for the grid.

The 69 kV and 230 kV transmission voltages have been determined prior to this study. The

other considerations are therefore as follows:

This study proposes the development of another hydropower station, possibly

Tumatumari. The extension of the 230 kV network to Tumatumari or any other location

in the Potaro basin would be necessary to transmit the power to Georgetown.

1 Amaila Falls Hydroelectric Project, Guyana, Power System Study Report, Transmission Interconnection, prepared for Sithe Global Power

Ventures LLC by MWH Americas, Inc. May 2008



It is also being proposed that the 69 kV network could be extended to areas to encourage

industrial development. The Soesdyke/Linden highway is one such area where this can

be considered.

The development of a 138 kV transmission network from Sophia to Onverwagt and also

possibly to Garden of Eden needs to be considered by 2016.

A 230 kV link to Berbice could also be considered if loads in that area increase

appreciably.

Guyana’s 230 kV transmission system is shown in Figure 5.1 below.

.

Figure 5.1: Guyana’s Proposed 230 kV Transmission Network



5.4 Interconnections with Other Industries

Guyana’s main traditional industries have been rice, sugar and bauxite. The rice industry has

been developed on relatively small scales and individual companies either self generate or

purchase power from the utility. The sugar and mining industries are more likely to present

opportunities for interconnection to a national grid.

5.4.1 The Sugar Industry

GPL is constructing a 69 kV interconnection to Guysuco’s Skeldon cogenerating facility with the

possibility of a maximum transfer of 10 MW to GPL. Guysuco has developed this cogeneration

facility as a part of its attempts to diversify from sugar, although sugar cultivation is an integral

aspect of the cogeneration. The use of bagasse for fuel is eco-friendly and the Skeldon project

has been registered as a Clean Development Mechanism (CDM) project. In its design for the

Skeldon power plant Guysuco had to change its traditional system frequency from 50 Hz to 60

Hz.

The other Guysuco estates operate at 50 Hz and have installed generating capacities ranging

from 3.5 to 8.5 MW. With the concept of Distributed Generation (small generating facilities

connected to national grids), these estates could have presented an excellent opportunities for

interconnection to the national grid. It is anticipated that the need for frequency conversion

would make such a venture uneconomical.

There is still however the possibility of another estate being chosen for a cogeneration project

similar to Skeldon, however, such a decision has not yet been made.

5.4.2 The Mining Industry

As mentioned previously in this section, the 230 kV network from the Amaila Falls hydropower

station will be connected to a substation at Linden to supply the bauxite plant at Linden and the

Linden community. This report forecasts this load growing to a maximum of 18 MW in 2025.

However the recovery of the global economy could change these forecasts. At present, however,

this represents the only ‘major’ load from the mining industry that can be connected to a national

grid.

5.5 Interconnection to Neighbouring Countries

In February of 2010 seven African countries announced their intention to jointly produce power

and have their supplies interconnected. These countries are Burundi, Democratic Republic of

Congo, Egypt, Kenya, Ethiopia, Sudan and Rwanda. It was stated that Uganda, Tanzania and

Djibouti were also willing to join. The expected benefits of such interconnections were stated as:

Export of power to other countries with energy deficits

Use of the natural renewable energy resources of those countries that have them

Reducing the cost of electricity

Trading in electrical energy



Contribution towards the economic growth of the region

A similar effort in Central America would see Guatemala, El Salvador, Honduras, Nicaragua,

Costa Rica and Panama cooperating on a $494 million project known as Siepac to build two 230

kV, 1830 km transmission lines with a capacity of 300 MW which could be doubled. This

project is expected to be completd in 2010. Siepac is not a full integration of the region’s

electricity grids but would create a transnational electricity market in which countries could trade

power while continuing to run their own national grids. Additionally in Central America Mexico

shares power with Guatemala, and Panama and Colombia are investigating bilateral

interconnection.

In South America, Brasil with an installed capacity of 85 GW has a 2.2 GW link to Argentina

and owns a joint 14 GW hydroeletric plant with Paraguay. In November 2007, Chile, Bolivia,

Ecuador, Peru, Colombia decided to explore the possibility of interconnecting their systems.

Venezuela has an installed capacity of 23 GW and does small exports to Brasil and Colombia. It

has however been reported that only about 1% of power is traded across countries in the Latin

American region.

Guyana has borders with three countries, namely, Brazil, Venezuela and Surinam. The installed

capacity of the Surinam system is in the region of two to three hundred megawatts, however both

Brazil and Venezuela have power systems several orders of magnitude larger than that of

Guyana. The transmission networks of these countries are shown In Figures 5.2 and 5.3. As

mentioned before both these countries have 230 kV systems, however Guyana’s proposed 230

kV transmission network is not in the region close to these borders. (See Figure 5.1)

The following reasons suggest that it is unlikely that interconnection with neighbouring countries

could be considered in the period covered by this report:

Guyana’s small loads makes such an interconnection economically unfeasible.

Connecting Guyana’s small system to large networks via long tranmsission lines would

make Guyana’s system operationally unstable.

Guyana is presently interested in developing its own hydropwer resources.

Venezuela is presently facing power shortages as the consequence of the El Nino effect

on the water supplies for its hydropower dams and such situatios coul reoccur.

Political considerations may make such a decision unfavourable.



Figure 5.2: Venezuela’s Transmission Network



Figure 5.3: Brazil’s Transmission Network



5.6 Smart Grid Technologies

A ‘smart grid’ delivers electricity from suppliers to consumers using two-way digital technology

to save energy, reduce cost and increase reliability. Such a modernized electricity network is

being promoted by many governments as a way of addressing energy independence or global

warming issues. The basic concept of the smart grid is to add monitoring, analysis, control and

communication capabilities to the national electricity delivery system in order to maximize the

output of the system while reducing energy consumption. The major driving forces to modernize

current power grids can be divided into three general categories.

Increasing reliability, efficiency and safety of the power grid

Enabling decentralised power generation so that homes can be both an energy client and

supplier and providing consumers with interactive tools so that they can manage their

energy usage.

Flexibility of power consumption at the client’s side so that the client can select the

supplier from either distributed generation, wind, solar or biomass, or any other.

The seven principle characteristics of a smart grid have been defined as2

o Enable active participation by consumers

o Accommodate all generation and storage options

o Enable new products, services and markets

o Provide power quality for the ranges of needs in a digital economy

o Optimise asset utilisation and operating efficiency

o Anticipate and respond to system disturbances in a self healing manner

o Operate resiliently against physical and cyber attacks and natural disasters

Six levels of intelligence have been defined to indicate the various levels that can be achieved in

the pursuit of a ‘smart gird’. These are

Level 0 - Manual observation, no observability, no controllability

Level 1 - Electronic digital communication. Either one way or two way.

Level 2 - Self actuation and basic automation

Level 3 - Self optimization and adaptive behavior

Level 4 - Collaboration

Level 5 - Prediction and Plan Development

2 Level of Intelligence White Paper on Smart Grid by National Electrical Manufacturers Association Copyright 2009

http://en.wikipedia.org/wiki/Grid_(electricity)

http://en.wikipedia.org/wiki/Energy_security

http://en.wikipedia.org/wiki/Global_warming

http://en.wikipedia.org/wiki/Global_warming



These six levels of intelligence are further defined in the following table for transmission

networks. These are based on the fact that conductor ratings are normally based on a worst case

scenario and higher short term ratings can be achieved if, for example, temperature readings of

the conductors are constantly taken.

Intelligence

Level

Intelligence Level Description

0 No real-time rating presence in the transmission network

1 A sufficient number of sensors are located on and along the

transmission line to capture parameters that reflect the impact of the

variability of weather on the rating of the transmission line. Self

diagnostic information e.g. battery voltages is also measured by the

sensors

2 A master unit, typically located at a substation provides time

synchronization to the Level 1 sensors. It also consolidates data from

Level 1 sensors to delivery for a wide area control unit. The master

unit interfaces with a wide array of SCADA communication

protocols.

3 A server PC on the SCADA network utilizes data from the Level 1

sensors and line load metering to calculate conductor temperature and

real time rating based on the actual weather conditions. Both a

continuous (24 hr) and a short term user-configurable emergency

rating are calculated.

4 The system monitors the sanity of data received from the Level 1

sensors. Invalid data are flagged and removed from the rating

calculations. All outputs from the software are delivered to the

SCADA as analog values or status points. The outputs can be

delivered as outputs to other programmes or displayed for the grid

operator as text or graphic format.

5 True capacity that is real time ratings from other regions enables the

local Level 4 regional system to optimize its own regional dispatch

and to draw from previously constrained economical power from

other level 4 regions

In addition to the scope for smart grid technology in the transmission network there are other

areas in the power system where smart grid innovations are being considered, namely,

Distribution feeder automation. An intelligent system entails installing devices that are

capable of communicating with each other, exchanging data and taking the necessary

control actions based on this data.

Distributed Generation (DG) and Demand Response (DR). Distributed generation

technology is concerned with integrating into the power system infrastructure small scale



generators that have been installed near load centres. Demand response is the adjustment

of consumer demand in response to real time system operating conditions.

Advanced Metering Infrastructure (AMI). The system measures, collects, analyses and

controls customer energy usage by advanced metering, communications and data

management systems. Some smart applications brought about by AMI systems include

automated meter reading, outage management, demand response and tamper/theft

detection

Smart grid technology is changing the way power systems are being monitored and controlled

and GPL should keep abreast of these developments even if it may not be economical or

necessary to install any of these systems at present. In its use of pre-paid meters GPL is utilizing

smart grid technologies and there may be other innovative areas in which it may be able to utilize

this technology in the future.

5.7 Unbundling Transmission and Distribution3

There are broadly two main electricity services, the production of electricity (known as

generation) and the delivery of electricity (known as transmission and distribution). There may

also be as many as ten ancillary services supporting the industry. Unbundling is defined as the

process of identifying each of the services provided by the electricity utility, determining its cost,

and providing a framework whereby these services can be provided independently.

Unbundling has been driven by the need for greater efficiency and deregulation of all or part of

the electricity industry. The provision of competition in any of the services is determined by the

following:

Effective competition should help to develop the market

Competition in the service will not harm any class of consumer

Competition is likely to decrease the cost of service to consumers or increase the quality

or innovation of the service to consumers, and,

Competition for the service will not jeopardize the safety and reliability of the service.

Different countries have unbundled transmission from supply and distribution in one of the

following models:

Transmission system operators have been effectively separated from generation and

distribution activities without ownership unbundling. This model enables companies to

retain ownership of their transmission networks however the networks are operated by a

new independent transmission network operator.

The independent transmission operator where the transmission system is fully unbundled

from the rest of the system and owns and operates its own assets.

3 The Ownership Unbundling of Electricity Transmission System Operators: The European Union Policy and the case in Lithuania ISSN 392-2785



The legally unbundled system operator where the transmission network is legally

unbundled from the rest of the system and owns and operates its own assets.

The independent system operator where the system operator does not own the

transmission system and is ownership unbundled from the rest of the system

The hybrid model where both the independent system operator and the transmission

operation are unbundled from the rest of the system. The independent system operator is

asset light and the transmission operation has no system operation function.

Ownership unbundling means that the same person or persons cannot exercise control over a

supply or generation undertaking and at the same time hold any interest in or exercise any right

over a transmission operator or transmission system and vice versa. The question of control in a

fully unbundled network operator means that irrespective of private or public ownership no

person or group of persons should be able to alone or jointly influence the composition of

boards, the voting or decision making of either transmission system operators or the supply and

distribution companies.

Full ownership unbundling of transmission systems has the following advantages:

It solves inherent conflict of interest, promotes transparency and inspires trust in third

parties

Transmission system operators focus on efficient operation and network expansion

Security of supply is assured because investment disincentive is removed

A careful cost benefit analysis is needed in each country’s case to estimate the size of costs

relative to the benefits. There is a high probability that in small countries where the scope of

competition may be limited and managerial experience is scarce the benefits of unbundling are

likely to be small in relation to its costs.

Guyana faces the following issues as it develops its first major 230 kV transmission network

which will be built by an Independent Power Producer.

Which entity would be the eventual owner of the network?

Which entity should control the network? At present GPL is the only company with

experience in power systems control and operations.

Should the 69 kV sub-transmission network be considered as a part of the transmission

system?

This study does not envisage any major development of the 230 kV transmission system, either

to other major industries, or to neighbouring countries, where the issue of power trading may

also come into play. GPL has also invested in a SCADA system which should become

operational in the next two years. It would therefore seem prudent that ownership and control of

the transmission system be given to GPL and the training of personnel to operate the new system

should be given the highest priority.




Regional Load Forecasts

This section shows that not only are national (top-down) approach to load forecasting

important, but also the regional (bottom-up) method of load forecasting. Some countries

adopt both methods and combine the two into one overall forecast. It is not possible to

plan the development of transmission and distribution systems without the regional load

forecasts.

It is recommended that, Regional and Area Managers within the GPL system be given

responsibilities, not only for operations and maintenance, but also for load forecasting,

that is, the provision of information to the System Planning section which can aid in the

development of regional load forecasts for the medium term (5 years).

69 kV Transmission Network Development

Although not considered in this study, the proposed 69 kV transmission network

development should reduce total system losses and provide the facilities for system

growth. However when the Amaila Falls hydropower station comes on stream the

transmission system losses increase when power is supplied only from that source.

The National Development Strategy (2001-2010) envisaged the development of Export

Promotion Zones in both Demerara and Berbice. These zones were not identified,

however it is noted that industrial development can be enhanced when electricity is first

provided. It is being suggested that the Linden/Soesdyke Highway area can be

considered as an industrial zone and a 69/13.8 kV substation with associated 13.8 kV

feeders can be established there.

Other Transmission Network Considerations

The need to develop a 138 kV network or extend the 230 kV network would have to be

addressed by 2016 and load growth would determine which option is chosen. This would

reduce transmission system losses especially in the Demerara/Berbice link.

National Grid

Future interconnections to other major industries do not seem likely during the study

period. Some of the issues that could change this are additional cogeneration facilities by

Guysuco or a new large mining development within the area of the proposed 230 kV

transmission network.

Interconnections to Neighbouring Countries

This also does not seem to be an option that can be recommended within the study

period. The small load of the Guyana system does not make construction of a

transmission line to any of the other neighbouring countries economically feasible. Also

Guyana should develop its own hydropower facilities and may in the future be in a

position to sell power to these countries.



Smart Grid Technology

GPL should continue to keep abreast of the innovative developments in the area of Smart

Grid Technology as it may be able to use such equipment to improve its system losses.

Unbundling Transmission and Distribution

With the present and proposed limited transmission network, and also the scarcity of

trained personnel, it seems prudent for GPL to continue to be a vertical utility, at least

during the period under study.



Figure 5.4: Load Flow Run - 2016 Forecast Projections



Figure 5.5: Load Flow Run - 2025 Load Projections

Chapter 6 ENERGY EFFICIENCY

CHAPTER 6 ENERGY EFFICIENCY


VERLYN KLASS - CONSULTANT

6.0 ENERGY EFFICIENCY

6.1 Introduction

Energy efficiency encompasses all changes that result in a reduction in the energy used for a

given energy service (heating, lighting...) or level of activity. This reduction in the energy

consumption is not necessarily associated to technical changes, since it can also result from a

better organization and management or improved economic efficiency in the sector (e.g. overall

gains of productivity).

Energy conservation is defined as the reduction in the amount of energy consumed by a process

or system or by an organization or society through economy, elimination of waste and rational

use.

Energy efficiency and conservation reduces energy consumption and energy demand per capita

and thus offsets some of the growth in energy supply needed to keep up with population growth.

The consequence of this is a reduction in the rise in energy costs, the need for new power plants

and energy imports. This reduced energy demand can also provide more flexibility in choosing

the most preferred method of energy production. It is therefore important that Guyana adopts

energy efficiency and conservation measures to ensure that is benefits from all of the results that

these measures can bring.

Energy intensity is a measure of the energy efficiency of a nation's economy and is calculated as

units of energy per unit of GDP.

High energy intensities indicate a high price or cost of converting energy into GDP.

Low energy intensity indicates a lower price or cost of converting energy into GDP.

Many factors influence an economy's overall energy intensity. It may reflect requirements for

general standards of living and weather conditions in an economy. It is not atypical for

particularly cold or hot climates to require greater energy consumption in homes and workplaces

for heating (furnaces, or electric heaters) or cooling (air conditioning, fans, refrigeration). A

country with an advanced standard of living is more likely to have a wider prevalence of such

consumer goods and thereby be impacted in its energy intensity than one with a lower standard

of living.

The Energy Intensity for Guyana for the period 1994-2008 has been calculated and is shown in

Table 6.1 below.

http://dictionary.babylon.com/Measurement#!!ARV6FUJ2JP

http://dictionary.babylon.com/Economic%20system#!!ARV6FUJ2JP

http://dictionary.babylon.com/energy#!!ARV6FUJ2JP

http://dictionary.babylon.com/GDP#!!ARV6FUJ2JP

http://dictionary.babylon.com/standards%20of%20living#!!ARV6FUJ2JP

http://dictionary.babylon.com/energy%20consumption#!!ARV6FUJ2JP

http://dictionary.babylon.com/furnace#!!ARV6FUJ2JP

http://dictionary.babylon.com/electric%20heater#!!ARV6FUJ2JP

http://dictionary.babylon.com/air%20conditioning#!!ARV6FUJ2JP

http://dictionary.babylon.com/fan%20%28mechanical%29#!!ARV6FUJ2JP

http://dictionary.babylon.com/refrigeration#!!ARV6FUJ2JP




Table 6.1 Energy Intensity Data for Guyana 1994-2008

YEAR POPULATION

GDP CURRENT

PRICES

FINAL

CONSUMPTION

GDP PER

CAPITA

ENERGY

INTENSITY

(POP -Thousands) (US$MILLION) (000's BBLS) US$GDP/POP TOE/ US$M-GDP

1994 763.7 456.8 3967.3 598.1 1185

1995 773.4 520.9 4029.8 673.5 1055

1996 777.6 583.1 4360.6 749.9 1020

1997 777.8 629.0 4417.1 808.7 958

1998 777.1 593.2 4441.4 763.4 1021

1999 781.2 591.6 4182.6 757.3 965

2000 743.1 592.4 4191.1 797.3 965

2001 744.2 579.0 3973.0 778.0 936

2002 751.2 614.1 4022.9 817.5 894

2003 753.7 636.0 3907.3 843.8 838

2004 756.3 658.2 4037.3 870.3 837

2005 758.9 638.2 3600.0 841.0 770

2006 761.5 755.3 3218.8 991.9 581

2007 770.8 835.1 3825.2 1083.4 625

2008 766.2 936.6 3867.3 1222.5 563

Source; GEA, Bureau of Statistics, Bank of Guyana

1 ton of oil equivalent (TOE) = 7.33 barrels of oil

Although the energy intensity figures for Guyana have been decreasing, this does not necessarily

mean that this has been as a result of improved energy efficiencies. The decreasing agriculture

and mining sector accompanied by an improving services sector means that less energy is used to

produce each dollar of GDP.

Energy intensity figures in tons of oil equivalent per/US$M-GDP for Trinidad and Tobago and

Jamaica for 20031 are 766.2 and 401.1 respectively. As mentioned before it is difficult to draw

an exact comparison between different countries because the nature of their economies is

sometimes vastly different.

1 http://en.wikipedia.org/wiki/List_of_countries_by_energy_intensity




The National Energy Policy (NEP) of Guyana (1994) has outlined as its objectives the following:

To provide stable, reliable and economic supply of energy

To reduce dependency on imported fuel

To promote where possible the increased utilization of domestic resources

To ensure energy is used in an environmentally sound and sustainable manner.

The National Energy Policy further states that the major policy options to achieve the stated

objectives are:

Rationalisation of the Energy Sector

Development of indigenous new and renewable sources of energy

Exploration and development of indigenous oil and gas resources

Promotion of energy conservation through the efficient and rational utilization of

energy while pursuing sustainable economic development

Ensuring stable supply of energy at the lowest possible cost

Provision of fiscal incentives and encouragement of joint-venture programmes to

achieve the above.

In an attempt therefore to produce a framework whereby the National Energy Policy can be

implemented, this section on Energy Efficiency will deal with the following five areas.

Energy Audits

Energy Efficiency Programmes

Renewable Energies for Commercial and Domestic Applications.

Demand Side Management

Incentive Schemes

6.2 Energy Audits

The primary objective of the energy audit is to determine ways to reduce energy consumption

per unit of product or to lower operating cost. It is an inspection, survey and analysis of energy

flows for energy conservation in a building, a process or system to reduce the amount of energy

input without negatively affecting the output(s).

The energy audit is a systematic study or survey to determine how energy is being used in a

building or a plant. It is also a useful procedure to find out the best options for energy

conservation. Energy audits provide an analysis of the amount of energy consumed during a

given period in the form of electricity, gas, fuel, oil or steam. Using that information, it is also

possible to determine how the energy was used according to the various processes in a plant or at

the various outlets in a building. The next step in an energy audit then is to identify the potential

for energy savings accurately.




6.2.1 Types of Energy Audits2

The term energy audit is commonly used to describe a broad spectrum of energy studies ranging

from a quick walk-through of a facility to identify major problem areas to a comprehensive

analysis of the implications of alternative energy efficiency measures sufficient to satisfy the

financial criteria of sophisticated investors. Some common audit programmes are described

below.

6.2.1.1 Preliminary Audit

The preliminary audit, alternatively called a simple audit or a walk-through audit, is the simplest

and quickest type of audit. It involves minimal interviews with site operating personnel, a brief

review of facility’s utility bills and operating data, and a walk through of the facility to become

familiar with the building operations and to identify any glaring areas of energy waste or

inefficiency.

Typically, only major problem areas will be uncovered during this type of audit. Corrective

measures are briefly described, and quick estimates of implementation cost, potential operation

cost savings and simple payback periods are provided. This level of detail, while not sufficient

for reaching a final decision on implementing proposed measures, is adequate to prioritise energy

efficient projects and to determine the need for a more detailed analysis.

6.2.1.2 The General Audit

The general, detailed or complete site energy audit expands on the preliminary audit described

above by collecting more detailed information about the facility’s operations and by performing

a more detailed evaluation of energy conservation measures. Utility bills are collected for a 12

to 36 month period to allow the audit to evaluate the facility’s energy/demand rate structures and

energy usage profiles. Additional metering of specific energy-consuming systems is often

performed to supplement utility data. In-depth interviews with facility operating personnel are

conducted to provide better understanding of major energy consuming systems and to gain

insight into short and longer term energy consumption patterns.

This type of audit will be able to identify all energy conservation measures appropriate for the

facility, given its operating parameters. A detailed financial analysis is performed for each

measure based on detailed implementation cost estimates, site specific operating cost savings,

and the customer’s investment criteria. Sufficient detail is provided to justify project

implementation.

6.2.1.3 Investment-grade Audit

The investment-grade audit expands on the general audit by providing a dynamic model of

energy-use characteristics of both the existing facility and all energy conservation measures

2 http://en.wikipedia.org/wiki/Energy_audit




identified. The building model is calibrated against actual utility data to provide a realistic

baseline against which to compute operating savings for proposed measures. Extensive attention

is given to understanding not only the operating characteristics of all energy consuming systems,

but also situations that cause load profile variations on short and longer term bases. Existing

utility data is supplemented by sub-metering of major consuming systems and monitoring of

system operating characteristics.

In most corporate settings, upgrades to a facility’s energy infrastructure must compete for capital

funding with non-energy related investments. Both energy and non-energy investments are rated

on a single set of financial criteria that generally stress the expected return on investments. The

project operating savings from the implementation of energy projects must be developed such

that they provide a high level of confidence.

6.2.1.4 Pollution Audits

With increases in carbon dioxide emissions or other greenhouse gases, pollution audits are now a

prominent factor in most energy audits. Implementing energy saving technologies help prevent

utility generated pollution.

Pollution audits generally take electricity and heating fuel consumption numbers over a two year

period and provide approximations for carbon dioxide, nitrous oxides, carbon monoxides, sulfur

dioxide, mercury, cadmium, lead mercury compounds, cadmium compounds and lead

compounds.

6.2.2 Building Audits

6.2.2.1 Residential Building Audit

In North America heavy emphasis is being placed on residential energy audits as a means of

energy conservation. An energy audit of a home may involve recording various characteristics

of the building including the walls, ceilings, floors, doors, windows, and skylights. The leakage

rate or infiltration of air through the building envelope is of concern and is strongly affected by

window construction and quality of door seals such as weatherstripping. The goal of this exercise

is to quantify the building's overall thermal performance. The audit may also assess the

efficiency, physical condition, and programming of mechanical systems such as the heating,

ventilation, air conditioning equipment, and thermostat.

In Ontario, Canada homeowners can earn up to $10,000 in rebates for implementing the

recommendations of the energy audits by certified energy auditors which would remove energy

leaks and reduce energy bills. It has been reported3 that most public utilities in the United States

would perform a free home energy audit offering specific strategies on how to reduce energy

consumption.

In Guyana, where the average energy consumption of each home was 137 kWh per month in

2008, there would not be the need for such extensive home energy audits as there is no heating

and very limited air conditioning. Each home however has lighting and many homes use

3 http://environment.about.com/od/greenlivinginyourhome/a/energy_audit.htm

http://en.wikipedia.org/wiki/Efficient_energy_use

http://en.wikipedia.org/wiki/HVAC




refrigeration and therefore home audits can identify the levels of energy utilized by these and the

savings that can be realised by the efficient use of lighting and refrigeration.

It is therefore important that any public relations energy efficiency/conservation programme in

Guyana quantifies the savings that would be made by undertaking energy conservation measures.

6.2.2.2 Commercial Building Audit

As mentioned above commercial energy audits comprise different types depending on the level

of detail required from the audit. As implementation of the recommendations of such an audit

would normally require some measure of capital investment and various schemes have been

employed to get owners of large commercial buildings to carry out such audits. In San

Francisco owners of large commercial buildings are being asked to carry out energy audits

within the next five years to maintain their business licence. They are also being offered loans

which they can pay back through increased taxes.

Here again, Guyana does not have huge commercial buildings with large heating and air

conditioning energy requirements. It has been noted, however, that many new commercial

buildings in Georgetown are air conditioned. An offer by a government agency to carry out

energy audits by certified energy auditors should be welcome and if it can be shown that there

would be a reasonable payback period for any investment, then the companies should be willing

to make these investments.

6.2.2.3 Industrial Building Audit

Industrial energy audits include the examination of the industrial processes to determine whether

they can be carried out more efficiently. Such audits are carried out by experts in their respective

fields. The bulk of Guyana’s industries are small manufacturing industries, however, it is

possible that some of these could be modernised with the use of more efficient machinery. As

mentioned before the necessary investment on energy projects would have to have the same

treatment as any other investment projects and be proven to be a worthwhile investment. In such

instances, government incentives may determine whether these investments are made.

In conclusion, it must be stated that energy audits are necessary for all types of buildings before

any comprehensive energy efficiency/conservation programme can be developed. The tariff

structure of the utility company needs to be further broken down into different types of

residences and different types of commercial and industrial companies. Baseline data needs to

be obtained in terms of the various types of energy usage, e.g. lighting, air conditioning, etc.

Savings as a result of energy conservation measures would need to be quantified.

6.3 Energy Efficiency Programmes

6.3.1 Efficiency in Generation of Electrical Energy

At the level of the generation of electricity, measures need to be adopted to ensure that this is

done by the most efficient means.




The majority of generated electrical energy in Guyana is done using fossil fuels. The

country is attempting to reduce its dependency on these, however, in the meantime,

electricity generation must be done as efficiently as possible. Larger generating sets are

more efficient than smaller ones. Sets that are maintained as per schedule and according

to manufacturers’ recommendations perform at higher efficiencies. Elimination of leaks

and other similar problems would also improve efficiencies.

In the section on Energy Balances and Forecasts, it was estimated that nearly 10% of the

country’s generated electrical energy had been generated by self generators in 2008. This

generation would have been done by diesel sets sized at 1 MW and under at reduced

energy efficiencies. Additionally electricity is generated independently in many of the

other sectors also utilising small sized diesel generators. A national grid to which all

electricity users are connected would greatly enhance energy efficiency in generation

especially if the main source of energy for that grid was a hydroelectric power station.

This must be an urgent goal of Guyana in terms of energy efficiency. Reducing power

outages would also result in less use of the smaller, less efficient generating sets normally

utilized during periods of power outages.

Conservation and improved efficiency of electricity generation also means generating

‘green’ energy rather than utilizing fossil fuels. Guyana will therefore need to make the

decision of whether to invest in wind energy solely as a means of displacing fossil fuel

energy and therefore improving its energy efficiency. Research into other types of

alternative energy is also required.

6.3.2 Efficiency in Transmission and Distribution of Electrical Energy

GPL will be expending over US$40M over the next five years on its transmission and

distribution system, which it has indicated should, among other things, reduce its technical losses

from 11.4% to 8.05%4. It was noted in Section 3 on Generation Technology that as a part of the

United Nations Clean Development Mechanism small projects that produce reduction in losses

can apply for CDM status. However baseline and validation data are important aspects of these

projects. As mentioned earlier, Guyana would need to determine whether it should pursue the

registration of small CDM projects to improve the feasibility of such projects.

6.3.3 Efficiency in the Utilisation of Electrical Energy

It is in the area of utilization of electrical energy that Guyana may be able to improve on its

efficiencies. Many countries have adopted various measures and programmes to do so and most

importantly they have been able to quantify the savings that these programmes and measures

would make. For example, in 2005 the Philippines proposed a series of measures based on

different fuel price thresholds, the higher the fuel price threshold, the more stringent the

measures. Initially ten measures were suggested for accelerated implementation which were

4 GPL’s Development and Expansion Programme (2009-2013)




expected to ‘cut the country’s fuel consumption by 1.34 million barrels of fuel oil equivalent or

savings close to 1.4 billion Philippines dollars (P$) per year.’ Some of these ten measures were:

Reducing mall hours by one hour a day with expected annual savings of 49,000 barrels or

P$147M.

Reducing mall temperatures to 25oC with annual savings of 149,000 barrels or

P$149.8M.

Installing power factor correction capacitors on all 152 government agency buildings

with expected savings of 11,000 barrels or P$34M.

Another measure whose savings could not yet be quantified was ‘conducting energy audits on all

commercial and industrial establishments and enhancing the implementation of energy efficiency

programmes across all sectors.’ It must be noted that there were also measures in the

transportation sector which is outside the scope of this study.

The above shows the following:

Energy conservation measures can be very simple but they must produce quantifiable

benefits.

Baseline energy consumption data are vital to any energy conservation programme.

Governments tend to act strongly when there are dire financial consequences.

6.3.3.1 Energy Efficiency in Buildings

Buildings in the United States account for a surprisingly high 40% of the United States energy

consumption5, and the resulting carbon footprint, significantly exceeding those of all

transportation combined. Large and attractive opportunities exist to reduce buildings’ energy use

at lower costs and higher returns than other sectors.

Energy efficiency in buildings has been recognized in the last decade as an area that is containing

the highest potential for decreasing the total quantity of energy consumption, which directly

contributes to a more comfortable and better quality of living in the building, longer building

lifespan and improves environmental protection and lowers emissions.

Buildings are the largest individual consumers of energy and a large source of undesirable

emission of greenhouse gases, CO2 in particular.

The chief goal of energy efficiency in buildings is to establish mechanisms that will permanently

decrease energy needs in the phases of design, construction and use of new buildings as well as

for the reconstruction of the existing ones and to eliminate obstacles to introducing energy

efficiency measures into the existing pool of housing and non-housing building units.

Successful implementation of energy efficiency measures in buildings is based on:

the application of renewable energy sources

increasing the efficiency of air conditioning and ventilation systems

5 http://newscenter.lbl.gov/feature-stories/2009/06/02/working-toward-the-very-low-energy-consumption-building-of-the-future/#high_4




increasing the efficiency of the lighting system and energy users

the control and management of energy in the existing and new buildings

training and the promotion of measures for increasing energy efficiency.

6.3.3.2 Energy Efficiency in Lighting Systems

In Guyana, the residential sector accounts for approximately 46 percent of the final electrical

energy demand. To this end it would be fair to assume that lighting in dwellings absorb a large

portion of this demand. This means that there is scope to reduce this demand and this can be

realized by using energy efficient lighting systems.

The cheapest and most efficient form of lighting available is natural lighting (daylight). However

not many buildings are designed to fully optimize the use of this valuable resource. This means

that more emphasis has to be placed on the architectural designs of buildings and this can be

done by revising the Building Codes to include energy efficient requirements. For example

emphasis should be placed on the layout and orientation of buildings.

Today much emphasis is being placed on energy efficient lighting systems. The historic

fluorescent lamp with the magnetic ballast utilizes an additional 25% energy and therefore lamps

with electronic ballasts have been designed to reduce this. The fluorescent lamp with the

electronic ballast also has a longer lifetime, however, it costs nearly two and a half times more

than the lamp with the magnetic ballast. It will require much education of the public for them to

understand that the increased costs will be paid back in a short time.

The advent of the compact fluorescent lamps popularly called energy savers has somewhat

revolutionised the lighting industry for the domestic and commercial sectors. The energy savers

in general offer more for less. That is you get more light output from a lower wattage bulb which

translate to higher light output using less energy to produce a given intensity of light hence less

cost.

Recently there has also been the introduction of the LEDs as an energy efficient lighting source.

The LED has evolved over the years from just being used in electronic circuits to becoming a

major player in the lighting market. LED’s are now being used for domestic, commercial and

industrial applications. Applications such as traffic light signals, street lighting replacing sodium

vapour and mercury vapour lamps, floodlights and domestic and office lighting to name a few .

LED’s are said to be as energy efficient as compact fluorescent lamps. Also, LEDs use, on

average, 90% less energy than incandescent bulbs. In addition, LEDs do not drive up air

conditioning costs because they remain cool and do not create excessive heat buildup6.

6.3.3.4 Energy Efficiency in Industry

With electricity being the primary source of energy used within industry, there should be the

potential for improving energy efficiency within industry in Guyana. At the same time there will

exists the opportunity to effect savings in electrical energy consumption.

6 http://www.ledtronics.com/products.




For example most of the motors presently being used in industry are standard low quality motors

or motors that have been rewound due to windings being burnt. These standard low quality

motors have a lower efficiency rating and that efficiency rating further reduces after the motor is

rewound.

Since electric motors generally consume the largest percentage of the electricity utilized in

industry it would be better to use High Energy Efficient Motors or Premium Efficiency motors

whenever doing a motor replacement. Improving motor efficiency lowers operating costs,

increases profits and reduces emissions of green house gases from industrial facilities.

Energy efficient motors cost 15 to 30 percent more than standard motors and are typically 2 to 6

percent more efficient than the standard motors. This efficiency improvement translates into

substantial energy and dollar savings7.

The introduction of energy auditing in industry will certainly provide great opportunities for

increasing energy efficiency in industries which would further result in energy savings both in

energy use and dollar terms.

6.3.3.5 Energy Efficient Appliances

In the quest to achieving a high level of energy efficiency the use of Energy Efficient Appliances

must be encouraged. In order to promote this there is the EU’s Energy label policy, EU

Directives (92/75/CEE, 94/2/CE, 95/12/CE, 96/89/CE, 2003/66/CE, et alia), where all ‘white

goods’ must be so labeled that consumers can be aware of a particular appliance’s energy

consumption in kWh, capacity etc. This policy also captures motor cars and buildings. Similarly

the United States of America passed the Energy Policy Act of 2005 in which Sections 101 to 154

deals with energy efficiency programs such as the Energy Star Program are dealt with under the

Act.

This is an area where the Guyana government would need to develop the appropriate policy

regard the importation of appliances and the necessary oversight to ensure that the policy is

being adhered to by importers and suppliers.

6.3.4 Energy Efficient Measurements, Monitoring Standards and Guidelines

Data on the energy intensity of a country is too broad a measure of energy efficiency and it will

be necessary to establish baseline data and measurement and verification techniques of the

various sections that utilize electrical (and other types of) energy to determine any improvements

in energy efficiencies as a result of any energy efficiency programmes and measures.

To establish relevant goals and objectives it will be necessary to evaluate projects that are

adhering to the SMART goal approach; specific, measurable, attainable, realistic and timely.

Energy efficiency gains are most pronounced with lighting retrofits and energy monitoring in

7 Energy Efficient Electrical Motor Selection Handbook (Rev 3). http:// www.wbdg.org/ccb/DOE/Tech/ce0384.pdf.

http://en.wikipedia.org/wiki/EU_Directive

http://en.wikipedia.org/wiki/EU_Directive

http://www.wbdg.org/ccb/DOE/Tech/ce0384.pdf




buildings. Energy monitoring systems demonstrate the fastest and most economical way to

achieve energy savings.

Energy efficiency is an important aspect of the drive to reduce carbon emissions and the World

Bank Report 8 outlines several methods of measurement, monitoring and evaluation of energy

efficiency projects. It was noted that in some instances utilities were relied on to promote energy

efficiency as a least cost resource with a combined set of regulations associated with Integrated

Resource Planning. Measurement of Gross Energy Savings require extensive data collection

methods including engineering calculations, surveys, modeling, end-use metering, on-site audits

and inspections, and collection of utility data.

Some examples of energy efficiency projects and the methodologies used for monitoring and

evaluation are as follows:

Non residential new building owners were offered incentives to construct buildings that

were more energy efficient than the building codes in terms of lighting, HVAC (heating,

ventilation and air conditioning), and refrigeration. In this case a building energy

simulation programme which allowed the calculation of savings for lighting, lighting

controls, HVAC efficiency improvements, HVAC control measures and grocery store

refrigeration systems was used to evaluate the project and quantify the savings. An

automated process integrated on-site data collections and the programme model

performed simulations of 347 sites under multiple baseline scenarios.

Commercial and industrial customers were offered cash rebates for installing energy

saving devices. In addition to an engineering analysis of energy savings, a multivariate

statistical analysis was conducted to account for weather patterns and customer

characteristics that affect energy consumption and realized savings. The savings

estimates were based on a statistical analysis of customers’ bills for a period spanning

one year before and one year after the energy savings equipment was installed. A

separate analysis was done for each type of equipment using data for customers who

installed that type of equipment.

A Commercial Lighting energy savings programme was evaluated using two types of

data sources, existing data and newly gathered evaluation data. The existing data

included historical billing data, programme participation data and industry standards

information. The new data came from evaluation surveys and metered data. The impact

analysis was based on a nested sample design, with a core of lighting loggered sites

supplying calibration for the on-site sample, and the on-site audit sample being leveraged

with a larger, less expensive telephone survey. The lighting logger data supplied the

most accurate source of data for calibration of engineering estimates. A relatively small

on-site audit sample supported the telephone sample for the largest participation

segments. The on-site audits provided equipment details, operating hours, operating

factors, equipment efficiency, burn-out rates, etc. The telephone survey provided

information on energy related changes made during the billing period covered by the

8 Guidelines for Monitoring, Evaluation, Reporting, Verification and Certification of Energy Efficiency Projects for

Climate Change Mitigation – March 1999




billing analysis. Demand estimates were based on engineering models to on-site data,

metered data and industry standards.

It can be seen that many sophisticated methods of measurement, evaluation and analysis of

energy efficiency projects have been utilized. These methods can be very expensive and would

not be used unless there is a comparative high level of savings. Guyana would therefore need to

develop a well formulated energy efficiency programme that would produce accurate baseline

data and outline energy savings opportunities and costs together with the source of financing for

such a programme.

6.4 Renewable Energy for Domestic and Commercial Application

In addition to other energy efficiency measures, renewable energy in domestic and commercial

applications has been developing as an important aspect of energy efficiency and conservation.

6.4.1 Renewable Energy for Domestic Applications

There are both passive and active solar energy designs for residences. Passive solar energy

designs include passive solar heating, cooling, the use of day light and natural ventilation.

Examples of such designs for tropical countries are:

Design the building so that natural lighting can always be utilized during daylight hours.

Orient the living areas to the side of the house that is the coolest for the greater part of the

day.

Position doors and windows opposite each other so that any cooling breeze can flow

throughout the house.

Position trees and plants to direct a cooling breeze into your house and to provide shade.

Concrete buildings absorb the heat during the day and release it slowly at nights. Wood

buildings are better materials for the passive solar energy design.

Solar water heaters represent the active solar energy design and there has been an increasing

market for these in the Caribbean. The use of hot water in homes is not prevalent in Guyana but

for those who utilize this, it has been proven to be more cost effective that normal electricity hot

water systems.

Of course, solar panels can be used to supply a part of the home’s electrical needs, for example,

lighting and small appliances. Some companies in Guyana are advertising the supply and

engineering of solar panels but detailed information has not been forthcoming.

Although the development of wind energy has been increasing for utility applications there has

not been the same for domestic applications unless these have been for farms or houses with

enough land space for them. It has been discovered that there is not much scope for wind energy

in Guyana away from the coastlands.




6.4.2 Renewable Energy for Commercial Applications

All the issues discussed for domestic applications are also applicable for commercial

applications. It has already been mentioned that nearly all of the new multi-storeyed commercial

buildings in Guyana are air conditioned. It would be necessary for the building codes in Guyana

require that these buildings are designed to maximize the passive solar energy designs.

The roofs of large commercial buildings offer space for the installation of solar panels and

companies are developing lightweight PV cells that can be installed on the roof of commercial

buildings to augment the power supplied by the utility. Here again cost would be a factor and in

the section on Incentive Schemes will outline some measures that are being used to provide

incentives for companies to utilize renewable energy.

6.4.3 Net Metering

Net metering is an electricity policy for consumers who own (generally small) renewable energy

facilities, such as wind, solar or home fuel cells. It is a low cost, easily administered method of

encouraging customers to invest in renewable energy technologies. Net, in this context means

the deduction of energy outflows from metered energy inflows. Under net metering a system

owner receives retail credit for at least a portion of the electricity they generate. Most electricity

meters accurately record in both directions allowing a no-cost method of effectively banking

excess electricity production for future credit.

Most net metering laws involve monthly rollover of kWh credits, a small monthly connection

fee, monthly payments of deficit (normal electricity bill), and annual settlement of any residual

credit.

Sources that produce direct current, such as solar panels, must be coupled with an inverter to

convert the output to alternating current for use of conventional appliances. Electricity

regulations will require that synchronizing facilities be available for smooth interconnection with

the grid, and a mechanism for the disconnection of the customer’s feed to the grid in the event of

grid failure. This safety measure is to protect workers on power lines from electricity supplied to

the network by customers generating facilities.

Net metering can be seen as an incentive for individuals and businesses to invest in renewable

energy systems. Different utilities in the developed countries apply different policies for the

payment of the electricity supplied to the customer. Net metering is fairly new and as such it

success is yet to be quantified.

6.5 Demand Side Management

Demand side management is used to describe the actions that are done by the utility beyond the

customers’ meter with the objective of altering the end-use of electricity - whether it is to

increase demand, decrease it, shift it between high and low peak periods, or manage it when

there are intermittent load demands - all in the interest of reducing utility costs. In other words

demand side management is the implementation of those measures that help the consumers to




use electricity more efficiently and in doing so reduce the costs to the utility. Demand side

management can be achieved through

Improving the efficiency of various end users through better housekeeping, correcting

energy leakages, system conversion losses, etc.

Developing and promoting energy efficient technologies

Demand management through soft options like higher prices during peak hours,

concessional rates during off peak hours, interruptible tariffs, etc.

Demand side management can offer significant benefits to the GPL and its customers from a

utility perspective, in addition to reducing supply cost. These benefits also include deferral of

capital expenditure on generation, transmission and distribution facilities. It also offers improved

system load factor, better customer relations and better data for load forecasting and system

planning.

The implementation of DSM programs is likely to:

Improve the efficiency of energy systems – through improved generation efficiency and

system load factor

Reduce financial needs to build new energy facilities (generation) – through deferral of

capital expenditure resulting from peak demand reduction through DSM

Minimize adverse environmental impacts – reduction of GHG emissions through efficient

generation and minimizing thermal generation.

Lower the cost of delivered energy to consumers – lower generation costs and lower

customer bills through the use of energy efficient equipment and appliances.

Reduce power shortages and power cuts – improved system reliability though decrease in

demand.

Improve the reliability and quality of power supply – through demand reduction in

distribution systems

GPL has already embarked on a programme to replace incandescent lamps with compact

fluorescent lamps (CFLs). Reports out of the GPL reveal that the first phase of the CFLs

programme resulted in a saving of approximately 4.21 MW spread out between the various GPL

load centres. The lamps distributed varied in sizes of 5, 11, 14 and 20 watts. Presently the GPL

has invited interested businesses to tender for the resale of 165,000 CFL’s.

In its Development and Expansion Programme (2009 – 2013) GPL has listed a series of

measures that it would like to adopt in its Demand Side Management programme. These include

Sensitising the public including school children about energy efficiency thus realising a

behavioural change.

Continuing its programme of replacement of incandescent bulbs with CFLs.

Using energy efficient lamps for its street lighting.

Encouraging suppliers to provide energy efficient equipment for the Guyana market.

Providing information on energy usage of various household equipment.

Having a register of energy efficiency consultants available in the region.

The steps that can be taken in pursuing Demand Side Management are:




The use of high efficiency fluorescent lighting fixtures with low loss ballast should be

encouraged. This will entail the use of 36 watt instead of 40 watt and 18 watt instead of

20 watt lamps. The level of light output remains the same although the wattage is

reduced.

Introduce energy labeling of fridges and freezers to enable customers to identify more

energy efficient units. Establish minimum efficiency standard, and prohibit sale of

refrigerators below this standard. The same should be done for Air Conditioning systems.

Without energy labeling, customers have no objective way to determine appliance

operating cost, as energy consumption is rarely declared on a voluntary basis by

manufacturers9.

Promote the use of solar water heaters in grid and off grid areas. Information received

from a major local supplier of renewable energy products reports that between January,

2002 and August, 2009 they have sold a total of 335 solar water heaters. The company

equates one of the units to a 2500 watt electric water heater, which means that they have

replaced 0.8375 MW of electric power with the alternative solar. These units have been

installed mainly in urban and coastal areas. Few units have been installed in rural

locations.

Encourage the use of high energy efficient motors for use in both commercial and

industrial enterprises. Most industries in Guyana are presently outfitted with older type

motors in their operations and some do still replace failed or burnt ones with the standard

type. Significant energy savings can be gained by the use of the more efficient motors

and this should be pursued.

Conduct energy audits to identify cost-effective energy efficiency opportunities for large

and medium size customers.

In the area of PV systems the use of Grid - Tie systems and Net Metering should be

examined and encouraged where applicable. However some sort of incentive scheme may

have to be developed to make it an attractive investment in the urban and perri -urban

areas where grid connections exist. Information suggests that there are few Grid - Tie or

Net Metering systems in operation in the Caribbean region.

The use of the pre paid energy meter not only combats the loss of energy, by way of theft,

but can also serve as a means of conserving electricity usage within a given household.

Encouraging and demonstrating the benefits of the improvement of power factors of

industrial and large commercial installations and government buildings.

6.6 Incentive Schemes

On the global stage countries such as Canada, USA and Singapore, to name a few have, a

number of renewable energy and energy efficiency incentive schemes in operation. For example

to accelerate the growth of the environmental industry and maintain Singapore’s image as a clean

and green city, the government has initiated several funding and incentive schemes related to

energy efficiency, clean energy, green buildings, water and environmental technologies, green

transport, waste minimization, environment management system, environmental initiatives and

9 Energy Conservation By Demand Side Management By Standardization and Energy Labeling. K.P. Gupta Member,

Gujarat Electricity Regulatory Commission. http://www.ficci.com/media-room/speeches/2006/Gerc.da.




clean development mechanism10

. Some of the incentive schemes which are operable in

Singapore are:

Energy Efficiency Improvement Assistance Scheme

Clean Energy Research Programme

Solar Capability Scheme

Water Efficient Fund

Land Transport Innovation Fund

A number of the schemes listed above can be examined and modified as required to fit Guyana’s

scenario.

In Canada there are also a number of incentive schemes in place. Canadians benefit from a series

of improvements that the federal supporting measures for solar thermal technology brought forth.

First of all, the funding for the EcoEnergy Retrofit Homes Program – a programme for

residential home owners - has been increased by 300 M Canadian Dollars (C$). The rebate for

the solar thermal system of an individual family rose from C$ 500 to C$ 1,250.

In addition, the federal government has granted a tax credit for homeowners since the 1st of

February 2009, as part of the Economic Action Plan budget. Families who pay between C$

1,000 and C$ 10,000 to renovate their homes will receive a 15 % income tax credit – with the

final cap being at C$ 1,350. All expenses that incurred for renovations, including the payments

for solar water heater systems, are eligible for the tax credit. The following Table 6.2 shows the

breakdown of these incentives.

Typical System Cost C$ 6,700

Rebate of EcoEnergy Retrofit programme 1,250

SolarBC discount 1,000

Federal tax credit (approx) 800

LiveSmartBC 125

PowerSense 300

Net cost to consumer C$3,225

Table 6.2: Typical Calculation of SolarBC Incentives

Five different incentive programmes can be combined, for example, in the Canadian province of

British Columbia when purchasing a solar water heater. PowerSense is a rebate programme by

the electricity utility FortisBC, set up for costumers with existing electric hot water boilers.

LiveSmart BC is a provincial efficiency incentive programme, which contributes C$ 125 to a

solar water heater11

.

10

http:// www.lowcarbonsg.com/tag/energy-efficiency..

11 SolarBC New and improved Incentive Schemes in Canada; http://www.solarthermalworld.org/node/553. Accessed Sept 22,

2009.

http://www.lowcarbonsg.com/tag/energy-efficiency

http://www.solarthermalworld.org/node/553




In Hong Kong buildings account for 89% of electricity consumed and the Hong Kong

government launched in April 2009 The Building Energy Efficiency Funding Schemes12

. These

are two schemes covering

Energy-cum-carbon audit projects (ECAs)

Energy efficiency projects

The energy-cum carbon audit scheme encourage existing building owners to apply for funding to

carry out audits which will review energy use, quantify greenhouse gas emissions and identify

opportunities to enhance energy efficiency of building operations. The scheme covers audits of

publicly accessible communal areas of residential, commercial or industrial buildings. The

audits are to be carried out in accordance with the latest editions of ‘Guidelines for Audits’ and

‘Guidelines to Account on GHG Emissions and Removals from Buildings.’

In the case of Energy Efficient Projects, this scheme encouraged building owners to carry out

alterations/additions or improvement works to upgrade the energy efficiency performance of

lighting, electrical, air conditioning and lift and escalator building services installations for

communal use in residential, commercial or industrial buildings. On completion of the project,

fitted installations should comply with or be more energy efficient than the energy efficiency

standards in the latest edition of the Building Energy Codes issued by the Electrical and

Mechanical Services department.

In both instances the applicants would be given 50% of the cost of the project not exceeding a

certain amount.

The following broad criteria will be used to assess the merits of individual applications

The project’s contribution to promoting a low carbon economy

Whether it is nonprofit making in nature

The applicant’s technical and project management capabilities

Whether the proposed projects schedule of implementation and the proposed budget is

reasonable, realistic and cost- effective

Priority will be given to buildings with high potential for energy savings and application

that seek to complement other environmental initiatives.

In Guyana currently the only incentive mechanism that is in place is the exemption of Custom

Duty and Value Added Tax (VAT) on all renewable energy equipment including those for

photovoltaic applications inclusive of batteries and inverters and solar water heaters. At present

consumers are being encouraged to use compact fluorescent lamps (CFL’s) to replace

incandescent bulbs, however the custom tariffs remain the same for CFL’s, fluorescent lamps

along with fittings and incandescent bulbs. A reduction in the tariff rate inclusive of the VAT for

both the fluorescent and CFL’s will make them much more attractive to consumers.

12

http://www.minterellison.com/public/connect/Internet/Home/Legal+Insights/Articles/A-CLU2-Energy+efficiency+funding




There are many other incentive models that can be investigated in order to come up with a model

that may be appropriate for Guyana.

6.7 Recommendations

The area of energy efficiency is at present both challenging and exciting as efforts are being

made to reduce carbon emissions. Guyana may consider itself a small country with a minimal

carbon footprint, however, especially because of its Low Carbon Development Strategy, Guyana

should lead the way in energy efficiency and conservation. The process that the country needs to

follow in the establishment of an energy efficiency and conservation programme is as follows:

Recognise Energy Efficiency as a high priority energy resource.

I. Establish policies to establish energy efficiency as priority resource

II. Integrate energy efficiency into utility and country resource planning activities

III. Quantify and establish the value of energy efficiency considering energy savings,

capacity savings and environmental benefits as appropriate.

Make strong long term commitment to implement cost effective energy efficiency as a

resource.

I. Establish appropriate cost effectiveness tests for portfolio of programmes to reflect

the long term benefits of energy efficiency

II. Establish the potential for long term cost effective energy efficiency savings by

customer class through proven programmes, innovative initiatives and cutting

edge(modern) technologies

III. Establish funding requirements for delivering long term, cost effective energy

efficiency

IV. Develop long term energy saving goals s part of energy planning process

V. Develop robust measurement and verification(M&V) procedures

VI. Designate which organisation is responsible for administering the energy efficiency

programmes

VII. Provide for frequent updates to energy resource plans to accommodate new

information and technology.

Broadly communicate the benefits of and opportunities for energy efficiency.

I. Establish and educate stakeholders on the business case for energy efficiency at the

utility and other appropriate levels addressing relevant utility and societal

perspectives

II. Communicate the role of energy efficiency in lowering customer energy bills and

system cost and risks over time

III. Communicate the role of building codes, appliances standards and tax and other

incentives.

Provide sufficient, timely and stable program funding to deliver energy efficiency where

cost effective.




I. Decide on and commit to consistent ways for program administrators to recover

energy efficiency costs in timely manner

II. Establish funding mechanisms for energy efficiency from among achievable options

such as revenue requirements or resource procurement funding, system benefits

changes, rate basing, incentive mechanisms etc.

III. Establish funding for multi year periods.


ISSUES OPTIONS

Policy related Institute legal and regulatory policy on

Energy Efficiency (EE) and Renewable

Energy.

Implement a National Energy Efficiency

Policy and Action Plan.

Implement Energy Efficiency standards

and labelling.

Financial Determine the financing mechanisms

required to support the energy efficiency

plan.

Develop an EE programme for the

implementation and financing of EE

projects in the commercial and industrial

sectors.

Encourage Private /Public partnership for

Renewable Energy projects.

Public Relations Establish an information centre (e.g. a

unit within GEA).

Establish a baseline data collection

programme.

Disseminate consumer information on

Energy Efficiency equipment in all

sectors.




Energy Audits Make energy audits mandatory for all

state run or controlled institutions and

organisations.

Ensure all major industries conduct

Energy Audits of their operations thus

using the Energy Audits as an effective

tool for industrial energy management.

Encourage and promote the use of

demand side management programs.

Training of Personnel Establish training programs.

Encourage the establishment of energy

efficiency consultants.

Build capacity of participants in the

renewable energy sector.

Chapter 7 COMMERCIAL ISSUES

CHAPTER 7 COMMERCIAL ISSUES


7.0 COMMERCIAL ISSUES

7.1 Introduction

This section on Commercial Issues will not deal with the critical issue of tariffs and the tariff

structure that are necessary to sustain the GPL as a commercially viable enterprise as this is the

subject of another study. Instead this section will deal with the following issues:

Propose a format that will guide GPL during negotiations with IPPs

Discuss initiatives that may attract private development of renewable energy projects in

the hinterland communities and investigate the licensing of hinterland operators

Define a long range programme for maintaining good system management

Determine the investment and activity priorities for sustainable loss reduction and

commercial viability

Determine the commercial issues that should be addressed as part of the power sector

policy

7.2 Format for Utility to Negotiate with IPPs

The information for this format has been taken from two source documents. 12

Independent Power Producers (IPPs) are companies that build and usually operate generating

(and transmission) facilities but are not considered utilities. They provide the large capital

resources needed to build or buy these plants and recover their costs from the sale of electricity.

Most contracts with IPPs are for a minimum of fifteen years as they seek to recover their

investment capital and acquire the necessary profits.

Electricity prices offered by IPPs will generally reflect the costs and risks borne by the IPPs. In

general the following will apply:

the greater the risks the higher the prices

the more competitive the market the lower the prices

the more stable and predictable the market the lower the prices

The risks to the IPP can come from several sources:

1 “Reforming power markets in developing countries: What have we learned? by J. Besant-Jones, Energy and Mining Sector Board Discussion

Paper No. 19 Washington D.C. The World Bank and retrieved on 29 March 2010 from

http://siteresources.worldbank.org/INTENERGY2/Resources/electricitysourcebookch7.pdf

2 “Best Practices Guide: Implementing Power Sector Reform” The Energy Group, United States Agency for International Development retrieved on 30 March 2010 from http://www.raponline.org/docs/RAP_BestPracticesGuideImplementingPowerSectorReform.pdf

http://siteresources.worldbank.org/INTENERGY2/Resources/electricitysourcebookch7.pdf

http://www.raponline.org/docs/RAP_BestPracticesGuideImplementingPowerSectorReform.pdf



Currency – The IPP would need to recover its capital and operating costs normally

through US dollars and not local currency

Payment – The agency with which the Power Purchase Agreement has been made may be

weak financially creating the risk of non-payment

Political – The existing or a future government may change the rules

Management – If there is joint ownership of the facility then there would be risks

involved if the IPP is not the majority owner

Technology and Performance – The selected technology may not perform as originally

expected.

In order to keep the electricity prices within reason, it will be desirable to assign risks to the

entity that can most efficiently deal with the risk or to reduce IPP risks through some form of a

guarantee from a stable government or an international financial institution.

Guyana will need to look to IPPs for the development of its power sector for the following

reasons:

GPL’s rates cannot sustain any major capital investment

GPL is government owned it is therefore unable to access concessional financing from

the multilateral agencies

Guyana is seeking to develop its hydropower resources which require substantial capital

investment

The use of IPPs in the power sector development is relatively new and international experience

in this area is still developing. As a result there is little clear guidance for power sector officials

as to the correct procurement methods for IPP contracts.

The following format is therefore recommended for negotiations with IPPs.

Firstly request for IPPs must flow from a Least Cost Generation Plan

The country should have a least cost generation plan indicating the type of generating technology

that it needs to meet the country’s future electricity requirements. The least cost generation

study will consider various types and sizes of generating plant to meet the energy needs of the

country for the next ten years. The option that shows the least net present worth would be the

recommended one. The expected costs of the recommended alternative would therefore be

known and can be compared with costs from the IPPs.

Secondly it is important that IPPs be selected from a competitive bidding process

In many instances a private sector investor may choose to set up a project using his own

resources and the government may feel that it is counterproductive to insist on competitive

bidding when the competitive bids require costly and time consuming preparatory work and the

expert knowledge and experience required for evaluating bids as well as for the identifying and



allocating risks are not available. It has been found however that large contracts, signed in an

environment of weak watchdog institutions can be enormously costly to the country.

It is better if a competitive bidding process is pursued with a very clear and complete Request for

Proposal (RFP). Although some RFPs simply describe the needs and let the bidders do the work

of describing in detail how they would meet those needs, it is better to design clear and complete

proposals because these will solicit the greatest number of bids. The greater the number of bids,

the more efficient the competition and the greater would be the confidence in the winning bidder.

An individual consultant who is experienced and competent in drawing up RFPs and negotiating

contracts with IPPs will serve the government well in negotiations with IPPs.

Thirdly it is better if a Power Purchase Agreement (PPA) is included with the

Request for Proposal

Most Power Purchase Agreements are long term full output contracts. These documents can be

very complex however the Caricom Renewable Energy Development Programme (CREDP) has

produced a Power Purchase Agreement template which is retrievable at

http://www.caricom.org/jsp/projects/credp/power_purchase_agreement_template.doc

The pricing terms are the most important aspect of the PPA and can be on an energy basis

(x$/kWh) or on a two part basis (y$/kW + z$/kWh). In this case a hydropower project would

have a high fixed component and a relatively low variable component as opposed to a diesel

engine project which would be vice versa.

Including all standard provisions of a PPA as a part of an RFP is beneficial and would simplify

negotiations, reduce uncertainty, improve the financing costs of the contract be fair, for all

participating vendors and speed the contracting process.

Fourthly there must be a plan to deal with contingencies

In the preconstruction phase there can be specific provisions that allow for delays in the

commissioning date. IPP projects are generally more efficient than utility run projects and such

delay costs may not be prohibitive. There can also be post construction flexibility, though these

are generally more expensive to obtain. These can include early termination and buy-outs.

Fifthly there may be the need for renegotiation of the contract

Many contracts that may have seemed reasonable when they were being negotiated may

subsequently seem too high. The approach to renegotiation should be based on the perspective

of meeting the needs of both the purchaser and the seller. The key to renegotiating is that both

parties should have a clear understanding of each other’s goals and constraints. This would often

result in creative solutions being found. Options can include contract extensions to bring down

near term prices, contract buy-outs or buy-downs.

http://www.caricom.org/jsp/projects/credp/power_purchase_agreement_template.doc



7.3 Investment and Activity Priorities for Loss Reduction and Commercial Viability

GPL has instituted a Loss Reductions Operations department to spearhead its efforts at reducing

losses and improving its commercial viability. Its programme is carried out in two main areas

Major meter investigation, and,

Minor meter investigation.

In the former, the success or otherwise of its replacement of ordinary demand meters with the

ITRON AMR meters is assessed. As of January 2010, 1176 services had been fitted with the

ITRON meters and it was estimated that this had resulted in an average of 17.3% increase in

monthly consumption. Monthly investigations are carried out on these services to determine

tampering, defective cables, defective meters, new standard meter service arrangements and

disconnected or unused services.

The minor meter investigation is an ongoing programme for ordinary residential and commercial

services to detect tampered meters, bypassed meters, defective meters, new standard meter

circuits, and disconnected or unused meters.

In both cases for the month of January 2010, 28% of major meter investigation and 51% of

minor meter investigation showed that service were found either vacant, disconnected or

line/meter removed. This shows that GPL’s customer records are very inaccurate and so are its

reports on customer numbers.

GPL’s ability to carry out an effective loss reduction programme must begin with its ability to

audit the energy output from its generators to its consumers. GPL has recently installed energy

meters on its feeders however its maximum demand figures are really those of maximum

generation as the actual demand of its consumers is not measured at any point. The installation

of the SCADA system should provide GPL with much needed data to audit its energy production

and distribution.

Major utilities have designed their consumer billing records so that data on each consumer shows

the feeder and transformer from which each consumer is supplied. This type of information is

essential for automatic meter reading. This information can only be produced by foot soldiers on

the ground and GPL’s ability to mount such an exercise is uncertain. This type of requirement

can be given to a company with a management contract for the utility.

GPL is keen to install prepaid meters as a means of ensuring that its energy sales are being paid

for. After an unsuccessful attempt to install these meters in certain areas GPL will be using

public relations strategy to convince its customers that this type of meter will be beneficial to

them and to make them voluntarily choose this meter. GPL is also hoping for a change in

legislation so that it can install these prepaid meters on all its new services.

GPL’s ability to achieve commercial ability must begin with accurate records of its customer

database and better information on its energy production and distribution.



7.4 Long Range Programme for Maintaining Good System Management

The Electricity Sector Reform Act mandates that there is a regular, efficient, coordinated and

economical supply of electricity and that all reasonable demands of electricity are satisfied. For

this to be achieved there needs to be good management of the power company. The question is

whether this is achievable when the utility remains government owned or whether only a

management contract with strong targets and penalties for non-performance or privatizing of the

utility can achieve these results.

In any case for the company to perform well there must be specific targets to improve sales and

collection, financial and technical performance, labour productivity and system stability and to

reduce outages to an acceptable level. As the power company will be government owned in the

short term the following is a suggested long range programme for improving the management of

the utility

o There must be continuing training and upgrading of staff at all levels.

o There must be accountability at all levels.

o The company must be completely audited at the various stages of its generation,

transmission and distribution.

o Wherever practical, incentives must be given to ensure employee loyalty.

o There must be good relationships with the major customers at a middle management

level.

7.5 Management of Renewable Energy Projects in Hinterland Communities

Electrification of hinterland communities is essentiality a social activity undertaken to help

persons in rural communities who without adequate and clean forms of energy risk being

deprived of socio-economic development. The situation of high electricity development costs,

low demand/consumption and limited affordability renders hinterland electrification largely

unprofitable to private investors. These factors call for both innovative programmes and

financing mechanisms to enable profitability and sustainability.

Guyana is a small country with less than one million people. See Table 8.1 below. Regions 1, 7,

8 and 9 can be considered as the hinterland regions of Guyana, however there are areas in all of

the other regions that can also be considered hinterland. As can be seen in the table below, the

economic activities in the hinterland areas are mainly small scale mining and forestry. Neither of

these activities are energy intensive and so there has been no development of an electricity supply

system.



Region Geographical Area Economic Activity Population

(2002

Census)

1 Barima-Waini Logging, small scale mining 24,275

2 Pomeroon – Supenaam Agriculture 49,253

3 Essequibo Islands, West Demerara Agriculture 103,061

4 Demerara – Mahaica Agriculture and commerce 310,320

5 Mahaica – Berbice Agriculture 52,428

6 East Berbice – Corentyne Agriculture 123,695

7 Cuyuni – Mazaruni Gold mining 17,597

8 Potaro – Siparuni Mining and forestry 10,095

9 Upper Takatu – Upper Essequibo Agriculture, small scale mining 19,387

10 Upper Demerara – Upper Berbice Bauxite mining 41,112

Total 751,223

Table 7.1: 2002 Regional Population Data

With the help of the multilateral financial agencies pilot projects have been done using

alternative energy sources to supply power in certain hinterland areas. Wind energy, though not

viable for large wind turbines, may be economic for micro wind turbines installed at individual

homes.

The pilot project for solar systems, which is still to be formally assessed has had a measure of

success. A feasibility study for a mini hydropower station in Region 8 has determined that such

a project can be economically viable. It therefore needs to be determined how to proceed in the

development of such projects in the hinterland.

In his paper Rural Electrification Policy and Institutions in a Reforming Power Sector 3 Charles

Haanyika states that

“The main role of government in the expansion and affordability of electricity services in

rural areas is to formulate policy and put in place a legal/regulatory and institutional

framework. In the process of policy development the government must consult widely

and obtain the views of all major stakeholders including rural communities, non-

governmental organizations, the private sector, international financing institutions and

the donor community.

Clearly, public financing alone would be far from adequate to meet rural electrification

needs of most affected countries while private investment would be limited due to high

investment risks compounded with low profitability. Appropriate financing mechanisms

would therefore call for a combination of both public and private financing in a

symbiotic relationship. The public-private partnership could be in a form whereby public

finances are availed for guaranteeing private financing in a form of capital subsidy on

private investment in rural electricity systems developments. Whereas direct

consumption subsidies should evidently be discouraged, public finances should be

directed towards supporting electricity demand and income enhancing activities in

applicable rural areas. This includes infrastructure development such as roads, water

3 http://www.un.org/esa/sustdev/sdissues/energy/op/parliamentarian_forum/haanyika_policy_institutions_re.pdf



supply systems and social services. Public financing should also be used to support

employment creation and skills training in applicable areas.

With rural electrification (RE) confronted by issues of poverty, profitability of utilities

and environmental considerations, it is quite evident that government need to formulate

policies that incorporate incentives for both private and public utilities to engage in RE.

Governments must not merely facilitate, but be engaged in financing and/or subsidizing

RE activities. Therefore, the executive wing of the government must ensure enough

budgetary allocation to RE activities while the legislature must check and approve such

allocation. If RE financing problems are to be resolved, governments must look beyond

the power sector for funding. For instance, measures to attract local investors, banks

and equipment suppliers must be put in place. These measures should include supportive

statutory measures”

Chile is an example of a country that has been successful both in its power sector reform

programme as well as its rural electrification because it sees electrification as a key measure to

alleviating poverty in rural areas.4 Chile has therefore used innovative measures in restructuring

its subsidy schemes. Its rural electrification programme includes subsidies designed to be

consistent with the broad principles of power sector reform

‒ Decentralization of decisions to the regional and community level

‒ Competition between technologies as well as suppliers, and,

‒ A requirement that all partners in the process, users and private companies as well

as the state, make a contribution to the financing of the expansion projects.

When the costs of providing services from the national grid are too high, several alternative

technologies are considered

‒ Photovoltaic solutions for isolated rural dwellings

‒ Hybrid schemes that reduce fossil fuel dependency and operating costs

‒ Small hydroelectric power stations, independent or combined with other sources

‒ Experimental solutions based on wind power or biomass systems, which would require a

resource assessment programme before being applied.

The state contributes the subsidies and the cost of running the programme. Distribution

companies bid for subsidies by submitting their RE projects to the regional governments who

allocate funds based on cost-benefit analysis, amount of investment and social impact. The

government allocates funds to the regions based on how much progress the region has made in

rural electrification and how many households still lack electricity.

The innovative aspect of the programme has been the use of competition. It has successfully

introduced competition at several levels:

‒ among communities, for financing of their projects,

4 Promoting Private Investment in Rural Electrification , The Case of Chile http://rru.worldbank.org/Documents/PublicPolicyJournal/214jadresic-710.pdf



‒ among distribution companies (which are private companies) for the implementation of

their projects, and,

‒ among regions for the funds provided by central government.

Several methods have been adopted for the licensing of hinterland operators in rural

electrification schemes. Concessions can be exclusive or non-exclusive. Incentives can be

provided based on connection rates or on equipment subsidies. The companies can provide both

equipment and ongoing maintenance for a small fee. They can also provide the financing for

consumers supported by a grant or equipment financing. As isolated rural areas may be neither

large enough nor viable enough to attract substantive private participation, an alternative is to

build delivery capability among small enterprises through business advisory services and

business development and working capital financing. This approach though initially slow may

ultimately be more financial sustainable. One variation of this approach is the “dealer sales’

model for delivering household solar systems being tried in a number of Asian countries.

Concessions and other models for subsidized private participation in rural electrification must be

done on a contractual relationship (licence) based on targets such as, connections of new

customers, investment targets, installation of equipment, etc. These obligations need to be

monitored and closely enforced, by the local authority or region granting the concession, a

national regulator, a rural electrification agency, and even the utility with respect to technical

standards.

A well tested approach has been to have a dedicated rural electrification agency to carry out the

monitoring. The agency can also play a supporting role, acting as a catalyst for private sector

and local participation and providing financial, technical and managerial support. A dedicated

independent agency can provide a focused supporting framework for the effective disbursement

of performance-related subsidies.

Guyana can therefore seek to implement its hinterland electrification programme as follows:

Create a hinterland electrification section within the Office of the Prime Minister

Determine the alternative/renewable technologies that would be supported for these

regions

Determine the financing methods for these developments – public/private partnership,

incentive schemes to private sector, investment to develop hinterland areas economically,

etc.

Prepare a planned programme for the hinterland region to receive electricity within

certain number a years.

Adopt a policy concerning hinterland electrification

National budget to include funding of hinterland electrification



7.6 Commercial Issues for Power Sector Policy

The following commercial issues need to be dealt with as policy issues within the power sector

Tariffs

‒ Should tariffs cover at least financial, if not, economic costs?

‒ Should there be cross subsidisation among tariff classes?

‒ Who should benefit and what should be the level of lifeline tariffs?

Regulation of tariffs

‒ Who should perform the regulation of the tariffs?

‒ Who should approve developmental plans in the power sector?

Hinterland Electrification

‒ What are reasonable rates/tariffs for hinterland areas?

‒ How should subsidies be given?

‒ What other commercial incentives can be given towards renewable energy

equipment for the hinterland areas

Commercial Losses

‒ Should loss reduction targets be policy issues?

‒ Should treatment of theft of electricity be a policy issue?

‒ Can incentives be given towards notification of theft of electricity?

Chapter 8 FINANCIAL ISSUES

CHAPTER 8 FINANCIAL ISSUES


8.0 FINANCIAL ISSUES

8.1 Introduction

The financial issues that are dealt with in this chapter investigate three important aspects of the

present government-owned electricity utility, the Guyana Power & Light Inc. These are

Who decides on the sufficiency of GPL’s profitability?

Should GPL pay a dividend if it is a government owned public utility?

Should GPL be allowed to pre-finance its capital investments through tariff surcharges?

8.2 Who Decides on the Sufficiency of GPL‟s Profitability?

This will be examined from two perspectives,

(i) during the implementation period of the current Development & Expansion Plan

(D&EP), the medium term period, during which there is a relaxation of the operational

standards and performance targets as well as there being no updated tariff.

(ii) during the post hydropower period or the next tariff setting period.

Four agencies are currently involved in the regulatory process of the power sector and the

following components of their functions could influence the level of profitability of GPL.

● The Guyana Energy Agency (GEA) – provides advice to the Minister on the issuance,

modification and extension of licences, national energy policy, adoption of standards and

monitors said standards, etc.

●The Office of the Prime Minister (OPM) – issues and enforces terms and conditions of licence

to public suppliers.

● The Public Utilities Commission (PUC) – confirms rates to be charged by public suppliers

(GPL) on the basis of a tariff setting mechanism in the licence which provides for verification of

the rates by an Independent Firm of Accountants (IFA). ‘If the IFA issues a Certificate of non-

compliance the PUC will make a determination in the matter.’

● The Government Electrical Inspectorate (GEI) – determines disputes between a public supplier

of electricity (e.g. GPL) and consumers in relation to the accuracy of meters.

The view has been expressed that the primary function of the power sector regulatory

framework is the optimization of the interests of the government, the investor and the

consumer.



8.2.1 The GEA and OPM

The GEA and OPM establish in the license the technical and commercial framework standards

which in turn influence the following;

(i) Investment in utility plant which ‘is prudently incurred and used and useful in public

service’ Used and useful is defined as ‘only that plant currently providing or capable of

providing utility service to the consuming public’. The value of this plant establishes the

rate base and the rate of return for purposes of determining the tariff.

(ii) In the operation of the plant the need for safety, reliability and quality of electricity give

rise for the licence to set benchmark standards and performance targets for GPL. In

complying with these standards and seeking to achieve the targets additional costs (apart

from the normal operating costs) will be incurred for specialized tools, testing and

monitoring equipment, etc. Some of this cost will be added to the rate base while most of

it will be of a recurrent nature and form part of the generating and T&D expenses which

will influence the level of the revenue requirement.

Because the electricity sector is capital intensive it is not unusual for utility management to

under take productivity studies to identify activities and operations that could generate

productivity gains to compensate for the extra cost of implementing costly performance

enhancement measures to comply with the operating standards and performance targets

established in the licence. Below are quotes from the Jamaica Public Service Co. Ltd.1 that

country’s privately owned (with 20% of equity held by GoJ) electricity utility and Barbados

Light & Power Co. Ltd (BL&P)2.

“..JPS has improved its cost efficiency since the last tariff period as reflected in the

containment of operating and maintenance costs over the period. This improvement in cost

efficiency was confirmed by a benchmarking study of JPS‟ non-fuel cost performance

conducted by international consultants…They found that JPS‟ non-fuel cost was about 28%

below the value predicted by the econometric model.‟

„Over the years a significant portion of the earnings of the company has been reinvested in

new plant and equipment …and to improve the efficiency of the company‟s operations. A

recent example is the installation of two 30 megawatt low speed diesel generators.. at a cost

of Bda$140million. This installation has played a crucial role in helping to moderate oil

price increases through the efficient operation of the plant on the lowest grade residual fuel

…which is the least expensive fuel oil on the market. Savings in fuel costs are automatically

passed on to customers through the Fuel Clause Adjustment.‟

1 http://www.our.org.jm/images/stories/content/Electricity/Tariff/JPS_Rate_Case_Submission_-_March_9_Final_-_for_publication.pdf, 15

January 2010

2 http://www.ftc.gov.bb/library/blip_app/2009-05-

08_volume_1_section_1_application_barbados_light_and_power_co_ltd_for_review_of_electricity_rates.pdf, 15 January, 2010

http://www.our.org.jm/images/stories/content/Electricity/Tariff/JPS_Rate_Case_Submission_-_March_9_Final_-_for_publication.pdf

http://www.ftc.gov.bb/library/blip_app/2009-05-08_volume_1_section_1_application_barbados_light_and_power_co_ltd_for_review_of_electricity_rates.pdf

http://www.ftc.gov.bb/library/blip_app/2009-05-08_volume_1_section_1_application_barbados_light_and_power_co_ltd_for_review_of_electricity_rates.pdf



These cost efficiency and productivity gains are also reflected in the head count of employees,

JPS states in its 2009 Rate Application;

“ ..JPS continues to take steps to be cost competitive in that of head count .Between 2001 and

2004 JPS reduced its head count by 15% and offered that saving to customers in the 2004 rate

case. Since 2004, JPS has reduced its head count by a further 7% as it seeks to improve the

organisation‟s efficiency.”

However these gains in cost efficiency and productivity are quite often only for the reset period

of the tariff since improvements in levels of performance at the end of one tariff period could

becomes the benchmark for the next.

8.2.2 OPM and PUC

One of the expected benefits of privatization as reported in the GoG Strategy Paper was;

„Privatization would open the door for the private sector to enter the utility with its investment

money , management skills and a focus on the bottom line for which the operation must be made

efficient and effective.‟

Given the present financial and operational capacity of GPL and the ongoing investment in the

utility (at least during the D&EP period) it is not surprising that the GoG has indicated that;

„It remains Government policy to seek the gains of privatization whilst limiting the upward

pressure on prices by requiring the utility to;

(i) Sustain and then expand its current operations.

(ii) Require improvements in the performance of all employees and take measures to end

collusion amongst the employees and customers to defraud the utility.

(iii) Maintain the lowest possible tariff as a result of cost cutting and cost saving initiatives.

In the event of GPL being unable to service the IFI loans (IDB, etc.) the GoG will need to do so,

after no doubt having provided the guarantee for them.

However it has also taken a number of measures to insulate GPL from certain shocks. It has ;

(i) Declared its intention to ‘forego any dividend to allow for a cash surplus to be

reinvested.’

(ii) Provided a ‘best effort’ safety plank in the GPL licence to insulate the utility against the

consequences of failure to achieve any of the operating standards and performance

targets.

(iii)Incorporated a provision in the PUC Act which constrains the regulatory body from

intervening in any matter involving an electricity supplier where there is an

agreement between the GoG and the electricity supplier.



These measures could seemingly place the GPL beyond the regulatory arm of the PUC, at least

during the D&EP period i.e. the medium term. Although the measures provide a welcome and

necessary breathing space for the utility it is at the same time facilitating the continuation of the

‘public utility’ culture of lack of efficiency and fails to provide any stimulus for acquiring the

‘bottom line’ focus of the private sector. This is however not the first occasion of the utility

being held outside of the scope of the PUC.

However the objective of the GoG appears to be seeking to ensure the successful outcome of the

D&EP.

On the other hand the PUC as the executive arm of the regulatory framework could by its

determinations impact directly on the profitability of the GPL. A very painful example of course

being the 2002 order for GPL to repay customers US$7m for not having achieved the loss

reduction target in the previous year as required in the licence.

In terms of tariff setting and performance there appears to be no relief for the utility! JPS in its

2004 Rate Application had included the following as one of four objectives of the new tariff;

„to ensure that while the price cap regime imposes a restraint on the Company to pass on

excessive costs to customers it does not unfairly impose on the company risks that are outside of

managerial control.‟

However in the later review of the said tariff the JPS said;

“ While the 2004 -2009 tariff regime has achieved considerable success in driving JPS towards

the first two objectives of continued improvement in service and product reliability, as well as

efficiency and productivity gains, it fell well short of adequately protecting investors‟

opportunity to earn a fair return on capital invested. The tariff regime also protected customers

from excessive costs but left the company vulnerable to risks outside its control.‟

JPS incurred net losses after tax and finance cost in three of the five years of the tariff period,

profits fell short of the required amount to pay equity cost (i.e. dividends included in finance

cost) and the short fall had to be met out of retained earnings of earlier years.

This underscores the point that rates could prove inadequate during the tariff period to generate

the required revenue and thus contribute to the utility incurring losses. Further it is necessary that

the tariff generate a rate of return consistent with the need to replace the existing equipment, in

the three years this was not the case.

A quote from the BL&P’s 2008 Rate Application confirms this view;

„ Inadequate rates and inappropriate rate structure do not benefit anyone , customers or

investors , and can result in significant costs to the economy through insufficient

investment and resulting decline in the availability of electricity supply.‟



8.2.3 The D&EP Period

It is not clear when (or if) the utility will be applying to the PUC for a tariff review, however it is

assumed this will be done after determination of the projected results of the planned tariff

rebalancing.

Subject to the foregoing and following on section 2 above, the OPM along with the Board and

management of the utility will determine the sufficiency of GPL’s profitability, since they are

responsible for the approval and implementation of the D&EP and consequently the attendant

performance of the utility. In so doing the Board and management are quite likely contributing to

the determination of the ‘base year’ for the subsequent tariff review decision.

(i) Investment and the Rate Base, etc.

Investment decisions have already been taken and implemented, plant and equipment

acquired and commissioned or in the course of so doing. There have already been changes in

the power generation levels in terms of availability and reliability to some extent based on

reports of the utility.

This will certainly influence changes in the rate base on which the present tariff has been

established. It will also impact on the operating standards and performance targets currently

suspended by the ‘grandfathering ‘ of old plant and equipment. In addition improvements to

the transmission and distribution system will also impact on the level of systems loss and the

quality of electricity delivered to customers.

(ii) Revenue Requirement.

The expansion of the distribution network to accommodate new housing schemes, the

introduction of ITRON and pre-paid meters, SCADA and CIS systems, etc., will all impact

on the expense / revenue configuration and therefore the existing revenue requirement.

(iii) Cost Reduction and Productivity.

The proposed increase in the outsourcing of T&D and customer services, increased demand

for power due to increasing economic activity in the Essequibo region and expansion of

existing self generators (e.g. DDL, Banks) and proposed efforts at cost cutting and

productivity improvements by the utility’s management will also affect the availability of and

the demand for electricity and thereby contribute to the level of performance of the utility.

The D&EP anticipates increases of 17% in gross generation, 20% in net generation and 32% in

billing between 2008 and 2012 resulting in a 25% increase in sales over the same period and an

average annual profit before tax of 8.5% of gross revenue over the said period, a planned

improvement over the annual average net loss before tax of 6.8% of revenue for the five

preceding years.



It is not clear when the planned tariff rebalancing will take place although the possible date of

2009 for a ‘comprehensive review of GPL’s’ tariff was mentioned in the D&EP. However in

addition the D&EP states six conditions on which the rebalancing is premised and it is not clear

whether all six or at least five need to be realized prior to the commencement of the rebalancing.

The tariff rebalancing forecast envisioned reductions in all the rates commencing in the third

quarter of 2009 and continuing onwards to 2012 on an annual basis at different quarters in the

respective years. It is not clear to what extent GPL would be able to implement the rebalanced

tariff on a timely basis to impact any of the years covered by the D&EP. If it is not implemented

prior to hydropower coming on stream the likelihood is that GPL could exceed the planned

revenue and profit. This could be seen as the Board and management determining the

profitability of GPL for the said period.

During this period the Government could therefore be seen as performing the functions of

both owner and investor and as such being obligated to represent the interests of those

parties as well as its own.

If on the other hand there is intervention by the PUC to approve lower rates in keeping with the

D&EP, the PUC could be deemed to be the final authority for deciding on the profitability of the

utility.

Similarly this is the case also if the PUC approves, the results of the tariff rebalancing, prior to

the advent of hydropower since such approval would be on the basis of the utility’s performance

enhanced or mitigated by any exogenous changes in the economy impacting on the utility’s

performance.

8.2.4 The Post Hydropower Period

It is unlikely that there will be any significant change in the relationships among OPM and GPL

on the one hand and the PUC during the first year or two after the signing of the PPA for the

supply of hydropower, although the option exists for;

(i) the utility to be retained as a ‘public utility commission’ under its own Act of parliament

similar to the Trinidad & Tobago Electricity Commission or

(ii) there to be an extension of the present reforms with a focus on the utility with the objective

of preparing it for privatisation.

In any event it is anticipated that there will be an eventual return to normal regulation of the GPL

by the PUC timed on the demonstrated sustainability of GPL’s improved performance during the

D & EP period and early hydropower period.

Such a return to regulation by the PUC will increase the GoG’s desire to withdraw from the

role of both owner and investor and thereby abandon its current role in determining the



profitability of the utility. This could possibly lead to exploring the option of (i) a gradual

withdrawal from sole ownership combined with (ii) continuing support for the sourcing and

negotiating development finance for the long term needs of the utility.

This change in the relationships of the main parties may require legislative review in the areas of

(i) GoG privatization policy (ii) GoG partnering with the private sector in the sourcing and

servicing of development finance from the international financial institutions

Within the context of the foregoing, the first tariff review in this period is likely to entail a

detailed review of the earlier performance of the utility in relation to either (i) the last tariff

review period if there was one subsequent to 1983 (i.e. during the period of the D&EP) or (ii) the

D&EP period in order to establish benchmarks for the performance o GPL in the ensuing tariff

period.

GPL, having implemented its D&EP and managed the attendant risks is in a stronger position to

negotiate and manage the hydropower PPA as well as the development and presentation of the

Rate Application to the PUC. Also the company would have had the benefit of the

‘comprehensive’ tariff review during the D&EP period thus providing appropriate and detailed

information for the rate application.

The determination of the sufficiency of GPL‟s profits will rest more with the GPL in its

emerging role as an independent provider of electricity services than with the GoG or the

PUC.

8.3 Should GPL pay a Dividend if it is a “Public Utility”?

Prior to privatization the GPL was a state corporation operating under the Public

Corporations Act. At the time of preparation for privatization the then corporation was

incorporated under the Companies Act 1991 as a limited liability company with a mix of

preference and common shares. On the failure of the privatization deal the GoG resumed

full ownership of the company along with its mix of equity and debt capital.

At this stage the GPL became subject both to the Companies Act and the Public

Corporations Act, the latter vesting certain powers in respect of the GPL in the President

of Guyana and the Sector Minister.

As at December 31, 2008 the audited financial statements of GPL disclosed an issued

share capital of G$9,999 being the value of 55,074,228 common shares, all the preference

shares along with the balance of the ‘usage fees’ having been previously converted to

common shares.

Prior to 2008 no dividends were declared and paid by the utility, having made only a

small profit in 2004 and 2005 and losses in the other years. The Preference Shares had

attached a 12% cumulative dividend which as at 31 December, 2008 was G$4.5bn and

was neither paid nor accrued in the GPL’s financial statement.



The total long term debt of GPL was G$4.925bn, represented by loans from Republic

Bank ($995m) and the GoG ($3.93 bn), and shareholders equity G$6.251 bn, resulting in

a debt/equity ratio of 44. (compared with the privately owned electricity utilities of

Jamaica 44.6 and Barbados 13.4).

During the period 2004 – 2008 investment in non-current assets amounted to G$9.05b

most of which was by GoG the balance by RB and GPL. Of this amount G$6.5b was

installed and the balance was in work-in-progress as at the end of 2008.

It is observed that during this period, except for G$4m in 2004 there were no retirements

of plant indicating no doubt that both new and existing plant (some of which were

rehabilitated no doubt) have been retained in service or some plant i.e. those

‘grandfathered’ had no book value. (This matter is of relevance when establishing the rate

base on the basis of plant and equipment ‘used and useful’ in the delivery of electricity to

the public).

Based on Table 7.1 below the focus of this investment was on T & D to improve

reliability and quality of electricity delivered based on the available level of generation

and also to reduce technical losses.

The proposed investment for the period 2009 to 2013 while continuing to focus on T & D

(the interconnection of the existing GPL network) also allocates most of the funds to

stabilizing and increasing generation in line with perceived current and anticipated

demand and upgrading and modernizing the customer service delivery systems.

Table – 8.1 Investment Allocation Generation T & D Other G$M

2004 - 2008 24.4% 70.8% 4.8% 9.048

2009-2013 45.4% 35.5% 19.1% 33,194

This significant investment is targeted at preparing the GPL for improved operational and

financial performance to (a) meet the obligations under the proposed hydropower PPA in 2013

and (b) prepare for reprivatisation beyond 2013. The D&EP setting out the foregoing also

requires the generation of a level of profitability to adequately compensate both lenders and

equity shareholders.

In this regard given the intensive capital nature of the power sector (whether represented by state

or private ownership) the GPL by entering into agreements to repay/service the capital

investment has an obligation to manage the investments in order to ensure over the medium term

(the duration of the tariff implementation period) the optimal satisfaction of investors, owners

and consumers. Consequently so long as the existing capital structure is in place and there is an

adequacy of profit, the GPL as a ‘Public Utility’ has a responsibility to pay a dividend.



During the forecast period and beyond therefore, GPL has the task of servicing the following.

Table 8.2 – Debt Servicing (Etc.)

2009-12 Beyond 2012

(G$M) (G$M)

i) Existing Debt

Bank 948 74

GoG (3%) 1,048 2,882

---------- -----------

1,996 2,956

---------- ------------

ii) Proposed Debt

GoG/IDB 8,292 8,292

GoG 1,885 1,885

Others 101,713 101,713

---------- ----------

111,890 111,890

---------- ----------

iii) 7.53% on Equity 753 753

In addition to the foregoing adequate working capital need to be available to sustain the required

level of operations of the utility. For example, the G$4,193M current liability reflected in the

2008 audited financial statements will need to be addressed. If it is to be settled as ‘current’,

additional funds will be required, if not it may need to be reclassified as a long term liability with

a concessionary rate of interest.

Tables 7.3 and 7.4 below reflect the actual and forecast interest charges and loan repayments for

the previous five years and the forecast five years, the average interest charges and loan

repayments being lower at an annual average of G$196M and G$198M respectively during the

earlier years and increasing to an annual average of G$327M and G$1,981M respectively in the

forecast years.

Table – 8.3 Interest Charges (G$M)

ACTUAL 2004 2005 2006 2007 2008

238 209 186 190 156

YEARS 2009 2010 2011 2012 2013

FORECAST 219 115 299 491 512

Table – 8.4 Loan Repayments (G$M)

YEARS 2004 2005 2006 2007 2008

ACTUAL 348 144 158 173 167

YEARS 2009 2010 2011 2012 2013

FORECAST 514 2,375 2,954 2,233 1,828



The proposed debt/equity ratio of 7.53 was applied in the calculation of the estimated

interest rates for the new debt and reveal a peak of 6.6% at 2009, a decline to 1.7% in

2010 and an increase to 3.3% in 2013 due no doubt to the timing of interest charges being

applied to various amounts of capital.

The return on equity (based on profit after tax) is 19% for 2009 increasing to 33% in

2011 and declining steadily over the remaining years to 6.59% in 2013. The proposal to

pay an annual 7.53% dividend to the shareholder will therefore deplete the retained

earnings and cash resources of the GPL (cash at 31/12/08 – G$954M; at 31/12/13 –

G$145m) and consequently undermine the financial capacity of GPL to (a) maintain

adequate working capital and (b) adequate resources to respond exogenous factors

outside of the utility’s control.

the GPL needs therefore to moderate its dividend payment proposals in compliance with

Section 50(5) of the Companies Act 1991 which states:

“A company shall not declare or pay a dividend if there are reasonable grounds

for believing that –

a) the company is or would be after the payment, unable to pay its

liabilities as they become due: or

b) the realizable value of the company’s assets would thereby be less

than the aggregate of its liabilities and stated capital.

Arising out of the foregoing the GoG as owner and lender may wish to consider the

following

a) the establishment of a power sector development support fund, which will

operate as a revolving fund under the control of the GoG (and external to

GPL) into which will be deposited

i) loan repayments to the GoG by GPL and

ii) dividend payments to the GoG by GPL

the funds to be used at the discretion of the GoG to support by way of

reinvestment, the ongoing development of GPL

b) the establishment of a dividend policy aimed at

i) ensuring a minimum return on its equity over the tariff

implementation period

ii) the retention of earnings at a level consistent with the need to

maintain working capital and

iii) providing for a percentage of the maintenance cost of the T & D

network.

GPL will therefore be responsible for paying a dividend as a „public utility‟ but within a

policy framework designed to satisfy the interests of the owners (GoG) and the consumers.

It is quite likely that there will be a need for legislative changes in order to implement the

above.



8.4 Should GPL be allowed to pre-finance its capital investments through tariff

surcharges?

Future Revenue

The question seeks a determination as to whether GPL would be allowed to recover from

its customers through a tariff surcharge, revenue associated with the future delivery of

services.

This ‘future revenue’ based on current accounting principles will be treated as ‘deferred

investment funds’ and held as a current or long term liability (depending on when the

capital expenditure is to be incurred) due to the subscribing customers.

It would be prudent for such funds to be held outside of GPL since there is the risk of it

being diluted by the current operations of the utility and becoming unavailable when

required. In addition the amounts held will need to be carefully monitored and adjusted

for purposes of determining the impact of inflation and foreign exchange movements,

unless these have already been taken account of when computing the future cost of the

investment.

However, based on the current design and structure of the rate making (tariff) mechanism

in the GPL license it is unlikely that this could be accomplished.

The Tariff/ Rate making mechanism

The major objective is to provide a means of recovering the reasonable average cost of

services delivered to electricity customers over a period set for the operation of the

‘means’ (i.e. the rate) established by the mechanism.

The rate making mechanism identifies the following major non- fuel components of the

rate to be used in the recovery of the utility’s cost.

i) The Rate Base – this is the value of the net investment in the approved business

of GPL i.e. in generation, transmission and distribution and general plant assets.

These assets are identified as those financed by the company and investors and

are ‘used and useful’ in the delivery of electricity services to the public. It is only

those assets that are currently (i.e. at the end of the last month of the last annual

audited financial statements of GPL) providing or capable of providing such

utility service to the public.

The ‘net investment’ is the net book value of the assets as reflected in the last

audited financial statements and determined by D of Part E of the license.

It is on this value of the assets ‘used and useful’ that a rate of return is determined

and included in the tariff.

ii) The Revenue Requirement – is the total value of electricity billed and collected,

on the basis of the agreed rates, from customers for GPL to cover recover its costs

expenses and earn a fair and reasonable return on its assets.



The revenue requirement includes among other items (a) the cost of equity and

debt (i.e. total cost of investment) and (b) the cost of depreciation. As result the

rate making mechanism seeks to recover from the customer by way of the tariff

both the capital portion of the investment (via the depreciation charge) and the

investment cost (via the rate of return) Table – 7.5 illustrates a ‘Revenue

Requirement Summary’

Illustration of Revenue Requirement

Summary (G$M)

Cost of Equity (Dividends) 3,500

Cost of debt (Interest) 2,250

Return of Investment 5,750

Operational Expenditure 8,900

Depreciation 3,200

Taxation 2,600

Revenue Requirement 20,450

Table 8.5 Revenue Requirement Summary

iii) Surcharge – the rate making mechanism also provides for adjustments to be

made to the rate by way of a surcharge. In the case of capital investments the

surcharge provides for changes in the inflation and foreign exchange rates that

may affect the level of revenue to be recovered by the application of the tariff

The existing rate making mechanism therefore has a focus on recovery of the estimated

current costs incurred by the utility in the provision of current services, the rates being

adjusted on an annual or monthly basis to take account of inflation and foreign exchange

movements.

In an attempt to have GPL pre-finance its capital investments in the manner

indicated, and this has not been observed as a practice by the electricity utilities in

Trinidad and Tobago (wholly state owned), Barbados (wholly privately owned) or

Jamaica (20% government interest), there will be need to be significant reform in

the existing laws of Guyana, including the constitution.



8.4 Conclusion

The determination of the sufficiency of GPL’s profits will rest more with the GPL in its


PUC.

GPL should be responsible for paying a dividend as a ‘public utility’ but within a policy

framework designed to satisfy the interests of the owners (GoG) and the consumers. It is

quite likely that there will be a need for legislative changes in order to implement this.

If GPL is to pre-finance its capital investments in the manner indicated, there will be need

to be significant reform in the existing laws of Guyana, including the constitution.

Chapter 9 POWER SECTOR ORGANISATION, MANAGEMENT

& REGULATION

CHAPTER 9 POWER SECTOR ORGANISATION, MANAGEMENT AND REGULATION


9.0 SECTOR ORGANISATION, MANAGEMENT AND REGULATION

9.1 Introduction

Guyana is seeking to develop its power industry so that it can meet the demands of the country

for a power system that can supply a reliable, high quality and economic source of power that

can meet the needs of a modern developing society. The developing of such a power sector has

many constraints, however, it is anticipated that with the correct policies, a step by step progress

can be made towards these goals. The previous sections of this report investigated such issues as

load forecasting, generation technology, primary energy, network issues, and commercial and

financing issues. This final task is a proposal of the organization, management and regulation of

the power sector that will support the various policies and investments that have been previously

recommended.

However before dealing with this task it is necessary to analyse the issue of power sector reform

as it has been attempted, both in Guyana and other countries, and then to determine the best

model for the Guyana power sector.

9.2 Power Sector Reform

Ever since the success of the introduction of competition in the telecommunications industry

which resulted in the reduction of telephone rates, there have been attempts in many countries to

replace the regulation of the power industry by competition, in order to, among other things,

reduce electricity tariffs. There has been a variable amount of success in the developed world,

although not so much in the reduction of electricity tariffs, but in the opening up of the electricity

sector and the bringing of many more players into the field. Various models of power sector

reform have been adopted by the different countries and in the case of USA, by the various states

within that country. The market of electricity generation has been opened up to so called

Independent Power Producers (IPPs) who openly compete to sell power to the national grids.

Other models have been adopted for the transmission systems and the distribution systems, with

the model of the vertically integrated utility structure becoming a thing of the past in most

developed countries.

In the developing countries, although tariff reduction has been a desirable outcome of power

sector reform, the need for reform, in the most part, has been because of poorly run state utilities

that have been unable to provide the capital investment required to run successful companies and

also have been unable to charge the economic prices for electricity because of the inability of the

consumers to pay that price. Quoting from the document ‘Power Sector Reform in Africa:

assessing the impact on poor people’1, the authors noted that

There are two primary drivers for power sector reform in Africa. The first has been the

need to attract new investment to improve security of supply and meet future needs.

Governments have sought to diminish the burden on public finances and to attract

1 Power Sector Reform in Africa: assessing the impact on poor people, Alix Clark, Mark davis, Anton Eberhard, Katharine Gratwick and Njeri

Wamukonya- March 2005,



private investment into the sector. The second driver has been the need to improve the

financial and technical performance of incumbent state-owned utilities – either through

commercialization, corporatisation or rationalization/concentration initiatives or

through seeking private sector participation through management contracts, concessions

or divestiture.

In another document ‘Power Sector Reform in Sub-Saharan Africa: The Need for Pragmatism’2

the authors recognized the failed efforts of power sector reform in most of the African countries,

but they argued

“These failures or mitigated results recorded in Sub-Saharan Africa in the privatization

of electricity companies do not mean the return or maintenance of the former system with

one main actor- the State- which was the owner, operator and regulator.

It simply means that the reform must better reflect local realities at the political,

economic and social levels especially, as well as the feasibility of the formulas of

disengagement in terms of risk sharing between the private sector and the State, which

wants everything at the same time, maximum financial returns for the Public Treasury,

extension of the electricity service, getting the Strategic Partner to finance investments

and maintaining the lowest possible prices.”

The article concludes:

“On the whole, the return of the private sector to the electric power sector in Africa calls

for an effort to revisit the type of public-private sector partnership by being more

realistic and pragmatic. In the current international context, it seems that the traditional

lease or concessional formulas which do not entail the redemption of existing assets

deserves to be reconsidered with more attention in Sub-Saharan Africa as may be

deduced from the conclusions of the World Bank-EDF round table on the taxonomy of

reforms in the electricity sector (outlined below).”

2 Power Sector Reform in Africa: The Need for Pragmatism <http://bpe.epfl.ch/webdav/site/lasen/shared/import/migration/Fall%20(en).pdf >,

11 March 2010

http://bpe.epfl.ch/webdav/site/lasen/shared/import/migration/Fall%20(en).pdf



TAXONOMY OF REFORMS IN THE ELECTRICITY SECTOR

Scenario 1 Scenario 2 Scenario 3

Characteristics of the

country, economic

system and facilities

- Very weak

economy

- Small inefficient

power system

managed like an

administrative

department

- Public

electricity

company,

technically

competent and

operating with a

Board of

Directors

- Private sector

limited

- Well developed

electric power

system

- Active private

sector

- Nascent capital

market

- Institutional

capacity

significant

Main objectives of

the reform

- Restore service

reliability and

reduce costs

- Improve

efficiency of

supply and that

of demand

- Mobilise

alternative

funding sources

- Control

environmental

effects

- Same as Scenario

2

Reform Strategy

Industrial

restructuring process

Private sector

participation

Approach to

regulation

- Maintain

vertical

integration

- None

- Sub-contracting

management to

a private

(foreign)

company

- No independent

agency

- Maintain the

structure but

authorize

private

production

(companies and

large scale

consumers)

- Joint generation

BOOT

- Subcontract

distribution

- Acquire or hire

facilities

- Subcontract

auxiliary

services

- Market

company

- Make full use of

the scope for

competition by

separating

production,

transport and

distribution

- All options up to

full or

predominant

private ownership

- Market control

through

competition +

incentive



- Performance

contract

- Prices: redeem

the structural

economic costs

- Independent

regulatory

agency

- Regulation per

cost-benefit

ratio

- Price for large

scale customers

facilitating

stock

management

regulation

- Independent

agency

- Commercially

oriented pricing

Electric power system

planning

Developmental

financing

Priorities of the

political reform

- Centralised at

the company

level and

approved by the

Government

- Fully endorsed

by the State

- Company

marketing

- Commercial law

to be developed

- Centralised

dominantly by

the company

and approved

by the

regulatory

agency

- Guaranteed by

the State

- Recourse to

financing by

private sector as

well

- Enact laws

governing the

sector in order

to establish

policy elements

for the sector

- Decentralised

following

competitive

segments under

the regulatory

agency’s

indicative

planning

- Substantial

private capital to

complete funds

guaranteed by the

State

- In addition to the

reforms in

Scenarios 1 and 2,

enact a law on the

sector as well a

planning scheme

for the major

structural reforms

Source: EDF-World Bank Round Table Proceedings

As the experience of Guyana is well mirrored in the above analysis, and as the Guyana power

sector appears to fall into ‘Scenario 2’ above, this section will develop the outline of a timetable

of steps that can be taken to bring reform to the power sector that will produce profitable results.

As stated in the above table the main objectives of the power sector reform will be

To improve efficiency of supply and that of demand

To mobilize alternative funding sources

To control environmental effects

The reform strategy should be in the following areas

Industrial restructuring process

Private sector participation



Approach to regulation

Electric power system planning

Development financing, and,

Priorities of the political reform

Each of these sectors will be discussed with recommendations made for the Guyana power

sector.

9.2.1 Industrial Restructuring Process

The recommendation in the Taxonomy of Reform states that the vertically integrated structure of

the utility should be maintained but that private production of electricity is authorized by both

independent companies and large consumers.

Any analysis of the restructuring of the power company in Guyana needs to be done for two

periods, the medium term, characterized in this document, as ‘before hydro’, and the long term,

denoted as ‘after hydro’.

The Medium Term

The following are some of the main details of the power company in the medium term:

o The commissioning of the new Kingston power station in 2009 will improve

reliability in the Demerara system.

o The Berbice system will still have power supply problems which may not be solved

by the Onverwagt/Sophia transmission line unless new generation is added in the

medium term.

o The completion of the investment in transmission and distribution should improve the

quality of supply and bring some reduction in technical losses.

o The tariff study should outline rates that would bring the company on a firmer

financial footing, with no cross subsidies among the various consumer categories. It

is expected that this would cause a reduction in the large commercial and industrial

tariffs and an increase in the residential tariffs. These rates have to be gradually

implemented over a period of time.

o The self generators may be cautious about returning to the power company.

o The reduction in commercial losses may be at a slow pace.

o There are still uncertainties concerning the price of fuel.

Efforts should be made in the medium term to convert GPL into a successful commercial

enterprise. The alternatives for doing so would be

The company remains as a government owned vertically integrated company

with the present management and seeks to implement rates and other

measures to improve the performance of the company.

The company remains as a government owned vertically integrated company

but a results oriented management contract is issued.



The company still remains government owned but distribution is separated

from generation and transmission and a management contract is issued for the

distribution section of the company.

In the other sections of the power sector the Essequibo systems of the GPL would continue to be

separate systems and so will be the Linden system and all the smaller power companies. Of the

major industries GPL will be interconnected to Guysuco at the Skeldon power station.

The Long Term

The long term period should commence with hydropower generation from the Amaila Falls

hydropower station being available to the Demerara and Berbice power systems. The Linden

system would be a part of the national grid and self generators should be attracted to the

power company as a result changes in the tariff structure and a more reliable and better

quality supply. Electricity prices should be stable as the hydropower station should meet the

needs of the country during most of this period. There should not be the need for any major

capital investment and a stable electricity supply should see economic growth.

If the structure of the utility is still a vertically integrated one there are several options that

could be examined to determine whether they can offer a more efficient way of providing

electricity to the country. These are

Separate distribution from transmission and generation. The country would be

looking to further develop its hydropower resources with the associated transmission

systems to transmit the power to the loads. The planning of these developments need

not be centred in the government ministry with the oversight for the power sector but

can be transferred to a Transmission and Generation company which will also be

responsible for the operations of the generation and transmission systems.

The separation of the distribution system into regional companies should also be

investigated. The distribution system is a relatively small one and this idea may not

seem appropriate at this time but it is possible that with the idea of privatization of the

power industry that small distribution companies may be more efficient and effective.

9.2.2 Private Sector Participation

It is apt to make the quote here from Tenebaum et al (1992)3 ‘When the state owns, nobody

owns, when nobody owns, nobody cares’. Whereas it may not be appropriate to privatise the

entire utility, there could still be private sector participation in certain areas, and the following

suggestions have been made in the above Taxonomy on Reforms in the Electricity Sector:

o Joint generation BOOT

o Subcontract distribution

o Acquire or hire facilities

o Subcontract auxiliary services

3 Tenenbaum et al., op. cit. Tenenbaum et al. quotes this from Putnam, Hayes and Bartlett, Report on Conference on

Reconstruction/Privatisation, Moscow, 4-5 September 1991, pp. 3-5.



9.2.2.1 Joint Generation BOOT

The suggestion is that new generation facilities be jointly financed in a Build Own Operate

Transfer (BOOT) arrangement with the government. This is similar to the negotiations that are

presently taking place with the government and the investors for the Amaila Falls hydropower

project. The government of Guyana will be building the road as its contribution to the project

and will also be responsible for some of the ‘risks’ associated with this project. This

arrangement may also be possible for the electrification of the hinterland communities. This

could become a recognized government policy to pursue the BOOT arrangement for additional

generation in the future whether it is for the national grid or for hinterland electrification.

It is conceivable that there may be certain cases where it may not be possible to guarantee the

long term use of the facility, for example, additional diesels or wind turbines to meet the medium

term needs of the grid. In such cases when the hydropower station is commissioned, the use of

these facilities will be severely limited and an IPP would not want to invest in such a project. In

such instances the government would need to finance these capital investments.

9.2.2.2 Subcontract Distribution

Many countries have pursued or intend to pursue their power sector reform by subcontracting the

distribution section of the power utility either to regional/local area authorities (Namibia, South

Africa, Sri Lanka) or to private investors (Namibia, Ghana). In one instance (Tanzania) the

distribution section of the utilitybwas given out to a management contract with specific targets to

improve sales and collection, financial and technical performance, labour productivity and

system stability, to reduce outages and also to make the distribution company ready for

privatization.

In the case of Guyana which now has a fairly small electricity market, the division of distribution

into regional areas, may not be feasible in the medium term but could be considered in the long

term. Although Guyana has not had good experiences with management contracts, the issuing

of a management contract to bring the distribution section of the company ready for privatization

will be worth consideration. In the case of Tanzania the contract was awarded to a South African

company and in Guyana’s case it may be worthwhile considering a Caribbean or South

American company. The management contract could be issued for the entire vertically

integrated company or the distribution section of the company could be separated from the rest

of the company and the management contract issued for distribution only.

9.2.2.3 Acquire or Hire Facilities

GPL has in the past hired generation facilities but this has been an expensive means of providing

generation. The issue of acquiring or hiring private facilities does not seem relevant to the

Guyana power sector at present.

9.2.2.4 Subcontract Auxiliary Services

GPL has been subcontracting the following services:

o Operations and maintenance of its diesel generating sets

o Maintenance and construction of primary and secondary distribution systems

o Installation and disconnection of customer services



The fact that the company needs to subcontract the operation and maintenance of its main diesel

generating sets together with some of its other services underscores the point that government

companies tend not to be successful in their operations. It therefore needs to be also analysed

whether the option of a government-owned power company, which subcontracts most of its

services, can be a viable alternative.

9.2.3 Approach to Regulation

In Scenario 2 of the above Taxonomy on Reforms in the Electricity Sector the following issues

are recommended in the approach to regulation:

9.2.3.1 Market Company

The recommendation is that the power company could remain vertically integrated and

government-owned and be operated under the principles of an open market with the company

paying dividends. This will mean that the company would have to be commercially viable

charging rates that reflect the cost of supply. This will be difficult to achieve with a government-

owned company however this still remains an option.

9.2.3.2 Independent Regulatory Agency

In Act No. 10 of 1999, the Public Utilities Commission Act 1999 was established. This Act sets

out the rules and regulations under which all the utilities would operate in relation to the Public

Utilities Commission. In particular however, the PUC was not given any regulatory oversight

over the rate setting mechanism of GPL whose rate calculating mechanism had been spelt out in

the its license. In a report produced by the World Bank on the State of the Power Sector in Sub-

Saharan Africa4 the following statement was made about the regulatory agencies:

“The emphasis on independent regulation has not delivered, either. Regulators are far

from independent in many situations. Governments still pressure regulators to modify or

overturn decisions. In some countries, turnover among commissioners has been high,

with many resigning under pressure before completing their full term. The gap between

law (or rule) and practice is often wide. Tariff-setting remains highly politicized, and

governments are sensitive to popular resentment against price increases that are often

necessary to cover costs.”

It also needs to be noted that in order for the regulatory commission to command the authority

and receive the respect that it deserves then it must be staffed with personnel that are competent

and qualified in the areas of engineering and finance. It may therefore be necessary for the

government to recruit personnel from overseas who would be able to train local staff. Staff with

electricity utility experience will also enhance the performance and the reputation of the

Commission.

A functioning independent regulatory commission which operates fearlessly regardless of the

structure and ownership of the power utility should be the long term goal of the Guyana power

sector.

4Africa Infrastructure Country Diagnostic - The State of the Power Sector in Sub-Saharan Africa, World Bank, June 2008



9.2.3.3 Regulation Per Cost-Benefit Ratio

The cost of the regulatory mechanism must not exceed the benefits accrued from the regulation

although it may not be possible to quantify all the benefit in monetary terms. One important

function of the regulatory agency is to bring transparency to the utility and to provide a forum

where consumers’ complaints can be dealt with efficiently and effectively. Whereas in the

developed countries the regulatory process is long, time consuming and expensive, with delaying

tactics by interest groups, it is not expected that this would be the case in Guyana.

9.2.3.4 Price for Large Scale Customers Facilitating Stock Management

This recommendation is with regards to tariff setting for bulk customers whose supply

requirements may not be the normal stock items. This is not particularly relevant to Guyana.

9.2.4 Electric Power System Planning

The recommendation is that power system planning should be centralised and be done

dominantly by the power company and approved by the regulatory agency.

In the case of Guyana the power company is presently not responsible for the entire power sector

and thus would only plan for its area of responsibility. There needs to be power sector planning

for the entire country with oversight over all the power being generated within the country and

with the goal of seeking to bring all of the generator and users on to one national grid.

National planning where GDP growth is forecasted must consider the electricity generation

required to fuel such growth. The planning cycles of the country must go hand in hand with the

power sector planning cycles. Therefore although the power company should be planning for its

growth and development, there must be an agency planning for the growth and development of

the entire power sector.

In India for example, where the country has national five year planning cycles, a Working Group

on Power was constituted for the 11th

Planning cycle, 2009 -2012. This Working Group was

further divided into 8 sub-committees, and then an additional committee was subsequently

needed on Human Resource Development. The sub committees were

o Demand

o Generation

o Transmission and Distribution Expansion Planning

o Households and Rural Electrification

o Demand Side Management and Energy Efficiency Issues

o Research and Development

o Manpower Development and Training

o Fund Requirement

o Human Resource Development

These committees would first analyse the achievements of the previous planning cycle and then

make plans for the subsequent planning cycle. The plans developed included the following:

o Load forecasts for the country by states



o Capacity and types of generating capacity to be added during the new period

o Lengths of transmission and distribution lines to be constructed

o Number of new services to be established during the period

o Energy Conservation/Efficiency methods to be adopted

o Training programmes to be established

o Methods of funding the sector

Admittedly, Guyana is a small country with limited resources, however, the culture of serious

planning must be encouraged. Planning must not be just an academic exercise, but achievable

goals must be set, and all efforts made for the plans to succeed.

It is therefore recommended that a power sector planning committee be formed comprising

personnel from the various agencies in the power sector. This committee can also comprise

of, or take inputs from the private sector, the regional administration and other interest groups.

In the long term, if so formed, the Transmission and Distribution Company can be responsible

for national power sector planning.

9.2.5 Development Financing

The two recommendations under development financing are that such financing should be

guaranteed by the State and that there should be recourse to financing by private sector as well.

Funding of the power sector is critical to the long term development of the sector. Recently

Guyana has used funds from the Petro Caribe Fund (Venezuela) and has also been able to receive

concessional financing from the China Exim Bank, which is also financing power sector projects

in Africa. The continued availability of funds from China in the long term is not known. It

would seem that Guyana will need to look to IPPs to finance its future generation requirements.

9.2.6 Priorities of the Political Reform

The final recommendation of the Taxonomy on Reforms in the Electrical Sector is to enact laws

governing the sector in order to establish policy elements for the sector.

It is important that the laws governing the power sector reflect the policies that the sector should

adhere to. It will also be necessary to enact laws governing the regulations of the power sector.

9.3 Sector Organisation and Management

The main agencies within the Guyana power sector are

o The Office of the Prime Minister under which falls the Government Electrical

Inspectorate

o Guyana Power & Light Inc.

o Guyana Energy Agency

o Public Utilities Commission

It is expected that the Environmental Protection Agency and other agencies may from time to

time provide inputs to the power sector.



This section investigates the role and function of each of these agencies and makes

recommendations where necessary.

9.3.1 Office of the Prime Minister

The Electricity Sector Reform Act 1999 (ESRA), outlines the duties of the Minister in respect to

the power sector in Guyana. The Minister, in turn, should carry out these duties through his staff

at the Office of the Prime Minister (OPM), the Guyana Power & Light Inc. (GPL), the Public

Utilities Commission (PUC), the Guyana Energy Authority (GEA), the Government Electrical

Inspectors (GEI) and any other relevant agency. The Act also gives the Minister the authority to

make regulations to give effect to the Act in various areas that are outlined by the Act.

Section No. 4 of ESRA 1999 gives the Prime Minister the authority to grant licences, which may

be exclusive, authorising persons to supply electricity, for public or private purposes and for a

period not to exceed twenty five years.

In addition Section No. 65 of ESRA 1999 says that ‘In carrying out the provisions of this Act,

the Minister shall have the duty to act in the manner best calculated -

(a) To secure a regular, efficient, coordinated and economical supply of electricity and to

ensure that all reasonable demands of electricity are satisfied.

(b) To protect the interest of consumers of electricity supplied by persons authorized by

licences to supply electricity in respect of –

i. The prices charged and other terms of supply,

ii. The continuity of supply

iii. The quality of the electricity supply services provided, and,

iv. The provision of electricity in rural areas.

(c) To ensure that, in relation to the powers regarding licences for the supply of electricity

granted to him pursuant to this Act, public suppliers are to finance the activities that they

are authorized by their licences to carry on, and to obtain a rate of return, if any,

provided for in their licences or a written agreement with the government, or if no rate of

return is provided for in a licence or in such a written agreement, to obtain a reasonable

rate of return on capital invested.

(d) To promote efficiency and economy on the part of persons authorized to supply

electricity, including, but not limited to, promotion of alternative form of electricity

generation using renewable resources wherever commercially feasible;

(e) To promote the efficient use of electricity by consumers

(f) To protect the public from dangers arising from the supply of electricity

(g) To take into account the effect on and the protection of the physical environment with

regard to activities connected with the supply of electricity



(h) To enforce the provisions of this Act and any licence or exemption granted pursuant to

this Act, and

(i) To carry out a national energy policy

The Minister can therefore seek to carry out these duties either through the Office of the Prime

Minister or through any of the agencies within the power sector. In addition ESRA no. 69 states

that the Minister may make regulations for giving effect to the Act with regard to –

(a) The promotions of efficiency and economy on the part of persons authorized by

licences or exemptions to supply electricity.

(b) The use of alternative forms of electricity generation using renewable resources

wherever commercially feasible

(c) The promotion of efficient use of electricity by consumers

(d) The protection of the public and property from dangers arising from the supply of

electricity including –

i. The safety of the public from personal injury or from fie or otherwise

ii. The protection of persons and property by reason of contact with or the

proximity of, or by reason of the defective or dangerous condition of, any

appliance, or installation used in the supply of electricity

iii. The methods of wiring premises

iv. The types of electrical apparatus and installations that may be used

v. The qualifications, examination, licencing and registration to be required of

electricians and electrical engineers, technicians and inspectors

vi. The inspection, testing and maintenance of works, supply lines, meters,

accumulators, fittings, installations, supply lines, and apparatus constructed

and placed on any public land or private premises

vii. The prevention of any telephone, other telecommunications or electric

signaling line, or the current in such line, from being injuriously affected by

an appliance, apparatus or installation used in the supply of electricity

viii. The units or standards for the measurement of electricity and the limits of

error, and

ix. The frequency, type of current and voltage of electricity to be generated or

supplied

(e) The information that a licence, or persons exempt from the licencing requirements of

this Act must provide to the Minister or to consumers

(f) The engineering, operational and other technical standards applicable to public

suppliers

(g) The creation, maintenance and disposition of any funding provided by the

government for the supply of electricity to low income or disabled persons



(h) The effect on and protection of the physical environment with regard to activities

connected with the supply of electricity

(i) The supply of electricity for private purposes

(j) Any matter concerning application for and granting, modification, extension,

revocation and suspense of licence for the supply of electricity concerning exemptions

from the requirements to obtain a licence for the supply of electricity

(k) The keeping, by persons authorized by a licence or by exemptions to supply

electricity, of maps, plans, and other drawings, diagrams and schematics and their

production for inspection and copying

(l) The mitigation of any natural disaster or other civil emergency that disrupts or is

likely to disrupt the supply of electricity

(m) Subject to the provisions of this Act, the reform of the electricity sector

(n) The penalties for contravention of any regulation made under this section, and,

(o) Any other matter necessary to establish and carry out national policy matters

involving electricity or for the Administration of this Act.

The Minister therefore faces the daunting task in regards to his duties under the Act and the need

to provide regulations for the power sector. There is therefore the need to delegate some of these

duties to the various agencies, work out a timetable for the establishment of the regulations

required for the sector, and determine means of enforcing these regulations.

It is therefore recommended that the Office of the Prime Minister be directly responsible for the

following:

Pursuing power sector reform with the aim of making definite improvements in the

performance of the Guyana power sector.

Determining the policy for the power sector. ESRA is silent on the issue of national

power sector policy and planning. A planning cycle and a periodic power sector policy

review are necessary. These of course are to be done in consultation with the various

agencies. The national power sector planning can be done by OPM after consultation

with stakeholders in the private sector, the major industries, regional administrations and

will of course include the plans of GPL and any other public supplier. If so formed the

Generation and Transmission Authority can be responsible for national power sector

planning in the future.

Issuing licences to private and public suppliers and independent power producers (IPPs).

In connection with the latter, according to ESRA 1999 Section no. 4 (c) the licence can

only be granted to an IPP for the generation of electricity sale to a public supplier if the



Minister is satisfied that the governing bodies of both the independent power producer

and the public supplier to which the independent power producer proposes to sell

electricity for transmission and distribution have approved the terms and conditions upon

which such electricity will be purchased by the public supplier, and such terms and

conditions insofar as they relate to rates have further been approved by the Commission

in the exercise of its authority under section 35 (1) of the Public Utilities Commission

Act 1999.

Pursuing developmental plans for hinterland electrification. Because hinterland

electrification is not immediately commercially viable and will not attract private sector

investment without incentives provided by the government this area should be left under

the purview of the OPM. A hinterland electrification section will help to manage this

area.

Seek avenues to establish and enforce regulations for the power sector

For the rest of the duties the Minister delegate his responsibilities to the Guyana Power & Light

Inc., the Public Utilities Commission, the Guyana Energy Agency in conjunction with the

Environmental Protection Agency and finally the Government Electrical Inspectors. The role

and functions of these agencies are dealt with in the subsequent sections.

The issuing of the regulations governing the power sector and the enforcing of these regulations

are critical to the effective functioning of the sector. Although some regulations have been

issued the plans for enforcing them have not been established. A schedule for the issuing of the

power sector regulations and the plans for enforcing them needs to be worked out and given

urgent attention.

A power sector regulations committee should be formed to pilot the development of the

necessary regulations for the sector and then laws enacted to enforce these regulations.

9.3.2 Guyana Power & Light Inc.

A vibrant and successful GPL is necessary for the Minister to fulfill the first duty under ESRA

„to secure a regular, efficient, coordinated and economical supply of electricity and to

ensure that all reasonable demands of electricity are satisfied‟.

GPL was granted a licence by the Prime Minister to the then private owners in October 1999.

The terms of the Licence were as follows:

(a) the generation of electricity except the generation of electricity through hydropower

(b) the transmission, distribution, storage, furnishing and sale of electricity

(c) the purchase of electricity in accordance with power purchase agreements between

the Licensee and independent power producers

(d) the supply, erection, maintenance, repair, removal, replacement and operation of

meters, electric lines and other electric apparatus, installation of facilities necessary

to carry out the activities and services authorized by this licence



(e) the use or rental of the Licensee‟s structures, wayleaves, easements, rights-of-way

and other facilities for running or operation of telecommunications lines or other

purposes.

The Authorised Area for the licence was the territory of Guyana with the exception of Linden

and any other area that may be given a licence by the Minister. Schedule I of the licence outlines

the formulas for setting rates and Schedule 2 gives a list of Operating Standards and Performance

Targets which the company was to use its best efforts to achieve. The areas covered by these

targets were:

o period for accounts receivable

o period for accounts payable

o reduction in bad debt expense

o reduction in commercial losses

o customer billings

o reduction in technical losses

o reduction is customer interruptions

o increase in average availability

o voltage and frequency regulation

o response times to various customer requests.

These targets were expected to show improvements reaching their best values by Year 5 of

GPL’s operations.

The licence stated that Development and Expansion Programmes should be submitted to the

Minister and this would be deemed to have satisfied the conditions of ESRA and the PUC Act

for the submission of such programmes. The Minister would give his approval after, if

necessary, advice from the Guyana Energy Agency.

It is uncertain whether any of the operating standards and targets were ever met or whether any

D&E programmes were approved however after making losses in the years 2000 to 2002, being

ordered by the PUC to pay US$7M because it had not reached its overall loss target in 2002, and

having its application for rate increase blocked, in April 2003 the company sold its shares to

Government of Guyana for US$1.

The present government-owned GPL is still deemed to be operating by the said licence but, as

mentioned in the Chapter 7 on Financial Issues, GPL has not sought a tariff review in recent

times. It is also unclear which of the Operating and Performance Standards targets it is presently

seeking to achieve.

As has been mentioned before several steps have been taken to improve GPL’s performance.

Some of these are:

o increased generating capacity

o proposed additions to the transmission and distribution system to reduce technical

losses,



o SCADA system to provide better system control and improvements to its data

gathering capability

o a loss reduction operations department including the offer of prepaid meters

o a tariff study

GPL is also expected to be the agency to sign the power purchase agreement with the IPP

developing the Amaila Falls hydropower project and to be responsible for the ensuing payments

to the IPP.

It is uncertain however whether these measures are enough to help GPL to ‘play a strategic role

in the development of the economy and help Guyana to realize its considerable development

potential’ as desired in the National Strategic Development Plan 2000-10.

It has been mentioned in Section 9.2 of this chapter that the culture that prevails in government

owned companies is difficult to break, as demonstrated by the fact that GPL outsources many of

its core functions. The recommendation has therefore been made that since the company is not

at present attractive to private investors, a management contract can be issued in the medium

term in an attempt to improve GPL’s performance and to make it ready for privatization in the

long term.

It is also being recommended that in the long term GPL continue to be responsible for the

maintenance and operation of the 69 kV transmission system, the distribution networks and the

diesel stations that are still connected to the distribution networks.

Additionally there should be the formation of a Generation and Transmission Authority which

should be responsible for

the development of Guyana’s hydropower resources

the development of the transmission networks leading from the hydropower stations

the operation of the national grid

the national power sector planning

interconnection with other major industries and even with other countries

The formation of this Authority will also broaden the base of electricity utility skills and

experience and not limit these to the GPL only. There will eventually be more experienced

personnel in the power sector to fill positions in the Public Utilities Commission and the OPM.

In the interim however the terms and conditions of GPL’s licence especially the Operations

Standards and Performance Targets need to be revisited and more realistic performance

goals must be set with the ensuing expectations that these must be met.



9.3.3 The Guyana Energy Agency

The role of the Guyana Energy Agency in helping the Minister to carry out his duties under

ESRA is as follows:

(a) To promote efficiency and economy on the part of persons authorized to supply

electricity, including, but not limited to, promotion of alternative form of electricity

generation using renewable resources wherever commercially feasible;

(b) To promote the efficient use of electricity by consumers

(c) To carry out a national energy policy

The Guyana Energy Agency’s mandate is stated in the provisions of the Guyana Energy Agency

Act 1997, Guyana Energy Agency (Amendment) Act 2004, Guyana Energy Agency

(Amendment) Act 2005 and the Petroleum and Petroleum Products Regulations 2004. The core

functions listed in section 5 of the Act are as follows:

to advise and to make recommendations to the Minister regarding any measures

necessary to secure the efficient management of energy and the source of energy in the

public interest and to develop and encourage the development and utilisation of sources

of energy other than sources presently in use.

to develop a national energy policy and secure its implementation.

to carry out research into all sources of energy including those sources presently used in

Guyana for the generation of energy, and securing more efficient utilization of energy

and sources of energy.

to monitor the performance of the energy sector in Guyana, including the production,

importation, distribution and utilization of petroleum and petroleum products.

to disseminate information relating to energy management, including energy

conservation and the development and utilization of alternative sources of energy.

to grant and issue licences relating to petroleum and petroleum products, including

import licences, wholesale licences, importing wholesale licences, retail licences, bulk

transportation carrier licences, storage licences and consumer installation licences.

to utilise a marking system to add markers to petroleum and petroleum products

imported by every person under an import licence or import wholesale licence for the

purpose of identifying such petroleum and petroleum products as having been

legitimately imported.

to take samples of petroleum and petroleum products from any person at random

throughout Guyana and carry out tests and examination to determine the presence or

level of the markers in the samples of the petroleum and petroleum products.



to perform the necessary tests to determine whether the marker(s) is in the required

proportion and any further test necessary to determine whether the petroleum and

petroleum products have been lawfully obtained, stored, possessed, offered for sale,

blended or mixed with any substance that is not approved.

to prosecute in the Magistrates‟ Courts persons who are in possession of petroleum and

petroleum products bearing no markers or at a concentration below that required.

to prosecute in the Magistrates‟ Courts persons who import petroleum and petroleum

products without an import licence or wholesale import licence.

to prosecute in the Magistrates‟ Courts persons who purchase, obtain, store, possess,

offer for sale, sell, distribute, transport or otherwise deal with illegal petroleum.

Section 6 of the Act further outlines several advisory functions of the Agency:

to study and keep under review matters relating to the exploration for, production,

recovery, processing, transmission, transportation, distribution, sale, purchase, exchange

and disposal of energy and sources of energy within and outside Guyana.

to report thereon to the Minister and recommend to the Minister such measures as the

Agency considers necessary or in the public interest for the control, supervision,

conservation, use and marketing and development of energy and sources of energy.

to prepare studies and reports at the request of the Minister on any matter relating to

energy or any source of energy, including research into alternative sources of energy, or

the application of such research, and to recommend to the Minister the making of such

arrangements as the Agency considers desirable for cooperation with governmental or

other agencies in or outside Guyana in respect of matters relating to energy and sources

of energy.

to advise the Minister or assigned authority on matters relating to the administration and

discharge of the functions of the Electricity Sector Reform Act 1997.

The Agency has a broader role in the energy sector than its role in the electricity sector. The

Agency should be represented on the national power sector planning committee and personnel

from the electricity sector planning should sit on the committee that plans energy policy.

Although ESRA states that power companies should send their development and expansions

programmes to the Agency, it is felt that these plans should only be sent to the Public Utilities

Commission who can then forward them to the Agency if an input is required.

It is not envisaged that the GEA would necessarily be staffed with personnel with electricity

utility experience however the Agency should be knowledgeable about the developmental path

of that sector and seek to influence decisions that would be environmentally friendly.



The following are the key functions of the Guyana Energy Agency as it relates to the power

(electricity) sector.

o spearhead the energy conservation/efficiency programme of the country as it relates to

the demand for electrical energy

o promote a renewable/alternative energy policy, and, notwithstanding the fact that the

Clean Development Mechanism (CDM) unit is now a part of the Low Carbon

Development Strategy in the Office of the President, GEA should develop expertise in

the knowledge about the conditions and requirements for CDM projects especially as it

relates to the power sector.

o play an active role in the hinterland electrification policy and practice

o play an active role in the power sector planning committee

o play an advisory role in respect to the development and expansion plans of power

companies

9.3.4 Other Agencies

The Government Electrical Inspectorate’s functions under the Office of the Prime Minister and

its role is to

(a) To protect the public from dangers arising from the supply of electricity

GEI has recently received funding to update its regulations however there is no mechanism to

have these enforced. It is important that laws be established to enforce these regulations

together with those governing ‘the qualifications, examinations, licencing and registration

of electricians and electrical engineers, technicians and inspectors.

The Environmental Protection Agency will advise the Minister as he seeks to

(a) To take into account the effect on and the protection of the physical environment with

regard to activities connected with the supply of electricity

This agency has been performing this role in the various plans and activities of the power sector.

9.4 Power Sector Regulation

The Public Utilities Commission is vital to the Minister as he seeks to carry out his duties as

follows:

(a) To protect the interest of consumers of electricity supplied by persons authorized by

licences to supply electricity in respect of –

i. the prices charged and other terms of supply,

ii. the continuity of supply

iii. the quality of the electricity supply services provided, and,



(b) To ensure that, in relation to the powers regarding licences for the supply of electricity

granted to him pursuant to this Act, public suppliers are to finance the activities that they

are authorized by their licences to carry on, and to obtain a rate of return, if any,

provided for in their licences or a written agreement with the government, or if no rate of

return is provided for in a licence or in such a written agreement, to obtain a reasonable

rate of return on capital invested,

The Public Utilities Commission Act, Act 10 of 1999 saw the formation of this Commission with

its functions being spelt out in Section 21. Section 21 (1) states that the Commission shall

perform the regulatory, investigatory, enforcement and other functions conferred on it by this

Act. However Section 21 (2) states that

“In carrying out the functions mentioned in subsection (1), the Commission shall be

bound by and shall give effect to, the provisions of the Guyana energy Agency Act 1997,

the Electricity Reform Act 1999, the Telecommunications Act 1990, any other law

governing a public utility subject to the Commission‟s jurisdiction, the terms of any

licence issued by the Government to a public utility, and the terms of any agreement

between the government and a public utility, and in event of a conflict between such

agreements or licence and any written law, the agreements or licence shall prevail for

the purpose of this subsection (3) and Section 33, “written law” shall not include the

Constitution.”

Section 28 of the PUC Act requires that a public utility must submit for the approval of the

Commission any programme for development of facilities or services, and that the Commission

shall within a period not exceeding ninety days consider and render a decision approving or

rejecting, or requiring the suitable modification of the programme, however Section 17 of GPL

licence requires that the development and expansion plans be submitted to the Minister for

approval. As Section 21 (2) states that in carrying out the functions the Commission shall be

bound and shall give effect to, ….the terms of any licence issued by the Government to a public

utility the PUC has no jurisdiction over GPL’s development and expansion plans. It also needs

to be noted that the Commission has no jurisdiction over GPL’s rates but they are prescribed in

the GPL’s licence. As the rates are closely tied to the development plans then the PUC’s

function in this area may seem unnecessary.

It would seem therefore that the first issue to be addressed is that the Public Utilities Commission

needs to be given the legal authority to perform its proper regulatory function. Following closely

is the issue of the need for experienced electricity utility personnel to be employed by the

Commission. As the Caribbean has properly functioning regulatory commissions in Barbados,

Trinidad and Tobago, and Jamaica, it is being recommended that Caribbean personnel could be

employed to staff the PUC for a given period. These persons would then train local counterparts

preferably those with utility experience.




The following table shows the issues and options that have been discussed in this Chapter on

Sector Organisation, Management and Regulation.

Options

Medium Term Long Term

Industry Restructuring Remain a vertically

integrated utility

Separate Distribution

from Generation and

Transmission

Remain a vertically

integrated utility


from Transmission and

Generation


into regional

companies

Private Sector

Participation

Joint Generation Buy

Own Operate Transfer

(BOOT)

Management Contract

for vertically integrated

utility

Management Contract

for Distribution

Government owned but

subcontract all main

utility services

Joint Generation

BOOT

Privatisation of

vertically integrated

utility

Privatisation of

distribution separate

from Generation and

Transmission

Privatisation of

regional distribution

companies

Regulation Recruit, from overseas

if necessary, and train

personnel to effectively

perform the duties of a

regulatory commission

Where necessary,

change the laws to give

the Public Utilities

Commission the full

authority of a


Regardless of the

ownership the

company must be

operated according to

the principles of the

open market economy

Institute a fully

functioning regulatory

commission regardless

of the ownership or the

structure of the power

companies in Guyana

Electrical Power

System Planning

GPL to undertake its

own long term

planning

Form a power sector

planning committee

Power sector planning

cycles coordinated

with country planning

cycles



Development

Financing

Use of IPPs jointly

with government

Government/private

participation in

hinterland

electrification

Private sector

participation in

distribution

Political Reform Establish power sector

policy

Enact laws to enforce

policy

Regular policy review

Power Sector

Regulation

Establish power sector

regulations committee


regulations

Hinterland

Electrification

Form Hinterland

Electrification section

within OPM

Chapter 10 SUMMARY OF ISSUES, OPTIONS AND

RECOMMENDATIONS

CHAPTER 10 SUMMARY OF ISSUES, OPTIONS AND RECOMMENDATIONS


10.1 Introduction

This chapter summarises the issues that were raised and the options that were recommended in

the various areas. It then outlined the decisions that were made to be implemented as policy.

10.2 Energy Balances and Forecasts

There were two issues raised subsequent to the development of the medium term and long term

forecasts.

The agency that should be responsible for the development of national forecasts

The availability of economic and other data and the appropriate method for load

forecasting.

The recommendation made was that the Guyana Power & Light should be responsible for load

forecasting for its area of operation and that Guyana Energy Agency should be responsible for

putting together a national forecast.

The following agencies should provide the relevant data for inputs into the national load

forecasts:

Guyana Power & Light

Statistical Bureau

Bank of Guyana

Goinvest

Bauxite and Sugar Industries

10.3 Generation Technology

The study on generation technology made several recommendations concerning the type of

technology that should be developed by Guyana in the medium and long term. These are as

follows:

Diesel engines powered by heavy fuel oil were deemed to meet the needs of the medium

term better than wind turbines. Wind turbines as more suitable for an energy shortfall

whereby the shortfall in the medium term would be that of demand in the case of

breakdown or maintenance of the present generating sets. Wind turbines were also not

deemed suitable for the long term.

The long term energy needs should be met by hydropower and the development of the

Potaro River basin with an estimated average power of 500 MW was recommended to

meet the needs of the national grid.



It was also recommended that the greater power potential of the Mazaruni River basin

should be developed in conjunction with major projects such as an aluminum smelter.

Biomass for electricity generation was recommended as this has been proven to be

economical in other countries.

The UN’s Clean Development Mechanism programme is recommended for large projects

and the Amaila Falls hydropower would qualify however a better infrastructure would

need to be put in place if applications would be made for smaller projects are such as

GPL’s loss reduction project.

Mini and small hydropower projects were recommended for the development of the

hinterland communities.

The diesel installed generation capacity would not disappear immediately, however, with the

above recommendations the following installed generation mix was anticipated.



10.4 Primary Energy

The study on Primary Energy allocated generation to meet the forecasted demand. In order for

there not to be a period when the use of fuel oil will have to again be made it is recommended

that there be an immediate decision for prefeasibility studies to determine the next hydropower

site after Amaila Falls.

10.5 Network Issues

The following issues were raised under the section on Issues and Options

Regional forecasts are essential to the development of the transmission network.

Earmarking industrial zones and taking power to those zones for development.

Linden/Soesdyke was one area identified.

138 kV link between Demerara and Berbice rather than a 69 kV line.

Apart from the proposed 230 kV linking Linden and GPL, no further industrial

connections were identified.

Interconnection with neighbouring countries does not seem feasible in the long term.

GPL should keep abreast of all new technological developments in the field and assess

the economic impact of each.

Unbundling transmission and distribution was not recommended at this stage of the

study.

During the discussion on these recommendations it was felt that the Linden/Soesdyke was not a

good area for industrial development.

10.6 Energy Efficiency

There were five areas that were highlighted under the issues and options section. These were as

follows:

Energy Efficiency Policy



‒ Define legal and regulatory policy for energy efficiency and renewable energy

‒ Implement national energy efficiency policy and action plan.

‒ Implement energy efficiency standards and labelling

Financing Energy Efficiency Programmes

‒ Determine the financing mechanisms required to support the energy efficiency plan.

‒ Develop an energy efficiency programme for the implementation and financing of energy

efficiency projects in the commercial and industrial sectors.

‒ Encourage Private /Public partnership for renewable energy projects.

Public relations

‒ Establish an information centre (e.g. a unit within GEA).

‒ Establish a baseline data collection programme.

‒ Disseminate consumer information on Energy Efficiency equipment in all sectors.

Energy Audits

‒ Make energy audits mandatory for all state run or controlled institutions and

organisations.

‒ Ensure all major industries conduct Energy Audits of their operations thus using

the Energy Audits as an effective tool for industrial energy management.

‒ Encourage and promote the use of demand side management programs

Personnel Training

‒ Establish training programs.

‒ Encourage the establishment of energy efficiency consultants.

‒ Build capacity of participants in the renewable energy sector.

The Guyana Energy Agency has already produced an energy efficiency programme

incorporating many of these ideas and is awaiting approval and financing for the programme.

10.7 Commercial Issues

The Issues and Options Section asked the following questions.

Tariffs

‒ Should tariffs cover at least financial, if not, economic costs?

‒ Should there be cross subsidisation among tariff classes?

‒ Who should benefit and what should be the level of lifeline tariffs?

Regulation of tariffs

‒ Who should perform the regulation of the tariffs?

‒ Who should approve developmental plans in the power sector?

Hinterland Electrification

‒ What are reasonable rates/tariffs for hinterland areas?

‒ How should subsidies be given?



‒ What other commercial incentives can be given towards renewable energy

equipment for the hinterland areas

Commercial Losses

‒ Should loss reduction targets be policy issues?

‒ Should treatment of theft of electricity be a policy issue?

‒ Can incentives be given towards notification of theft of electricity?

On the issue of the tariffs it was felt that tariffs should at least cover financial costs of the utility

operations and cross subsidization should be very limited. There was a suggestion that in the

residential category there should be a minimum free level of electricity and then all customers

should pay for all use above that level.

In the medium term the Office of the Minister would be responsible for the regulation of tariffs.

There was no definitive agreement on the policy governing hinterland electrification.

10.8 Financial Issues

The following was recommended and concluded:

The Government of Guyana (GoG) as owner and lender may wish to consider the

following

a) the establishment of a power sector development support fund, which will

operate as a revolving fund under the control of the GoG (and external to

GPL) into which will be deposited

i) loan repayments to the GoG by GPL and

ii) dividend payments to the GoG by GPL

the funds to be used at the discretion of the GoG to support by way of

reinvestment, the ongoing development of GPL

b) the establishment of a dividend policy aimed at

i) ensuring a minimum return on its equity over the tariff

implementation period

ii) the retention of earnings at a level consistent with the need to

maintain working capital and

iii) providing for a percentage of the maintenance cost of the T & D

network.

The determination of the sufficiency of GPL’s profits will rest more with the GPL in its


PUC.

GPL should be responsible for paying a dividend as a ‘public utility’ but within a policy

framework designed to satisfy the interests of the owners (GoG) and the consumers. It is

quite likely that there will be a need for legislative changes in order to implement this.



If GPL is to pre-finance its capital investments in the manner indicated, there will be need

to be significant reform in the existing laws of Guyana, including the constitution.

10.9 Power Sector Organisation Management and Regulation

The following table shows the issues and options that were proposed on Sector Organisation,

Management and Regulation.

Options

Medium Term Long Term

Industry Restructuring Remain a vertically

integrated utility


from Generation and

Transmission

Remain a vertically

integrated utility


from Transmission and

Generation


into regional

companies

Private Sector

Participation

Joint Generation Buy

Own Operate Transfer

(BOOT)

Management Contract

for vertically integrated

utility

Management Contract

for Distribution

Government owned but

subcontract all main

utility services

Joint Generation

BOOT

Privatisation of

vertically integrated

utility

Privatisation of

distribution separate

from Generation and

Transmission

Privatisation of

regional distribution

companies

Regulation Recruit, from overseas

if necessary, and train

personnel to effectively

perform the duties of a


Where necessary,

change the laws to give

the Public Utilities

Commission the full

authority of a


Regardless of the

ownership the

company must be

operated according to

the principles of the

open market economy

Institute a fully

functioning regulatory

commission regardless

of the ownership or the

structure of the power

companies in Guyana



Electrical Power

System Planning

GPL to undertake its

own long term

planning

Form a power sector

planning committee

Power sector planning

cycles coordinated

with country planning

cycles

Development

Financing

Use of IPPs jointly

with government

Government/private

participation in

hinterland

electrification

Private sector

participation in

distribution

Political Reform Establish power sector

policy


policy

Regular policy review

Power Sector

Regulation

Establish power sector

regulations committee


regulations

Hinterland

Electrification

Form Hinterland

Electrification section

within OPM

10.10 Conclusion The Guyana Power Sector Policy and Implementation Strategy which is presented in a separate

document lists the policy decisions that were taken after discussions with officials from the

Office of the Prime Minister, the Guyana Power & Light Inc., the Guyana Energy Agency and

after review by a Cabinet Sub Committee.

Appendix I

APPENDIX I ENERGY BALANCES AND FORECASTS

Appendix I ENERGY BALANCES AND FORECASTS


Appendix I-1: Self Generators List I - GPL Industrial Customers now Self Generators (Source GPL)

No. Type of

Business

Disconnect

Date

Avge

Maximum

Demand

(kVA)

Annual

Consumption

(kWh)

1 Fishery 2008 100 67,656

2 Fishery 2004 145 741,630

3 Fishery 2005 103 133,453

4 Fishery 2003 393 1,491,333

5 Fishery 2006 51 14,518

6 Fishery 2008 198 1,128,516

7 Fishery 2003 339 999,195

8 Rice Mill 2006 56 124,101

9 Rice Mill 2007 339 494,496

10 Manufacturing 2004 52 29,495

11 Saw Mill 2008 108 50,808

12 Saw Mill 2006 139 21,581

13 Hotel 2004 56 119,303

14 Hotel 2002 133 443,023

15 Hotel 2008 103 154,080

16 Hotel 2008 122 234,516

17 Hotel 2008 377 1,103,400

18 Hotel 2002 175 395,370

19 Hotel 2002 82 270,522

20 Restaurant 2002 197 775,109

21 Services 2002 53 104,326

22 Commercial 2008 100 7,200

23 Commercial 2006 0 63,140

24 Commercial 2005 0 57,021

25 Commercial 2002 53 56,023

26 Manufacturing 2008 450 869,400

27 Not Specified 2007 152 162,408

28 Not Specified 2007 0 81,810

29 Not Specified 2008 100 117,000

30 Not Specified 2008 100 67,656

31 Not Specified 2006 289 29,660

32 Manufacturing 2002 500 1,941,308

33 Manufacturing 2002 300 1,253,443

34 Manufacturing 2001 100 347,372

35 Manufacturing 2002 150 495,021

Total 5615.0159 14,444,894



Appendix I-2: Self Generators List II (Source OPM)

No. Type of

Business

Date of

Installation

Maximum

Demand

(kW)

Annual

Consumption

(kWh)


2 Fishery 2004 110 228,800

3 Wood working 2008 30 62,400

4 Wood working 2008 30 62,400

5 Wood working 2006 100 208,000

6 Not Specified 2002 100 208,000


8 Bakery 2005 68 141,440

9 Manufacturing 2006 204.8 425,984

10 Services 2005 67.2 139,776

11 Services

60 124,800

12 Not Specified 1995 124.8 259,584

13 Services 2005 100 208,000

14 Manufacturing 1995 300 624,000



17 Saw Mill 1986 125.2 260,416

18 Fishery 2000 700 1,456,000

19 Bakery 1977 6.4 13,312



22 Services 2007 120 249,600

23 Services

60 124,800

24 Rice Mill 1992, 2002 1100 2,288,000

25 Not Specified 1998 52 108,160

26 Services 2006 12 24,960

27 Commercial 2007 150 312,000

28 Manufacturing 1986 126 262,080

29 Rice Mill 2004 142.8 297,024

30 Rice Mill 2004 130 270,400

31 Manufacturing 1996,2001 110 228,800

32 Manufacturing 2002 190 395,200

33 Manufacturing 1999 120 249,600


35 Services 2007 140 291,200

36 Manufacturing

80 166,400

37 Manufacturing

1270 2,641,600

38 Manufacturing

992 2,063,360



39 Services

300 624,000

40 Manufacturing

400 1,310,400

41 Services

340 707,200

Total 8,335 17,815,616



Appendix I-3: Self Generators Survey Form

GUYANA POWER SECTOR POLICY & INVESTMENT STRATEGY

SELF GENERATORS SURVEY

CONFIDENTIAL

1. What is the nature of your business?

o Manufacturing o Commerce o Services o Other ………….

2. In what year do you start to generate your own electricity? ………………….

3. What was/were the reason(s) for doing so?

o Price o Reliability o Power Quality o Other …………….

4. What is your installed generating capacity?

No.

Installed

Capacity

(kW)

Installation

Date

1

2

3

4

5

6

5. What has been your annual maximum (or average) demand (kW) and generation (kWh) over the

last five years?

Year

Maximum

Demand

(kW)

Generation

(kWh)

2004

2005

2006

2007

2008



6. Based on pour company’s development plans what level of increase in your electricity demand

and consumption do you project over the next five years?

0 – 5%

6 – 10%

11 – 15%

16 – 20%

Other ………….

7. What reduction in prices could attract you back to GPL?

30%

40%

50%

Other …………..

8. What level of reliability is necessary for your operations?

1 outage for 1 hour per week

1 outage for 1 hour per month

6 outages for 6 hours annually

Other ……………………………..

9. What power quality problems did you encounter from GPL?

High/low voltages

Power surges

Other ………



Appendix I-4: Self Generators List III (Survey Results)

No. Type of

Business

Survey

Year

Installed

Capacity

(kW)

Maximum

Demand

(kW)

Annual

Consumption

(kWh)

1 Manufacturing 2008 3288 1650 2,910,506

2 Manufacturing 2008 6045 2300 11,977,182

3 Manufacturing 2008 6000 3500 16,200,000

4 Manufacturing 2008 1260 500 1,300,000

5 Manufacturing 2008 3300 800 1,664,000

Total 19893 8750 34,051,688



Appendix I-5: GPL’s Monthly Generation and Sales Data

Month GEN SALES Residential Commercial Small

Industrial Large

Industrial St. Lighting Losses

MWH

Jan-00 37.91 24.49 11.24 4.63 2.55 5.88 0.18 13.42

Feb-00 35.97 23.13 10.62 4.37 2.41 5.56 0.17 12.84

Mar-00 39.11 24.11 11.07 4.56 2.51 5.79 0.18 15.00

Apr-00 37.78 23.48 10.78 4.44 2.45 5.64 0.17 14.29

May-00 40.10 23.14 10.62 4.37 2.41 5.56 0.17 16.97

Jun-00 38.88 23.79 10.92 4.49 2.48 5.71 0.17 15.10

Jul-00 40.44 24.06 11.05 4.55 2.51 5.78 0.17 16.38

Aug-00 40.32 25.10 11.52 4.74 2.62 6.03 0.18 15.22

Sep-00 40.77 23.79 10.92 4.50 2.48 5.71 0.17 16.98

Oct-00 42.53 24.84 11.40 4.69 2.59 5.97 0.18 17.70

Nov-00 40.87 25.40 11.66 4.80 2.65 6.10 0.18 15.48

Dec-00 42.22 21.93 10.07 4.14 2.29 5.27 0.16 20.29

Jan-01 41.45 24.84 11.40 4.69 2.59 5.97 0.18 16.62

Feb-01 35.95 23.84 10.95 4.51 2.49 5.73 0.17 12.11

Mar-01 41.30 24.21 11.12 4.57 2.53 5.82 0.18 17.09

Apr-01 40.21 23.49 10.79 4.44 2.45 5.64 0.17 16.72

May-01 42.94 22.92 10.52 4.33 2.39 5.51 0.17 20.02

Jun-01 41.14 25.14 11.54 4.75 2.62 6.04 0.18 16.00

Jul-01 42.25 23.72 10.89 4.48 2.47 5.70 0.17 18.53

Aug-01 43.37 25.13 11.54 4.75 2.62 6.04 0.18 18.24

Sep-01 41.56 24.50 11.25 4.63 2.56 5.88 0.18 17.07

Oct-01 44.75 23.89 10.97 4.51 2.49 5.74 0.17 20.86

Nov-01 43.25 25.44 11.68 4.81 2.65 6.11 0.18 17.81

Dec-01 46.37 25.81 11.85 4.88 2.69 6.20 0.19 20.56

Jan-02 44.84 24.95 11.32 4.59 2.35 6.58 0.10 19.89

Feb-02 39.19 24.64 11.18 4.53 2.33 6.50 0.10 14.55

Mar-02 44.00 21.81 9.90 4.01 2.06 5.76 0.09 22.20

Apr-02 43.57 22.88 10.39 4.21 2.16 6.04 0.09 20.69

May-02 43.89 24.69 11.21 4.54 2.33 6.52 0.10 19.20

Jun-02 41.33 23.65 10.73 4.35 2.23 6.24 0.09 17.68

Jul-02 43.42 23.18 10.52 4.26 2.19 6.12 0.09 20.24

Aug-02 43.25 25.26 11.46 4.64 2.38 6.67 0.10 18.00

Sep-02 42.14 23.06 10.47 4.24 2.18 6.09 0.09 19.08

Oct-02 43.11 24.08 10.93 4.43 2.27 6.35 0.10 19.04

Nov-02 41.32 23.62 10.72 4.34 2.23 6.23 0.09 17.70

Dec-02 42.69 23.92 10.86 4.40 2.26 6.31 0.10 18.77





Industrial Large


MWH

Jan-03 42.14 23.75 10.99 4.60 2.36 5.66 0.14 18.39

Feb-03 36.35 20.28 9.39 3.93 2.02 4.83 0.12 16.07

Mar-03 38.17 19.81 9.17 3.84 1.97 4.72 0.12 18.36

Apr-03 38.82 20.27 9.38 3.93 2.02 4.83 0.12 18.56

May-03 40.91 23.53 10.89 4.56 2.34 5.61 0.14 17.38

Jun-03 40.33 21.21 9.82 4.11 2.11 5.05 0.12 19.12

Jul-03 40.89 22.37 10.35 4.33 2.23 5.33 0.13 18.52

Aug-03 41.75 24.78 11.47 4.80 2.47 5.90 0.15 16.97

Sep-03 41.58 23.15 10.71 4.48 2.30 5.51 0.14 18.43

Oct-03 42.75 23.19 10.73 4.49 2.31 5.52 0.14 19.56

Nov-03 41.52 23.11 10.69 4.48 2.30 5.50 0.14 18.42

Dec-03 43.62 22.62 10.47 4.38 2.25 5.39 0.13 20.99

Jan-04 42.88 25.52 12.22 4.82 2.37 5.92 0.20 17.36

Feb-04 39.17 22.60 10.82 4.27 2.10 5.24 0.18 16.57

Mar-04 41.74 22.17 10.61 4.19 2.06 5.14 0.17 19.58

Apr-04 40.68 24.00 11.49 4.53 2.23 5.56 0.19 16.68

May-04 42.53 24.66 11.80 4.66 2.29 5.72 0.19 17.87

Jun-04 41.84 21.98 10.52 4.15 2.04 5.10 0.17 19.86

Jul-04 43.87 25.54 12.22 4.83 2.37 5.92 0.20 18.34

Aug-04 44.05 25.50 12.20 4.82 2.37 5.91 0.20 18.55

Sep-04 43.51 24.19 11.58 4.57 2.25 5.61 0.19 19.32

Oct-04 44.95 25.71 12.31 4.86 2.39 5.96 0.20 19.24

Nov-04 43.79 25.54 12.22 4.83 2.37 5.92 0.20 18.25

Dec-04 45.97 25.68 12.29 4.85 2.38 5.95 0.20 20.29

Jan-05 42.67 25.69 12.44 5.03 2.31 5.68 0.22 16.98

Feb-05 38.98 23.33 11.30 4.57 2.10 5.16 0.20 15.66

Mar-05 44.60 22.97 11.12 4.49 2.07 5.08 0.20 21.64

Apr-05 43.31 25.15 12.18 4.92 2.26 5.56 0.22 18.16

May-05 45.29 24.86 12.04 4.87 2.24 5.50 0.22 20.43

Jun-05 43.80 25.14 12.17 4.92 2.26 5.56 0.22 18.66

Jul-05 44.13 25.60 12.40 5.01 2.31 5.66 0.22 18.53

Aug-05 45.60 25.20 12.20 4.93 2.27 5.58 0.22 20.39

Sep-05 45.10 25.94 12.56 5.08 2.34 5.74 0.23 19.17

Oct-05 46.23 26.31 12.74 5.15 2.37 5.82 0.23 19.92

Nov-05 43.95 26.44 12.80 5.17 2.38 5.85 0.23 17.51

Dec-05 44.20 26.80 12.98 5.25 2.41 5.93 0.23 17.40





Industrial Large


MWH

Jan-06 42.83 26.55 12.03 5.39 2.51 6.25 0.37 16.28

Feb-06 38.59 22.80 10.33 4.63 2.15 5.36 0.32 15.80

Mar-06 43.79 24.90 11.29 5.06 2.35 5.86 0.35 18.88

Apr-06 42.76 24.74 11.21 5.02 2.34 5.82 0.35 18.02

May-06 44.84 24.70 11.19 5.02 2.33 5.81 0.35 20.14

Jun-06 42.47 26.12 11.84 5.30 2.47 6.15 0.37 16.35

Jul-06 43.78 26.36 11.94 5.35 2.49 6.20 0.37 17.43

Aug-06 44.91 25.10 11.37 5.10 2.37 5.90 0.35 19.82

Sep-06 44.00 28.25 12.80 5.74 2.67 6.65 0.40 15.75

Oct-06 46.67 27.42 12.43 5.57 2.59 6.45 0.38 19.24

Nov-06 43.99 27.72 12.56 5.63 2.62 6.52 0.39 16.27

Dec-06 45.73 29.45 13.35 5.98 2.78 6.93 0.41 16.29

Jan-07 46.64 28.69 12.76 5.73 2.65 7.07 0.49 17.95

Feb-07 41.52 28.52 12.68 5.69 2.63 7.03 0.49 13.00

Mar-07 46.51 27.25 12.12 5.44 2.51 6.71 0.46 19.27

Apr-07 46.50 30.04 13.36 6.00 2.77 7.40 0.51 16.47

May-07 46.81 27.87 12.40 5.56 2.57 6.87 0.47 18.94

Jun-07 44.64 28.68 12.76 5.73 2.65 7.07 0.49 15.95

Jul-07 46.54 28.41 12.63 5.67 2.62 7.00 0.48 18.13

Aug-07 47.28 29.36 13.06 5.86 2.71 7.23 0.50 17.93

Sep-07 46.92 30.32 13.48 6.05 2.80 7.47 0.52 16.61

Oct-07 49.03 29.97 13.33 5.98 2.76 7.38 0.51 19.06

Nov-07 45.58 31.74 14.12 6.34 2.93 7.82 0.54 13.84

Dec-07 47.72 30.12 13.40 6.01 2.78 7.42 0.51 17.60

Jan-08 46.99 30.13 13.59 5.47 2.66 7.89 0.53 16.86

Feb-08 43.30 29.05 13.10 5.27 2.56 7.61 0.51 14.25

Mar-08 45.80 27.11 12.23 4.92 2.39 7.10 0.48 18.70

Apr-08 46.25 28.31 12.77 5.13 2.49 7.41 0.50 17.94

May-08 47.74 31.36 14.15 5.69 2.76 8.21 0.55 16.38

Jun-08 46.41 28.73 12.96 5.21 2.53 7.52 0.51 17.69

Jul-08 47.44 28.06 12.65 5.09 2.47 7.35 0.49 19.38

Aug-08 49.26 30.75 13.87 5.58 2.71 8.05 0.54 18.51

Sep-08 48.17 30.21 13.62 5.48 2.66 7.91 0.53 17.96

Oct-08 48.04 29.98 13.52 5.44 2.64 7.85 0.53 18.05

Nov-08 48.84 30.92 13.95 5.61 2.73 8.10 0.55 17.91

Dec-08 49.02 31.29 14.11 5.68 2.76 8.19 0.55 17.74



Appendix I-8: IMF GDP 2009 Country Projections - Guyana

Subject Descriptor Units Scale 2004 2005 2006 2007

GDP, constant prices Annual percent change

1.573 -1.9 5.13 5.356

GDP, current prices National currency Billions 155.854 164.943 183.084 216.856

GDP, current prices U.S. dollars Billions 0.78 0.824 0.913 1.062

GDP, deflator Index

2,787 3,007 3,175 3,569

GDP per capita, constant prices National currency Units 7,416 7,252 7,599 7981

GDP per capita, current prices National currency Units 206,697 218,050 241,257 284843

GDP per capita, current prices U.S. dollars Units 1,089 1,203 1395

Subject Descriptor Units Scale 2008 2009 2010 2011


3.233 2.604 3.448 5.78

GDP, current prices National currency Billions 236.157 252.932 275.383 305.072

GDP, current prices U.S. dollars Billions 1.13 1.193 1.279 1.395

GDP, deflator Index

3765 3930 4137 4332

GDP per capita, constant prices National currency Units 8212 8399 8661 9161

GDP per capita, current prices National currency Units 309200 330102 358250 396873

GDP per capita, current prices U.S. dollars Units 1480 1557 1664 1815

Subject Descriptor Units Scale 2012 2013 2014


4.568 4.338 3.801

GDP, current prices National currency Billions 334.525 365.748 398.22

GDP, current prices U.S. dollars Billions 1.506 1.639 1.777

GDP, deflator Index

4543 4760 4993

GDP per capita, constant prices National currency Units 9580 9995 10375

GDP per capita, current prices National currency Units 435189 475807 518050

GDP per capita, current prices U.S. dollars Units 1959 2133 2312 International Monetary Fund, World Economic Outlook Database, April 2009



Appendix I-9: Generation, Sales, GDP, and Population Data 1981 - 2008

Year Generation

(MWH) Sales

(MWH) GDP G$M

Exchange Rates

GDP US$M

POPULATION

1981 213.0 N.A. 1350 2.81 480.43 758.00

1982 188.9 N.A. 1250 3.0 416.67 757.60

1983 205.1 N.A. 1200 3.0 400.00 757.30

1984 205.8 162.7 1410 3.83 368.15 756.90

1985 213.2 169.5 1630 4.25 383.53 756.50

1986 204.7 160.9 1821 4.27 426.46 756.10

1987 209.9 178.9 2851 9.76 292.11 755.70

1988 202.4 161.6 3600 10 360.00 757.21

1989 159.1 121.6 9074 27.16 334.09 756.82

1990 212.4 150.4 13815 39.53 349.48 750.65

1991 219.1 171.0 33622 111.8 300.73 719.09

1992 237.5 167.0 40391 125.09 322.90 738.97

1993 252.2 169.0 49532 130.16 380.55 746.95

1994 290.6 217.0 63145 138.89 454.64 763.69

1995 333.7 217.0 73927 141.85 521.16 773.41

1996 347.3 262.0 82258 140.13 587.01 777.65

1997 390.4 262.0 89744 141.93 632.31 778.80

1998 431.2 285.0 90471 150.46 601.30 780.48

1999 443.2 N.A. 105095 177.05 593.59 781.16

2000 476.9 287.2 108087 181.09 596.87 743.11

2001 504.6 289.9 112219 187.11 599.75 744.20

2002 512.7 288.1 117762 190.63 617.75 751.22

2003 488.9 268.1 123261 195.34 631.01 753.77

2004 514.9 292.2 130533 199.79 653.35 756.35

2005 528.4 300.8 137788 200.64 686.74 758.93

2006 534.6 312.1 154000 201.29 765.07 761.51

2007 559.2 349.8 171190 201.86 848.06 765.18

2008 566.0 355.6 190728 201.89 944.71 768.87



Appendix I-10: Projected GDP, and Population Data 2009

Year GDP G$M

Exchange Rates GDP US$M POPULATION

2009 195694.6 201.89 969.31 778.14

2010 202442.1 201.89 1002.73 787.52

2011 214143.3 201.89 1060.69 791.63

2012 223925.3 201.89 1109.15 795.77

2013 233863.1 201.89 1158.37 799.94

2014 242752.3 201.89 1202.40 804.12

2015 254889.9 201.89 1262.52 808.32

2016 267634.4 201.89 1325.64 811.90

2017 281016.1 201.89 1391.93 815.49

2018 295066.9 201.89 1461.52 819.10

2019 309820.2 201.89 1534.60 822.73

2020 325311.3 201.89 1611.33 826.37

2021 341576.8 201.89 1691.90 828.59

2022 358655.7 201.89 1776.49 830.81

2023 376588.4 201.89 1865.31 833.04

2024 395417.9 201.89 1958.58 835.28

2025 415188.8 201.89 2056.51 837.53

APPENDIX II GENERATION TECHNOLOGY

[Type the abstract of the document here. The abstract is typically a short summary of the contents of the document. Type the abstract of the document here. The abstract is typically a short summary of the contents of the document.]

Appendix II GENERATION TECHNOLOGY


APPENDIX II-1

FIRST ADDED INVENTORY SITES IN ORDER OF COST PER RATED KW (US$)

Site River Basin/ Region

Average Capacity

(MW)

Rated Capacity

(MW)

Cost/kW Rated (US$)

Remarks

1 Kaieteur Potaro 350 583 540 2 Sand Landing Mazaruni 655 1,092 552 Full Development (C)

3 Kaieteur Potaro 216 320 669 First Stage

4 Upper Mazaruni Mazaruni 440 733 844 First Stage

5 Sand Landing Mazaruni 328 546 850 First Stage (C)

6 Turtruba Mazaruni 320 533 886 7 Sand Landing Mazaruni 650 1,083 889 Full Development (T)

8 Takwari Essequibo 346 577 997 9 Sand Landing Mazaruni 325 542 1,077 First Development (T)

10 Amaila Potaro 103 172 1,100 11 Oko-Blue Cuyuni 162 270 1,140 12 Arisaru Essequibo 120 200 1,170 13 Chi-Chi Mazaruni 96 160 1,500 14 King George V Essequibo 112 187 1,540 15 Tumatumari Potaro 45 75 1,653 16 Great Falls Mazaruni 13 22 1,682 17 Amarioa New River 107 178 1,915 18 Kumarau Mazaruni 86 143 2,000 19 Iatuk Potaro 77 128 2,050 20 No. 1 Dam Mazaruni 14 23 2,087 21 Tumatumari Potaro 34 57 2,105 Low Head

22 Devil's Hole Cuyuni 62 103 2,126 23 Sakaika Cuyuni 17 28 2,143 24 Manarowa Essequibo 63 105 2,229 25 Paruima Mazaruni 26 43 2,372

26 Tiger Hill

Northeast Coastal 15 25 2,440

27 Tiboku Mazaruni 40 67 2,460 28 Apaikwa Mazaruni 34 57 2,950

29 Queen Diamond Potaro 29 48 3,042

30

Towokaima Northwest Coastal 6 11 3,100

31 Utshi Mazaruni 17 28 3,107 32 Aruwai Mazaruni 38 63 3,590 33 Chitigokeng Mazaruni 31 52 3,980



Site River Basin/ Region

Average Capacity

(MW)

Rated Capacity

(MW)

Cost/kW Rated (US$)

Remarks

34 Peaima Mazaruni 19 32 5,380 35 No.4 Dam Cuyuni 20 33 5,485 36 Akobenang Potaro 13 22 6,000

37 King William IV Essequibo 12 20 7,550

38 Patterson Essequibo 10 17 7,588

39 Itabru

Northeast Coastal 6 10 7,800

Total

5,057 8,388



APPENDIX II-2 INVENTORY SITES DEVELOPED IN CONJUNCTION WITH UPSTREAM STORAGE

IN ORDER OF COST PER RATED KW (US$)

Site

River Basin/ Region

Average Capacity

(MW)

Rated Capacity

(MW)

Cost/kW Rated US$

Remarks

1 Kaieteur Potaro 347 579 402 2 Sand Landing Mazaruni 655 1,092 417 Full Development (C)

3 Kaieteur Potaro 212 353 507 First Stage

4 Chitigokeng Mazaruni 264 440 511

5 Upper Mazaruni

Mazaruni 1,320 2,200 844 Full Development

6 Turtruba Mazaruni 456 760 604 7 Sand Landing Mazaruni 328 546 850 First Stage (C)

8 Upper Mazaruni

Mazaruni 440 733 681 First Stage

9 Aruwai Mazaruni 272 454 696 10 Sand Landing Mazaruni 650 1,083 750 Full Development (T)

11 Chi-Chi Mazaruni 96 160 769 12 Amaila Potaro 103 172 779 13 Tiboku Mazaruni 133 222 806 14 Sakaika Cuyuni 50 83 807 15 Peaima Mazaruni 148 247 850 16 Sand Landing Mazaruni 325 452 750 First Development (T)

17 Tumatumari Potaro 89 148 892 18 King George V Essequibo 112 187 936 19 Arisaru Essequibo 233 388 966 20 Takwari Essequibo 350 583 967 21 Kamaria Mazaruni 103 172 977 22 Oko-Blue Cuyuni 167 278 1,025 23 Apaikwa Mazaruni 74 123 1,050

24 Tumatumari Potaro 66 110 1,082 High TWL

25 Manarowa Essequibo 182 303 1,209

26 Barrington Brown Falls

New River 65 108 1,259

27 King William IV Essequibo 52 87 1,264 28 Iatuk Potaro 83 138 1,319 29 Amaripa New River 107 178 1,371 30 Kumarau Mazaruni 86 143 1,406 31 No. 1 Dam Mazaruni 14 23 2,050 32 Devil's Hole Cuyuni 83 138 1,428



Site

River Basin/ Region

Average Capacity

(MW)

Rated Capacity

(MW)

Cost/kW Rated US$

Remarks

33 Patterson Essequibo 37 62 1,468 34 Great Falls Mazaruni 13 22 1,682

35 Queen Diamond Potaro 40 67 1,716

36 No. 1 Dam Mazaruni 14 23 2,087 37 Paruima Mazaruni 29 48 2,146

38 Tiger Hill Northeast Coastal

15 25 2,440

39 Towokaima

Northwest Coastal

6 11 2,545

40 Akobenang Potaro 13 22 2,682 41 Utshi Mazaruni 17 28 3,107 42 No.4 Dam Cuyuni 20 33 3,809

43 Itabru Northeast Coastal

6 10 7,800

Total

7,875 13,034

APPENDIX III NETWORK ISSUES

Appendix III NETWORK ISSUES


Appendix III-1 Load Flow Results 2012 Load Forecast

Busbar Name Nom kV PU Volt Volt

(kV)

Angle

(Deg)

Load

MW

Load

Mvar

Gen

MW

Gen

Mvar

Switched

Shunts

Mvar

#53 Village 14.0 1.00 14.0 -1.1 5.0 2.1 0

#53 Village Sub 69.0 1.01 70.0 0.4 0

Canefield 14.0 1.00 14.0 -2.4 7.5 3.1 4.5 4.5 0

Canefield Sub 69.0 0.99 68.6 -1.4 0

Diamond 14.0 1.02 14.3 -2.1 3.5 1.8 0

Diamond Sub 69.0 0.98 67.7 -1.3 0

DP1 14.0 1.00 14.0 2.4 11.0 1.9 0

Durban 14.0 1.03 14.4 -2.2 10.0 5.0 0

Durban Sub 69.0 0.98 67.4 -2.0 0

Edinburgh 14.0 1.02 14.3 -2.8 3.0 1.5 0

Edinburgh Sub 69.0 0.98 67.8 -2.0 0

Garden of Eden 14.0 1.00 14.0 1.4 4.0 2.0 17.2 3.6 0

Garden of Eden Sub 69.0 0.99 68.5 -0.7 0

Good Hope 14.0 0.99 13.8 -3.6 5.0 2.5 0

Good Hope Sub 69.0 0.97 67.2 -2.1 0

Kingston 14.0 1.00 14.0 -1.1 24.0 12.0 42.7 32.2 0

Kingston Sub 69.0 0.99 68.3 -1.7 0

Mahaica 14.0 1.00 14.0 -2.7 2.5 1.0 0

Mahaica Sub 69.0 0.98 67.6 -2.0 0

Onverwagt 14.0 1.00 14.0 -0.9 2.5 1.0 5.0 2.7 0

Onverwagt Sub 69.0 0.99 68.3 -1.6 0

Skeldon 14.0 1.00 14.0 4.3 10.0 3.2 0

Skeldon Sub 69.0 1.03 70.8 1.2 0

Sophia 14.0 1.01 14.1 -3.4 18.5 9.3 0

Sophia Sub 69.0 0.98 67.6 -1.7 0

Versailles 14.0 1.03 14.4 -2.9 4.0 2.0 0

Versailles Sub 69.0 0.99 68.1 -1.8 0

TOTAL

89.5 43.37 90.51 48.74 0

Busbar Voltages for Load Flow Run 2012 Load Projections



Appendix III-2 Line Flows 2012 Load Forecast

From Name To Name Xfrmr MW

From

Mvar

From

MVA

From

% of

MVA

Limit

(Max)

MW Loss Mvar

Loss

Canefield Sub Onverwagt Sub No 1.8 0.9 2 11.9 0 0.01

Onverwagt Onverwagt Sub Yes 2.5 1.2 2.8 16.5 0 0.04

Onverwagt Sub Mahaica Sub No 4.3 2 4.7 0 0.03 0.08

Canefield Sub #53 Village Sub No -3.8 0 3.8 22.9 0.06 0.1

Canefield Canefield Sub Yes -2 0.9 2.2 13.2 0 0.03

#53 Village Sub Skeldon Sub No -9.9 -2.8 10.2 34.6 0.08 0.17

#53 Village Sub #53 Village Yes 6 2.7 6.6 39.6 0.03 0.23

Skeldon Sub Skeldon Yes -9.9 -3 10.4 66.4 0.07 0.62

Mahaica Sub Mahaica Yes 2 0.9 2.2 0 0 0.03

Mahaica Sub Good Hope Sub No 2.2 1.1 2.5 14.8 0.01 0.01

Good Hope Sub Good Hope Yes 5 2.7 5.7 34.1 0.02 0.18

Good Hope Sub Sophia Sub No -2.8 -1.6 3.2 19.4 0.01 0.01

Garden of Eden Sub Sophia Sub No 11.3 1 11.3 37.7 0.14 0.22

Sophia Sub Kingston Sub No -11 -17 20.3 58.6 0.12 0.2

Sophia Sub Sophia Yes 4.8 4.7 6.7 40.3 0.03 0.23



Sophia Sub Sophia Yes 3.6 -4.6 5.8 35.4 0.02 0.19

Diamond Sub Sophia Sub No 9.3 -0.5 9.3 46.6 0.03 0.07

Sophia Sub Durban Sub No 10 5.4 11.4 68.3 0 0.07

Garden of Eden Sub Garden of Eden Yes -8 -0.5 8 48.6 0.04 0.36

Garden of Eden Sub DP1 Yes -8.2 -1.6 8.4 50.6 0 0.35

Garden of Eden Sub Diamond Sub No 13 1.6 13.1 65.3 0.12 0.15

Garden of Eden Sub 38 Yes -8 -0.6 8 48.5 0.04 0.32

Kingston Sub Versailles Sub No 7.6 4 8.5 51.3 0.02 0.03

Kingston Kingston Sub Yes 18.7 21.6 28.6 81.6 0 0.41

Versailles Sub Edinburgh Sub No 3.5 1.9 4 24 0.01 0.03

Versailles Sub Versailles Yes 4 2.1 4.5 22.6 0.01 0.08

Edinburgh Sub Edinburgh Yes 3.5 1.9 4 39.8 0.01 0.12

38 Garden of Eden No -5.3 -0.3 5.3 0 0 0.03

DP1 38 No 2.8 0.6 2.8 0 0 0

Diamond Sub Diamond Yes 1.3 -2.2 2.5 25.9 0.01 0.05

Diamond Sub Diamond Yes 2.2 4.2 4.7 47.4 0.02 0.17

Durban Sub Durban Yes 5 2.6 5.7 34 0.02 0.15

Durban Sub Durban Yes 5 2.6 5.7 34 0.02 0.15

TOTAL 1.03 5.38

Line Flows for Load Flow Run - 2012 Load Projections



Appendix III-3 - Busbar Voltages 2016 Load Forecast

Name Nom kV PU Volt Volt (kV) Angle

(Deg)

Load

MW

Load

Mvar

Gen

MW

Gen

Mvar

Switched

Shunts

Mvar

#53 Village 14.0 1.02 14.2 -9.7 7.5 3.1 3.1

#53 Village Sub 69.0 1.02 70.4 -7.5 0.0

38 14.0 1.00 14.0 -0.3 0.0

Canefield 14.0 1.02 14.3 -11.0 9.0 3.8 0.0 0.0 8.3

Canefield Sub 69.0 1.00 69.2 -8.0 0.0

Diamond 14.0 1.02 14.3 -2.8 9.0 4.5 0.0

Diamond Sub 69.0 1.00 68.7 -0.6 0.0

DP1 14.0 1.00 14.0 0.0 3.5 0.4 0.0

Durban 14.0 1.05 14.7 -0.9 14.0 7.0 0.0

Durban Sub 69.0 1.00 68.8 -0.7 0.0

Edinburgh 14.0 1.03 14.4 -1.6 5.0 2.5 0.0

Edinburgh Sub 69.0 0.99 68.3 -0.2 0.0

Garden of Eden 14.0 1.01 14.2 -2.5 5.5 2.8 0.0 0.0 6.2

Garden of Eden Sub 69.0 1.00 68.9 -0.6 0.0

Good Hope 14.0 0.99 13.9 -5.1 7.0 3.5 0.0

Good Hope Sub 69.0 0.98 67.9 -3.0 0.0

Kingston 14.0 1.00 14.0 1.0 25.0 12.5 50.0 10.7 0.0

Kingston Sub 69.0 1.00 69.1 0.3 0.0

Mahaica 14.0 1.01 14.1 -5.8 2.5 1.0 0.0

Mahaica Sub 69.0 0.99 68.0 -5.1 0.0

Onverwagt 14.0 1.00 14.1 -7.9 3.5 1.5 0.0 0.0 4.0

Onverwagt Sub 69.0 0.99 68.5 -6.7 0.0

Skeldon 14.0 1.00 14.0 -3.5 10.0 2.4 0.0

Skeldon Sub 69.0 1.03 71.2 -6.6 0.0

Sophia 14.0 1.03 14.4 -2.0 20.0 10.0 0.0

Sophia Sub 69.0 1.00 69.0 -0.3 50.0 25.7 0.0

Versailles 14.0 1.04 14.5 -1.0 4.0 2.0 0.0

Versailles Sub 69.0 1.00 68.8 0.2 0.0

TOTAL

112.0 53.14 111.74 42.56 19.05

Busbar Voltages for Load Flow Runs 2016 Load Projections – 50 MW from Amaila Falls



Appendix III-4 – Line Flows 2016 Load Forecast


From

Mvar

From

MVA

From

% of

MVA

Limit

(Max)

MW

Loss

Mvar

Loss

Canefield Sub Onverwagt Sub No -6.8 3.7 7.7 25.6 0.04 0.17

Onverwagt Onverwagt Sub Yes -3.5 2.5 4.3 25.9 0.01 0.1

Onverwagt Sub Mahaica Sub No -10.3 5.9 11.9 0 0.22 0.51

Canefield Sub #53 Village Sub No -2.3 -1.9 3 18.3 0.04 0.06

Canefield Canefield Sub Yes -9 2.2 9.3 55.4 0.05 0.47


#53 Village Sub #53 Village Yes 7.5 0.4 7.5 45.2 0.03 0.3

Skeldon Sub Skeldon Yes -9.9 -2.5 10.3 65.5 0.07 0.6

Mahaica Sub Mahaica Yes 2.5 1.1 2.7 16.4 0 0.04

Mahaica Sub Good Hope Sub No -13 4.3 13.7 34.4 0.18 0.44

Good Hope Sub Good Hope Yes 5 2.7 5.7 34 0.02 0.17

Good Hope Sub Sophia Sub No -18.2 1.2 18.3 46.3 0.31 0.77

Garden of Eden Sub Sophia Sub No -4.9 0.8 5 16.6 0.03 0.04

Sophia Sub Kingston Sub No -17.4 9.3 19.7 56.3 0.1 0.18





Diamond Sub Sophia Sub No -9.7 -2.7 10 50.5 0.03 0.08

Sophia Sub Durban Sub No 14.1 7.7 16 53.5 0 0.13

Garden of Eden Sub Garden of Eden Yes 2 -1.3 2.3 14.1 0 0.03

Garden of Eden Sub DP1 Yes 1.8 -0.9 2 12.3 0 0.02

Garden of Eden Sub Diamond Sub No -0.6 2.4 2.4 12.2 0 0.01

Garden of Eden Sub 38 Yes 1.7 -1 2 11.9 0 0.02

Kingston Sub Versailles Sub No 9.1 4.9 10.3 61.7 0.02 0.04

Kingston Kingston Sub Yes 26.7 -2.6 26.9 76.8 0.21 1.67

Versailles Sub Edinburgh Sub No 4 2.2 4.6 27.5 0.01 0.03


Edinburgh Sub Edinburgh Yes 4 2.2 4.6 45.6 0.02 0.15

38 Garden of Eden No 3.5 -2 4 0 0 0.01

DP1 38 No 1.8 -0.9 2.1 0 0 0

Diamond Sub Diamond Yes 3.7 -3 4.8 29 0.01 0.11

Diamond Sub Diamond Yes 5.3 8 9.6 57.5 0.05 0.41

Durban Sub Durban Yes 7 3.8 8 47.9 0.03 0.28


TOTAL 1.74 8.44

Line Flows from Load Flow Run 2016 Load Projections - 50 MW from Amaila Falls



Appendix III-5 - Busbar Voltages 2016 Load Forecast 100 MW from Amaila Falls

Busbar Name Nom

kV

PU

Volt

Volt

(kV)

Angle

(Deg)

Load

MW

Load

Mvar

Gen

MW

Gen

Mvar

Switched

Shunts

Mvar

#53 Village 14.0 1.02 14.2 -8.6 7.5 3.1 3.1

#53 Village Sub 69.0 1.02 70.6 -6.3 0.0

Canefield 14.0 1.02 14.3 -9.8 9.0 3.8 0.0 0.0 8.4

Canefield Sub 69.0 1.01 69.5 -6.9 0.0

Diamond 14.0 1.02 14.3 -2.1 9.0 4.5 0.0

Diamond Sub 69.0 0.99 68.6 0.2 0.0

DP1 14.0 1.00 14.0 0.0 0.0 0.0 0.0

Durban 14.0 1.05 14.7 0.0 14.0 7.0 0.0

Durban Sub 69.0 1.00 68.8 0.2 0.0

Edinburgh 14.0 1.02 14.2 -2.3 5.0 2.5 0.0

Edinburgh Sub 69.0 0.98 67.8 -0.9 0.0

Garden of Eden 14.0 1.00 14.1 -0.9 5.5 2.8 0.0 0.0 6.0

Garden of Eden Sub 69.0 1.00 68.7 0.0 0.0

Good Hope 14.0 1.00 14.0 -3.4 5.0 2.5 0.0

Good Hope Sub 69.0 0.99 68.2 -2.0 0.0

Kingston 14.0 1.00 14.0 -1.1 25.0 12.5 1.6 24.3 0.0

Kingston Sub 69.0 0.99 68.6 -0.4 0.0

Mahaica 14.0 1.01 14.2 -4.7 2.5 1.0 0.0

Mahaica Sub 69.0 0.99 68.3 -4.0 0.0

Onverwagt 14.0 1.01 14.1 -6.8 3.5 1.5 0.0 0.0 4.1

Onverwagt Sub 69.0 1.00 68.8 -5.6 0.0

Skeldon 14.0 1.00 14.0 -2.3 10.0 2.1 0.0

Skeldon Sub 69.0 1.03 71.3 -5.5 0.0

Sophia 14.0 1.03 14.4 -1.2 20.0 10.0 0.0

Sophia Sub 69.0 1.00 69.0 0.6 100.0 11.7 0.0

Versailles 14.0 1.03 14.4 -1.7 4.0 2.0 0.0

Versailles Sub 69.0 0.99 68.3 -0.6 0.0

Table 5. : Busbar Results from Load Flow Runs 2016 – 100 MW Import from Amaila Falls



Appendix III-6 - Line Flows 2016 Load Forecast – 100 MW from Amaila Falls


From

Mvar

From

MVA

From

% of MVA

Limit

(Max)

MW

Loss

Mvar

Loss


Onverwagt Onverwagt Sub Yes -3.5 2.6 4.4 26.2 0.01 0.1


Canefield Sub #53 Village Sub No -2.3 -0.9 2.5 15.1 0.02 0.04

Canefield Canefield Sub Yes -9 4.7 10.1 60.7 0.06 0.54



Skeldon Sub Skeldon Yes -9.9 -1.5 10 63.8 0.06 0.57


Mahaica Sub Good Hope Sub No -13.1 5.7 14.3 35.7 0.19 0.47


Good Hope Sub Sophia Sub No -18.3 2.6 18.4 46.7 0.31 0.78

Garden of Eden Sub Sophia Sub No -4.9 0.8 5 16.6 0.03 0.04

Sophia Sub Kingston Sub No 32.6 -0.4 32.6 93.1 0.29 0.5






Sophia Sub Durban Sub No 14.1 7.7 16 53.5 0 0.13

Garden of Eden Sub Garden of Eden Yes 2 -1.3 2.3 14.1 0 0.03

Garden of Eden Sub DP1 Yes 1.8 -0.9 2 12.3 0 0.02


Garden of Eden Sub 38 Yes 1.7 -1 2 11.9 0 0.02


Kingston Kingston Sub Yes -23.1 7.2 24.2 69 0.17 1.35

Versailles Sub Edinburgh Sub No 5.1 2.8 5.8 34.7 0.02 0.05


Edinburgh Sub Edinburgh Yes 5 2.8 5.7 57.3 0.03 0.25

38 Garden of Eden No 3.5 -2 4 0 0 0.01

DP1 38 No 1.8 -0.9 2.1 0 0 0

Diamond Sub Diamond Yes 3.7 -3 4.8 29 0.01 0.11




TOTAL 1.92 8.66

Line Flows from Load Flow Runs 2016 Load Flow Projections – 100 MW from Amaila Falls



Appendix III-7 Load Flow Results 2020 Load Forecast – 115 MW from Amaila Falls

Name Nom kV PU Volt Volt

(kV)

Angle

(Deg)

Load

MW

Load

Mvar

Gen

MW

Gen

Mvar

Switched

Shunts

Mvar

#53 Village 14.0 1.01 14.19 -10.33 8.0 3.13 3.15

#53 Village Sub 69.0 1.02 70.29 -8.04 0.00

38 14.0 1.00 13.98 -0.32 0.00

Canefield 14.0 1.02 14.24 -11.50 9.50 3.76 0.00 0.00 11.15

Canefield Sub 69.0 1.00 68.93 -8.55 0.00

Diamond 14.0 1.00 14.00 -1.13 12.00 6.00 0.00

Diamond Sub 69.0 0.99 68.48 0.41 0.00

DP1 14.0 1.00 13.98 -0.26 0.00 0.00 0.00

Durban 14.0 1.02 14.33 -1.51 16.00 8.00 0.00

Durban Sub 69.0 1.00 68.70 0.43 0.00

Edinburgh 14.0 1.01 14.16 -1.98 4.50 2.25 0.00

Edinburgh Sub 69.0 0.98 67.79 -0.10 0.00

Garden of Eden 14.0 1.00 14.00 -0.43 6.00 3.00 0.00 0.00 6.00

Garden of Eden Sub 69.0 0.99 68.62 0.30 0.00

Good Hope 14.0 1.00 14.06 -4.38 8.00 4.00 0.00

Good Hope Sub 69.0 0.98 67.60 -2.08 0.00

Kingston 14.0 1.00 14.00 -1.11 26.00 13.00 2.52 20.69 0.00

Kingston Sub 69.0 0.99 68.56 0.36 0.00

Mahaica 14.0 1.00 14.01 -5.17 3.00 1.25 0.00

Mahaica Sub 69.0 0.98 67.54 -4.27 0.00

Onverwagt 14.0 1.00 13.98 -8.58 4.00 1.66 0.00 0.00 6.44

Onverwagt Sub 69.0 0.99 68.18 -7.22 0.00

Skeldon 14.0 1.00 14.00 -4.10 10.00 1.02 0.00

Skeldon Sub 69.0 1.03 71.05 -7.22 0.00

Sophia 14.0 1.02 14.30 -0.55 22.00 11.00 0.00

Sophia Sub 69.0 1.00 69.00 0.90 115.00 22.87 0.00

Versailles 14.0 1.00 14.01 -0.96 5.50 2.75 0.00

Versailles Sub 69.0 0.99 68.26 0.22 0.00

TOTAL 124.5 59.8 127.5 44.58 26.8

Busbar Results from Load Flow Runs 2020 – 115 MW Import from Amaila Falls



Appendix III-8 - Load Flow Results 2020


From

Mvar

From

MVA

From

% of

MVA

Limit

(Max)

MW

Loss

Mvar

Loss

Canefield Sub Onverwagt Sub No -7.8 6.3 10 33.3 0.07 0.27

Onverwagt Onverwagt Sub Yes -4 4.8 6.2 37.3 0.02 0.2


Canefield Sub #53 Village Sub No -1.8 0.2 1.8 11 0.01 0.02

Canefield Canefield Sub Yes -9.5 7.2 11.9 71.4 0.08 0.7


#53 Village Sub #53 Village Yes 8 0.5 8.1 48.2 0.04 0.34

Skeldon Sub Skeldon Yes -9.9 -0.5 10 62.8 0.06 0.56


Mahaica Sub Good Hope Sub No -14.7 8.6 17.1 42.7 0.26 0.66


Good Hope Sub Sophia Sub No -23 3.5 23.3 58.8 0.33 0.72

Garden of Eden Sub Sophia Sub No -5.9 0.4 5.9 19.8 0.04 0.06

Sophia Sub Kingston Sub No 35.1 0.4 35.1 58.5 0.33 0.58






Sophia Sub Durban Sub No 16.1 8.9 18.4 61.3 0 0.17

Garden of Eden Sub Garden of Eden Yes 2.2 -1.2 2.5 14.8 0 0.03

Garden of Eden Sub DP1 Yes 2 -0.8 2.1 12.9 0 0.02


Garden of Eden Sub 38 Yes 1.8 -1 2.1 12.5 0 0.02


Kingston Kingston Sub Yes -23.5 7.7 24.7 70.6 0.17 1.41


Versailles Sub Versailles Yes 5.5 2.9 6.2 31.2 0.02 0.15

Edinburgh Sub Edinburgh Yes 5.5 3.1 6.3 63.3 0.04 0.31

38 Garden of Eden No 3.8 -1.8 4.2 0 0 0.01

DP1 38 No 2 -0.8 2.2 0 0 0

Diamond Sub Diamond Yes 6.6 6.8 9.5 94.7 0.08 0.67

Diamond Sub Diamond Yes 5.5 0.1 5.5 55 0.03 0.25

Durban Sub Durban Yes 8 4.4 9.2 54.9 0.05 0.37

Durban Sub Durban Yes 8 4.4 9.2 54.8 0.05 0.37

2.43 10.82

Line Flows from Load Flow Runs 2020 Load Projections – 115 MW from Amaila Falls




Name Nom kV PU Volt Volt

(kV)

Angle

(Deg)

Load

MW

Load

Mvar

Gen

MW

Gen

Mvar

Switched

Shunts

Mvar

#53 Village 14.0 0.98 13.76 -18.48 9.00 3.74 2.90

#53 Village Sub 69.0 0.99 68.62 -15.61 0.00

38 14.0 0.99 13.89 -3.85 0.00

Canefield 14.0 0.97 13.65 -18.81 11.00 4.58 0.00 0.00 7.60

Canefield Sub 69.0 0.97 66.69 -15.02 0.00

Diamond 14.0 0.99 13.85 -4.96 16.00 8.00 0.00

Diamond Sub 69.0 0.99 68.22 -2.88 0.00

DP1 14.0 0.99 13.89 -3.77 0.00 0.00 0.00

Durban 14.0 1.02 14.28 -4.96 20.00 9.00 0.00

Durban Sub 69.0 0.99 68.65 -2.75 0.00

Edinburgh 14.0 1.01 14.08 -5.10 5.50 2.75 0.00

Edinburgh Sub 69.0 0.98 67.80 -2.80 0.00

Garden of Eden 14.0 0.99 13.89 -4.01 8.50 4.25 0.00 0.00 5.91

Garden of Eden Sub 69.0 0.99 68.33 -2.99 0.00

Good Hope 14.0 0.98 13.73 -9.04 10.00 5.00 0.00

Good Hope Sub 69.0 0.97 66.61 -6.05 0.00

Kingston 14.0 1.00 14.00 -1.11 27.00 13.50 37.55 14.20 0.00

Kingston Sub 69.0 1.00 68.73 -2.23 0.00

Mahaica 14.0 0.98 13.66 -10.04 3.50 1.46 0.00

Mahaica Sub 69.0 0.96 66.02 -8.94 0.00

Onverwagt 14.0 0.96 13.50 -14.54 4.50 1.91 0.00 0.00 3.72

Onverwagt Sub 69.0 0.96 66.05 -12.94 0.00

Skeldon 14.0 1.00 14.00 -11.84 10.00 5.94 0.00

Skeldon Sub 69.0 1.01 69.75 -14.90 0.00

Sophia 14.0 1.02 14.29 -3.75 23.00 11.50 0.00

Sophia Sub 69.0 1.00 69.00 -2.23 100.00 41.26 0.00

Versailles 14.0 1.00 14.00 -3.79 6.50 3.25 0.00

Versailles Sub 69.0 0.99 68.38 -2.40 0.00

TOTAL 144.5 68.9 147.6 61.4 20.1

Busbar Results from Load Flow Runs 2025 – 100 MW Import from Amaila Falls





From

Mvar

From

MVA

From

% of

MVA

Limit

(Max)

MW Loss Mvar

Loss


Onverwagt Onverwagt Sub Yes -4.5 1.8 4.8 29 0.02 0.14

Onverwagt Sub Mahaica Sub No -15 7.1 16.6 0 0.45 1.07

Canefield Sub #53 Village Sub No -0.7 -3.6 3.7 22.5 0.06 0.1

Canefield Canefield Sub Yes -11 3 11.4 68.3 0.08 0.75

#53 Village Sub Skeldon Sub No -9.8 -5 11 37.3 0.1 0.21


Skeldon Sub Skeldon Yes -9.9 -5.2 11.2 72.7 0.08 0.74

Mahaica Sub Mahaica Yes 3.5 1.5 3.8 23 0.01 0.08

Mahaica Sub Good Hope Sub No -19 4.5 19.5 49.1 0.37 0.93

Good Hope Sub Good Hope Yes 10.1 5.7 11.6 69.4 0.08 0.71

Good Hope Sub Sophia Sub No -29.4 -2.2 29.5 76.3 0.84 2.1

Garden of Eden Sub Sophia Sub No -8.1 -0.6 8.1 27.3 0.07 0.11

Sophia Sub Kingston Sub No 3.6 6.1 7.1 11.9 0.01 0.02

Sophia Sub Sophia Yes 5 -4.7 6.9 41.9 0.03 0.23





Sophia Sub Durban Sub No 18.1 10.2 20.8 69.2 0 0.22

Garden of Eden Sub Garden of Eden Yes 3.1 -0.7 3.2 19.1 0.01 0.06

Garden of Eden Sub DP1 Yes 2.8 -0.3 2.8 16.7 0 0.04

Garden of Eden Sub Diamond Sub No -0.4 2.1 2.2 10.9 0 0

Garden of Eden Sub 38 Yes 2.6 -0.6 2.7 16.2 0 0.04

Kingston Sub Versailles Sub No 12.1 6.7 13.8 83 0.04 0.07

Kingston Kingston Sub Yes 8.5 0.7 8.6 24.5 0.02 0.17


Versailles Sub Versailles Yes 6.5 3.5 7.4 36.9 0.03 0.21

Edinburgh Sub Edinburgh Yes 5.5 3.1 6.3 63.2 0.04 0.3

38 Garden of Eden No 5.4 -0.9 5.5 0 0 0.02

DP1 38 No 2.8 -0.3 2.8 0 0 0

Diamond Sub Diamond Yes 7.2 -0.9 7.3 43.6 0.03 0.26


Durban Sub Durban Yes 9.1 5 10.3 62 0.06 0.47

Durban Sub Durban Yes 9.1 5 10.3 61.9 0.06 0.47

TOTAL 3.0 12.6

Line Flows from Load Flow Runs 2025 Load Projections – 100 MW from Amaila Falls